RANGE RESOURCES CORP
ITEM 1.
BUSINESS
General
We are a Fort Worth, Texas-based independent natural gas company, engaged in the exploration, development and acquisition of primarily natural gas properties, mostly in the Southwestern and Appalachian regions of the United States. We were incorporated in 1980 under the name Lomak Petroleum, Inc. and, later that year, we completed an initial public offering and began trading on the NASDAQ. In 1996, our common stock was listed on the New York Stock Exchange. In 1998, we changed our name to Range Resources Corporation. In 1999, we implemented a strategy of internally generated drillbit growth coupled with complementary acquisitions. Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. During the past five years, we have increased our proved reserves 166% (from 1.2 Tcfe in 2004 to 3.1 Tcfe in 2009), while production has increased 122% (from 71,726 Mmcfe in 2004 to 159,112 Mmcfe in 2009) during that same period.
At year-end 2009, our proved reserves had the following characteristics:
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3.1 Tcfe of proved reserves;
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84% natural gas;
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55% proved developed;
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79% operated;
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a reserve life of 18.6 years (based on fourth quarter 2009 production);
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a pre-tax present value of $2.6 billion of future net cash flows attributable to our reserves, discounted at 10% per annum (“PV-10”); and
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a standardized after-tax measure of discounted future net cash flows of $2.1 billion.
PV-10 may be considered a non-GAAP financial measure as defined by the SEC. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on prices and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. The difference between the standardized measure and the PV-10 amount is discounted estimated future income tax of $501.7 million at December 31, 2009.
At year-end 2009, we owned 3,214,000 gross (2,504,000 net) acres of leasehold, including 289,000 acres where we also own a royalty interest. We have built a multi-year drilling inventory that is estimated to contain over 11,500 drilling locations, both proven and unproven.
Our corporate offices are located at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. Our telephone number is (817) 870-2601.
Business Strategy
Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy is to employ internally generated drillbit growth coupled with complementary acquisitions. Our strategy requires us to make significant investments in technical staff, acreage and seismic data and technology to build drilling inventory. Our strategy has the following principal elements:
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Concentrate in Core Operating Areas. We currently operate in two 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 the Anadarko Basin of Western Oklahoma) and Appalachian (which includes tight-gas, shale, coal bed methane and conventional oil and gas production in Pennsylvania, Virginia, Ohio, New York and West Virginia). 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 blend the production characteristics of each area to balance our portfolio toward our goal of consistent production and reserve growth.
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Focus on cost efficiency. We concentrate in core areas which we believe to have sizeable hydrocarbon deposits in place that will allow us to consistently increase production while controlling costs. As there is little long-term competitive sales price advantage available to a commodity producer, the costs to find, develop, and produce a commodity are important to organizational sustainability and long-term shareholder value creation. We endeavor to control costs such that our cost to find, develop and produce oil and gas is in the best performing quartile of our peer group.
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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 11,500 identified drilling locations in inventory, both proven and unproven. In 2009, we drilled 463 gross (285.4 net) wells.
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Maintain Long-Life Reserve Base. Long-life oil and gas reserves provide a more stable growth platform than short-life reserves. Long-life reserves reduce reinvestment risk as they lessen the amount of reinvestment capital deployed each year to replace production. Long-life oil and gas reserves also assist us in minimizing costs as stable production makes it easier to build and maintain operating economies of scale. We use our acquisition, divestiture, and drilling activity to execute this strategy.
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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 to seize an attractive acquisition opportunity. If certain areas generate higher than anticipated returns, we may accelerate drilling and acquisitions in those areas and decrease capital expenditures and acquisitions elsewhere. We also believe in maintaining a strong balance sheet and using commodity hedging, which allows us to be more opportunistic in lower price environments and provides more consistent financial results.
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Make Complementary Acquisitions. We target complementary acquisitions in existing core areas 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 $612.1 million of complementary acquisitions. These acquisitions have been located primarily in the Barnett Shale in North Central Texas and the Marcellus Shale in Pennsylvania.
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Equity Ownership and Incentive Compensation. We want our employees to think and act like owners. To achieve this, we reward and encourage them through equity ownership in Range. All full-time employees receive equity
grants. As of December 31, 2009, our employees owned equity securities in our benefit plans (vested and unvested) that had an aggregate market value of approximately $312.7 million.
Significant Accomplishments in 2009
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Production and reserve growth - Fourth quarter 2009 marked Range’s 28th consecutive quarter of sequential production growth. In 2009, our annual production averaged 435.9 Mmcfe per day, an increase of 13% from 2008. Proven reserves increased 18% in 2009 to 3.1 Tcfe, marking the eighth consecutive year our proven reserves have increased. This achievement is the result of our continued drilling success, as all of production and reserve growth in 2009 came from our drilling program. Our business is inherently volatile, and while consistent growth such as we have experienced over the past seven years will be challenging to sustain, the quality of our technical teams and our sizable drilling inventory bode well for the future.
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Successful drilling program - In 2009, we drilled 463 gross wells. Production was replaced by 484% through drilling in 2009, and our overall success rate was nearly 100%. 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 critical.
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Large resource potential from unconventional plays - Maintaining a large exposure to potential resources is important. We continued expansion of our resource shale plays in 2009. We have two large unconventional plays - the Marcellus Shale in Pennsylvania and the Barnett Shale in North Texas. These plays cover expansive areas, provide multi-year drilling opportunities and have sustainable lower risk growth profiles. The economics of these plays have been enhanced by continued advancements in drilling and completion technologies. We have now leased 1.2 million net acres in these two shale plays. We also have 263,000 net acres in our coal bed methane plays in Virginia, West Virginia and Pennsylvania.
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Maintenance of a strong balance sheet - Financial leverage, as measured by the debt-to-capitalization ratio, remained level at 42% for both year-end 2008 and 2009. We refinanced $285.2 million of shorter-term bank debt by issuing $300.0 million of senior subordinated fixed rate 8.0% notes having a 10-year maturity, at a discount. This helped to align the maturity schedule of our debt with the long-term life of our assets and reduce interest rate volatility.
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Successful unproved property purchases completed - In 2009, we acquired $176.9 million of acreage located in our core areas, primarily in the Marcellus Shale. We paid cash and issued stock for this acreage. We continued to see outstanding results in the Marcellus Shale. Production increased 150%, we proved up additional unproved acreage, acquired additional acreage and continue to work with outside parties to gain pipeline and processing capacity.
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Successful dispositions completed - In second quarter 2009, we sold oil properties in West Texas for proceeds of $181.8 million. In fourth quarter 2009, we sold our natural gas properties in New York for proceeds of $36.3 million. See also Note 3 to our consolidated financial statements.
Industry Operating Environment
The oil and gas industry is affected by many factors that we generally cannot control. Government regulations, particularly in the areas of taxation, energy, climate change and the environment, can have a significant impact on operations and profitability. For several years preceding the 2008 worldwide economic decline, the oil and gas industry had been characterized by volatile but upward trending oil, NGL and gas commodity prices. However, since mid-year 2008, we have experienced declines in commodity prices, especially with regard to natural gas prices.
Significant factors that will impact 2010 crude oil prices include: political and social developments in the Middle East, demand in Asian and European markets, and the extent to which members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations are able to manage oil supply through export quotas. Natural gas prices are generally determined by North American supply and demand and are also affected by imports of liquefied natural gas. In addition, weather has a significant impact on demand for natural gas since it is a primary heating source.
Plans for 2010
Our capital expenditure budget for 2010 has been initially set at approximately $950.0 million. As has been our historical practice, we will periodically review our capital expenditures throughout the year and adjust the budget based on commodity prices and drilling success. The 2010 budget includes $700.0 million to drill 464 gross (338.2 net) wells and to undertake 38 gross (29.0 net) recompletions. Also included is $190.0 million for land, $20.0 million for seismic and $40.0 million for the expansion and enhancement of gathering systems and facilities. Approximately 82% of the budget is attributable to the Appalachian region and 18% to the Southwestern region.
In December 2009, we announced our plan to offer for sale our tight gas sand properties in Ohio. The properties include approximately 3,500 producing wells, 418,000 net acres of leasehold and 1,600 miles of pipeline and gathering system infrastructure. Parties began conducting evaluations in January 2010 and on February 8, 2010 we announced that we had entered into a definitive agreement to sell these assets for a price of $330.0 million, subject to typical post-closing adjustments. However, the completion of the sale is dependent upon prospective buyer due diligence procedures and there can be no assurance the sale will be completed.
Production, Price and Cost History
The following table sets forth information regarding oil and gas production, realized prices and production costs for the last three years. For additional information on price calculations, see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
(a)
Oil and NGLs are converted at the rate of one barrel equals six mcf.
Employees
As of January 1, 2010, we had 787 full-time employees, 373 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 use independent consultants and contractors to perform various professional services, particularly in the areas of drilling, completion, field, on-site production services and certain accounting functions.
Available Information
Our internet website is available under the name http://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. In addition, other information such as company presentations are also available on our website. 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 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. Our Code of Business Conduct and Ethics applies to all directors, officers and employees, including the chief executive officer and senior financial officer.
We file annual reports on Form 10-K, quarterly reports on Form 10-Q, 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, NE, 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 http://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.
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 and gas 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 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. See “
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. Our business could also be impacted by additional risks and uncertainties not currently known to us or that we currently deem to be immaterial.
Risks Related to Our Business
Volatility of oil and gas prices significantly affects our cash flow and capital resources and could hamper our ability to produce oil and gas economically
Oil and gas prices are volatile, and a decline in prices adversely affects our profitability and financial condition. The oil and gas industry is typically cyclical, and prices for oil and gas have been volatile. Historically, the industry has experienced downturns characterized by oversupply and/or weak demand. Long-term supply and demand for oil and gas is uncertain and subject to a myriad of factors such as:
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the domestic and foreign supply of oil and gas;
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the price and availability of alternative fuels;
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weather conditions;
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the level of consumer demand;
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the price of foreign imports;
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worldwide economic conditions;
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the availability, proximity and capacity of transportation facilities and processing facilities;
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the effect of worldwide energy conservation efforts;
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political conditions in oil and gas producing regions; and
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domestic and foreign governmental regulations and taxes.
Oil and gas prices have been volatile over the past 18 months. In July 2008, the average New York Mercantile Exchange (“NYMEX”) price of oil was $133.49 per barrel and the average NYMEX price of gas was $12.96 per mcf. In December 2008, the average NYMEX price of oil had fallen to $42.04 per barrel and gas was $6.56 per mcf. In 2009, oil prices rebounded to $74.60 per barrel as of December 31, 2009, while gas prices remained depressed at $4.46 per mcf. Decreases in oil and gas prices have adversely affected 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. Sustained decreases in oil and gas prices will further adversely affect our revenues, net income, cash flows, proved reserves and our ability to fund capital expenditures.
Information concerning our reserves and future net cash flow estimates is uncertain
There are numerous uncertainties inherent in estimating quantities of proved oil and 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.
Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of oil and gas that cannot be directly measured. As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may calculate different estimates of reserves and future net cash flows based on the same available data. Because of the subjective nature of oil and gas reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:
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the amount and timing of oil and gas production;
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the revenues and costs associated with that production; and
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the amount and timing of future development expenditures.
The discounted future net cash flows from our proved reserves included in this report should not be considered as the market value of the reserves attributable to our properties. For 2009, as required by generally accepted accounting principles, the estimated discounted future net revenues from our proved reserves are based on a twelve month average price (beginning of month) while cost estimates are as of the end of the year. Actual future prices and costs may be materially higher or lower. In addition, the 10 percent discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under generally accepted accounting principles is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and gas industry in general.
If oil and gas prices decrease or drilling efforts are unsuccessful, we may be required to record write downs of our oil and gas properties
In the past we have been required to write down the carrying value of certain of our oil and gas properties, and there is a risk that we will be required to take additional writedowns in the future. Writedowns may occur when oil and 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 drilling results or mechanical problems with wells where the cost to redrill or repair is not supported by the economics.
Accounting rules require that the carrying value of oil and 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 gas prices at the time of the impairment review, or as a result of 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.
We acquire significant amounts of unproved property to further our development efforts. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire both producing and unproved properties as well as lease undeveloped acreage that we believe will enhance growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.
Significant capital expenditures are required to replace our reserves
Our exploration, development and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flow from operations, our bank credit facility and debt and equity issuances. From time to time, we have also engaged in asset monetization transactions. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and gas and our success in developing and producing new reserves. If our access to capital were limited due to numerous factors, which could include a decrease in revenues due to lower gas and oil prices or decreased production or deterioration of the credit and capital markets, we would have a reduced ability to replace our reserves. We may not be able to incur additional bank debt, issue debt or equity, engage in asset monetization or access other methods of financing on an economic basis to meet our reserve replacement requirements.
The amount available for borrowing under our bank credit facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. The decline in oil and gas prices in 2008 has adversely impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base. If commodity prices (particularly gas prices) continue to decline in 2010, it will have similar adverse effects on our reserves and borrowing base.
Our future success depends on our ability to replace reserves that we produce
Because the rate of production from oil and 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 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 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.
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 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:
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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;
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a portion of our borrowings are at variable rates of interest, making us vulnerable to increases in interest rates;
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we may be more highly leveraged than some of our competitors, which could place us at a competitive disadvantage;
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our degree of leverage may make us more vulnerable to a downturn in our business or the general economy;
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we are subject to numerous financial and other restrictive covenants contained in our existing credit agreements the breach of which could materially and adversely impact our financial performance;
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our debt level could limit our flexibility to grow the business and in planning for, or reacting to, changes in our business and the industry in which we operate; and
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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. In addition to those risks above, we may not be able to obtain funding on acceptable terms because of the deterioration of the credit and capital markets. This may hinder or prevent us from meeting our future capital needs. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly.
Our business is subject to operating hazards that could result in substantial losses or liabilities that may not be fully covered under our insurance policies
Oil and 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:
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injury or loss of life;
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severe damage to or destruction of property, natural resources and equipment;
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pollution or other environmental damage;
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clean-up responsibilities;
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regulatory investigations and penalties; or
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suspension of operations.
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. We have experienced substantial increases in premiums, especially in areas affected by 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 our credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, at December 31, 2009, approximately 81% of our debt is at fixed interest rates with the remaining 19% subject to variable interest rates.
Recent and continuing disruptions and volatility in the global finance markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital; a significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results. We are exposed to some credit risk related to our senior credit facility to the extent that one or more of our lenders may be unable to provide necessary funding to us under our existing revolving line of credit if it experiences liquidity problems.
Difficult conditions in the global capital markets and the economy generally may materially adversely affect our business and results of operations
Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the repricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain financing. In addition, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of accessing the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards and limited the amount of funding available to borrowers.
As a result, we may be unable to obtain adequate funding under our current credit facility because (i) our lending counterparties may be unwilling or unable to meet their funding obligations or (ii) the amount we may borrow under our current credit facility could be reduced as a result of lower oil, natural gas liquids or gas prices, declines in reserves, stricter lending requirements or regulations, or for other reasons. Due to these factors, we cannot be certain that funding will be available on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures any of which could have a material adverse effect on our production, revenues and results of operations.
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 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:
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our production is less than expected;
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the counterparties to our futures contracts fail to perform under the contracts; or
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an event materially impacts oil or gas prices or the relationship between the hedged price index and the oil and gas sales price.
We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and gas. On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in oil and gas prices than our competitors who engage in hedging transactions.
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 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. As a result, these competitors may be able to address these competitive factors more effectively than we can or weather industry downturns more easily than we can.
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
In a rising price environment, such as those experienced in 2007 and early 2008, well service providers and related equipment and personnel are in short supply. This caused escalating prices, the possibility of poor services coupled with potential damage to downhole reservoirs and personnel injuries. Such pressures 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. In some cases, we are operating in areas where services and infrastructure are limited, or do not exist or in urban areas which are more restrictive.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase
Section 1(b) of the Natural Gas Act of 1938 (“NGA”) exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress.
While our natural gas gathering operations are generally exempt from FERC regulation under the NGA, our gas gathering operations may be subject to certain FERC reporting and posting requirements in a given year. FERC has recently issued a final rule (as amended by orders on rehearing, “Order 704”) requiring certain participants in the natural gas market, including certain gathering facilities and natural gas marketers that engage in a minimum level of natural gas sales or purchases, to submit annual reports regarding those transactions to FERC. In addition, FERC has issued a final rule (“Order 720”) requiring major non-interstate pipelines, defined as certain non-interstate pipelines delivering more than an average of 50 million MMBtu of gas over the previous three calendar years, to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has design capacity equal to or greater than 15,000 MMBtu per day.
Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, gas quality, ratemaking, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipelines rates and rules and policies that may affect rights of access to transportation capacity. For more information regarding the regulation of our operations, please see “Government Regulation” in Item 1 of this report.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines
Under the EPAct 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated as a natural gas company by FERC under the NGA, FERC has adopted regulations that may subject certain of four otherwise non-FERC jurisdiction facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. We also must comply the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject Range to civil penalty liability. For more information regarding regulation of our operations, please see “Government Regulation” in Item 1 of this report.
The oil and gas industry is subject to extensive regulation
The oil and 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 gas industry. Compliance with such rules and regulations often increases our cost of doing business, delays our operations and, in turn, decreases our profitability.
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.
Climate change is receiving increasing attention from scientists and legislators alike. The debate is ongoing as to the extent to which our climate is changing, the potential causes of this change and its potential impacts. Some attribute global warming to increased levels of greenhouse gases, including carbon dioxide, which has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.
Presently there are no federally mandated greenhouse gas reduction requirements in the United States. However, in June 2009 the U.S. House of Representatives passed bill H.R. 2454, American Clean Energy and Security Act of 2009, which proposes reducing greenhouse gas emissions to 17% below 2005 levels by 2020 and 83% below 2005 levels by 2050. The bill has now passed to the United States Senate for debate and vote. Consequently, the precise federal mandatory emissions reduction program that may be adopted and the specific requirements of any such program are uncertain.
There are a number of legislative and regulatory proposals to address greenhouse gas emissions, which are in various phase of discussion or implementation. The outcome of federal and state actions to address global climate change could result in a variety of regulatory programs including potential new regulations, additional charges to fund energy efficiency activities, or other regulatory actions. These actions could:
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result in increased costs associated with our operations;
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increase other costs to our business;
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affect the demand for natural gas, and
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impact the prices we charge our customers.
Any adoption by federal or state governments mandating a substantial reduction in greenhouse gas emissions could have far-reaching and significant impacts on the energy industry and the U.S. economy. We cannot predict the potential impact of such laws or regulations on our future consolidated financial condition, results of operations or cash flows.
Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
Among the changes contained in President Obama’s budget proposal for fiscal year 2011, released by the White House on February 1, 2010, is the elimination of certain U.S. federal income tax provisions currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective. As of December 31, 2009, we have a tax basis of $526 million related to prior year capitalized intangible drilling costs which will be amortized over the next five years.
The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operation.
In addition, Pennsylvania Governor Ed Rendell’s budget proposal for fiscal year 2011, released on February 9, 2009, proposed a new natural gas wellhead tax on both volumes and sales of natural gas extracted in Pennsylvania, where the majority of our acreage in the Marcellus Shale is located. The passage of any legislation as a result of the Pennsylvania state budget proposal could increase the tax burden on our operations in the Marcellus Shale.
The elimination of certain federal tax deductions or the imposition of new state taxes discussed about could negatively affect our financial condition and results of operations.
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.
In addition, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our acquisition strategy is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our acquisition strategy may be hindered if we are unable 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 and none of them 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. Also, the loss of experienced personnel could lead to a loss of technical expertise.
Drilling is a high-risk activity
The cost of drilling, completing, and operating a well is often uncertain, and many factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce enough oil and gas to be commercially viable after drilling, operating and other costs. Furthermore, our drilling and producing operations may be curtailed, delayed, or canceled as a result of other factors, including:
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high costs, shortages or delivery delays of drilling rigs, equipment, labor, or other services;
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unexpected operational events and drilling conditions;
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reductions in oil and gas prices;
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limitations in the market for oil and gas;
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adverse weather conditions;
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facility or equipment malfunctions;
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equipment failures or accidents;
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title problems;
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pipe or cement failures;
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casing collapses;
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compliance with environmental and other governmental requirements;
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environmental hazards, such as natural gas leaks, oil spills, pipelines ruptures, and discharges of toxic gases;
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lost or damaged oilfield drilling and service tools;
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unusual or unexpected geological formations;
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loss of drilling fluid circulation;
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pressure or irregularities in formations;
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fires;
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natural disasters;
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surface craterings and explosions; and
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uncontrollable flows of oil, natural gas or well fluids.
If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.
New technologies may cause our current exploration and drilling methods to become obsolete
The oil and 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 unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.
Federal legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.
The United States Congress is currently considering legislation to amend the Safe Drinking Water Act to eliminate an existing exemption for hydraulic fracturing activities. Hydraulic fracturing involves the injection of water, sand and additives under pressure into rock formation to stimulate natural gas production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of natural gas and oil from many reservoirs, especially shale formations such as the Barnett Shale and the Marcellus Shale. If adopted, this legislation could establish an additional level of regulation and permitting at the federal level. This additional regulation and permitting could lead to operational delays or increased operating costs and could result in additional burdens that could increase our costs of compliance and doing business as well as delay the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing.
Our business depends on oil and gas transportation facilities, most of which are owned by others
The marketability of our oil and gas production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties. The 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. We have recently entered into some firm arrangements in certain of our production areas. Federal and state regulation of oil and 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 gas. If any of these third party pipelines and other facilities become partially or fully unavailable to transport our product, or if the natural gas quality specifications for a natural gas pipeline or facility changes so as to restrict our ability to transport natural gas on those pipelines or facilities, our revenues could be adversely affected.
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.
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 regarding our existing or planned operations or allege a violation of an existing contract. Any such action could delay when planned operations can actually commence or could cause a halt to existing production until such alleged violations are resolved by the courts. Not only could we incur significant legal and support expenses in defending our rights, but halting existing production or delaying planned operations could impact our future operations and financial condition. Such legal disputes could also distract management and other personnel from their primary responsibilities.
Our financial statements are complex
Due to United States generally accepted accounting rules and the nature of our business, 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 plans. We expect such complexity to continue and possibly increase.
Risks Related to Our Common Stock
Common stockholders will be diluted if additional shares are issued
In 2004, 2005 and 2006, we sold 40.2 million shares of common stock to finance acquisitions. In 2007, we sold 8.1 million shares of common stock to finance acquisitions. In 2008, we sold 4.4 million shares of common stock with the proceeds used to pay down a portion of the outstanding balance of our bank credit facility. In 2009, we issued 744,000 shares of common stock to purchase acreage in the Marcellus Shale. Our ability to repurchase securities for cash is limited by our bank credit facility and our senior subordinated note agreements. We also issue restricted stock and stock appreciation rights to our employees and directors as part of their compensation. 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 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, 2007 to December 31, 2009, the price of our common stock reported by the New York Stock Exchange ranged from a low of $23.77 per share to a high of $76.81 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 factors include:
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changes in oil and gas prices;
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variations in quarterly drilling, recompletions, acquisitions and operating results;
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changes in governmental regulation;
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changes in financial estimates by securities analysts;
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changes in market valuations of comparable companies;
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additions or departures of key personnel; or
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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.
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 data for our operating regions for the year ended December 31, 2009.
Approximately 65% of our proved reserves at December 31, 2009 are located in the Barnett Shale in our Southwestern region and the Marcellus Shale and Nora Area in our Appalachian region. Each of these plays has a large portfolio of drilling opportunities. Our reserve estimates do not include any probable or possible reserves. We have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments; therefore, segment reporting is not applicable to us. 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.
Southwestern Region
The Southwestern region includes 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, Anadarko Basin of western Oklahoma and Louisiana and Mississippi. In the Southwestern region, we own 1,854 net producing wells, 96% of which we operate. Our average working interest is 66%. We have approximately 886,000 gross (568,000 net) acres under lease.
Total proved reserves in the Southwestern region decreased 26.6 Bcfe, or 2%, at December 31, 2009, when compared to year-end 2008. Production, asset sales (103.5 Bcfe) and an unfavorable reserve revision for lower prices were partially offset by drilling additions (195.5 Bcfe). Annual production increased 4% over 2008. During 2009, the region spent $252.9 million to drill 90 (77.1 net) development wells, of which 89 (76.5 net) were productive, and 7 (6.1 net) exploratory wells, of which 6 (5.4 net) were productive. During the year, the region achieved a 99% drilling success rate.
At December 31, 2009, the Southwestern region had a development inventory of 441 proven drilling locations and 421 proven recompletions. During the year, the Southwestern region drilled 37 proven locations and added 75 new proven locations. 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 cost control, upgrading lifting equipment, improving gathering systems and surface facilities, and performing restimulations and refracturing operations.
Barnett Shale
Our operations in the Barnett Shale of North Texas began with the 2006 acquisition of Stroud Energy. We added additional properties from various acquisitions in 2007 and 2008. We now own approximately 131,700 net acres. At December 31, 2009, we have 167 proven drilling locations in this area, and 51 proven recompletions and plan to drill 28 wells in 2010. Our production in the Barnett Shale increased from 93,654 mcfe per day in 2008 to 122,030 mcfe per day in 2009. During 2009, we drilled 47 net development wells, all of which were successful.
Appalachian Region
Our properties in this area are located in the Appalachian Basin in the northeastern United States, principally in Pennsylvania, Ohio, West Virginia and Virginia. The reserves principally produce from the Pennsylvanian (coalbed formation), Upper Devonian, Medina, Clinton, Big Lime and Marcellus Shale formations at depths ranging from 2,500 to 9,000 feet. Generally, after initial flush production, most of these properties are characterized by gradual decline rates, typically producing for more than 40 years. We own 8,052 net producing wells, 66% of which we operate, and approximately 4,000 miles of gas gathering lines. Our average working interest is 77%. We have approximately 2.3 million gross (1.9 million net) acres under lease, which include 289,000 acres where we also own a royalty interest.
Reserves at December 31, 2009 increased 501.8 Bcfe, or 38%, from 2008 with drilling additions (574.4 Bcfe) partially offset by asset sales (36.1 Bcfe) and production. Annual production increased 28% over 2008. During 2009, the region spent $348.8 million to drill 352 (194.0 net) development wells, all of which were productive, and 14 (8.3 net) exploratory wells, all of which were productive. At December 31, 2009, the Appalachian region had an inventory of 3,600 proven drilling locations and 500 proven recompletions. During the year, the Appalachian region drilled 248 proven locations and added 566 new proven locations.
In December 2009, we announced our plans to offer for sale our tight gas sand properties in Ohio, which include 3,500 producing wells, 418,000 net acres of leasehold and 1,600 miles of pipelines and gathering system infrastructure. Parties began evaluations in January 2010 and on February 8, 2010, we announced that we had entered into a definitive agreement to sell these assets for a purchase price of $330.0 million, subject to typical post-closing terms and conditions. In 2009, these properties produced 25.9 Mmcfe per day.
Marcellus Shale
We began operations in the Marcellus Shale, located in Pennsylvania, in 2004. This has been our largest investment area over the last two years. We recorded 167 proven drilling locations at December 31, 2009. Our 2009 production was 150% greater than 2008 and at year-end 2009 was about 113,000 mcfe per day. During 2009, we drilled 44 net development wells and 4 net exploratory wells in the Marcellus Shale, all of which were successful. In 2010, we plan to drill 150 wells.
We have long-term agreements with third parties to provide gathering and processing services and infrastructure assets in the Marcellus Shale. In fourth quarter 2009, MarkWest Liberty Midstream, L.L.C. completed a phase three expansion, pursuant to these agreements. This expansion included an additional 120,000 mcf per day of cryogenic natural gas processing, 20 additional miles of gathering and residue gas pipelines and 21,000 horsepower of additional compression.
Nora Area
In 2004, we acquired natural gas properties in the Nora Area. In 2007, we equalized our working interests in a portion of the field with EQT Corporation and entered into a joint development plan. We have over 1,600 proven drilling locations in the Nora Field. Production in the Nora Area increased from 46,800 Mcfe per day in 2008 to 52,400 Mcfe per day in 2009. During 2009, we drilled 148 net development wells and 4 net exploratory wells and achieved a 100% drilling success rate. In 2010, we plan to drill 229 wells.
Proved Reserves
In December 2008, the SEC announced that it had approved revisions to modernize its oil and gas company reserve reporting requirements. We adopted the new rules as of December 31, 2009. See additional disclosures below and also in Item 8. Financial Statements and Supplemental information on Natural Gas and Oil Exploration, Development and Production Activities. The following table sets forth our estimated proved reserves based on the new SEC rules as defined in Rule 4.10(a) of Regulation S-X and Item 1200 of Regulation S-K:
The following table sets forth our estimated proved reserves for 2008, 2007, 2006 and 2005 based on end of year prices:
(a)
Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf.
The following table sets forth summary information by area with respect to estimated proved reserves at December 31, 2009:
(a)
PV-10 was prepared using the twelve-month average prices for 2009, discounted at 10% per annum. Year-end PV-10 may be considered a non-GAAP financial measure as defined by the SEC. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure, or after tax amount, because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on prices and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. The difference between the standardized measure and the PV-10 amount is the discounted estimated future income tax of $501.7 million at December 31, 2009. Included in the $2.6 billion PV-10 is $2.1 billion (pre-tax) related to proved developed reserves.
Recent SEC Rule-Making Activity
In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:
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Commodity Prices - Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.
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Disclosure of Unproved Reserves - Probable and possible reserves may be disclosed separately on a voluntary basis.
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Proved Undeveloped Reserve Guidelines - Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.
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Reserves Estimation Using New Technologies - Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.
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Reserves Personnel and Estimation Process - Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.
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Non-Traditional Resources - The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.
We adopted the rules effective December 31, 2009, as required by the SEC.
Effect of Adoption
Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of the new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 86.0 Bcfe. Use of the old year-end prices rules would have resulted in an increase in proved reserves of approximately 3.0 Bcfe at December 31, 2009. Therefore, the total impact of the new price methodology rules resulted in negative reserves revisions of 89.0 Bcfe. We also estimate that we added 230 Bcfe of additional proved undeveloped reserves, primarily in our Marcellus Shale play, where we have experienced good drilling results as allowed by the new SEC definitions.
Reserve Estimation
At year-end 2009, the following independent petroleum consultants conducted a review of our reserves: DeGolyer and MacNaughton (Southwestern), H.J. Gruy and Associates, Inc. (Southwestern) and Wright and Company, Inc. (Appalachian). These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2009, these consultants collectively reviewed approximately 88% of our proved reserves. A copy of the summary reserve report of each of these independent petroleum consultants is included as an exhibit to this Annual Report on Form 10-K. The technical person at each independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished to independent petroleum consultants for their reserves review process. Throughout the year, our technical team meets periodically with representatives of each of our independent petroleum consultants to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves any internally estimated significant changes to our proved reserves. We provide historical information to our consultants for our largest producing properties such as ownership interest; oil and gas production; well test data; commodity prices and operating and development costs. The consultants perform an independent analysis and differences are reviewed with our Senior Vice President of Reservoir Engineering. In some cases, additional meetings are held to review additional reserve work performed by the technical teams related to any identified reserve differences.
Historical variances between our reserve estimates and the aggregate estimates of our consultants have been less than 5%. The reserves included in this report on Form 10-K are those reserves estimated by our employees. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering, who reports directly to our President. Our Senior Vice President of Reservoir Engineering holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with Amoco, Hunt Oil and Union Pacific Resources and has thirty years of experience in the oil and gas industry. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operation conditions. We did not file any reports during the year ended December 31, 2009 with any federal authority or agency with respect to our estimate of oil and gas reserves.
Reserve Technologies
Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal technical staff employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, empirical evidence through drilling results and well performance, well logs, geologic maps and available downhole and production data, seismic data, well test data and reservoir simulation modeling.
Reporting of Oil and Natural Gas Liquids
We produce natural gas liquids as part of the processing of our natural gas. The extraction of natural gas liquids in the processing of natural gas reduces the volume of natural gas available for sale. At December 31, 2009 natural gas liquids represented approximately 10% of our total proved reserves on an Mcf equivalent basis. Natural gas liquids are products sold
by the gallon. In reporting proved reserves and production of natural gas liquids, we include this production as barrels of oil. Prices for a standard barrel of natural gas liquids in 2009 averaged approximately 47% lower than the average prices for equivalent volumes of oil. We report all production information related to natural gas net of the effect of any reduction in natural gas volumes resulting from the processing of natural gas liquids.
Proved Undeveloped Reserves (PUDs)
As of December 31, 2009, our PUDs totaled 38.8 Mmbbls of crude oil and 1.2 Tcf of natural gas, for a total of 1.4 Tcfe. Approximately 77% of our PUDs at year-end 2009 were associated with our major development areas in the Barnett, Marcellus and Nora properties. Changes in PUDs that occurred during the year were due to:
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conversion of approximately 117 Bcfe PUDs into proved developed reserves;
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new PUDs added of 528 Bcfe; and
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negative revisions of approximately 30 Bcfe in PUDs due to change in commodity prices.
Costs incurred relating to the development of PUDs were approximately $140 million in 2009. Estimated future development costs relating to the development of PUDs are projected to be approximately $292 million in 2010, $472 million in 2011, and $428 million in 2012. All PUD drilling locations are scheduled to be drilled prior to the end of 2014.
The following table sets forth the estimated future net cash flows, excluding open hedging contracts, from proved reserves, the present value of those net cash flows (PV-10), and the expected benchmark prices and average field prices used in projecting net cash flows over the past five years (in millions except prices):
Future net cash flows represent projected revenues from the sale of proved reserves net of production and development costs (including operating expenses and production taxes). Based on the new SEC rules, prices for 2009 were based on a twelve-month average, without escalation. Prices for 2005, 2006, 2007 and 2008 were based on prices in effect at December 31 of each year, without escalation. Such calculations are also based on costs in effect at December 31 of each year, without escalation. There can be no assurance that the proved reserves will be produced in the future or that prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties.
Producing Wells
The following table sets forth information relating to productive wells at December 31, 2009. We also own royalty interests in an additional 2,600 wells in which 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 gas according to their predominant production stream. We do not have a significant number of dual completions.
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
We own interests in developed and undeveloped oil and gas acreage. These ownership interests generally take the form of working interests in oil and gas leases 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 the developed and undeveloped acreage in which we own a working interest as of December 31, 2009. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary:
Undeveloped Acreage Expirations
The table below summarizes by year our undeveloped acreage scheduled to expire in the next five years.
We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years. However, we have in the past and expect in the future, to be able to extend the lease terms of some of these leases and exchange or sell some of these leases with other companies. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed acreage to expire and will allow additional acreage to expire in the future.
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. As of December 31, 2009, we were in the process of drilling 13 gross (13 net) wells.
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 before 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:
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customary royalty interests;
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liens incident to operating agreements and for current taxes;
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obligations or duties under applicable laws;
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development obligations under oil and gas leases; or
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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 15 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 fourth quarter 2009.
PART II
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “RRC.” During 2009, trading volume averaged 2.7 million shares per day. The following table shows the quarterly high and low sale prices and cash dividends declared as reported on the NYSE composite tape for the past two years.
Between January 1, 2010 and February 19, 2010, the common stock traded at prices between $45.00 and $54.65 per share. Our senior subordinated notes are not listed on an exchange, but trade over-the-counter.
Holders of Record
On February 19, 2010, there were approximately 1,545 holders of record of our common stock.
Dividends
The payment of dividends is subject to declaration by the Board of Directors and depends on earnings, capital expenditures and various other factors. The bank credit facility 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 2008 for the repurchase of up to $10.0 million of common stock based on market conditions and opportunities. There were no repurchases during 2009. As of December 31, 2009, we have $6.8 million remaining under this authorization.
Stockholder Return Performance Presentation*
The following graph is included in accordance with the SEC’s executive compensation disclosure rules. This historic stock price performance is not necessarily indicative of future stock performance. The graph compares the change in the cumulative total return of Range’s common stock, the Dow Jones U.S. Exploration and Production Index, and the S&P 500 Index for the five years ended December 31, 2009. The graph assumes that $100 was invested in the Company’s common stock and each index on December 31, 2004, and that dividends were reinvested.
Range Resources Corporation
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S&P 500 Index
DJ U.S. Expl. & Prod. Index
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The performance graph and the information contained in this section is not “soliciting material,” is being “furnished” not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the Securities Act or the Exchange Act whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing.
ITEM 6.
SELECTED FINANCIAL DATA
The following table shows selected financial information for the five years ended December 31, 2009. Significant producing property acquisitions in 2006, 2007 and 2008 affect the comparability of year-to-year financial and operating data. In March 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million. The financial and statistical data contained in the following discussion reflect our Gulf of Mexico operations as discontinued operations. All weighted average shares and per share data have been adjusted for a three-for-two stock split effected December 2, 2005. This information should be read in conjunction with
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 company engaged in the exploration, development and acquisition of primarily gas properties, mostly in the Southwestern and Appalachian 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 economically find, develop, acquire and produce oil and gas reserves. We use the successful efforts method of accounting for our oil and gas activities. Our corporate headquarters is located in Fort Worth, Texas.
Industry Environment
We operate entirely within the United States. As traditional basins in the U.S. have matured, exploration and production has shifted to unconventional “resource” plays, typically shale reservoirs that historically were not thought to be productive for oil and gas. These plays cover large areas, provide multi-year inventories of drilling opportunities and, with modern oil and gas technology, have sustainable lower risk growth profiles. The economics of these plays have been enhanced by continued advancements in drilling and completion technologies. These advancements make these plays more resilient to lower commodity prices while increasing the domestic supply of natural gas and, with increased supply, an expected reduction in the volatility of natural gas prices. Examples of such technological advancements include advanced 3-D seismic processing, hydraulic reservoir fracture stimulation using almost one hundred percent sand and water, advances in well logging and analysis, horizontal drilling and completion technologies and automated remote well monitoring and control devices.
Oil and gas are commodities. The price that we receive for the natural gas we produce is largely a function of market supply and demand in the United States. Demand for natural gas in the United States increased substantially over the past 10 years; however, the current economic slowdown has reduced this demand. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of natural gas can result in price volatility. Factors impacting the future supply balance are the growth in domestic gas production and the increase in the United States’ LNG import capacity. American gas supplies have increased as a result of recent expansion in domestic unconventional gas production. Existing LNG capacity may result in lower natural gas prices. Crude oil prices are generally determined by global supply and demand.
The reduced liquidity provided by the worldwide financial markets and other factors resulted in an economic slowdown in the United States and other industrialized countries in 2008, which resulted in reductions in worldwide energy demand. At the same time, North American gas supply has increased as a result of the expansion in domestic unconventional gas production. The combination of lower demand due to the economic slowdown and higher North American gas supply has resulted in declines in natural gas prices from their highs in mid-2008. These circumstances have led to a decrease in drilling activity and reduced the demand for drilling rigs, oilfield supplies, tubulars and drill pipe. During 2009, we experienced lower overall industry costs, but these declines lagged behind the decline in prices. The duration and magnitude of the commodity price declines cannot be predicted.
Oil and gas prices affect:
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the amount of cash flow available to us for capital expenditures;
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our ability to borrow and raise additional capital;
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the quantity of oil and gas that we can economically produce;
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revenues and profitability; and
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the accounting for our oil and gas activities.
Any continued or extended decline in oil and gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital.
Capital Budget for 2010
Our capital budget for 2010 is currently set at $950.0 million, excluding acquisitions. The 2010 capital budget is more than the 2009 capital spending levels with higher expected operating cash flows resulting from higher projected oil and gas prices and higher production. For 2010, we expect our cash flow and proceeds from asset sales to fund our capital budget. As has been our historical practice, we will periodically review our capital expenditures throughout the year and adjust the budget based on commodity prices, drilling success and other factors.
Source of Our Revenues
We derive our revenues from the sale of oil and gas that is produced from our properties. Revenues are a function of the volume produced, the prevailing market price at the time of sale, quality, Btu content and transportation costs to market. Production volumes and the price of oil and gas are the primary factors affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to hedge future sales prices on a substantial, but varying, portion of our gas and oil production. The use of derivative instruments has in the past and may in the future, prevent us from realizing the full benefit of upward price movements but also protects us from declining price movements. Our average realized price calculations (including all derivative settlements) include both the effects of the settlement of derivative contracts that are accounted for as hedges and the settlement of derivative contracts that are not accounted for as hedges.
Principal Components of Our Cost Structure
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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 maintenance, repairs and workovers expenses related to our oil and gas properties. These costs, on an mcfe basis, are expected to continue to moderate in 2010. Direct operating expenses also include stock-based compensation expense (non-cash) associated with grants of stock appreciation rights (SARs) and the amortization of restricted stock grants as part of employee compensation.
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Production and Ad Valorem Taxes. Production taxes are paid on produced oil and gas based on a percentage of market prices (not hedged prices) or at fixed rates established by federal, state or local taxing authorities. Ad valorem taxes are generally based on reserve values at the end of each year.
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Exploration Expenses. These are geological and geophysical costs, including payroll and benefits for the geological and geophysical staff, seismic costs, delay rentals and the costs of unsuccessful exploratory dry holes. Exploration expense includes stock-based compensation expense (non-cash) associated with grants of SARs and the amortization of restricted stock grants as part of employee compensation.
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General and Administrative Expenses. These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other professional fees and legal compliance. General and administrative expense includes stock-based compensation expense (non-cash) associated with grants of SARs and the amortization of restricted stock grants as part of employee compensation.
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Abandonment and impairment of unproved properties. This category includes unproved property impairment and costs associated with lease expirations.
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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 debt securities. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We will likely continue to incur interest expense as we continue to grow.
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Depreciation, Depletion and Amortization. This includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop 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 expense also includes the systematic, monthly accretion of the future abandonment costs of tangible assets such as wells, service assets, pipelines, and other facilities.
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Income Taxes. We are subject to state and federal income taxes but are currently not in a tax paying position for 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 a basis other than federal taxable income. Currently, substantially all of our federal taxes are deferred, however, we anticipate using 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. For additional information, see “Risk Factors-Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation,” in Item 1A of this report.
Management’s Discussion and Analysis of Income and Operations
Overview of 2009 Results
During 2009, we achieved the following financial and operating results:
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achieved 13% production growth;
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achieved 18% reserve growth;
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drilled 285 net wells with a 99.6% success rate;
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continued expansion of key plays by growing production, proving up acreage and acquiring additional unproved acreage;
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maintained a strong balance sheet by retaining a debt to capitalization ratio of 42% and issuing $300 million of new senior subordinated notes;
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received proceeds of $234 million from asset sales;
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realized $592 million of cash flow from operating activities; and
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ended the year with stockholders’ equity of $2.4 billion.
Our 2009 performance reflects another year of successfully executing our strategy of growth through drilling. During 2009, we did not make a material acquisition of proved reserves. Instead, we acquired unproved acreage, primarily in the Marcellus Shale. 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 our operations are critical to profitability and long-term value creation for stockholders. As a result of the drop in commodity prices, we have increased our efforts on improving our operating efficiency. These efforts resulted in lower direct operating expense per mcfe for 2009 when compared to 2008. However, as we continue to expand our Marcellus Shale team to meet the needs of this developing asset, we have experienced upward pressure on our general and administrative costs per mcfe. To mitigate this trend, we closed our Gulf Coast division office effective November 1, 2009 with those operations being combined and operated out of the Southwest division in Fort Worth. We successfully faced other challenges in 2009, including accessing the capital markets to fund our growth on sufficiently favorable terms, continuing to introduce new extraction technologies into the Marcellus Shale and retaining qualified operational people despite our lower capital spending program. We began the year in the midst of a worldwide economic decline and have taken several steps to improve our liquidity (see Management’s Discussion and Analysis of Financial Condition-Cash Flows and Liquidity). Our inventory of exploration and development prospects continues to provide new growth opportunities. We continue to believe that our portfolio of long-lived assets positions us for future growth.
Total revenues decreased 32% in 2009 over the same period of 2008. This decrease was due to lower realized oil and gas prices somewhat offset by higher production. Our 2009 production growth was due to the continued success of our drilling program. Average realized prices (including all derivative settlements) were 25% lower in 2009. As discussed in Item 1A of this report, significant changes in oil and gas prices can have a material impact on our balance sheet and our results of operations, including the fair value of our derivatives.
2010 Outlook
For 2010, the Board has approved a $950.0 million capital budget for oil and gas related activities, excluding proved property acquisitions. We expect to fund our 2010 capital budget expenditures with cash flows from operations and proceeds from asset sales. The price risk on a portion of our forecasted oil and gas production for 2010 is mitigated using commodity derivative contracts and we intend to continue to enter into these transactions. The prices we receive for our oil and natural gas production are largely based on current market prices, which are beyond our control. We announced our plan to offer for sale our tight gas sand properties in Ohio and the data room opened in January 2010. These properties include approximately 3,500 producing wells, 418,000 net acres of leasehold and 1,600 miles of pipeline and gathering system infrastructure. On February 8, 2010, we announced that we had entered into a definitive agreement to sell these assets for a price of $330.0 million, subject to typical post-closing adjustments. The completion of the sale is dependent upon prospective buyer due diligence procedures and there can be no assurance the sale will be completed.
Oil and Gas Sales, Production and Realized Price Calculations
Our oil and gas sales vary from year to year as a result of changes in realized commodity prices and production volumes. Hedges included in oil and gas sales reflect settlements on those derivatives that qualify for hedge accounting. Cash settlement of derivative contracts that are not accounted for as hedges are included in the statement of operations in derivative fair value income (loss). Oil and gas sales decreased 32% from 2008 due to a 39% decrease in realized prices, partially offset by a 13% increase in production. Oil and gas sales in 2008 increased 42% from 2007 due to a 21% increase in production and an 17% increase in realized prices. The following table illustrates the primary components of oil and gas sales for each of the last three years (in thousands):
Our production continues to grow through drilling success as we place new wells into production and through additions from acquisitions, partially offset by the natural decline of our oil and gas wells and asset sales. For 2009, our production volumes increased 28% in the Appalachian region and 4% in the Southwestern region. Crude oil production declined from 2008 primarily due to the sale of certain oil properties in West Texas. For 2008, our production volumes increased 18% in the Appalachian region, increased 22% in our Southwestern region and increased 61% in our Gulf Coast region. For 2007, our production volumes increased 15% in the Appalachian region, increased 28% in the Southwestern region and declined 17% in our Gulf Coast region. Our production for each of the last three years is set forth in the following table:
(a)
Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf.
Our average realized price (including all derivative settlements) received for oil and gas during 2009 was $6.44 per mcfe compared to $8.58 per mcfe in 2008 and $8.02 per mcfe in 2007. Our average realized price (including all derivative settlements) calculation includes all cash settlements for derivatives, whether or not they qualify for hedge accounting. Average price calculations for each of the last three years is shown below:
(a)
Oil and NGLs are converted at the rate of one barrel equals six mcf.
(b)
Based on average of bid week prompt month prices.
Derivative fair value income (loss) was a gain of $66.4 million in 2009 compared to a gain of $71.9 million in 2008 and a loss of $9.5 million in 2007. Some of our derivatives do not qualify for hedge accounting and are accounted for using the mark-to-market accounting method whereby all realized and unrealized gains and losses related to these contracts are included in derivative fair value income (loss). Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues and are not included in our consolidated balance sheet in accumulated other comprehensive income (loss). As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Any gains on our derivatives will be offset by lower wellhead revenues in the future or any losses will be offset by higher wellhead revenues based on the value at the settlement date. At December 31, 2009, our derivative contracts are recorded at their fair value, which is a net asset of $10.9 million, a decrease of
$215.8 million from the $226.7 million asset recorded as of December 31, 2008. Most of the year-end 2008 net asset was related to 2009 derivative contracts; therefore, this decrease is primarily related to the settlement of these contracts. We have also entered into basis swap agreements to limit volatility caused by changing differentials between index and regional prices received. These basis swaps do not qualify for hedge accounting purposes and are marked to market. Hedge ineffectiveness, also included in derivative fair value income (loss), is associated with contracts that qualify for hedge accounting. The ineffective portion is calculated as the difference between the change in the fair value of the derivative and the estimated change in future cash flows from item hedged.
The following table presents information about the components of derivative fair value income (loss) for each of the years in the three-year period ended December 31, 2009 (in thousands):
(a)
These amounts are unrealized and are not included in average sales price calculations.
(b)
These amounts represent realized gains and losses on settled derivatives that do not qualify for hedge accounting.
(c)
These settlements are included in average realized price calculations (including all derivative settlements).
Other revenue decreased in 2009 to $488,000 compared to $21.7 million in 2008 and $5.0 million in 2007. The 2009 period includes a $10.4 million gain on the sale of Marcellus acreage and a $3.8 million lawsuit settlement offset by a non-cash loss from equity method investments of $13.7 million. The 2008 period includes a $20.2 million gain on the sale of assets and a non-cash loss from equity method investments of $218,000. The 2007 period includes non-cash income from equity method investments of $974,000 and other miscellaneous income.
We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on a per mcfe basis for 2009, 2008 and 2007.
Direct operating expense was $133.8 million in 2009 compared to $142.4 million in 2008 and $107.5 million in 2007. We experience increases in operating expenses as we add new wells and maintain production from existing properties. In 2009, this effect was more than offset by lower overall industry costs, lower workover expenses and asset sales. On an absolute dollar basis, our spending for direct operating expenses is lower when compared to 2008 despite higher production levels reflecting cost containment measures and lower overall industry costs. We incurred $6.5 million of workover costs in 2009 compared to $9.9 million in 2008 and $7.1 million in 2007. On a per mcfe basis, direct operating expense for 2009 decreased $0.17 or 17% from the same period of 2008 with the decrease consisting primarily of lower workover costs ($0.03 per mcfe), lower utility costs ($0.02 per mcfe), lower well service costs, asset sales and our focus on cost containment. On a per mcfe basis, direct operating expenses for 2008 increased $0.09 or 10% from the same period of 2007 with the increase consisting primarily of higher workover costs ($0.01 per mcfe), higher personnel and related costs ($0.02 per mcfe) along with higher equipment leasing costs ($0.02 per mcfe) and higher overall industry costs. Stock-based compensation expense represents the amortization of restricted stock grants and SARs as part of employee compensation. The following table summarizes direct operating expenses per mcfe for 2009, 2008 and 2007:
Production and ad valorem taxes are paid based on market prices and not hedged prices. These costs were $32.2 million in 2009 compared to $55.2 million in 2008 and $42.4 million in 2007. On a per mcfe basis, production and ad valorem taxes decreased to $0.20 in 2009 from $0.39 in 2008 due to a 56% decrease in pre-hedge prices. On a per mcfe basis, production and ad valorem taxes increased to $0.39 in 2008 from $0.36 in the same period of 2007 primarily due to a 24% increase in pre-hedge prices.
General and administrative expense was $116.7 million for 2009 compared to $92.3 million in 2008 and $69.7 million in 2007. The 2009 increase of $24.4 million when compared to the prior year is due primarily to higher salaries and benefits ($11.7 million) due to an increase in the number of employees (4%) and salary increases, higher stock based compensation ($9.7 million), higher legal fees and office expenses, including rent and information technology. 2009 also includes $1.0 million ($0.01 per mcfe) accrued severance costs and $1.4 million ($0.01 per mcfe) bad debt expense. The 2008 increase of $22.6 million when compared to 2007 is due primarily to higher salaries and benefits ($12.0 million) due to an increase in the number of employees (14%) and salary increases, higher stock-based compensation ($5.6 million), higher legal and professional fees ($921,000), an allowance for bad debt expense of $450,000 and higher office expenses, including rent and information technology. Our personnel costs continue to increase as we invest in our technical teams and other staffing to support our expansion into the Marcellus Shale in Appalachia. Stock-based compensation expense represents the amortization of restricted stock grants and SARs to our employees and directors as part of compensation. The following table summarizes general and administrative expenses per mcfe for 2009, 2008 and 2007:
Interest expense was $117.4 million for 2009 compared to $99.7 million in 2008 and $77.7 million in 2007. Interest expense for 2009 increased $17.6 million from the same period of 2008 due to the refinancing of certain debt from floating rates to higher fixed rates and higher average debt balances. In May 2009, we issued $300.0 million of 8% senior subordinated notes due 2019, which added $15.1 million of additional interest costs in 2009. The proceeds from this issuance was used to retire bank debt, which carried a lower interest rate. Interest expense for 2008 increased $22.0 million from the same period of 2007 due to the refinancing of certain debt from floating rates to higher fixed rates along with higher overall debt balances. In September 2007, we issued $250.0 million of 7.5% senior subordinated notes due 2017, which added $13.9 million of additional interest costs in 2008. In May 2008, we issued $250.0 million of 7.25% senior subordinated notes due 2018, which added $11.8 million of interest costs in 2008. The proceeds from both issuances were used to retire bank debt which carried a lower interest rate. The 2008 and 2009 note issuances were undertaken to better match the maturities of our debt with the life of our properties and to give us greater liquidity for the near term. Average debt outstanding on the bank credit facility for 2009 was $584.5 million compared to $494.2 million for 2008 and $417.6 million for 2007 and the weighted average interest rate was 2.4% in 2009 compared to 4.4% in 2008 and 6.4% in 2007.
Depletion, depreciation and amortization (“DD&A”) was $374.4 million in 2009 compared to $299.8 million in 2008 and $220.6 million in 2007. The increase in 2009 compared to 2008 is due to a 13% increase in production, 6% increase in depletion rates and accelerated depreciation expense of $10.3 million on an interim processing plant in Appalachia that will be dismantled in the first quarter of 2010. The increase in 2008 compared to the same period of 2007 is due to a 21% increase in production and a 14% increase in depletion rates. On a per mcfe basis, DD&A increased to $2.35 in 2009 compared to $2.12 in 2008 and $1.89 in 2007. Depletion expense, the largest component of DD&A, was $2.11 per mcfe in 2009 compared to $1.99 per mcfe in 2008 and $1.74 per mcfe in 2007. We have historically adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and other times during the year when circumstances indicate there has been a significant change in reserves or costs. In areas where we are actively drilling, such as the Marcellus and Barnett Shale areas, fourth quarter 2009 depletion rates are lower than 2008. Depletion rates in new plays tend to be higher in the beginning as
increased initial outlays are amortized over proved reserves based on early stages of evaluations. The increase in DD&A per mcfe is related to the accelerated depreciation expense on an interim processing plant ($0.06) and the mix of our production. The following table summarizes DD&A expense per mcfe for 2009, 2008 and 2007:
Other Operating Expenses
Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, exploration expense, abandonment and impairment of unproved properties and deferred compensation plan expenses. In 2009, stock-based compensation was a component of direct operating expense ($2.6 million), exploration expense ($4.8 million) and general and administrative expense ($33.5 million) for a total of $41.8 million. In 2008, stock-based compensation was a component of direct operating expense ($2.8 million), exploration expense ($4.1 million) and general and administrative expense ($23.8 million) for a total of $31.2 million. In 2007, stock-based compensation was a component of direct operating expense ($1.8 million), exploration expense ($3.5 million) and general and administrative expense ($18.2 million) for a total of $24.0 million. Stock-based compensation includes the amortization of restricted stock grants and SARs grants. These costs are increasing due to increasing grant date fair values and an increase in the number of grants on our increasing employee base.
Exploration expense was $46.9 million in 2009 compared to $67.7 million in 2008 and $45.8 million in 2007. The following table details our exploration-related expenses for 2009, 2008 and 2007. Exploration expense was significantly lower in 2009 when compared to 2008 due to our focus on development of our large shale and coal bed methane projects and the closure of our Gulf Coast office. The increase in exploration expense from 2007 to 2008 reflects higher seismic and personnel costs due, in part, to the early stages of the Marcellus Shale development. The following table details our exploration related expenses for 2009, 2008 and 2007 (in thousands):
Abandonment and impairment of unproved properties was $113.5 million in 2009 compared to $47.4 million in 2008 and $11.2 million in 2007. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. This increase is primarily due to the significant increase in lease acquisition costs over the past three years and increased leasing activity in new areas that require several years to delineate along with lower oil and gas prices which resulted in reduced drilling activity. As we continue to review our acreage positions and high grade our drilling inventory based on the current price environment, additional leasehold impairments and abandonments will likely be recorded.
Deferred compensation plan expense was a loss of $31.1 million in 2009 compared to a gain of $24.7 million in 2008 and a loss of $35.4 million in 2007. Our stock price increased to $49.85 at December 31, 2009 compared to $34.39 at December 31, 2008. This non-cash expense relates to the increase or decrease in value of the liability associated with our common stock that is vested and held in our deferred compensation plan. The deferred compensation liability is adjusted to fair value by a charge or a credit to deferred compensation plan expense. The year ended 2008 decreased $60.1 million from the same period of 2007 due to a decline in our stock price, which decreased from $51.36 at December 31, 2007 to $34.39 at December 31, 2008. During 2007, our stock price increased from $27.46 at December 31, 2006 to $51.36 at December 31, 2007.
Income tax (benefit) expense was a benefit of $4.9 million in 2009 compared to expense of $193.8 million in 2008 and expense of $96.3 million in 2007. The 2009 decrease reflects a 111% decrease in income from continuing operations compared to the same period of 2008. The year ended 2009 also includes an unfavorable $16.3 million charge to reflect updated state tax rates used in establishing deferred taxes due to a change in our state apportionment factors to higher rate states, particularly in Pennsylvania due to our increased focus on development of the Marcellus Shale along with increased proved reserves and acreage in Pennsylvania. 2009 provides for tax expenses at an effective tax rate of 8.3% compared to an effective tax rate in 2008 of 35.6%. For the year ended December 31, 2009, the current income tax benefit of $636,000 includes state income taxes of $364,000 and a federal income tax benefit of $1.0 million. The effective tax rate on continuing operations was different than the statutory rate of 35% due to an increase in our state apportionment factors in certain higher-rate states, offset by a benefit related to a partial release of valuation allowance on our capital loss carryforward. Income tax expense for 2008 increased to $193.8 million, reflecting a 118% increase in income from continuing operations before taxes compared to the same period of 2007. 2008 provided for tax expenses at an effective rate of 35.6% compared to an effective rate of 38.5% in the same period of 2007. For 2008, current income taxes of $4.3 million include state income taxes of $3.3 million and $1.0 million of federal income taxes. The effective tax rate on continuing operations was different than the statutory rate of 35% due to state income taxes. Income tax expense for 2007 decreased to $96.3 million, reflecting a 22% decrease in income from continuing operations before taxes compared to the same period of 2006. The year ended December 31, 2007 provided for tax expense at an effective rate of 38.5%. For the year ended December 31, 2007, current income taxes includes state income taxes of $449,000 and a benefit of $129,000 of federal income taxes. We expect our effective tax rate to be approximately 38% for 2010.
Discontinued operations in 2007 include the operating results related to our Gulf of Mexico properties and Austin Chalk properties sold in first quarter 2007.
Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity
Our main sources of liquidity and capital resources are internally generated cash flow from operations, a bank credit facility with both uncommitted and committed availability, asset sales and access to the debt and equity capital markets. In a continuing effort to mitigate the effect of the deterioration in the capital markets and the decline in oil and gas commodity prices which began in mid-2008, we took additional measures in 2009 to enhance our liquidity. In May 2009, we issued $300.0 million of 8.0% senior subordinated notes due 2019, at a discount. We used the $285.2 million of proceeds received from the issuance of these senior subordinated notes to repay outstanding bank debt, increasing the availability of our credit line. Also in 2009, we entered into commodity derivative contracts covering 108.5 Bcf of gas and 0.4 million barrels of oil. These contracts expire through December 2011. We also sold oil and gas properties in West Texas and New York for $218.1 million with the proceeds used to repay outstanding bank debt. Our 2009 capital spending was significantly reduced in all areas except our Marcellus Shale operations. As part of our semi-annual bank review completed September 30, 2009, our borrowing base and facility amounts were reaffirmed at $1.5 billion and $1.25 billion. The borrowing base represents the amount approved by the bank group that can be borrowed based on our assets and liabilities while the bank commitment (or facility amount) is the amount the banks have committed to fund pursuant to the credit agreement.
During 2009, our net cash provided from continuing operations of $591.7 million and proceeds from the sale of assets of $234.1 million were used to fund $720.0 million of capital expenditures (including acquisitions and equity investments). At December 31, 2009, we had $767,000 in cash and total assets of $5.4 billion. Our debt to capitalization ratio was 42%. As of December 31, 2009 and 2008, our total debt and capitalization were as follows (in thousands):
Long-term debt at December 31, 2009 totaled $1.7 billion, including $324.0 million of bank credit facility debt and $1.4 billion of senior subordinated notes. Our available committed borrowing capacity at December 31, 2009 was $925.9 million. Cash is required to fund capital expenditures necessary to offset inherent declines in production and reserves that are 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 currently 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, asset sales 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 proven reserves.
Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance, the state of the worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate and, in particular, with respect to borrowings, the level of our working capital or outstanding debt and credit ratings by rating agencies. For additional information, see “Risk Factors-Difficult Conditions in the global capital markets and the economy generally may materially adversely affect our business and results of operations” in Item 1A of this report.
Credit Arrangements
We maintain a $1.25 billion 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, 2012. Availability under the bank credit facility is subject to a borrowing base set by the lenders semi-annually with an option to set more often in certain circumstances. The borrowing base is dependent on a number of factors but primarily the lenders’ assessment of future cash flows. Redeterminations of the borrowing base require approval of 2/3rds of the lenders; increases require unanimous approval. At February 19, 2010, the bank credit facility had a $1.5 billion borrowing base and a $1.25 billion facility amount. Remaining credit availability was $880.0 million on February 19, 2010. Our bank group is comprised of twenty-six commercial banks, with no one bank holding more than 5.0% of the bank credit facility. We believe our large number of banks and relatively low commitment levels allows for sufficient lending capacity should we elect to increase our $1.25 billion commitment up to the $1.5 billion borrowing base and also allows for flexibility should there be additional consolidation within the banking sector.
Our bank debt and our subordinated notes impose limitations on the payment of dividends and other restricted payments (as defined under the debt agreements for our bank debt and our subordinated notes). The debt agreements also contain customary covenants relating to debt incurrence, working capital, dividends and financial ratios. We were in compliance with all covenants at December 31, 2009.
Cash Flow
Cash flows from operations are primarily affected by production volumes and commodity prices, net of the effects of settlements of our derivatives. Our cash flows from operations also are impacted by changes in working capital. We generally maintain low cash and cash equivalent balances because we use available funds to reduce our bank debt. Short-term liquidity needs are satisfied by borrowings under our bank credit facility. Because of this, and since our principal source of operating cash flows (or proved reserves to be produced in the following year) cannot be reported as working capital, we often have low or negative working capital. We sell substantially all of our oil and gas production at the wellhead under floating market contracts. However, we generally hedge a substantial, but varying portion of our anticipated future oil and gas production for the next 12 to 24 months. Any payments due to counterparties under our derivative contracts should ultimately be funded by prices received from the sale of our production. Production receipts, however, often lag payments to the counterparties. Any interim cash needs are funded by borrowing under the credit facility. As of December 31, 2009, we have entered into hedging agreements covering 90.7 Bcfe for 2010 and 20.1 Bcfe for 2011.
Net cash provided from continuing operations in 2009 was $591.7 million compared to $824.8 million in 2008 and $632.1 million in 2007. Cash provided from operations is largely dependent upon commodity prices and production, net of the effects of settlement of our derivative contracts. The decrease in cash provided from operating activities from 2008 to 2009 reflects lower price realizations (a decline of 25%) somewhat offset by a 13% increase in production. The increase in cash provided by operating activities from 2007 to 2008 was primarily due to increased production from acquisitions and development activity and higher price realizations. As of December 31, 2009, we have hedged approximately 51% of our projected 2010 production and 9% of our projected 2011 production. Net cash provided from continuing operations is also
affected by working capital changes or the timing of cash receipts and disbursements. Changes in working capital (as reflected in our consolidated statement of cash flows) for 2009 was a negative $44.8 million compared to a positive $20.2 million in 2008 and a negative $13.0 million in 2007.
Net cash used in investing activities in 2009 was $473.8 million compared to $1.7 billion in 2008 and $1.0 billion in 2007.
During 2009, we:
•
spent $541.2 million on oil and gas property additions;
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spent $139.3 million on acreage primarily in the Marcellus Shale;
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received proceeds of $234.1 million primarily from the sale of West Texas and New York oil and gas properties; and
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contributed $6.4 million of capital to Nora Gathering, LLC, an equity method investment.
During 2008, we:
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spent $881.9 million on oil and gas property additions;
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spent $834.8 million on acquisitions, including the purchase of producing and unproved Barnett Shale properties and Marcellus Shale leasehold;
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contributed $29.0 million of capital to Nora Gathering, LLC, an equity method investment; and
•
received proceeds of $68.2 million primarily from the sale of East Texas oil and gas properties.
During 2007, we:
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spent $782.4 million on oil and gas property additions;
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spent $336.5 on acquisitions including acquiring additional interests in the Nora field in Virginia;
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spent $94.7 million for a 50% membership interest in Nora Gathering, LLC, an equity method investment; and
•
received proceeds of $234.3 million primarily from the sale of our Gulf of Mexico assets and Austin Chalk properties.
Net cash (used in) provided from financing activities in 2009 was ($117.9 million), compared to $903.7 million in 2008 and $379.9 million in 2007. Historically, sources of financing have been primarily bank borrowings and capital raised through equity and debt offerings.
During 2009, we:
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borrowed $707.0 million and repaid $1.1 billion under our bank credit facility, ending the year with $369 million lower bank debt; and
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issued $300.0 million aggregate principal amounts of our 8% senior subordinated notes due 2019, at a discount.
During 2008, we:
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borrowed $1.5 billion and repaid $1.1 billion under our bank credit facility, ending the year with $390 million higher bank debt; and
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issued $250.0 million aggregate principal amount of our 7.25% senior subordinated notes due 2018; and
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received proceeds of $282.2 million from a common stock offering.
During 2007, we:
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borrowed $865.0 million and repaid $1.0 billion under our bank credit facility, ending the year with $149 million lower bank debt; and
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issued $250.0 million aggregate principal amount of our 7.5% senior subordinated notes due 2017; and
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received proceeds of $280.4 million from a common stock offering.
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 2009, $601.7 million of capital was expended on drilling projects. Also in 2009, $139.3 million was expended on acquisitions of unproved acreage, primarily in the Marcellus Shale. In addition, 744,000 shares of stock were issued in exchange for Marcellus Shale unproved acreage. Our 2009 capital program, excluding acquisitions, was funded by net cash flow from operations, proceeds from asset sales and issuance of equity. Our capital expenditure budget for 2010 is currently set at $950.0 million, excluding acquisitions. Development and exploration activities are highly discretionary, and, for the near term, 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. We currently believe we have sufficient liquidity and cash flow to meet our obligations for the next twelve months; however, a continued 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. We monitor our capital expenditures on a regular basis, adjusting the amount up or down and also between our operating regions, depending on commodity prices, cash flow and projected returns. 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 primarily depends on cash flow and capital expenditures. In 2009, we paid $25.2 million in dividends to our common shareholders ($0.04 per share in each quarter). In 2008, we paid $24.6 million in dividends to our common shareholders ($0.04 per share in each quarter). In 2007, we paid $19.1 million in dividends to our common shareholders ($0.04 per share in the fourth quarter and $0.03 per share in the third, second and first quarters).
Cash Contractual Obligations
Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, asset retirement obligations and transportation commitments. As of December 31, 2009, we do not have any capital leases nor have we entered into any material long-term contracts for equipment. As of December 31, 2009, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed the debt of any unrelated party. As of December 31, 2009, we had a total of $100,000 of letters of credit outstanding under our bank credit facility. 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, 2009. In addition to the contractual obligations listed on the table below, our balance sheet at December 31, 2009 reflects accrued interest payable on our bank debt of $985,000 which is payable in first quarter 2010. We expect to make interest payments of $9.6 million per year on our 6.375% senior subordinated notes, $14.8 million per year on our 7.375% senior subordinated notes, $18.8 million per year on our 7.5% senior subordinated notes due 2016, $18.8 million per year on our 7.5% senior subordinated notes due 2017, $18.1 million per year on our 7.25% senior subordinated notes and $24.0 million per year on our 8% senior subordinated notes.
The following summarizes our contractual financial obligations at December 31, 2009 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities, borrowings under our bank credit facility, additional debt issuances and proceeds from asset sales (in thousands).
(a)
Due at termination date of our bank credit facility. We expect to renew our bank credit facility, but there is no assurance that can be accomplished. Interest paid on our bank credit facility would be approximately $6.9 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, 2009. While such payments will be funded by higher prices received from the sale of our production, production receipts may be received after our payments to counterparties, which can result in borrowings under our bank credit facility.
(c)
The ultimate settlement and timing cannot be precisely determined in advance.
(d)
This table excludes the liability for the deferred compensation plans since these obligations will be funded with existing plan assets.
In addition to the amounts included in the above table, we have contracted with several pipeline companies through 2027 to deliver natural gas production volumes in Appalachia from certain Marcellus Shale wells. The agreements call for total incremental increases of 402,000 Mmbtu per day over the 100,000 Mmbtu per day at December 31, 2009. These increases, which are contingent on certain pipeline modifications, are for 30,000 Mmbtu per day in March 2010, 72,000 Mmbtu per day in July 2010, 150,000 Mmbtu per day in November 2011 and an additional 150,000 Mmbtu per day for November 2012.
Delivery Commitments
Under a sales agreement, we have an obligation to deliver 30,000 Mmbtu per day of volume at various delivery points within the Barnett Shale basin. The contract, which began in 2008, extends for five years ending March 2013. As of December 31, 2009, remaining volumes to be delivered under this commitment are approximately 35.6 Bcf. Our proved reserves in the Barnett Shale are sufficient to fulfill these delivery commitments.
Hedging - Oil and Gas Prices
We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. We typically utilize commodity swap and collar contracts to (1) reduce the effect of price volatility on the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. While there is a risk that the financial benefit of rising oil and gas 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.
At December 31, 2009, we had collars covering 108.5 Bcf of gas at weighted average floor and cap prices of $5.62 to $7.39 and 0.4 million barrels of oil at weighted average floor and cap prices of $75.00 to $93.75. Their 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 $28.7 million at December 31, 2009. The contracts expire monthly through December 2011.
At December 31, 2009, the following commodity derivative contracts were outstanding:
In addition to the collars above, we have entered into basis swap agreements. The price we receive for our production can be less than NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix the basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax loss of $17.8 million at December 31, 2009.
Interest Rates
At December 31, 2009, we had $1.7 billion of debt outstanding. Of this amount, $1.4 billion bears interest at fixed rates averaging 7.4%. Bank debt totaling $324.0 million bears interest at floating rates, which averaged 2.1% at year-end 2009. The 30-day LIBOR rate on December 31, 2009 was 0.2%. A 1% increase in short-term interest rates on the floating-rate debt outstanding at December 31, 2009 would cost us approximately $3.2 million in additional annual interest expense.
Off-Balance Sheet Arrangements
We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance our liquidity or capital resource position, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments as described above under cash contractual obligations.
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 through the middle of 2008, commodity prices for oil and gas increased significantly. The higher prices led to increased activity in the industry and, consequently, rising costs. These cost trends put pressure on our operating costs and also on our capital costs. Due to the decline in commodity prices that began in the last half of 2008 and continued into 2009, costs moderated in 2009. We expect costs in 2010 to continue to be a function of supply and demand.
The following table indicates the average oil and gas prices received over the last five years and quarterly for 2009, 2008 and 2007. Average price calculations exclude all derivative settlements whether or not they qualify for hedge accounting. Oil is converted to natural gas equivalent at the rate of one barrel equals six mcf.
(a)
Based on average of bid week prompt month prices.
Credit Ratings
We receive credit ratings from Standard & Poor’s Ratings Group, Inc. (“S&P”) and Moody’s Investor Services, Inc. (“Moody’s”), which are subject to regular reviews. S&P’s corporate rating for us is BB with a stable outlook. Moody’s corporate rating for us is Ba2 with a stable outlook. We believe that S&P and Moody’s consider many factors in determining our ratings including: production growth opportunities, liquidity, debt levels, asset, and proved reserve mix. We also believe that the rating agencies take into consideration our size, corporate structure, the complexity of our capital structure and organization, and history of how we have chosen to finance our growth. We believe that our single line of business, and practice of funding our growth with a balanced mix of long-term debt and common equity positively impact our ratings. In addition to qualitative and quantitative factors unique to Range, we believe that the rating agencies consider various macro-economic factors such as the projected future price of oil and gas, trends in industry service costs, and global supply and demand for energy. Based upon the factors influencing our credit ratings which are within our control, we are currently not aware of any reason why our credit rating would change materially from the present ratings. A reduction in our debt ratings could negatively impact our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.
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, the reported amounts of revenues and expenses during the year and proved oil and gas reserves. Some accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Actual results could differ from the estimates and assumptions used.
Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material.
Oil and Gas Properties
We follow the successful efforts method of accounting for oil and gas producing activities. 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. Proven property leasehold costs are amortized to expense using the units of production method based on total proved reserves. Properties are assessed for impairment as circumstances warrant (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.
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 in future years 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, including the recent rule revisions designed to modernize the oil and gas company reserves reporting requirements which we adopted effective December 31, 2009, 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 used by us. We cannot predict what reserve revisions may be required in future periods. Reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering who reports directly to our President. For additional discussion, see “Proved Reserves,” in Item 2 of this report. To further ensure the reliability of our reserve estimates, we engage independent petroleum consultants to review our estimates of proved reserves. Independent petroleum consultants reviewed 88% of our reserves in 2009 compared to 87% in 2008 and 86% in 2007. Historical variances between our reserve estimates and the aggregate estimates of our consultants have been less than 5%. The reserves included in this report are those reserves estimated by our employees and were based on a 12-month average commodity price in accordance with SEC rules.
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. While total depletion expense for the life of a property is limited to the property’s total cost, proved reserve revisions result in a change in timing when depletion expense is recognized. Downward revisions of proved reserves result in an acceleration of depletion expense, while upward revisions tend to lower the rate of depletion expense recognition. Based on proved reserves at December 31, 2009, we estimate that a 1% change in proved reserves would increase or decrease 2010 depletion expense by approximately $33.6 million (assuming a 12% production increase). 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 20 to our consolidated financial
statements. Changes in the estimated reserves are considered a change in estimate for accounting purposes and are reflected on a prospective basis. We adopted the new SEC accounting and disclosure regulations for oil and gas companies effective December 31, 2009 which will be accounted for prospectively. We estimate the effect of this change in estimate was an increase to depletion, depreciation and amortization expense in fourth quarter 2009 of approximately $3.4 million primarily due to lower prices reflected in our estimated reserves.
We monitor our long-lived assets recorded in oil and gas properties 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 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 adjustments to reserves, physical damage to production equipment and facilities, a change in costs, or other changes to contracts or environmental regulations. All of these factors must be considered when testing a property’s carrying value for impairment. 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 undiscounted future net cash flows. The expected future net cash flows are estimated based on our plans to produce and develop reserves. Expected future net cash inflow from the sale of production of reserves is calculated based on estimated future prices and estimated operating and development costs. 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, 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 using a discount rate similar to market participants) and the carrying value of the asset. We cannot predict whether impairment charges may be required in the future. Our historical impairment of producing properties has been $930,000 in 2009, $74.9 million in 2006, $3.6 million in 2004, $31.1 million in 2001, $29.9 million in 1999 and $214.7 million in 1998. We believe that a sensitivity analysis regarding the effect of changes in assumptions on estimated impairment is impractical to provide because of the number of assumptions and variables involved which have interdependent effects on the potential outcome.
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 our consolidated financial statements for information on these acquisitions.
We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. We continue to experience an increase in lease expirations caused by (1) current economic conditions, which have impacted our future drilling plans thereby increasing the amount of lease expirations and (2) our expansion in shale plays which involved acquisition of a significant acreage position prior to development. Unproved properties had a net book value of $774.5 million in 2009 compared to $758.0 million in 2008 and $262.6 million in 2007. The increase from 2007 represents additional acreage purchases primarily in the Marcellus and Barnett Shale. We have recorded abandonment and impairment expense related to unproved properties of $113.5 million in 2009 compared to $47.4 million in 2008 and $11.2 million in 2007.
Oil and Gas Derivatives
Every derivative instrument is recorded on our consolidated balance sheet as either an asset or a liability measured at its fair value. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. All of our derivative instruments are issued to manage the price risk attributable to our expected oil and gas production. In determining the amounts to be recorded for our open hedge contracts, we are required to estimate the fair value of the derivative. Our derivatives are measured using a market approach using third-party pricing services which have been corroborated with data from active markets or broker quotes. While we remain at risk for possible changes in the market value of commodity derivatives, such risk should be mitigated by price changes in the underlying physical commodity. The determination of fair values includes various factors including the impact of our nonperformance risk on our liabilities and the credit standing of our counterparties. Our counterparties include twelve financial institutions, eleven of which are secured lenders in our bank credit facility.
Through December 2009, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as oil or gas sales when the underlying transaction occurs. If it is determined that the designated hedged transaction is not probable to occur, any unrealized gains or losses are recognized immediately in the statement of operations as derivative fair value income (loss). During 2009, there were gains of $5.4 million compared to losses of $583,000 in 2008 and losses of $16.3 million in 2007 reclassified into earnings as a result of the discontinuance of hedge accounting treatment for our derivatives.
We apply hedge accounting to qualifying derivatives used to manage price risk associated with our oil and gas production. Accordingly, we record changes in the fair value of our derivative contracts, including changes associated with time value, in accumulated other comprehensive income (loss) (“AOCI”) on our consolidated balance sheet. Gains or losses on these swap and collar contracts are reclassified out of AOCI and into oil and gas sales when the underlying physical transaction occurs. Any hedge ineffectiveness associated with contracts qualifying for and designated as a cash flow hedge (which represents the amount by which the change in the fair value of the derivative differs from the change in the cash flows of the forecasted sale of production) is reported currently each period in derivative fair value income (loss) on our consolidated statement of operations. Ineffectiveness can be associated with open positions (unrealized) or can be associated with closed contracts (realized).
Realized and unrealized gains and losses on derivatives that are not designated as hedges are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in our consolidated statement of operations each period in derivative fair value income (loss). We also enter into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix our basis adjustments. Cash flows from our derivative contract settlements are reflected in cash flow provided from operating activities in our consolidated statement of cash flows.
Asset Retirement Obligations
We have significant obligations to remove tangible equipment and restore land at the end of oil and gas production operations. Removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future asset removal costs is difficult and requires us to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit-adjusted discount rates, timing of retirement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation, (“ARO”), a corresponding adjustment is made to the oil and gas property balance. For example, as we analyze actual plugging and abandonment information, we may revise our estimate of current costs, the assumed annual inflation of the costs and/or the assumed productive lives of our wells. During 2009, we increased our existing estimated asset retirement obligation by $4.5 million or approximately 5% of the asset retirement obligation at December 31, 2008. 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. Because of the subjectivity of assumptions and the relatively long lives of most of our wells, the costs to ultimately retire our wells may vary significantly from prior estimates.
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 accumulated other comprehensive income to be considered, even though such income or loss has not yet been earned. At year-end 2009, deferred tax liabilities exceeded deferred tax assets by $768.9 million, with $3.8 million of deferred tax liabilities related to unrealized hedging gains included in accumulated other comprehensive income. At year-end 2008, deferred tax liabilities exceeded deferred tax assets by $816.4 million, with $44.7 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.
Revenue Recognition
Oil, gas and natural gas liquids revenues are recognized when the products are sold and delivery to the purchaser has occurred. We use the sales method to account for gas imbalances, recognizing revenue based on gas delivered rather than our working interest share of gas produced. We recognize the cost of revenues, such as transportation and compression expense, as a reduction of revenue.
Stock-based Compensation Arrangements
The fair value of stock options and stock-settled SARs is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The model employs various assumptions, based on management’s best estimates at the time of the grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the award. We utilize historical data and analyze current information to reasonably support these assumptions. The fair value of restricted stock awards is determined based on the fair market value of our common stock on the date of grant.
We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. Restricted stock awards are classified as a liability and are remeasured at fair value each reporting period with the resulting gain or loss recognized in deferred compensation plan expense in our consolidated statement of operations.
Accounting Standard Not Yet Adopted
In June 2009, the FASB issued ASC 810-10-65 (formerly SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)”) which amends the consolidation guidance applicable to a variable interest entity (“VIE”). This standard also amends the guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is therefore required to consolidate an entity, by requiring a qualitative analysis rather than a quantitative analysis. Previously, the standard required reconsideration of whether an enterprise was the beneficiary of a VIE only when specific events had occurred. This standard is effective for calendar year companies beginning in January 1, 2010. Early adoption is prohibited. We are currently evaluating the potential impact of the adoption of this standard on our financial statements, but do not expect it to have a material effect.
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.
Financial Market Risk
The debt and equity markets have exhibited adverse conditions since late 2007. The unprecedented volatility and upheaval in the capital markets may increase costs associated with issuing debt instruments due to increased spreads over relevant interest rate benchmarks and may affect our ability to access those markets. At this point, we do not believe our liquidity has been materially affected by the recent events in the global markets and we do not expect our liquidity to be materially impacted in the near future. We will continue to monitor our liquidity and the capital markets. Additionally, we will continue to monitor events and circumstances surrounding each of our twenty-six lenders in the bank credit facility. See also “Item 1A. Risk Factors.”
Market Risk
We are exposed to market risks related to the volatility of oil and gas prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. 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. We are also exposed to market risks related to changes in interest rates.
Commodity Price Risk
We use commodity-based derivative contracts to manage exposures to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. At times, certain of our derivatives are swaps where we receive a fixed price for our production and pay market prices to the counterparty. At December 31, 2009, our derivatives program includes collars, which establish a minimum floor price and a predetermined ceiling price. As of December 31, 2009, we had collars covering 108.5 Bcf of gas and 0.4 million barrels of oil. These contracts expire monthly through December 2011. The fair value, represented by the estimated amount that would be realized upon immediate liquidation as of December 31, 2009, approximated a net unrealized pre-tax gain of $28.7 million.
At December 31, 2009, the following commodity derivative contracts were outstanding:
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 price 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. In addition to the collars and swaps above, we have entered into basis swap agreements. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix the basis adjustments. The fair value of the basis swaps was a net realized pre-tax loss of $17.8 million at December 31, 2009.
The following table shows the fair value of our collars and the hypothetical change in fair value that would result from a 10% change in commodity prices at December 31, 2009. We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risks should be mitigated by price changes in the underlying physical commodity. The hypothetical change in fair value would be a gain or loss depending on whether prices increase or decrease (in thousands):
Hypothetical
Change in
Fair Value
Fair Value
Collars
$ 28,735
$ 43,000
Our commodity-based contracts expose us to the credit risk of non-performance by the counterparty to the contracts. Our exposure is diversified among major investment grade financial institutions and we have master netting agreements with the majority of our counterparties that provide for offsetting payables against receivables from separate derivative contracts. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. Our derivative counterparties include twelve financial institutions, eleven of which are secured lenders in our bank credit facility. We have one counterparty that is not part of our bank group and three counterparties in our bank group with no master netting agreement. J. Aron & Company is the counterparty not in our bank group. At December 31, 2009, our net derivative receivable includes a payable to J. Aron & Company of $1.6 million. Counterparty credit risk is considered when determining the fair value of our derivative contracts. While counterparties are major investment grade financial institutions, the fair value of our derivative contracts have been adjusted to account for the risk of non-performance by counterparty, which was immaterial.
Interest Rate Risk
We are exposed to interest rate risk on our bank debt. We attempt to balance variable rate debt, fixed rate debt and debt maturities to manage interest costs, interest rate volatility and financing risk. This is accomplished through a mix of fixed rate senior subordinated debt and variable rate bank debt.
At December 31, 2009, we had $1.7 billion of debt outstanding. Of this amount, $1.4 billion bears interest at a fixed rate averaging 7.4%. Bank debt totaling $324.0 million bears interest at floating rates, which was 2.1% on that date. On December 31, 2009, the 30-day LIBOR rate was 0.2%. A 1% increase in short-term interest rates on the floating-rate debt outstanding at December 31, 2009 would cost us approximately $3.2 million in additional annual interest expense.
The fair value of our subordinated debt is based on year-end quoted market prices. The following table presents information on these fair values (in thousands):
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.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures. As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective as of December 31, 2009.
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, 2009. Ernst & Young LLP, our registered public accountants, also attested to, and reported on, the effectiveness of internal control over financial reporting. Management’s report and the independent public accounting firm’s attestation report are included in our 2009 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 on Internal Control over Financial Reporting,” 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 fourth quarter 2009 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.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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 2009 annual stockholders’ meeting. Officers are appointed by our board of directors.
Charles L. Blackburn was first elected as a director in 2003. 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). Mr. Blackburn received his Bachelor of Science degree in Engineering Physics from the University of Oklahoma.
Anthony V. Dub became a director in 1995. Mr. Dub is Chairman of Indigo Capital, LLC, a financial advisory firm based in New York. Before 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 & Poor’s in 2004. Capital IQ is a 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 and was selected as Lead Independent Director in 2008. Mr. Eales has over 35 years of experience in the energy, 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. Before 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 degree from Cornell University and his Master’s degree in Business Administration from Stanford University.
James M. Funk became a director in December 2008. Mr. Funk is an independent consultant and producer with over 30 years of experience in the energy industry. Mr. Funk served as Sr. Vice President of Equitable Resources and President of Equitable Production Co. from June 2000 until January 2003. Previously, Mr. Funk was employed by Shell Oil Company for 23 years in senior management and technical positions. Mr. Funk has previously served on the boards of Westport Resources (2000 to 2004) and Matador Resources Company (2003 to 2008). Mr. Funk currently serves as a Director of Superior Energy Services, Inc., a public oil field services company headquartered in New Orleans, Louisiana. Mr. Funk received an A.B. degree in Geology from Wittenberg University, a M.S. in Geology from the University of Connecticut, and a PhD in Geology from the University of Kansas. Mr. Funk is a Certified Petroleum Geologist.
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 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 industry for over 37 years. Mr. Linker joined First Reserve Corporation in 1988 and was a Managing Director of the firm from 1996 through 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 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., Pro Petro Services, Inc. and Direct Fuel Partners, L.P, three private energy companies. 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, Chairman & Chief Executive Officer and a director, became a director in 1988 and was elected Chairman of the Board of Directors in 2008. 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 (“Snyder”). Before joining Snyder in 1980, Mr. Pinkerton was with Arthur Andersen. Mr. Pinkerton received his Bachelor of Arts in Business Administration from Texas Christian University and a Master’s degree from the University of Texas at Arlington.
Jeffrey L. Ventura, President & Chief Operating Officer and a director, 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. Before 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 Inc., where he held various engineering and operating positions. Mr. Ventura holds a Bachelor of Science degree in Petroleum and Natural Gas Engineering from the Pennsylvania State University.
Roger S. Manny, Executive Vice President & Chief Financial Officer. Mr. Manny joined Range in 2003. Previously, Mr. Manny served as Executive Vice President and Chief Financial Officer of Matador Petroleum Corporation from 1998 until joining Range. Before 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.
Alan W. Farquharson, Senior Vice President - Reservoir Engineering, joined Range in 1998. Mr. Farquharson has held the positions of Manager and Vice President of Reservoir Engineering before being promoted to his senior position in February 2007. Previously, Mr. Farquharson held positions with Union Pacific Resources including Engineering Manager Business Development - International. Before 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 the 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 holds a Bachelor of Science degree in Petroleum Engineering from Marietta College.
David P. Poole, Senior Vice President - General Counsel & Corporate Secretary, joined Range in June 2008. Mr. Poole has over 21 years of legal experience. From May 2004 until March 2008 he was with TXU Corp., serving last as Executive Vice President - Legal, and General Counsel. Prior to joining TXU, Mr. Poole spent 16 years with Hunton & Williams LLP and its predecessor, where he was a partner and last served as the Managing Partner of the Dallas office. Mr. Poole graduated from Texas Tech University with a B.S. in Petroleum Engineering and received a J.D. magna cum laude from Texas Tech University School of Law.
Chad L. Stephens, Senior Vice President - Corporate Development, joined Range in 1990. Before 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. Before 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 holds a Bachelor of Arts degree in Finance and Land Management from the University of Texas.
Ray N. Walker, Jr., Senior Vice President - Marcellus Shale, joined Range in 2006 and was elected to his current position in February 2010. Previously, Mr. Walker served as Vice President - Marcellus Shale where he lead the development of the Company’s Marcellus Shale division. Mr. Walker is a Registered Petroleum Engineer with more than 34 years of oil and gas operations and management experience having previously been employed by Halliburton in various technical and management roles, Union Pacific Resources and several private companies in which Mr. Walker served as an officer. Mr. Walker has a Bachelor of Science degree, in Agricultural Engineering from Texas A&M University.
Rodney L. Waller, Senior Vice President joined Range in 1999. Mr. Waller served as Corporate Secretary from 1999 until 2008. Previously, Mr. Waller was Senior Vice President of Snyder Oil Corporation. Before joining Snyder, Mr. Waller was with Arthur Andersen. Mr. Waller is a certified public accountant and petroleum land man. Mr. Waller received a Bachelor of Arts degree in Accounting from Harding University.
Mark D. Whitley, Senior Vice President - Southwest & Engineering Technology, joined Range in 2005. Previously, he served as Vice President - Operations with Quicksilver Resources for two years. Before joining Quicksilver, he served as Production/Operation Manager for Devon Energy, following the merger of Mitchell Energy with Devon. 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 Barnett Shale formation 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.
Dori A. Ginn, Vice President, Controller and Principal Accounting Officer, joined Range in 2001. Ms. Ginn has held the positions of Financial Reporting Manager, Vice President and Controller before being elected to Principal Accounting Officer in September 2009. Prior to joining Range, she held various accounting positions with Doskocil Manufacturing Company and Texas Oil and Gas Corporation. Ms. Ginn received a Bachelor of Business Administration in Accounting degree from the University of Texas at Arlington. She is a certified public accountant.
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 2010 Annual Meeting of stockholders which is incorporated herein by reference. Section 16(a) of the Exchange Act requires our directors, officers (including a person performing a principal policy-making function) and persons who own more than 10% of a registered class of our equity securities to file with the Commission initial reports of ownership and reports of changes in ownership of our common stock and other equity securities. Directors, officers and 10% holders are required by Commission regulations to send us copies of all of the Section 16(a) reports they file. Based solely on a review of the copies of the forms sent to us and the representations made by the reporting persons to us, we believe that, other than as described below, during the fiscal year ended December 31, 2009, our directors, officers and 10% holders complied with all filing requirements under Section 16(a) of the Exchange Act. Mr. Chad Stephens had a delinquent Form-4 filing on May 25, 2009 for twenty transactions occurring in the first four months of 2009.
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 (as well as directors and all other employees). A copy is available on our website, www.rangeresources.com and a copy in print will be provided to any person without charge, upon request. Such requests should be directed to the Corporate Secretary, 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102 or by calling (817) 870-2601. 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, 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 2010 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 2010 Annual Meeting of stockholders, which is incorporated herein by reference.
NYSE 303A Certification
The Chief Executive Officer of Range Resources Corporation made an unqualified certification to the NYSE with respect to the Company’s compliance with the NYSE Corporate Governance listing standards on June 3, 2009.
ITEM 11. EXECUTIVE COMPENSATION
Information required by this item is incorporated by reference to such information as set forth in the Range Proxy Statement for the 2010 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 the Range Proxy Statement for the 2010 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 the Range Proxy Statement for the 2010 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 the Range Proxy Statement for the 2010 Annual Meeting of stockholders.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a)
Documents filed as part of the report:
1.
Financial Statements:
Page
Number
Management’s Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm - Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm - Consolidated Financial Statements
Consolidated Balance Sheets as of December 31, 2009 and 2008
Consolidated Statements of Operations for the Year Ended December 31, 2009, 2008 and 2007
Consolidated Statements of Cash Flows for the Year Ended December 31, 2009, 2008 and 2007
Consolidated Statements of Stockholders’ Equity for the Year Ended December 31, 2009, 2008 and 2007
Consolidated Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2009, 2008 and 2007
Notes to Consolidated Financial Statements
Selected Quarterly Financial Data (Unaudited)
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)
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 61 for a description of the exhibits filed as a part of this report.
GLOSSARY OF CERTAIN DEFINED TERMS
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 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.
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.
proved developed reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
recompletion. The completion for production an existing well bore in another formation from that in which the well has been previously completed.
reserve life. 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.
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.
RANGE RESOURCES CORPORATION
By: /s/ JOHN H. PINKERTON
John H. Pinkerton
Chairman of the Board and
Chief Executive Officer
Dated: February 23, 2010
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.
Signature
Capacity
Date
/s/ JOHN H. PINKERTON
John H. Pinkerton
Chairman of the Board and Chief Executive Officer
February 23, 2010
/s/ JEFFREY L. VENTURA
Jeffrey L. Ventura
Director, President and Chief Operating Officer
February 23, 2010
/s/ ROGER S. MANNY
Roger S. Manny
Executive Vice President and Chief Financial Officer
February 23, 2010
/s/ DORI A. GINN
Dori A. Ginn
Vice President, Controller and Principal Accounting Officer
February 23, 2010
/s/ CHARLES L. BLACKBURN
Charles L. Blackburn
Director
February 23, 2010
/s/ ANTHONY V. DUB
Anthony V. Dub
Director
February 23, 2010
/s/ V. RICHARD EALES
V. Richard Eales
Lead Independent Director
February 23, 2010
/s/ JAMES M. FUNK
Director
February 23, 2010
James M. Funk
/s/ JONATHAN S. LINKER
Jonathan S. Linker
Director
February 23, 2010
/s/ KEVIN S. MCCARTHY
Kevin S. McCarthy
Director
February 23, 2010
RANGE RESOURCES CORPORATION
Page
Number
Management’s Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm - Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm - Consolidated Financial Statements
Consolidated Balance Sheets at December 31, 2009 and 2008
Consolidated Statements of Operations for the Year Ended December 31, 2009, 2008 and 2007
Consolidated Statements of Cash Flows for the Year Ended December 31, 2009, 2008 and 2007
Consolidated Statements of Stockholders’ Equity for the Year Ended December 31, 2009, 2008 and 2007
Consolidated Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2009, 2008 and 2007
Notes to Consolidated Financial Statements
Selected Quarterly Financial Data (Unaudited)
Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Stockholders of
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 the 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. 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. 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, 2009. 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, 2009, our internal control over financial reporting is effective based on those criteria.
Ernst and Young, LLP, the independent registered public accounting firm that audited our financial statements included in this annual report, has issued an attestation report on our internal control over financial reporting as of December 31, 2009. This report appears on the following page.
By:
/s/ JOHN H. PINKERTON
By:
/s/ ROGER S. MANNY
John H. Pinkerton
Roger S. Manny
Chairman of the Board and Chief Executive Officer
Executive Vice President and Chief Financial Officer
Fort Worth, Texas
February 23, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING
To the Board of Directors and Stockholders of
Range Resources Corporation:
We have audited Range Resources Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Range Resources Corporation’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 included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, 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, Range Resources Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, 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, 2009 and 2008 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, 2009 and our report dated February 23, 2010 expressed an unqualified opinion thereon.
Ernst & Young LLP
Fort Worth, Texas
February 23, 2010
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Range Resources Corporation:
We have audited the accompanying consolidated balance sheets of Range Resources Corporation (the “Company”) as of December 31, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, in 2008, the Company adopted a standard allowing for the option to measure eligible financial assets at fair value. Also, as discussed in Note 20 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Range Resources Corporation’s internal control over financial reporting as of December 31, 2009, 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 23, 2010 expressed an unqualified opinion thereon.
Ernst & Young LLP
Fort Worth, Texas
February 23, 2010
RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data)
See accompanying notes.
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
See accompanying notes.
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
See accompanying notes.
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands, except per share data)
See accompanying notes.
RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In thousands)
See accompanying notes.
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 natural gas properties primarily in the Southwestern and Appalachian regions of the United States. We seek to increase our reserves and production primarily through drilling and complementary acquisitions. Range is a Delaware corporation with our common stock listed and traded on the New York Stock Exchange under the symbol “RRC.”
(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. 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. We have evaluated events or transactions that occurred subsequent to December 31, 2009 through the date and time this annual report on Form 10-K was filed.
During first quarter 2007, we sold our interests in our Austin Chalk properties that we purchased as part of the 2006 Stroud Energy acquisition. We also sold our Gulf of Mexico properties in first quarter 2007. We have reflected the results of operations of these divestitures as discontinued operations, rather than a component of continuing operations. See also Note 4 for additional information regarding discontinued operations.
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, the reported amounts of revenues and expenses during the year and the reported amount of proved oil and gas reserves. We base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments that are not readily apparent from other sources. Actual results could differ from these estimates and changes in these estimates are recorded when known.
Income per Common Share
Basic income (loss) per common share is calculated based on the weighted average number of common shares outstanding. Diluted income (loss) per common share assumes issuance of stock compensation awards, provided the effect is not antidilutive.
Business Segment Information
We have evaluated how Range is organized and managed and have identified only one operating segment, which is the exploration and production of oil, natural gas and natural gas liquids. We consider our gathering, processing and marketing functions as ancillary to our oil and gas producing activities. 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.
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.
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. We recognize the cost of revenues, such as transportation and compression expense, as a reduction to revenue. Although receivables are concentrated in the oil and gas industry, we do not view this as an 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. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We have allowances for doubtful accounts relating to exploration and production receivables of $2.2 million at December 31, 2009 compared to $954,000 at December 31, 2008. During the year ended 2009, we recorded $1.4 million of bad debt expense compared to $450,000 in the same period of the prior year.
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, 2009 and December 31, 2008 were not significant. At December 31, 2009, we had recorded a net liability of $326,000 for those wells where it was determined that there were insufficient reserves to recover the imbalance situation.
Cash and Cash 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 held in our deferred compensation plans qualify as trading and are recorded at fair value. Investments in the deferred compensation plans are in mutual funds and consist of various publicly-traded mutual funds that include investments from equities to money market instruments.
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, on a first-in, first-out basis. Our inventory is primarily acquired for use in future drilling operations.
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. The status of suspended well costs is monitored continuously and reviewed not less than quarterly. We capitalize successful exploratory wells and all developmental wells, whether successful or not. Oil and NGLs are converted to gas equivalent basis or mcfe at the rate of one barrel of oil equating to 6 mcf of gas. Depreciation, depletion and amortization of proved producing properties is provided on the units of production method. Historically, we have adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report. We adopted the new SEC accounting and disclosure regulations for oil and gas companies effective December 31, 2009. Accounting Standards Codification (ASC) 2010-3 clarified that the effect of the change in price encompassed in the new SEC rules is a change in accounting principle inseparable from a change in estimate for 2009 and will be accounted for prospectively. We estimate the effect of this change in estimate increased depletion, depreciation and amortization expense by approximately $3.4 million ($2.2 million after tax) primarily due to lower prices reflected in our estimated reserves.
Our oil and gas producing properties are reviewed for impairment periodically as events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. These 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 reserves. Expected future net cash inflow from the sale of production of reserves is calculated based on estimated future prices and estimated operating and development costs. 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 using a discount rate similar to market participants) and the carrying value of the asset. 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 gas 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. We cannot predict whether impairment charges may be required in the future.
Proceeds from the disposal of oil and gas producing 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.
We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leasehold costs. The costs are capitalized and evaluated (at least quarterly) as to recoverability, based on changes brought about by economic factors and potential shifts in business strategy employed by management. Impairment of a significant portion of our unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. Impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. We continue to experience an increase in lease expirations caused by (1) current economic conditions, which have impacted our future drilling plans thereby increasing the amount of lease expirations and (2) our expansion in shale plays which involve acquisitions of significant acreage positions prior to development. Unproved properties had a net book value of $774.5 million in 2009 compared to $758.0 million in 2008 and $262.6 million in 2007. The increase from 2007 represents additional acreage purchases primarily in the Marcellus Shale and Barnett Shale. We have recorded abandonment and impairment expense related to unproved properties of $113.5 million in 2009 compared to $47.4 million in 2008 and $11.2 million in 2007.
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 field service and certain transportation services, which are recognized as earned. Depreciation on the associated assets is calculated on the straight-line method based on estimated useful lives ranging from five to seven years. Buildings are depreciated over 10 to 15 years. Depreciation expense was $31.7 million in 2009 compared to $13.7 million in 2008 and $10.9 million in 2007. The fourth quarter 2009 includes accelerated depreciation expense of $10.3 million related to an interim processing plant in our Appalachian region that will be dismantled in first quarter 2010.
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 a security is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed. Other assets at December 31, 2009 include $24.2 million of unamortized debt issuance costs, $43.6 million of marketable securities held in our deferred compensation plans and $11.1 million of other investments.
Stock-based Compensation Arrangements
The fair value of stock options and stock-settled SARs is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The model employs various assumptions, based on management’s best estimates at the time of the grant, which impact the fair value calculated and ultimately, the expense that is recognized over the life of the award. We have utilized historical data and analyzed current information to reasonably support these assumptions. The fair value of restricted stock awards is determined based on the fair market value of our common stock on the date of grant.
We recognize stock-based compensation expense on a straight-line basis over the requisite service period for the entire award. The expense we recognize is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. Restricted stock awards are classified as a liability and are remeasured at fair value each reporting period.
Derivative Financial Instruments and Hedging
All of our derivative instruments are issued to manage the price risk attributable to our expected oil and gas production. While there is risk that the financial benefit of rising oil and gas prices may not be captured, we believe the benefits of stable and predictable cash flow are more important. Among these benefits are 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 capital markets. Every unsettled derivative instrument is recorded on our consolidated balance sheet as either an asset or a liability measured at its fair value. Changes in a derivative’s fair value should be recognized in earnings unless specific hedge accounting criteria are met. Cash flows from oil and gas derivative contract settlements are reflected in operating activities in our consolidated statements of cash flows.
Through December 2009, we have elected to designate our commodity derivative instruments that qualify for hedge accounting as cash flow hedges. To designate a derivative as a cash flow hedge, we document at the hedge’s inception our assessment that the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the hedge is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged. If, during the derivative’s term, we determine the hedge is no longer highly effective, hedge accounting is prospectively discontinued and any remaining unrealized gains or losses, based on the effective portion of the derivative at that date, are reclassified to earnings as oil or gas revenue when the underlying transaction occurs. If it is determined that the designated hedged transaction is not probable to occur, any unrealized gains or losses are recognized immediately in the statement of operations as derivative fair value income (loss). During 2009, we recognized a gain of $5.4 million compared to a loss of $583,000 in 2008 and a loss of $16.3 million in 2007 as a result of the discontinuance of hedge accounting treatment for certain of our derivatives.
We apply hedge accounting to qualifying derivatives (or “hedge derivatives”) used to manage price risk associated with our oil and gas production. Accordingly, we record changes in the fair value of our swap and collar contracts, including changes associated with time value, in accumulated other comprehensive income (loss) (“AOCI”) on our consolidated balance sheet. Gains or losses on these swap and collar contracts are reclassified out of AOCI and into oil and gas sales when the underlying physical transaction occurs. Any hedge ineffectiveness associated with a contract qualifying and designated as a cash flow hedge (which represents the amount by which the change in the fair value of the derivative differs from the change in the cash flows of the forecasted sale of production) is reported currently each period in derivative fair value income (loss) on our consolidated statement of operations. Ineffectiveness can be associated with open positions (unrealized) or can be associated with closed contracts (realized).
Realized and unrealized gains and losses on derivatives that are not designated as hedges (or a “non-hedge derivative”) are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in our consolidated statement of operations each period in derivative fair value income (loss). We also enter into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreement that effectively fix our basis adjustments.
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.
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. Deferred tax assets are recorded when it is more likely than not that they will be realized. 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)
The following details the components of AOCI and related tax effects for the three years ended December 31, 2009. Amounts included in AOCI as of December 31, 2009 and 2008, relates to our derivative activity.
Accounting Pronouncements Implemented
In February 2008, the FASB issued Accounting Standards Codification (“ASC”) 820-10 (formerly FASB Staff Position FAS No. 157-2), which delayed the effective date of ASC 820-10 (formerly SFAS No. 157) for all non-financial assets and non-financial liabilities except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This deferral primarily applied to our asset retirement obligation, which uses fair value measures at the date incurred to determine our liability and any property impairment that may occur. We adopted the provisions of this standard effective January 1, 2009 and the adoption did not have a material effect on our consolidated results of operations or financial position.
In June 2008, the FASB issued ASC 260-10 (formerly Staff Position No. EITF 03-6-1), “Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities,” which provides that unvested share-based payment awards that contain nonforteitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share under the two class method. We adopted the provisions of this standard on January 1, 2009 with no impact on our reported earnings per share.
In March 2008, the FASB issued ASC 815-10 (formerly SFAS No. 161), which amends and expands disclosure requirements with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why any entity uses derivative instruments; (ii) how derivative instruments and related hedged items are accounted for; and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of this standard were adopted on January 1, 2009. See Note 11 for additional disclosures about our derivative instruments and hedging activities.
In December 2007, the FASB issued ASC 805-10 (formerly SFAS No. 141(R)), “Business Combinations,” which retains the purchase method of accounting for acquisitions, but requires a number of changes, including changes in the way assets and liabilities are recognized in the purchase method of accounting. It changes the recognition of assets acquired and liabilities assumed arising from contingencies, requires the capitalization of in-process research and development at fair value, and requires the expensing of acquisition-related costs as incurred. The provisions of this standard will apply prospectively to business combinations occurring in our fiscal year beginning January 1, 2009 and the adoption did not have an impact on our financial position or results of operations.
In April 2009, the FASB issued additional application guidance and enhancements to disclosures regarding fair value measurements. ASC 825-10 (formerly FASB Staff Position No. FAS 107-1 and APB 28-1), “Interim Disclosures about Fair Value of Financial Instruments,” enhances consistency in financial reporting by increasing the frequency of fair value disclosures. ASC 820-10 (formerly “FASB Staff Position No. FAS 157-4”), “Determining Fair Value when the Volume and Level of Activity for the Asset or Liability have Significantly Decreased and Identifying Transactions that are Not Orderly,”
provides guidelines for making fair value measurements more consistent. We adopted the provisions of these standards for the period ended June 30, 2009, which did not have an impact on our financial position or results of operations.
In May 2009, the FASB issued ASC 855-10 (formerly SFAS No. 165), “Subsequent Events,” which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. We adopted this standard upon issuance with no impact on our financial position or results of operations.
In June 2009, the FASB issued ASC 105-10 (formerly SFAS No. 168), “Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles.” The FASB Accounting Standards Codification (“Codification”) has become the source of authoritative accounting principles recognized by the FASB to be applied by nongovernmental entities in the preparation of financial statements in accordance with GAAP. All existing accounting standard documents are superseded by the Codification and any accounting literature not included in the Codification will not be authoritative. However, rules and interpretive releases of the SEC issued under the authority of federal securities laws will continue to be the source of authoritative generally accepted accounting principles for SEC registrants. Effective September 30, 2009, all references made to GAAP in our consolidated financial statements will include the new Codification numbering system along with original references. The Codification does not change or alter existing GAAP and, therefore, will not have an impact on our financial position, results of operations or cash flows.
In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures. The new disclosure requirements include provisions that:
•
Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.
•
Require companies to report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices. The FASB aligned the current accounting standards with these rules.
•
Permit companies to disclose their probable and possible reserves on a voluntary basis. In the past, proved reserves were the only reserves allowed in the disclosures.
•
Require companies to provide additional disclosure regarding the aging of proved undeveloped reserves.
•
Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.
•
Replace the existing “certainty” test for areas beyond one offsetting drilling unit from a productive well with a “reasonable certainty” test.
•
Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures regarding internal controls over reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory.
We began complying with the disclosure requirements in this annual report on Form 10-K.
In January 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-03, “Oil and Gas Reserve Estimation and Disclosures.” This ASU amends the FASB’s Accounting Standards Codification Topic 932, “Extractive Activities - Oil and Gas” to align the accounting requirements of Topic 932 with the SEC’s final rule, “Modernization of the Oil and Gas Reporting Requirements” issued on December 31, 2008. In summary, the revisions in ASU 2010-3 modernize the disclosure rules to better align with current industry practices and expand the disclosure requirements for equity method investments so that more useful information is provided. More specifically, the main provisions include the following:
•
An expanded definition of oil and gas producing activities to include nontraditional resources such as bitumen extracted from oil sands.
•
The use of an average of the first day of the month price for the 12-month period, rather than a year-end price for determining whether reserves can be produced economically.
•
Amended definitions of key terms such as “reliable technology” and “reasonable certainty” which are used in estimating proved oil and gas reserve quantities.
•
A requirement for disclosing separate information about reserve quantities and financial statement amounts for geographical areas representing 15 percent or more of proved reserves.
This ASU is effective for annual reporting periods ended on or after December 31, 2009, and it requires (1) the effect of the adoption to be included within each of the dollar amounts and quantities disclosed, (2) qualitative and quantitative disclosure of the estimated effect of adoption on each of the dollar amounts and quantities disclosed, if significant and practical to estimate and (3) the effect of adoption on the financial statements, if significant and practical to estimate. Adoption of these requirements did not significantly impact our reported reserves or our consolidated financial statements.
In February 2007, the FASB issued ASC 825-10 (formerly SFAS 159), “The Fair Value Option for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. It requires that unrealized gains and losses on items for which the fair value option has been elected be recorded in net income or loss. The statement also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. We adopted ASC 825-10 effective January 1, 2008 and the impact of the adoption resulted in a reclassification of a $2.0 million pre-tax loss ($1.3 million after tax) related to our investment securities held in our deferred compensation plan from accumulated other comprehensive loss to retained earnings. We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. As of January 1, 2008, all of these investment securities are accounted for using the mark-to-market accounting method, are classified as trading securities and all subsequent changes to fair value will be included in our statement of operations.
Accounting Pronouncements Not Yet Adopted
In June 2009, the FASB ASC 810-10-65 (formerly SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)”) which amends the consolidation guidance applicable to a variable interest entity (“VIE”). This standard also amends the guidance governing the determination of whether an enterprise is the primary beneficiary of a VIE, and is therefore required to consolidate an entity, by requiring a qualitative analysis rather than a quantitative analysis. Previously, the standard required reconsideration of whether an enterprise was the beneficiary of a VIE only when specific events had occurred. This standard is effective for calendar year companies beginning in January 1, 2010. Early adoption is prohibited. We are currently evaluating the potential impact of the adoption of this standard on its financial statements, but do not expect it to have a material effect.
(3) ACQUISITIONS AND DISPOSITIONS
Acquisitions
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. In the past, acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities.
In 2009, we completed no material acquisitions. In 2008, we completed several acquisitions of Barnett Shale producing and unproved properties for $331.2 million. After recording asset retirement obligations and transactions costs of $827,000, the purchase price allocated to proved properties was $232.9 million and unproved properties was $99.4 million.
In May 2007, we acquired additional interests in the Nora field of Virginia and entered into a joint development plan with EQT Corporation (“EQT”). As a result of this transaction, EQT and Range equalized their working interests in the Nora field, including producing wells, undrilled acreage and gathering systems. Range retained its separately owned royalty interest in the Nora field. EQT will operate the producing wells and manage the drilling operations of all future coal bed methane wells and the gathering system. Range will oversee the drilling of formations below the coal bed methane formations, including tight gas, shale and deeper formations. A newly-formed limited liability corporation will hold the investment in the gathering system which is owned 50% by EQT and 50% by Range. All business decisions require the unanimous consent of both parties. The gathering system investment is accounted for as an equity method investment. Including estimated transaction costs, we paid $281.8 million, which includes $190.2 million allocated to oil and gas properties, $94.7 million allocated to our equity method investment and a $3.1 million asset retirement obligation. In December 2007, we paid an additional $7.1 million for additional interests in the same field. No pro forma information has been provided as the acquisition was not considered significant.
Dispositions
In second quarter 2009, we sold certain oil properties located in West Texas for proceeds of $181.8 million. In fourth quarter 2009, we sold natural gas properties in New York for proceeds of $36.3 million. The proceeds from the sale of these properties were credited to oil and gas properties, with no gain or loss recognized, as the dispositions did not materially impact the depletion rate of the remaining properties in the amortization base. Additionally, in 2009 we sold Marcellus Shale acreage for $11.2 million and we recognized a gain of $10.4 million.
In first quarter 2008, we sold East Texas properties for proceeds of $64.0 million and recorded a gain of $20.2 million. In February 2007, we sold the Stroud Austin Chalk properties for proceeds of $80.4 million and recorded a loss on the sale of $2.3 million. These Austin Chalk properties were acquired in 2006 as part of our Stroud acquisition and were classified as assets held for sale on the acquisition date. In March 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million and recorded a gain on the sale of $95.1 million. We have reflected the results of operations of the Austin Chalk and Gulf of
Mexico divestitures as discontinued operations rather than a component of continuing operations for 2007 and all prior years. See Note 4 for additional information.
In December 2009, we announced our plan to offer for sale our tight gas sand properties in Ohio. The properties include approximately 3,500 producing wells, 418,000 net acres of leasehold and 1,600 miles of pipeline and gathering system infrastructure. The data room opened in January 2010 and on February 8, 2010, we announced that we signed a definitive agreement to sell these assets for a price of $330.0 million, subject to normal post-closing adjustments. However, the completion of the sale is dependent upon customary prospective buyer due diligence procedures and there can be no assurance the sale will be completed. The approximate net book value of these assets at December 31, 2009 was $240.0 million.
(4) DISCONTINUED OPERATIONS
As part of an acquisition completed in 2006, we purchased Austin Chalk properties in Central Texas, which were sold in 2007 for proceeds of $80.4 million. Also in 2007, we sold our Gulf of Mexico properties for proceeds of $155.0 million. All prior year periods reflect our Gulf of Mexico operations and the Austin Chalk properties as discontinued operations. Discontinued operations for the year ended December 31, 2007 is summarized as follows (in thousands):
(a)
Realized hedging gains and losses for the Gulf of Mexico properties have been allocated to discontinued operations based on the designated hedge values for those assets.
(b)
Interest expense is allocated to discontinued operations for our Austin Chalk properties based on the debt incurred at the time of the acquisition and for the Gulf of Mexico properties, interest expense was allocated based upon the ratio of the Gulf of Mexico properties to our total oil and gas properties at December 31, 2006.
(c)
Oil is converted to mcfe at the rate of one barrel equals six mcf.
(5) INCOME TAXES
Our income tax benefit from continuing operations was $4.9 million for the year ended December 31, 2009 compared to income tax expense of $193.8 million in 2008 and $96.3 million in 2007. A reconciliation between the statutory federal income tax rate and our effective income tax rate (benefit) is as follows:
Income tax (benefit) provision attributable to income from continuing operations consists of the following:
Significant components of deferred tax assets and liabilities are as follows:
At December 31, 2009, deferred tax liabilities exceeded deferred tax assets by $768.9 million, with $3.8 million of deferred tax liability related to net deferred hedging gains included in OCI. We have a full valuation allowance of $601,000 recorded against our capital loss carryover and a $2.0 million valuation allowance on the deferred tax asset related to our deferred compensation plan for planned future distributions to top level executives to the extent that their estimated future compensation plus distribution amounts would exceed the $1.0 million deductible limit provided under I.R.C. Section 162(m).
At December 31, 2009, we had regular net operating loss (“NOL”) carryforwards of $321.5 million and alternative minimum tax (“AMT”) NOL carryforwards of $259.0 million that expire between 2012 and 2027. Our deferred tax asset related to regular NOL carryforwards at December 31, 2009 was $159.4 million, which is net of the SFAS No. 123(R) reduction for unrealized benefits. Regular NOLs generally offset taxable income and to such extent, no income tax payments are required. At December 31, 2009, we have AMT credit carryforwards of $777,000 that are not subject to limitation or expiration.
We file consolidated tax returns in the United States federal jurisdiction. We file separate company state income tax returns in Louisiana, Mississippi, Ohio, Pennsylvania and Virginia and file consolidated or unitary state income tax returns in New Mexico, Oklahoma, Texas and West Virginia. We are subject to U.S. Federal income tax examinations for the years after 2005 and we are subject to various state tax examinations for years after 2004. We have not extended the statute of limitation period in any tax jurisdiction. Our continuing policy is to recognize interest related to income tax expense in interest expense and penalties in general and administrative expense. We do not have any accrued interest or penalties related to tax amounts as of December 31, 2009. Throughout 2009, our unrecognized tax benefits were not material.
(6) EARNINGS (LOSS) PER COMMON SHARE
The following table sets forth the computation of basic and diluted earnings (loss) per common share (in thousands, except per share amounts):
Weighted average shares-basic excludes 2.6 million shares at December 31, 2009, 2.3 million shares at December 31, 2008 and 2.0 million shares at December 31, 2007 of restricted stock that is held in our deferred compensation plans (although all restricted stock is issued and outstanding upon grant). Due to our net loss for the year ended December 31, 2009, we excluded 7.2 million of outstanding stock options/SARs and 2.6 million of restricted stock held in our deferred compensation plans from the computations of diluted net loss per share because the effect would have been anti-dilutive. For December 31, 2008, stock appreciation rights for 880,000 shares were outstanding but not included in the computations of diluted earnings per share, because the grant price of the SARs was greater than the average price of the common stock and would be anti-dilutive to the computations (345,000 shares for the year ended December 31, 2007).
(7) SUSPENDED EXPLORATORY WELL COSTS
We capitalize exploratory well costs until a determination is made that the well has either found proved reserves or that it is impaired. Capitalized exploratory well costs are presented in oil and gas properties in our consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to expense. The following table reflects the changes in capitalized exploratory well costs for the year ended December 31, 2009, 2008 and 2007 (in thousands):
As of December 31, 2009, the $8.3 million of capitalized exploratory well costs that have been capitalized for more than one year relates to wells waiting on pipelines. Of the $19.1 million of capitalized exploratory well costs at December 31, 2009, $10.7 million was incurred in 2009 and $8.3 million in 2008.
(8) INDEBTEDNESS
We had the following debt outstanding as of the dates shown below (bank debt interest rate at December 31, 2009 is shown parenthetically). No interest was capitalized during 2009, 2008, and 2007 (in thousands):
Bank Debt
In October 2006, we entered into an amended and restated revolving bank facility, which we refer to as our bank debt or our 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 the facility amount or the borrowing base. On December 31, 2009, the facility amount was $1.25 billion and the borrowing base was $1.5 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually each April and October and for event-driven unscheduled redeterminations. Our current bank group is comprised of twenty-six commercial banks each holding between 2.4% and 5.0% of the total facility. The facility amount may be increased to the borrowing base amount with twenty days notice, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. As of December 31, 2009, the outstanding balance under the bank credit facility was $324.0 million and $100,000 of undrawn letters of credit leaving $925.9 million of borrowing capacity available under the facility amount. The loan matures on October 25, 2012. Borrowings under the bank facility can either be at the Alternate Base Rate (as defined) plus a spread ranging from 0.875% to 1.625% or LIBOR borrowings at the Adjusted LIBO Rate (as defined) plus a spread ranging from 1.75% to 2.5%. The applicable spread is dependent upon borrowings 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 2.4% for the year ended December 31, 2009 compared to 4.4% for the year ended December 31, 2008. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At December 31, 2009, the commitment fee was 0.375% and the interest rate margin was 1.75% on our LIBOR loans and 0.875% on our base rate loans.
Senior Subordinated Notes
In May 2008, we issued $250.0 million aggregate principal amount of 7.25% senior subordinated notes due 2018 (“7.25% Notes”). In May 2009, we issued $300.0 million aggregate principal amount of our 8.0% senior subordinated notes due 2019 (“8.0% Notes”). The 8.0% Notes were issued at a discount, which is being amortized over the life of the 8.0% Notes. Interest on our senior subordinated notes is payable semi-annually, at varying times, and each of the notes is guaranteed by certain of our subsidiaries.
We may redeem the 7.25% Notes, in whole or in part, at any time on or after May 1, 2013 at redemption prices of 103.625% of the principal amount as of May 1, 2013 and declining to 100.0% on May 1, 2016 and thereafter. Before May 1, 2011, we may redeem up to 35% of the original aggregate principal amount of the 7.25% Notes at a redemption price equal to 107.25% of the 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 principal amount of the 7.25% Notes remain outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering. We may redeem the 8.0% Notes, in whole or in part, at any time on or after May 15, 2014, at redemption prices of 104.0% of the principal amount as of May 15, 2014 declining to 100.0% on May 15, 2017 and thereafter. Before May 15, 2012, we may redeem up to 35% of the original aggregate principal amount of the 8.0% Notes at a redemption price equal to 108.0% of the 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 the 8.0% Notes remain outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of the closing of the equity offering.
If we experience a change of control, there will 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 by our subsidiaries of our senior subordinated notes are full and unconditional and joint and several; any subsidiaries other than the subsidiary guarantors are minor subsidiaries.
Debt Covenants and Maturity
Our bank credit facility contains negative covenants that limit our ability, among other things, to pay cash dividends, incur additional indebtedness, sell assets, enter into certain hedging contracts, change the nature of our business or operations, merge, consolidate, or make investments. In addition, we are required to maintain a ratio of debt to EBITDAX (as defined in the credit agreement) of no greater than 4.0 to 1.0 and a current ratio (as defined in the credit agreement) of no less than 1.0 to 1.0. We were in compliance with our covenants under the bank credit facility at December 31, 2009.
Following is the principal maturity schedule for the long-term debt outstanding as of December 31, 2009 (in thousands):
The indentures governing our senior subordinated notes contain various restrictive covenants that are substantially identical to each other and may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, enter into transactions with affiliates, or change the nature of our business. At December 31, 2009, we were in compliance with these covenants.
(9) ASSET RETIREMENT OBLIGATION
Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant assumptions used in determining such obligations include estimates of plugging and abandonment costs, estimated future inflation rates and well life. The inputs are calculated based on historical data as well as current estimated costs. A reconciliation of our liability for plugging and abandonment costs for the years ended December 31, 2009 and 2008 is as follows (in thousands):
Accretion expense is recognized as a component of depreciation, depletion and amortization on our statement of operations.
(10) CAPITAL STOCK
We have authorized capital stock of 485.0 million shares which includes 475.0 million shares of common stock and 10.0 million shares of preferred stock. The following is a schedule of changes in the number of common shares outstanding since the beginning of 2008:
In May 2008, we completed a public offering of 4.4 million shares of common stock at $66.38 per share. After underwriting discount and other offering costs of $12.3 million, net proceeds of $282.2 million were used to repay indebtedness on our bank credit facility. In January 2010, we issued 380,229 additional shares of common stock for acreage purchases.
Treasury Stock
In 2008, the Board of Directors approved up to $10.0 million of repurchases of common stock based on market conditions and opportunities. During 2008, we repurchased 78,400 shares of common stock an average price of $41.11 for a total of $3.2 million. As of December 31, 2009, we have $6.8 million remaining authorization to repurchase shares.
Shelf Registration Statement
In June 2009, we filed a shelf registration statement with the Securities and Exchange Commission to potentially offer securities which include debt securities or common stock. The securities will be offered at prices and on terms to be determined at the time of sale. Net proceeds from the sale of such securities will be used for general corporate purposes, including a reduction of bank debt. Also in June 2009, we issued a $200.0 million registration statement where we may, from time to time, sell shares of our common stock in connection with an acquisition or business combination. As of December 31, 2009, we have $176.5 million remaining under this registration statement.
Common Stock Dividends
The Board of Directors declared quarterly dividends of $0.04 per common share for each of the four quarters of 2009, $0.04 per common share for each of the four quarters of 2008, and $0.03 per common share for the first three quarters of 2007 and $0.04 per common share for fourth quarter 2007. The determination of the amount of future dividends, if any, to be declared and paid is at the sole discretion of the Board of Directors and will depend on our financial condition, earnings and cash flow from operations, level of capital expenditures, our future business prospects and other matters the Board of Directors deems relevant.
(11) DERIVATIVE ACTIVITIES
We use commodity-based derivative contracts to manage exposure to commodity price fluctuations. We do not enter into these arrangements for speculative or trading purposes. We do not utilize complex derivatives such as swaptions, knockouts or extendable swaps. We typically utilize commodity swap and collar contracts to (1) reduce the effect of price volatility of the commodities we produce and sell and (2) support our annual capital budget and expenditure plans. At December 31, 2009, we had collars covering 108.5 Bcf of gas at weighted average floor and cap prices of $5.62 to $7.40 per mcf and 0.4 million barrels of oil at weighted average floor and cap prices of $75.00 to $93.75 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 $28.7 million at December 31, 2009. These contracts expire monthly through December 2011. The following table sets forth the derivative volumes by year as of December 31, 2009:
Every derivative instrument is required to be recorded on the balance sheet as either an asset or a liability measured at its fair value. Fair value is determined based on the difference between the fixed contract price and the underlying market price at the determination date. Changes in the fair value of our hedge derivatives are recorded as a component of AOCI, which is later transferred to oil and gas sales when the hedged transaction occurs and the hedging contract is settled. As of December 31, 2009, an unrealized pre-tax derivative gain of $10.2 million was recorded in AOCI. This gain will be reclassified into earnings as a gain of $7.0 million in 2010 and a gain of $3.2 million in 2011 as the contracts settle. The actual reclassification to earnings will be based on mark-to-market prices at the contract settlement date. If the derivative does not qualify as a hedge or is not designated as a hedge, changes in fair value of these non-hedge derivatives are recognized in earnings in derivative fair value income (loss).
For those derivative instruments that qualify for hedge accounting, settled transaction gains and losses are determined monthly, and are included as increases or decreases to oil and gas sales in the period the hedged production is sold. Oil and gas sales include $203.1 million of gains in 2009 compared to losses of $63.6 million in 2008 and gains of $4.2 million in 2007, related to settled hedging transactions. Any ineffectiveness associated with these hedge derivatives are reflected in derivative fair value income (loss) in our statement of operations. The ineffective portion is calculated as the difference between the change in fair value of the derivative and the estimated change in future cash flows from the item hedged. Derivative fair value income (loss) for the year ended December 31, 2009 includes ineffective gains (unrealized and realized) of $3.1 million compared to gains of $3.1 million in 2008 and gains of $148,000 in 2007.
In addition to the collars above, we have entered into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our gas production can be more or less than the NYMEX price because of adjustments for delivery location, relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix our basis adjustments. The fair value of the basis swaps was a net unrealized pre-tax loss of $17.8 million at December 31, 2009.
Derivative fair value income (loss)
The following table presents information about the components of derivative fair value income (loss) in the three-year period ended December 31, 2009 (in thousands):
(a)
These amounts represent the realized gains and losses on settled derivatives that do not qualify for hedge accounting, which before settlement are included in the category above called the change in fair value of derivatives that do not qualify for hedge accounting.
Derivative assets and liabilities
The combined fair value of derivatives included in our consolidated balance sheets as of December 31, 2009 and 2008 is summarized below (in thousands). We conduct derivative activities with twelve financial institutions, eleven of which are secured lenders in our bank credit facility. We believe all of these institutions are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The credit worthiness of our counterparties is subject to periodic review. The assets and liabilities are netted where derivatives with both gain and loss positions are held by a single counterparty. For
example, we have two counterparties with a total derivative position equal to a net receivable of $8.0 million. This receivable includes a basis swap payable of $1.1 million which is netted and reported in our derivative receivable.
The table below provides data about the fair value of our derivative contracts. Derivative assets and liabilities shown below are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in our consolidated balance sheets (in thousands):
(1)
Include in unrealized derivative gain (loss) on our balance sheet.
The effects of our hedge derivatives on accumulated other comprehensive income (loss) on the consolidated balance sheets are summarized below:
(a)
For realized gains upon contract settlement, the reduction in other comprehensive income is offset by an increase in oil and gas sales. For realized losses upon contract settlement, the increase in other comprehensive income is offset by a decrease in oil and gas sales.
The effects of our non-hedge derivatives and the ineffective portion of our hedge derivative on our consolidated statement of operations is summarized below:
(12) FAIR VALUE MEASUREMENTS
We use a market approach for our fair value measurements and endeavor to use the best information available. Accordingly, valuation techniques that maximize the use of observable impacts are favored. The following presents the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):
These items are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2009 market value. Derivatives in Level 2 are measured at fair value with a market approach using third-party pricing services, which have been corroborated with data from active markets or broker quotes.
Our trading securities held in the deferred compensation plan are accounted for using the mark-to-market accounting method and are included in the balance sheet category called “other assets.” We elected to adopt the fair value option to simplify our accounting for the investments in our deferred compensation plan. Interest, dividends, and mark-to-market gains/losses are included in the statement of operations category called deferred compensation plan expense. For the year ended December 31, 2009, interest and dividends were $487,000 and mark-to-market was a gain of $10.4 million. For the year ended December 31, 2008, interest and dividends were $1.5 million and the mark-to-market was a loss of $19.4 million.
The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2009 and 2008 (in thousands):
(a)
Marketable securities are held in our deferred compensation plans.
(b)
The book value of our bank debt approximate fair value because of its floating rate structure. The fair value of our senior subordinated notes is based on end of period market quotes.
Our current assets and liabilities contain financial instruments, the most significant of which are trade accounts receivables and payables. We believe the carrying values of our trade accounts receivables and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments and (2) our historical incurrence of and expected future insignificance of bad debt expense.
Concentration of Credit Risk
Most of our receivables are from a diverse group of companies, including major energy companies, pipeline companies, local distribution companies, financial institutions and end-users in various industries. Letters of credit or other appropriate security are obtained as necessary to limit risk of loss. Our allowance for uncollectible receivables was $2.2 million at December 31, 2009 and $954,000 at December 31, 2008. Commodity-based contracts expose us to the credit risk of nonperformance by the counterparty to the contracts. As of December 31, 2009, these derivative contracts consist of collars. This exposure is diversified primarily among major investment grade financial institutions the majority of which we have master netting agreements with that provide for offsetting payables against receivables from separate derivative contracts. Our derivative counterparties include twelve financial institutions, eleven of which are secured lenders in our bank credit facility. J. Aron & Company is the only counterparty not in our bank group. At December 31, 2009, our net derivative receivable includes a payable to J. Aron & Company of $1.6 million.
(13) STOCK-BASED COMPENSATION PLANS
Description of the Plans
The 2005 Equity Based Compensation Plan (the “2005 Plan”) authorizes the Compensation Committee of the Board of Directors to grant, among other things, stock options, stock appreciation rights and restricted stock awards to employees and directors. The 2004 Non-Employee Director Stock Option Plan (the “Director Plan”) allows such grants to our non-employee directors of our Board of Directors. The 2005 Plan was approved by stockholders in May 2005 and replaced 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 Option Plan before 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 plus (iii) subsequent shares approved by the shareholders. The Director Plan was approved by stockholders in May 2004 and no more than 450,000 shares of common stock may be issued under the Plan.
Stock-based awards under the Plans
Stock options represent the right to purchase shares of stock in the future at the fair 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. Beginning in 2005, we began granting stock appreciation rights (“SARs”) to reduce the dilutive impact of our equity plans. Similar to stock options, SARs represents 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.
The Compensation Committee grants restricted stock to certain employees and non-employee directors of the Board of Directors as part of their compensation. Compensation expense is recognized over the balance of the vesting period, which is typically three years for employee grants and immediate vesting for non-employee directors. All restricted stock awards are issued at prevailing market prices at the time of the grant and the vesting is based upon an employee’s continued employment with us. Prior to vesting, all restricted stock awards have the right to vote such stock and receive dividends thereon. All restricted shares that are granted are placed in our deferred compensation plan. Restricted stock awards are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market is reported in our statement of operations in deferred compensation plan expense.
As part of the closure of our Houston office, there were eighteen employees whose unvested SARs and restricted stock grants were modified and fully vested effective with the closing of the office on November 1, 2009. The incremental compensation cost of this modification was $2.5 million.
Total Stock-Based Compensation Expense
Stock-based compensation represents amortization of restricted stock grants and stock option/SARs expense. In 2009, stock-based compensation was allocated to operating expense ($2.6 million), exploration expense ($4.8 million), and general administrative expense ($33.5 million) for a total of $41.8 million. In 2008, stock-based compensation was allocated to direct operating expense ($2.8 million), exploration expense ($4.1 million) and general and administrative expense ($23.8 million) for a total of $31.2 million. In 2007, stock-based compensation was allocated to direct operating expense ($1.8 million), exploration expense ($3.5 million) and general and administrative expense ($18.2 million) for a total of $23.9 million. Unlike the other forms of stock-based compensation mentioned above, the mark-to-market of the vested restricted stock held in our deferred compensation plans is directly tied to the change in our stock price and not directly related to the functional expenses and therefore, is not allocated to the functional categories. For the year ended December 31, 2009, cash received upon exercise of stock option awards was $12.7 million. Due to the net operating loss carryforward for tax purposes, tax benefits realized for deductions that were in excess of the stock-based compensation expense were not recognized.
Stock and Option Plans
We have two active equity-based stock plans. Under these plans, incentive and non-qualified stock options, stock appreciation rights and annual cash incentive awards may be issued to directors and employees pursuant to decisions of the Compensation Committee, which is made up of non-employee, independent directors from the Board of Directors. All awards granted under these plans have been issued at prevailing market prices at the time of the grant. Since the middle of 2005, only SARs have been granted under the plans to limit the dilutive impact of our equity plans. Of the 7.2 million grants outstanding at December 31, 2009, 1.3 million of the grants relate to stock options with the remainder of 5.9 million grants relating to SARs. Information with respect to stock option and SARs activities is summarized below:
The following table shows information with respect to outstanding stock options and SARs at December 31, 2009:
Stock Appreciation Right Awards
During 2009, 2008 and 2007, we granted SARs to officers, non-officer employees and directors. The weighted average grant date fair value of these SARs, based on our Black-Scholes-Merton assumptions, is shown below:
The dividend yield is based on the current annual dividend at the time of grant. For SARs granted in 2007, we used the “simplified” method to estimate the expected term of the options, which is calculated based on the midpoint between the vesting date and the life of the SAR. For SARs granted in 2008 and 2009, the expected term was based on the historical exercise activity. The volatility factors are based on a combination of both the historical volatilities of the stock and implied volatility of traded options on our common stock. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant for periods commensurate with the expected terms of the options.
The total intrinsic value (the difference in value between exercise and market price) of stock options and SARs exercised during the years ended December 31, 2009 was $50.9 million compared to $67.9 million in 2008 and $67.2 million in 2007. As of December 31, 2009, the aggregate intrinsic value of the awards outstanding was $147.4 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option/SARs awards currently exercisable was $118.7 million and 1.6 years. As of December 31, 2009, the number of fully vested awards and awards expected to vest was 7.1 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $31.23 and 2.4 years and the aggregate intrinsic value was $146.4 million. As of December 31, 2009, unrecognized compensation cost related to the awards was $26.4 million, which is expected to be recognized over a weighted average period of 1.6 years.
Restricted Stock Awards
In 2009, we granted 686,000 shares of restricted stock grants as compensation to directors and employees at an average price of $39.99. The restricted stock grants included 22,700 issued to directors, which vest immediately and 663,300 to employees with vesting generally over a three-year period. In 2008, we issued 362,000 shares of restricted stock grants as compensation to directors and employees at an average price of $63.00. The restricted stock grants included 14,400 issued to directors, which vest immediately and 347,600 to employees with vesting generally over a three-year period. In 2007, we issued 435,000 shares of restricted stock grants as compensation to directors and employees, at an average price of $34.85. The restricted grants included 15,900 issued to directors, which vest immediately, and 419,100 to employees with vesting over a three-year period. We recorded compensation expense for restricted stock grants of $19.7 million in the year ended December 31, 2009 compared to $14.7 million in 2008 and $8.7 million in 2007. As of December 31, 2009, there was $25.8 million of unrecognized compensation related to restricted stock awards expected to be recognized over the next three years. All of our restricted stock grants are held in our deferred compensation plan. All restricted stock awards are classified as liability award and are remeasured at fair value each reporting period. This mark-to-market is reported in the deferred compensation expense in our consolidated statement of operations (see additional discussion below). The proceeds received from the sale of stock held in our deferred compensation plan was $7.2 million in 2009.
A summary of the status of our non-vested restricted stock outstanding at December 31, 2009 and changes during the twelve months then ended, is presented below:
401(k) Plan
We maintain a 401(k) benefit plan that allows employees to contribute up to 50% of their salary (subject to Internal Revenue Service limitations) on a pretax basis. Prior to 2008, we made discretionary contributions of our common stock to the 401(k) Plan annually. Beginning in 2008, we began matching up to 6% of salary in cash. All our contributions become fully vested after the individual employee has two years of service with us. In 2009, we contributed $3.2 million to the plan compared to $2.7 million in 2008 and $2.3 million in 2007. We do not require that employees hold any contributed Range stock in their account. Employees have a variety of investment options in the plan. Employees may, at any time, diversify out of our stock, based on their personal investment strategy.
Deferred Compensation Plan
In December 2004, the Board of Directors approved a deferred compensation plan. The deferred compensation plan gives directors, officers and key employees the ability to defer all or a portion of their salaries and bonuses and invest in Range common stock or make other investments at the individual’s discretion. Range provides a matching contribution which vests over three years. The assets of all of the plans are held in a grantor 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 as a liability award as employees are allowed to take withdrawals from the Rabbi Trust either in cash or in Range stock. The liability for the vested portion of the stock held in the Rabbi Trust is reflected in the deferred compensation liability on our balance sheet and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense 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 their market value in other assets. The deferred compensation liability on our consolidated balance sheet reflects the vested market value of the marketable securities and the vested Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the liability are charged or credited to deferred compensation plan expense each quarter. We recorded a mark-to-market loss of $31.1 million in 2009 compared to mark-to-market income of $24.7 million in 2008 and a mark-to-market loss of $35.4 million in 2007. The Rabbi Trust held 2.7 million shares (2.1 million of vested shares) of Range stock at December 31, 2009 compared to 2.3 million shares (1.9 million of vested shares) at December 31, 2008.
(14) SUPPLEMENTAL CASH FLOW INFORMATION
(15) 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.
Lease Commitments
We lease certain office space, office equipment, production facilities, compressors and transportation equipment under cancelable and non-cancelable leases. Rent expense under operating leases (including renewable monthly leases) totaled $11.8 million in 2009 compared to $9.2 million in 2008 and $5.4 million in 2007. Commitments related to these lease payments are not recorded in our consolidated balance sheets. Future minimum rental commitments under non-cancelable leases having remaining lease terms in excess of one year are as follows (in thousands):
Transportation Contracts
We have entered firm transportation contracts with various pipelines. Under these contracts, we are obligated to transport minimum daily gas volumes, or pay for any deficiencies at a specified reservation fee rate. In most cases, our production committed to these pipelines is expected to exceed the minimum daily volumes provided in the contracts. As of December 31, 2009, future minimum transportation fees under our gas transportation commitments are as follows (in thousands):
In addition to the amounts included in the above table, we have contracted with several pipeline companies through 2017 to deliver natural gas production volumes in Appalachia from certain Marcellus Shale wells. The agreements call for total incremental increases of 402,000 Mmbtu per day over the initial 100,000 Mmbtu per day at December 31, 2009. These increases, which are contingent on certain pipeline modifications, are 30,000 Mmbtu per day in March 2010, 72,000 Mmbtu per day in July 2010, 150,000 Mmbtu per day in November 2011 and an additional 150,000 Mmbtu per day in November 2012.
Drilling Contracts
As of December 31, 2009, we have contracts with drilling contractors to use six drilling rigs with terms of up to three years and minimum future commitments of $57.9 million in 2010, $58.4 million in 2011, $39.2 million in 2012 and $484,000 in 2013. These six rigs were custom built for our Marcellus Shale program. Early termination of these contracts at December 31, 2009 would have required us to pay maximum penalties of $115.3 million. We do not expect to pay any early termination penalties related to these contracts.
Delivery Commitments
Under a sales agreement, we have an obligation to deliver 30,000 Mmbtu per day of volume at various delivery points within the Barnett Shale in the Fort Worth Basin. The contract, which began in 2008, extends for five years ending March 2013. As of December 31, 2009, remaining volumes to be delivered under this commitment are approximately 35.6 Bcf.
Other
We have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally not exceeding three years. We do not expect to lose significant lease acreage because of failure to drill due to inadequate capital, equipment or personnel. However, based on our evaluation of prospective economics, we have allowed acreage to expire and will allow additional acreage to expire in the future. To date, our expenditures to comply with environmental or safety regulations have not been significant and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.
(16) 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. Pricing on the month-to-month and short-term contracts is based largely on NYMEX, with fixed or floating basis. For one to five-year contracts, we sell our gas on NYMEX pricing, published regional index pricing or percentage of proceeds sales based on local indices. We sell our oil under contracts ranging in terms from month-to-month, up to as long as one year. The price for oil is generally equal to a posted price set by major purchasers in the area or is based on NYMEX pricing or fixed pricing, adjusted for quality and transportation differentials. We sell to oil and gas purchasers on the basis of price, credit quality and service reliability. For the year ended December 31, 2009, we had no customers that accounted for 10% or more of total oil and gas revenues. For the year ended December 31, 2008, one customer accounted for 10% or more of total oil and gas revenues. For the year ended December 31, 2007, we had no customers that accounted for 10% or more 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.
(17) EQUITY METHOD INVESTMENTS
We account for our investments in entities over which we have significant influence, but not control, using the equity method of accounting. Under the equity method of accounting, we record our proportionate share of the net earnings, declared dividends and partnership distributions based on the most recently available financial statements of the investee. We also evaluate our equity method investments 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. For our investment in Whipstock, these indicators were present during the year ended December 31, 2009, and as a result, we did recognize impairment charges of $9.0 million related to our equity method investment in 2009.
Investment in Whipstock Natural Gas Services, LLC
In 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 membership interest in Whipstock.
Whipstock follows a calendar year basis of financial reporting consistent with us and our equity in Whipstock’s earnings from the acquisition date is included in other revenue in our results of operations for 2009, 2008 and 2007. During the year ended December 31, 2009, we received $301,000 in cash distributions from Whipstock. During the year ended December 31, 2008, we received cash distributions from Whipstock of $1.8 million. There were no dividends or partnership distributions received from Whipstock during the year ended December 31, 2007. In determining our proportionate share of the net earnings of Whipstock, certain adjustments are required to be made to Whipstock’s reported results to eliminate the profits recognized by Whipstock for services provided to us. For the year ended December 31, 2009, our equity in the losses of Whipstock totaled $13.1 million, compared to losses of $479,000 in 2008 and earnings of $132,000 in 2007. In 2009, equity in the losses of Whipstock was reduced by $422,000 to eliminate the profit on services provided to us compared to $1.8 million in 2008 and $2.7 million in 2007. In addition, equity in 2009 losses of Whipstock reflected a $9.0 million impairment charge due to an other than temporary decline in the fair value of our investment. Our fair value determination was based on a discounted cash flow analysis which qualifies as a level 3 fair value measurement in the fair value hierarchy table. Our net book value in this equity investment was $2.8 million at December 31, 2009. Range and Whipstock have entered into an agreement whereby Whipstock will provide us with the right of first refusal such that we 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 us are based on Whipstock’s usual and customary terms.
Investment in Nora Gathering, LLC
In May 2007, we completed the initial closing of a joint development arrangement with EQT Corporation. Pursuant to the terms of the arrangement, Range and EQT (the parties) agreed to, among other things, form a new pipeline and natural gas gathering operations entity, Nora Gathering, LLC (NGLLC). NGLLC is an unconsolidated investee created by the parties for the purpose of conducting pipeline, natural gas gathering, and transportation operations associated with the parties’ collective interests in properties in the Nora Field. In connection with the acquisition, we contributed cash of $94.7 million for a 50% membership interest in NGLLC. During 2009 and 2008, Range and EQT each contributed $6.4 million and $29.0 million, respectively, in additional capital to NGLLC in order to fund the expansion of the Nora Field gathering system infrastructure.
NGLLC follows a calendar year basis of financial reporting consistent with Range and our equity in NGLLC earnings from the acquisition date is included in other revenue in our results of operations for 2009, 2008 and 2007. There were no dividends or partnership distributions received from NGLLC during the years ended December 31, 2009 or December 31, 2008. In determining our proportionate share of the net earnings of NGLLC, certain adjustments are required to be made to NGLLC’s reported results to eliminate the profits recognized by NGLLC included in the gathering and transportation fees charged to us on production in the Nora field. For the year ended December 31, 2009 our equity in the losses of NGLLC of $629,600 was reduced by $7.0 million to eliminate the profit on gathering and transportation fees charged to us. For the year ended December 31, 2008, our equity in the earnings of NGLLC of $261,000 was reduced by $4.8 million to eliminate the profit on gathering and transportation fees charged to us. For the year ended December 31, 2007, our equity in earnings of NGLLC of $841,000 was reduced by $1.8 million to eliminate the profit on gathering and transportation fees charged to us. Our net book value in this equity investment was $144.0 million at December 31, 2009. The gathering and transportation rate charged by NGLLC to us on our production in the Nora field is considered to be at market.
(18) OFFICE CLOSING AND EXIT ACTIVITIES
In the third quarter 2009, we announced the closing of our Gulf Coast Area administrative and operations office in Houston, Texas. The properties are now operated out of our Southwest Area office in Fort Worth. As of December 31, 2009, we have accrued $1.3 million of severance costs. Expenses related to lease termination and severance costs are included in general and administrative expenses in our consolidated statement of operations.
In addition, in December 2009 we sold our natural gas properties in New York. We have accrued $635,000 of severance costs related to this divestiture and the cost is included in direct operating expense in our consolidated statement of operations. The following table details our exit activities (in thousands):
(19) SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following tables set forth unaudited financial information on a quarterly basis for each of the last two years (in thousands).
Principal Unconsolidated Investees (unaudited)
Company
December 31, 2009 Ownership
Activity
Whipstock Natural Gas Services, LLC
%
Drilling services
Nora Gathering, LLC
%
Gas gathering and transportation
(20) SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION, DEVELOPMENT AND PRODUCTION
ACTIVITIES
Our gas and oil producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.
Capitalized Costs and Accumulated Depreciation, Depletion and Amortization (a)
(a)
Includes capitalized asset retirement costs and the associated accumulated amortization.
Costs Incurred for Property Acquisition, Exploration and Development (a)
(a)
Includes cost incurred whether capitalized or expensed.
(b)
2008 includes a single transaction to acquire Marcellus Shale acreage for $223.9 million.
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.
Recent SEC and FASB Rule-Making Activity
In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. See Note 2. Summary of Significant Accounting Policies - Accounting Pronouncements Implemented. We adopted the rules effective December 31, 2009 and the rule changes, including those related to pricing and technology, are included in our reserves estimates. In addition, in January 2010 the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures,” to provide consistency with the SEC rules. See Note 2. Summary of Significant Accounting Policies - Accounting Pronouncements Implemented.
Application of the new rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of 12-month average pricing at December 31, 2009 as required by the new rules resulted in a decrease in proved reserves of approximately 86.0 Bcfe. Use of year-end prices as required by the old rules would have resulted in an increase in proved reserves of approximately 3.0 Bcfe at December 31, 2009. Therefore, the total impact of the new price methodology was negative reserves revisions of 89.0 Bcfe. We also estimate that we added 230 Bcfe of additional proved developed reserves, primarily in our Marcellus Shale play, where we have experienced good drilling results, as allowed by the new SEC definitions.
Because we use year-end reserves and add back current quarter production to calculate fourth quarter depletion expense, adoption of these new standards had an impact on fourth quarter 2009 DD&A expense. We estimate the impact of using 12-month average commodity prices, as required by the new standards, instead of year-end commodity prices, to be an increase in fourth quarter 2009 DD&A expense of approximately $3.4 million before income taxes.
Reserve Estimation
At year-end 2009, the following independent petroleum consultants conducted a process review of our reserves: DeGolyer and MacNaughton (Southwest), H.J. Gruy and Associates, Inc. (Southwest) and Wright and Company, Inc. (Appalachia). These engineers were selected for their geographic expertise and their historical experience in engineering certain properties. At December 31, 2009, these consultants collectively reviewed approximately 88% of our proved reserves. A copy of the summary reserve report of each of these independent petroleum consultants is included as an exhibit to this Annual Report on Form 10-K. The technical person at each independent petroleum consulting firm responsible for reviewing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished to independent petroleum consultants for their reserves review process. Throughout the year, our technical team meets regularly with representatives of each of our independent petroleum consultants to review properties and discuss methods and assumptions. While we have no formal committee specifically designated to review reserves reporting and the reserves estimation process, our senior management reviews and approves any internally estimated significant changes to our proved reserves. We provide historical information to our consultants for our largest producing properties such as ownership interest; oil and gas production; well test data; commodity prices and operating and development costs. The consultants perform an independent analysis and differences are reviewed with our Senior Vice President of Reservoir Engineering. In some cases, additional meetings are held to review additional reserve work performed by the technical teams related to any identified reserve differences.
Historical variances between our reserve estimates and the aggregate estimates of our consultants have been less than 5%. The reserves included in this report on Form 10-K are those reserves estimated by our employees. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering, who reports directly to our President. Mr. Alan Farquharson, our Senior Vice President of Reservoir Engineering, holds a Bachelor of Science degree in Electrical Engineering from the Pennsylvania State University. Before joining Range, he held various technical and managerial positions with Amoco, Hunt Oil and Union Pacific Resources. During the year, our reserves group may also perform separate, detailed technical reviews of reserve estimates for significant acquisitions or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions.
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 in future years 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 from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Proved undeveloped reserves can only be assigned to acreage for which improved recovery technology is
contemplated unless such techniques have been proven effective by actual tests in the area and in the same reservoir. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances, justify a longer time.
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, 2009 to estimate reserve information were $54.65 per barrel of oil, $34.05 per barrel for natural gas liquids and $3.19 per mcf for gas, using benchmark prices (NYMEX) of $60.85 per barrel and $3.87 per Mmbtu. The average realized prices used at December 31, 2008 to estimate reserve information were $42.76 per barrel of oil, $25.00 per barrel for natural gas liquids and $5.23 per mcf for gas, using benchmark prices (NYMEX) of $44.60 per barrel and $5.71 per Mmbtu. The average realized prices used at December 31, 2007 to estimate reserve information were $91.88 per barrel for oil, $52.64 per barrel for natural gas liquids and $6.44 per mcf for gas, using benchmark prices (NYMEX) of $95.98 per barrel and $6.80 per Mmbtu.
(a)
The December 31, 2006 balance excludes reserves associated with the Austin Chalk properties. The total proved developed and undeveloped reserves for these assets at December 31, 2006 were 42.3 Bcfe, which includes 39.3 Bcf of gas. These assets were sold in first quarter 2007.
(b)
Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf.
The following details the changes in proved undeveloped reserves for 2009 (Mmcfe):
During 2009, various exploration and development drilling evaluations were completed. Approximately $140.0 million was spent during 2009 related to undeveloped reserves that were transferred to developed reserves. Estimated future development costs relating to the development of proved undeveloped reserves are projected to be approximately $292 million in 2010, $472 million in 2011 and $428 million in 2012. Included in proved undeveloped reserves at December 31, 2009 are approximately 116,000 Mmcfe of reserves that have been reported for five or more years, 45% of which will be sold with our Ohio properties. The remaining reserves are in fields in which we are currently active. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2014.
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 gas and oil reserve disclosures, standardized measures of discounted future net cash flows from proved gas and oil reserves and the reconciliations of standardized measures from year to year. The information disclosed 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 gas and oil properties as of December 31 of the years presented. These estimates were prepared by our petroleum engineering staff. Proved reserves are estimated quantities of natural gas and crude oil, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:
1.
Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions.
2.
Prior to 2009, estimated future cash inflows were calculated by applying current year-end prices of gas and oil relating to our proved reserves to the quantities of those reserves produced in each future year. For 2009, estimated future cash inflows are calculated by applying a twelve-month average price of 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, administrative 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 gas and oil properties, other deductions, credits and allowances relating to our proved 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 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 gas and oil reserves is as follows and excludes cash flows associated with hedges outstanding at each of the respective reporting dates.
The following table summarizes changes in the standardized measure of discounted future net cash flows.
RANGE RESOURCES CORPORATION
INDEX TO EXHIBITS
Exhibit
Number
Exhibit Description
3.1
Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on May 5, 2004) as amended by the Certificate of First Amendment to Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on July 28, 2005 and the Certificate of Second Amendment to the Restated Certificate of Incorporation of Range Resources Corporation (incorporated by reference to Exhibit 3.1 to our Form 10Q (File No. 001-1209) as filed with the SEC on July 24, 2008)
3.2
Amended and Restated By-laws of Range (incorporated by reference to Exhibit 3.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on February 17, 2009)
4.1
Form of 7.375% Senior Subordinated Notes due 2013 (incorporated by reference to Exhibit A to Exhibit 4.4.2 to our Form 10-Q (File No. 001-12209) as filed with the SEC on August 6, 2003)
4.2
Indenture dated July 21, 2003 by and among Range, as issuer, the Subsidiary Guarantors (as defined therein), 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 (incorporated by reference to Exhibit A to Exhibit 4.1 on our Form 8-K (File No. 001-12209) as filed with the SEC on March 15, 2005)
4.4
Indenture dated March 9, 2005 by and among Range, as issuer, the Subsidiary Guarantors (as defined therein), 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 (incorporated by reference to Exhibit A to Exhibit 4.2 on our Form 8-K (File No. 001-12209) as filed with the SEC on May 23, 2006)
4.6
Indenture dated May 23, 2006 by and among Range, as issuer, the Subsidiary Guarantors (as defined therein), 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)
4.7
Form of 7.5% Senior Subordinated Notes due 2017 (incorporated by reference to Exhibit A to Exhibit 4.2 (File No. 001-12209) as filed with the SEC on October 1, 2007)
4.8
Indenture dated September 28, 2007 by and among Range, as issuer, the subsidiary Guarantors (as defined therein), 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 October 1, 2007)
4.9
Form of 7.25% Senior Subordinated Notes due 2018 (incorporated by reference to Exhibit A to Exhibit 4.2 on our Form 8-K (File No. 001-12209) as filed with the SEC on May 6, 2008)
4.10
Indenture dated May 6, 2008 by and among Range, as issuer, the subsidiary Guarantors (as defined therein), 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 6, 2008)
4.11
Form of 8.0% Senior Subordinated Notes due 2019 (incorporated by reference to Exhibit A to Exhibit 4.2 on our Form 8-K (File No. 001-12209) as filed with the SEC on May 14, 2009)
4.12
Indenture dated May 14, 2009 by and among Range, as issuer, the Subsidiary Guarantors (as defined therein), as guarantors and J.P. Morgan Trust Company, National Association as trustee (incorporated by reference to Exhibit 4.1 on Form 8-K (File No. 001-12209) as filed with the SEC on May 14, 2009)
Exhibit
Number
Exhibit Description
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 (incorporated by reference to Exhibit 10.1 to our Form 10-K (File No. 001-12209) as filed with the SEC February 27, 2007)
10.2
First Amendment to the Third Amended and Restated Credit Agreement dated October 26, 2006 among Range (as borrower) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent (incorporated by reference to Exhibit 10.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC April 26, 2007)
10.3
Second Amendment to the Third Amended and Restated Credit Agreement dated October 26, 2006 among Range (as borrower) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent (incorporated by reference to Exhibit 10.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC April 26, 2007)
10.4
Third Amendment to the Third Amended and Restated Credit Agreement dated October 26, 2006 among Range (as borrower) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent (incorporated by reference to Exhibit 10.4 to our Form 10-K (File No. 001-12209) as filed with the SEC February 27, 2008)
10.5
Fourth Amendment to the Third Amended and Restated Credit Agreement dated October 26, 2006 among Range (as borrower) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent (incorporated by reference to Exhibit 10.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC April 24, 2008)
10.6
Fifth Amendment to the Third Amended and Restated Credit Agreement dated October 26, 2006 among Range (as borrower) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent (incorporated by reference to Exhibit 10.6 to our Form 10-K (File No. 001-12209) as filed with the SEC on February 25, 2009)
10.7
Sixth Amendment to the Third Amended and Restated Credit Agreement dated October 26, 2006 among Range (as borrower) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent (incorporated by reference to Exhibit 10.7 to our Form 10-K (File No. 001-12209) as filed with the SEC on February 25, 2009)
10.8
Seventh Amendment to the Third Amended and Restated Credit Agreement dated October 26, 2006 among Range (as borrower) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent (incorporated by reference to Exhibit 10.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on April 29, 2009)
10.9
Eighth Amendment to the Third Amended and Restated Credit Agreement dated October 26, 2006 among Range (as borrower) and J.P.Morgan Chase Bank, N.A. and institutions named (therein) as lenders, J.P.Morgan Chase as Administrative Agent (incorporated by reference to Exhibit 10.1 to our Form10-Q (File No. 001-12209) as filed with the SEC on October 22, 2009)
10.10
Amended and Restated Range Resources Corporation 2004 Deferred Compensation Plan for Directors and Select Employees effective December 31, 2008 (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 001-12209) as filed with the SEC on December 5, 2008)
10.11
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)
10.12
Range Resources Corporation Amended and Restated 2005 Equity Based Compensation Plan (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on June 4, 2009)
10.13
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)
Exhibit
Number
Exhibit Description
10.14
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)
10.15
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)
10.16
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)
10.17
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)
10.18
Second Amendment to the Lomak 1994 Outside Directors Stock Option Plan dated August 21, 1996 (incorporated by reference to Exhibit 4.7 to our Form S-8 (File No. 333-40380) as filed with the SEC on June 29, 2000)
10.19
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)
10.20
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)
10.21
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)
10.22
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)
10.23
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)
10.24
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)
10.25
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)
10.26
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)
10.27
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)
10.28
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)
10.29
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)
10.30
Amended and Restated Range Resources Corporation Executive Change in Control Severance Benefit Plan dated December 31, 2008 (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 001-12209) as filed with the SEC on December 5, 2008)
10.31
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.6 of our Form 8-K (File No. 001-12209) as field with the SEC on February 17, 2009)
21.1*
Subsidiaries of Registrant
23.1*
Consent of Independent Registered Public Accounting Firm
Exhibit
Number
Exhibit Description
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 Chairman 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 Chairman 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 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1*
Report of H.J. Gruy and Associates, Inc. independent consulting engineers
99.2*
Report of DeGoyler and MacNaughton, independent consulting engineers
99.3*
Report of Wright and Company, independent consulting engineers
*
Filed herewith.
**
Furnished herewith.