RANGE RESOURCES CORP - Annual Report: 2012 (Form 10-K)

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Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark one)

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-12209

RANGE RESOURCES CORPORATION

(Exact Name of Registrant as Specified in Its Charter)


Delaware		34-1312571
(State or Other Jurisdiction of Incorporation or Organization)		(IRS Employer Identification No.)

100 Throckmorton Street, Suite 1200, Fort Worth, Texas		76102
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s telephone number, including area code

(817) 870-2601

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class		Name of Exchange on Which Registered
Common Stock, $.01 par value		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the proceedings 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (check one):

Indicate by check mark whether the registrant is a shell company (as defined in 12b-2 of the Act). Yes ¨ No þ

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2012 was $9,760,273,000. This amount is based on the closing price of registrant’s common stock on the New York Stock Exchange on that date. Shares of common stock held by executive officers and directors of the registrant are not included in the computation. However, the registrant has made no determination that such individuals are “affiliates” within the meaning of Rule 405 of the Securities Act of 1933.

As of February 22, 2013, there were 162,842,514 shares of Range Resources Corporation Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement to be furnished to stockholders in connection with its 2013 Annual Meeting of Stockholders, which shall be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates, are incorporated by reference in Part III, Items 10-14 of this report.

RANGE RESOURCES CORPORATION

Unless the context otherwise indicates, all references in this report to “Range,” “we,” “us” or “our” are to Range Resources Corporation and its wholly-owned subsidiaries and its ownership interests in equity method investments. Unless otherwise noted, all information in the report relating to natural gas, natural gas liquids and oil reserves and the estimated future net cash flows attributable to those reserves are based on estimates and are net to our interest. If you are not familiar with the oil and gas terms used in this report, please refer to the explanation of such terms under the caption “Glossary of Certain Defined Terms” at the end of Item 15 of this report.

TABLE OF CONTENTS


		Page

PART I

ITEMS 1 & 2.	Business and Properties
	General		1
	Available Information		2
	Our Business Strategy		2
	Significant Accomplishments in 2012		3
	Industry Operating Environment		4
	Segment and Geographical Information		5
	Outlook for 2013		5
	Production, Price and Cost History		6
	Proved Reserves		7
	Property Overview		10
	Producing Wells		12
	Drilling Activity		13
	Gross and Net Acreage		13
	Undeveloped Acreage Expirations		14
	Title to Properties		14
	Delivery Commitments		14
	Employees		14
	Competition		14
	Marketing and Customers		15
	Seasonal Nature of Business		15
	Governmental Regulation		15
	Environmental and Occupational Health and Safety Matters		17
ITEM 1A.	Risk Factors		21
ITEM 1B.	Unresolved Staff Comments		31
ITEM 3.	Legal Proceedings		31
ITEM 4.	Mine Safety Disclosures		31

PART II

ITEM 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
	Market for Common Stock		32
	Holders of Record		32
	Dividends		32
	Stockholder Return Performance Presentation		33

RANGE RESOURCES CORPORATION

TABLE OF CONTENTS (Continued)


ITEM 6.	Selected Financial Data and Reserve Data	34
ITEM 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Overview of Our Business	36
	Sources of Our Revenues	36
	Principle Components of Our Cost Structure	37
	Management’s Discussion and Analysis of Results of Operations	38
	Management’s Discussion and Analysis of Financial Condition, Cash Flows, Capital Resources and Liquidity	46
	Management’s Discussion of Critical Accounting Estimates	52
ITEM 7A.	Quantitative and Qualitative Disclosures about Market Risk
	Market Risk	57
	Commodity Price Risk	57
	Other Commodity Risk	58
	Interest Rate Risk	58
ITEM 8.	Financial Statements and Supplementary Data	59
ITEM 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	59
ITEM 9A.	Controls and Procedures	59
ITEM 9B.	Other Information	59

PART III

ITEM 10.	Directors, Executive Officers and Corporate Governance	60
ITEM 11.	Executive Compensation	63
ITEM 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	63
ITEM 13.	Certain Relationships and Related Transactions and Director Independence	63
ITEM 14.	Principal Accountant Fees and Services	63

PART IV

ITEM 15.	Exhibits and Financial Statement Schedules
	Financial Statements	64
	Financial Statement Schedules	64
	Exhibits	64
GLOSSARY OF CERTAIN DEFINED TERMS		65
SIGNATURES		67

Disclosures Regarding Forward-Looking Statements

This Annual Report on Form 10-K, particularly Item 1. Business and Properties, Item 1A. Risk Factors, Item 3. Legal Proceedings, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Item 7A. Quantitative Disclosures about Market Risk, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. These statements typically contain words such as “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “predict,” “target,” “project,” “could,” “should,” “would” or similar words, indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements in this Report may include, but are not limited to, levels of revenues, income from operations, net income or earnings per share; levels of capital and exploration expenditures; the success or timing of completion of ongoing or anticipated capital, exploration projects; volumes of production or sales of natural gas, natural gas liquids, and crude oil; levels of worldwide prices of crude oil; levels of domestic natural gas prices; levels of natural gas liquids, natural gas and crude oil reserves; the acquisition or divestiture of assets; the potential effect of judicial proceedings on our business and financial condition; and the anticipated effects of actions of third parties such as competitors, or federal, state or local regulatory authorities.

While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions, should we choose to make any. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in “Item 1A. Risk Factors.”

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

PART I

ITEMS

1 AND 2. BUSINESS AND PROPERTIES

General

We are a Fort Worth, Texas-based independent natural gas, natural gas liquids (“NGLs”) and oil company, engaged in the exploration, development and acquisition of natural gas and oil properties, mostly in the Appalachian and Southwestern regions of the United States. We were incorporated in Delaware in 1980 under the name Lomak Petroleum, Inc. In 1998, we changed our name to Range Resources Corporation. Our corporate offices are located at 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102 (telephone (817) 870-2601). Our common stock is listed and traded on the New York Stock Exchange under the symbol “RRC.” At December 31, 2012, we had 162.6 million shares outstanding.

Our 2012 average production from continuing operations consisted of the following:

•

total production of 752.6 Mmcfe per day, an increase of 45% from 2011;

•

79% natural gas;

•

NGLs production volume of 7.0 Mmbls increased 30% from 2011; and

•

crude oil production volume of 2.9 Mmbls increased 46% from 2011.

At year-end 2012, our proved reserves had the following characteristics ^(a):

•

6.5 Tcfe of proved reserves;

•

74% natural gas;

•

53% proved developed;

•

89% operated;

•

a reserve life index of 21 years (based on fourth quarter 2012 production);

•

a pre-tax present value of $4.0 billion of future net cash flows attributable to our reserves, discounted at 10% per annum (“PV-10”); and

•

a standardized after-tax measure of discounted future net cash flows of $3.2 billion.

^(a)

PV-10 is 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 $736.1 million at December 31, 2012.

Available Information

Our internet website is available at http://www.rangeresources.com. 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 we make with the SEC. 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 filing such reports with the SEC. Other information such as Company presentations, 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 President and Chief Executive Officer and Senior Financial Officer.

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.

Our Business Strategy

Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy to achieve our objective is to increase reserves and production through internally generated drilling projects coupled with occasional complementary acquisitions. Our strategy requires us to make significant investments and financial commitments in technical staff, acreage, seismic data and technology to build drilling inventory and market our products. Our core strategy has the following principal elements:

•

concentrate in core operating areas;

•

maintain multi-year drilling inventory;

•

focus on cost efficiency;

•

commit to environmental protection, health and safety and community stewardship;

•

maintain long-life reserve base;

•

maintain flexibility; and

•

provide employee equity ownership and incentive compensation.

Concentrate in Core Operating Areas. We currently operate in two regions: the Appalachian (which includes Pennsylvania, Virginia, and West Virginia) and Southwestern (which includes the Permian Basin of West Texas, the Texas Panhandle, the Nemaha Uplift in Northern Oklahoma and Kansas and the Anadarko Basin of Western Oklahoma). 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 a number of core areas allows us to create a portfolio to assist in our goal of consistent production and reserve growth at attractive returns.

Maintain Multi-Year Drilling Inventory. We focus on areas with multiple prospective, productive horizons and development opportunities. We use our technical expertise to build and maintain a multi-year drilling inventory. We believe that a large, multi-year inventory of drilling projects increases our ability to efficiently plan for the economic growth of production and reserves. Currently, we have over 9,000 proven and unproven drilling locations in inventory.

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 natural gas and oil is in the best performing quartile of our peer group.

Commit to Environmental Protection, Health and Safety and Community Stewardship. We implement the latest technologies and best commercial practices to minimize potential impacts from the development of our nation’s natural resources on the environment, worker health and safety, and the health and safety of the communities where we operate. Working with peer companies, regulators, nongovernmental organizations, industries not related to the natural gas industry, and other engaged stakeholders, we consistently analyze and review performance while striving for continual improvement. In July 2010, we voluntarily elected to provide, on our website, the hydraulic fracturing additives for all wells operated by us and completed to the Marcellus Shale formation. We participate in FracFocus, a national publically accessible web-based registry to report, on a well-by-well basis, the additives and chemicals and amount of water used in the hydraulic fracturing process for each of the wells we operate.

Maintain Long-Life Reserve Base. Long-life natural gas and oil 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 natural gas and oil 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 activities to assist in executing this strategy.

Maintain Flexibility. Because of the risks involved in drilling, coupled with changing commodity prices, we are flexible and adjust our capital budget throughout the year. If certain areas generate higher than anticipated returns, we may accelerate development in those areas and decrease expenditures elsewhere. We also believe in maintaining a strong balance sheet, ample liquidity and using commodity derivatives to stabilize our realized prices. This allows us to be more opportunistic in lower price environments and provides more consistent financial results.

Provide Employee Equity Ownership and Incentive Compensation. We want our employees to think and act like stockholders. To achieve this, we reward and encourage them through equity ownership in Range. All full-time employees are eligible to receive equity grants. As of December 31, 2012, our employees owned equity securities in our benefit plans (vested and unvested) that had an aggregate market value of approximately $277 million.

Significant Accomplishments in 2012

•

Production growth – In 2012, our production averaged 752.6 Mmcfe per day, an increase of 45% from 2011. Including our Barnett Shale properties, which were sold in April 2011 and are presented as discontinued operations, our production in 2012 increased 36% from 2011. Targeted drilling in the Marcellus Shale play in Pennsylvania drove our production growth.

•

Reserve growth – Total proved reserves increased 29% in 2012 to 6.5 Tcfe, marking the eleventh consecutive year our proved reserves have increased. This achievement is the result of continued drilling success, as all of our production and reserve growth in 2012 came from our drilling program. While consistent growth is challenging to sustain, we believe the quality of our technical teams and our substantial inventory of drilling locations provide the basis for future reserve, production and cash flow growth.

•

Successful drilling program – In 2012, we drilled 298 gross wells. Production was replaced by 773% through drilling in 2012 and our overall drilling success rate was 100%. We continue to build our drilling inventory which is critical to our ability to drill a large number of wells each year on a cost effective and efficient basis.

•

Large resource potential from unconventional and conventional plays – Maintaining a large exposure to potential resources is important. We continued expansion of our unconventional resource shale plays in 2012. We have five large unconventional plays – the Marcellus, Utica and Upper Devonian shales in Pennsylvania, the Huron Shale in Virginia and the Cline Shale in West Texas. These plays cover expansive areas, provide multi-year drilling opportunities and, collectively, have sustainable lower risk growth profiles. The economics of these plays

have been enhanced by continued advancements in drilling and completion technologies. We have expanded into the conventional horizontal Mississippian play in Northern Oklahoma and Kansas. We have now leased 1.9 million net acres in these five shale plays and approximately 160,000 in the Mississippian. We also have 150,000 net acres in our coal bed methane plays in Virginia.

•

Focus on financial flexibility – Debt per mcfe of proved reserves was $0.44 in 2012 compared to $0.39 in 2011. In 2012, we issued $600.0 million of senior subordinated fixed rate 5.00% notes having a 10-year maturity. The proceeds we received from the issuance of the 5.00% senior subordinated notes were used to reduce the outstanding balance on our bank credit facility and for general corporate purposes. The issuance helped to better align the maturity schedule of our debt with the long-term life of our assets and reduce interest rate volatility. In April 2012, we added three additional financial institutions to our bank credit facility and we increased our liquidity through an increase in the facility amount from $1.5 billion to $1.75 billion. In December 2012, we redeemed all $250.0 million aggregate principal amount of our 7.5% senior subordinated notes due 2017 with borrowings under our bank credit facility.

•

Successful land acquisitions completed – In 2012, we leased or renewed $188.8 million of acreage located in our core areas, primarily in the Marcellus Shale and the horizontal Mississippian conventional play in Oklahoma and Kansas. We continued to see outstanding results in the Marcellus Shale. Production in the Marcellus Shale increased 80% while we continue to prove up acreage, acquire additional acreage and gain access to additional pipeline and processing capacity.

•

Successful disposition completed – In November 2012, we sold our Ardmore Woodford properties in Southern Oklahoma for gross proceeds of $135.0 million. We also received $33.2 million of additional proceeds related to the sale of miscellaneous proved and unproved properties.

Industry Operating Environment

We operate entirely within the continental 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 economically productive for natural gas and oil. These plays cover large areas, provide multi-year inventories of drilling opportunities and, with modern oil and gas technology, have sustainable lower risk and higher 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 oil. Examples of such technological advancements include advanced 3-D seismic processing, hydraulic 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.

The oil and natural gas industry is affected by many factors that we 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 was characterized by volatile but upward trending oil, NGLs and natural gas commodity prices. The combination of lower demand due to the economic slowdown and greater North American natural gas supply has resulted in significant declines in natural gas prices from mid-2008. Natural gas prices are generally determined by North American supply and demand. The New York Mercantile Exchange (“NYMEX”) monthly settlement prices for natural gas averaged $2.82 per mcf in 2012, with a high of $3.73 per mcf in December and a low of $2.03 per mcf in May. Natural gas prices continue to be under pressure due to concerns over excess supply of natural gas due to the high productivity of shale plays in the United States and continued slow growth in demand caused by a weakened economy and mild weather. The unseasonably warm winter of 2012 experienced in the northeastern United States significantly impacted demand for natural gas since it is a primary heating source. This decrease in demand is somewhat offset by an increase in the use of natural gas for power generation.

Significant factors that will impact 2013 crude oil prices include worldwide economic conditions, political and economic developments in the Middle East, demand in Asian and European markets, and the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to manage oil supply through export quotas. NYMEX monthly settlement prices for oil averaged $93.36 per barrel in 2012, with a high of $106.21 per barrel in March and a low of $82.41 per barrel in June.

NGLs prices are generally determined by North American supply and demand. We expect NGLs prices in 2013 to continue to be under pressure due to concerns over excess supply and mild weather.

Natural gas, NGLs and oil prices affect:

•

the amount of cash flow available to us for capital expenditures;

•

our ability to borrow and raise additional capital;

•

the quantity of natural gas, NGLs and oil that we can economically produce; and

•

revenues and profitability.

Natural gas prices are likely to affect us more than oil prices because approximately 74% of our proved reserves is natural gas. Any continued or extended decline in natural gas, NGLs and oil prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we currently, and may in the future, use derivative instruments to hedge future sales prices on our natural gas, NGLs 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 partially protects us from declining price movements.

Segment and Geographical Information

Our operations consist of one reportable 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 operations are limited to the United States and we focus on both unconventional resource plays and conventional plays in the Appalachian and Southwestern regions of the United States.

Outlook for 2013

Our capital expenditure budget for 2013 has been initially set at approximately $1.3 billion. 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 markets for our products. At December 31, 2012 approximately 68% of our expected 2013 natural gas, NGL and oil production is hedged. For a complete discussion of our hedging activities, a listing of open contracts at December 31, 2012 and the estimated fair value of these contracts as of that date, see Note 11 to our consolidated financial statements. Our estimated 2013 capital expenditure budget detail and by area is shown below:


2013 Capital Budget Detail		2013 Capital Budget by Area

Production, Price and Cost History

The following table sets forth information regarding natural gas, NGLs and oil production, realized prices and production costs for the last three years. For additional information see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”


	Year Ended December 31,
	2012		2011		2010
Production
Natural gas (Mmcf)		216,555		145,206		106,148
Natural gas liquids (Mbbls)		6,967		5,352		3,600
Crude oil (Mbbls)		2,851		1,960		1,934
Total (Mmcfe) ^(a)		275,465		189,077		139,357
Average sales prices (wellhead)
Natural gas (per mcf)	$	2.83	$	4.21	$	4.54
Natural gas liquids (per bbl)		38.05		50.23		39.75
Crude oil (per bbl)		83.46		86.22		69.18
Total (per mcfe) ^(a)		4.05		5.55		5.44
Average realized prices (including derivatives that qualify for hedge accounting):
Natural gas (per mcf)	$	3.93	$	5.06	$	5.15
Natural gas liquids (per bbl)		38.05		50.23		39.75
Crude oil (per bbl)		82.77		86.22		69.19
Total (per mcfe) ^(a)		4.91		6.21		5.91
Average realized prices (including all derivative settlements and third party transportation costs)
Natural gas (per mcf)	$	3.11	$	4.43	$	4.89
Natural gas liquids (per bbl)		41.03		50.82		39.75
Crude oil (per bbl)		83.64		81.34		69.19
Total (per mcfe) ^(a)		4.35		5.68		5.71
Production costs
Lease operating (per mcfe)	$	0.39	$	0.57	$	0.66
Workovers (per mcfe)		0.02		0.02		0.02
Stock-based compensation (per mcfe)		0.01		0.01		0.01

Total (per mcfe)	$	0.42	$	0.60	$	0.69

^(a)	Oil and NGLs are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship of oil, NGLs and natural gas prices.

Proved Reserves

The following table sets forth our estimated proved reserves for 2012, 2011 and 2010 based on the average of prices on the first day of each month of the given fiscal year, in accordance with the SEC rules that became effective on December 31, 2009. We have no natural gas, NGLs or oil reserves from non-traditional sources. Additionally, we do not provide optional disclosures of probable or possible reserves.


	Summary of Oil and Gas Reserves as of Fiscal Year-End Based on Average Fiscal-Year Prices
Reserve Category	Natural Gas (Mmcf)		NGLs (Mbbls)		Oil (Mbbls)		Total (Mmcfe)^(a)		%
2012:
Proved
Developed		2,373,604		154,984		25,667		3,457,502		53	%
Undeveloped		2,419,072		85,415		19,415		3,048,068		47	%

Total Proved		4,792,676		240,399		45,082		6,505,570		100	%

2011:
Proved
Developed		1,907,209		64,472		17,872		2,401,274		48	%
Undeveloped		2,102,467		78,043		13,660		2,652,687		52	%

Total Proved		4,009,676		142,515		31,532		5,053,961		100	%

2010:
Proved
Developed		1,762,766		53,071		17,050		2,183,488		49	%
Undeveloped		1,803,760		69,651		6,189		2,258,802		51	%

Total Proved		3,566,526		122,722		23,239		4,442,290		100	%

^a)	Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the relative energy content of oil to natural gas, which is not indicative of the relationship of oil, NGLs and natural gas prices.

The following table sets forth summary information by area with respect to estimated proved reserves at December 31, 2012:


	Reserve Volumes											PV-10 ^(a)
	Natural Gas (Mmcf)		NGLs (Mbbls)		Oil (Mbbls)		Total (Mmcfe)		%			Amount (In thousands)		%
Appalachian Region		4,393,075		203,782		21,627		5,745,536		88	%	$	2,562,931		65	%
Southwestern Region		399,601		36,617		23,455		760,034		12	%		1,396,959		35	%

Total		4,792,676		240,399		45,082		6,505,570		100	%	$	3,959,890		100	%

^(a)

PV-10 was prepared using the twelve-month average prices for 2012, discounted at 10% per annum. Year-end PV-10 is 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 $736.1 million at December 31, 2012. Included in the $4.0 billion PV-10 is $3.6 billion (pre-tax) related to proved developed reserves.

Reserve Estimation

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. We also have the following independent petroleum consultants conduct an audit of our year-end reserves: DeGolyer and MacNaughton (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, 2012, these consultants collectively audited approximately 93% of our proved reserves. Copies of the summary reserve reports prepared by each of these independent petroleum consultants are 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 meets 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 reserve audit 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. Our senior management reviews and approves significant changes to our proved reserves. We provide historical information to our consultants for our largest producing properties such as ownership interest, natural gas, NGL and oil 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 and Economics. In some cases, additional meetings are held to review identified reserve differences.

Historical variances between our reserve estimates and the aggregate estimates of our independent petroleum consultants have been less than 5%. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering and Economics, who reports directly to our President and Chief Executive Officer. Our Senior Vice President of Reservoir Engineering and Economics 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 more than thirty years of engineering 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, 2012 with any federal authority or agency with respect to our estimate of natural gas and oil reserves.

Reserve Technologies

Proved reserves are those quantities of natural gas, natural gas liquids and oil, 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 natural gas, NGLs and oil actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal technical staff employs 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 Natural Gas Liquids

We produce natural gas liquids, or NGLs, as part of the processing of our natural gas. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. At December 31, 2012, NGLs represented approximately 22% of our total proved reserves on an mcf equivalent basis. NGLs are products sold by the gallon. In reporting proved reserves and production of NGLs, we have included production and reserves in barrels. Prices for a barrel of NGLs in 2012 averaged approximately 54% 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 NGLs. In 2012, we added 307 Bcfe of incremental ethane reserves (51.2 Mmbbls), which are included in NGLs proved reserves, associated with initial ethane deliveries under certain contracts under which we begin to make deliveries in 2013.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2012, our PUDs totaled 19.4 Mmbbls of crude oil, 85.4 Mmbbls of NGLs and 2.4 Tcf of natural gas, for a total of 3.0 Tcfe. Costs incurred in 2012 relating to the development of PUDs were approximately $451.9 million in 2012. Approximately 88% of our PUDs at year-end 2012 were associated with our major development area in the Marcellus Shale. All PUD drilling locations are scheduled to be drilled prior to the end of 2017 with more than 59% of the future development costs to be spent in the next three years. Changes in PUDs that occurred during the year were due to:

•

conversion of approximately 413 Bcfe PUDs into proved developed reserves;

•

new PUDs added consisting of 927 Bcfe; and

•

119 Bcfe negative revision with reserves reclassified to unproved because of a slower pace of development activity beyond the five-year development horizon and a negative price revision partially offset by a favorable performance revision.

Proved Reserves (PV-10)

The following table sets forth the estimated future net cash flows, excluding open derivative contracts, from proved reserves, the present value of those net cash flows discounted at a rate of 10% (PV-10), and the expected benchmark prices and average field prices used in projecting net cash flows over the past five years. Our reserve estimates do not include any probable or possible reserves. Field prices, or wellhead prices reported below, are net of third party transportation, gathering and compression expense paid by Range (in millions, except prices):


	2012		2011		2010		2009		2008
Future net cash flows	$	11,156	$	15,610	$	12,516	$	6,721	$	8,441
Present value
Before income tax		3,960		6,084		4,647		2,593		3,400
After income tax (Standardized Measure)		3,224		4,515		3,479		2,091		2,581
Benchmark prices (NYMEX)
Gas price (per mcf)		2.76		4.12		4.38		3.87		5.71
Oil price (per barrel)		95.05		95.61		79.81		60.85		44.60
Wellhead prices
Gas price (per mcf)		2.75		3.55		3.70		3.19		5.23
Oil price (per barrel)		86.91		85.59		72.51		54.65		42.76
NGLs price (per barrel)		32.23		49.24		39.14		34.05		25.00

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). Prices for 2012, 2011, 2010 and 2009 were based on a twelve-month unweighted average of the first day of the month pricing, without escalation. Prices for 2008 were based on prices in effect at December 31, 2008 without escalation, in accordance with SEC rules in effect that year. 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. 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.

Property Overview

Our natural gas and oil operations are concentrated in the Appalachian and Southwestern regions of the United States. Our properties consist of interests in developed and undeveloped natural gas and oil leases in these regions. These interests entitle us to drill for and produce natural gas, NGLs and oil from specific areas. Our interests are mostly in the form of working interests and, to a lesser extent, royalty and overriding royalty interests. 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.

The table below summarizes data for our operating regions for the year-ended December 31, 2012.


Region	Average Daily Production (Mcfe per day)		Production (Mmcfe)		Percentage of Production			Proved Reserves (Mmcfe)		Percentage of Proved Reserves
Appalachian		622,370		227,787		83	%		5,745,536		88	%
Southwestern		130,267		47,678		17	%		760,034		12	%

		752,637		275,465		100	%		6,505,570		100	%

The following table summarizes our costs incurred by operating region for 2012 (in thousands):


Region	Acreage Purchases		Development Costs		Exploration Costs		Gathering Facilities		Asset Retirement Obligations		Total
Appalachian	$	164,350	$	868,675	$	338,232	$	31,796	$	53,894	$	1,456,947
Southwestern		24,493		180,454		41,391		9,239		4,088		259,665

Total costs incurred	$	188,843	$	1,049,129	$	379,623	$	41,035	$	57,982	$	1,716,612

Approximately 77% of our proved reserves at December 31, 2012 are located in the Marcellus Shale in our Appalachia region. This play has a large portfolio of drilling opportunities. The following table below sets forth annual production volumes, average sales prices and production cost data for our Marcellus Shale field which, as of December 31, 2012, is our only field whose reserves are greater than 15% of our total proved reserves.


	2012		2011		2010
Marcellus Shale
Production:
Natural gas (Mmcf)		149,589		80,554		39,577
NGLs (Mbbls)		5,034		3,423		2,209
Crude oil (Mbbls)		1,564		695		496
Total Mmcfe ^(a)		189,178		105,264		55,802
Sales Prices: ^(b)
Natural gas (per mcf)	$	1.86	$	3.17	$	3.56
NGLs (per bbl)		38.51		51.83		41.44
Crude oil (per bbl)		78.56		74.84		48.98
Total (per mcfe)		3.15		4.60		4.60
Production Costs:
Lease operating (per mcfe)		0.17		0.33		0.37
Production and ad valorem tax (per mcfe) ^(c)		0.26		—		—

^(a)	Oil and NGLs are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship of oil, NGLs and natural gas prices.

^(b)	We do not record hedging or the results of hedging at the field level. Includes deductions for third party transportation, gathering and compression expense.

^(c)	Includes Pennsylvania impact fee.

Appalachian Region

Our properties in this area are located in the Appalachian Basin in the northeastern United States, principally in Pennsylvania, West Virginia and Virginia. The reserves principally produce from the Marcellus Shale, the Pennsylvanian (coalbed formation), Berea, Big Lime, Huron Shale, Medina and Upper Devonian formations at depths ranging from 2,500 feet to 9,000 feet. We own 4,637 net producing wells, 88% of which we operate. Our average working interest in this region is 71%. We have approximately 1.6 million gross (1.4 million net) acres under lease, which includes 290,000 acres in which we also own a royalty interest.

Reserves at December 31, 2012 were 5.7 Tcfe, an increase of 1.5 Tcfe, or 34%, from 2011 with drilling additions and a favorable reserve revision for performance somewhat offset by production and an unfavorable pricing revision. Annual production increased 59% over 2011. During 2012, we spent $1.2 billion in this region to drill 179 (166.3 net) development wells and 68 (51.4 net) exploratory wells, all of which were productive. At December 31, 2012, the Appalachian region had an inventory of over 1,000 proven drilling locations and 600 proven recompletions. During the year, the Appalachian region drilled 141 proven locations, added 269 new proven drilling locations and deleted 835 proven drilling locations with reserves reclassified to unproved because of a slower pace of development activity beyond the five-year development horizon as required by the SEC’s reserve reporting requirements and lower prices. During the year, the region achieved a 100% drilling success rate.

Marcellus Shale

We began operations in the Marcellus Shale in Pennsylvania during 2004. The Marcellus Shale is a non-conventional reservoir, which produces natural gas, NGLs and oil. This has been our largest investment area over the last four years. We had 689 proven drilling locations at December 31, 2012. Our 2012 production from the Marcellus Shale was 80% greater than 2011. During 2012, we drilled 132.8 net development wells and 51.4 net exploratory wells in the Marcellus Shale, of which all wells were successful. In 2013, we plan to drill 123.5 net wells. During 2012, we had approximately eleven drilling rigs in the field and expect to run an average of seven rigs throughout 2013.

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. (“MarkWest Liberty”) completed a phase two expansion, pursuant to these agreements. This expansion included an additional 120 Mmcf per day of cryogenic natural gas processing, 20 additional miles of gathering and residue gas pipelines and 21,000 horsepower of additional compression. In May 2010, MarkWest Liberty brought an additional 200 Mmcf per day of additional processing capacity on line, increasing the total processing capacity contractually committed to us to 350 Mmcf per day. At the end of 2011, this processing capacity was increased to 415 Mmcf per day. MarkWest is also expanding its natural gas liquids infrastructure to include new de-ethanization capacity at two of its complexes which are expected to be operational by mid 2013. Liquid fractionation capacity to make purity products was installed and operational late in 2011.

In 2011, we executed an ethane sales contract for the liquids-rich gas in southwestern Pennsylvania whereby a third party will transport ethane from the tailgate of the third-party processing and fractionation facilities to the international border for further delivery into Canada. Initial deliveries are expected to commence in mid to late 2013. Also in 2011, we entered into an agreement to transport ethane to the Gulf Coast. Initial deliveries are expected to commence in early to mid 2014.

In 2012, we entered into a fifteen year agreement to transport ethane and propane from the tailgate of a third-party processing plant to a terminal and dock facility near Philadelphia. Initial deliveries are expected to commence by the end of 2014. In the meantime, during 2012, we began transporting propane by rail and truck to the terminal and dock facility near Philadelphia for sale to domestic and international customers. Also in 2012, we executed a fifteen year ethane sales agreement for delivery, from the aforementioned terminal near Philadelphia which is expected to begin in the first half of 2015. The sales agreement is contingent on FERC approval of the Mariner East pipeline project.

Since 2008, we have entered into various firm transportation agreements to provide gas gathering and transportation from southwestern and northeastern Pennsylvania which, at December 31, 2012 provide commitments for 1.3 Bcfe per day. Some of our agreements, which extend to 2028, are contingent on pipeline modifications and/or construction. To support our drilling efforts and to control costs, we have contracts with drilling contractors to use three drilling rigs through 2015, and agreements for hydraulic fracturing services, including related equipment, material and labor, through 2013 in Pennsylvania.

Southwestern Region

The Southwestern region includes drilling, production and field operations in the Permian Basin of West Texas, the Delaware Basin of New Mexico, as well as in the Texas Panhandle, Anadarko Basin of western Oklahoma, Nemaha Uplift of northern Oklahoma and Kansas, the East Texas Basin and Mississippi. In the Southwestern region, we own 1,536 net producing wells, 96% of which we operate. Our average working interest is 80%. We have approximately 811,000 gross (604,000 net) acres under lease.

Total proved reserves in the Southwestern region decreased 13.5 Bcfe, or 2%, at December 31, 2012, when compared to year-end 2011. Drilling additions (234.9 Bcfe) were offset by production, sales (149.2 Bcfe) and negative performance and pricing revisions. Annual production volumes increased 5% from 2011. During 2012, this region spent $221.8 million to drill 47.0 (36.0 net) development wells and 4 (3.1 net) exploratory wells, all of which were productive. During the year, the region achieved a 100% drilling success rate.

At December 31, 2012, the Southwestern region had a development inventory of 132 proven drilling locations and 362 proven recompletions. During the year, the Southwestern region drilled 8 proven locations, added 86 new proven drilling locations and deleted 81 proven drilling locations primarily due to lower prices. Development projects include recompletions and infill drilling. 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.

Producing Wells

The following table sets forth information relating to productive wells at December 31, 2012. We also own royalty interests in an additional 3,507 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 natural gas or crude oil according to their predominant production stream. We do not have a significant number of dual completions.


	Total Wells				Average Working
	Gross		Net		Interest
Natural gas		7,629		5,492		72	%
Crude oil		787		681		87	%

Total		8,416		6,173		73	%

The day-to-day operations of natural gas and oil 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.

Drilling Activity

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, 2012, we were in the process of drilling 65.0 gross (43.8 net) wells.


	2012						2011						2010
	Gross			Net			Gross			Net			Gross			Net
Development wells
Productive		226.0			202.3			262.0			236.5			353.0			253.4
Dry		—			—			—			—			3.0			3.0
Exploratory wells
Productive		72.0			54.5			38.0			28.2			8.0			6.4
Dry		—			—			1.0			1.0			3.0			3.0
Total wells
Productive		298.0			256.8			300.0			264.7			361.0			259.8
Dry		—			—			1.0			1.0			6.0			6.0

Total		298.0			256.8			301.0			265.7			367.0			265.8

Success ratio		100	%		100	%		99.7	%		99.6	%		98.4	%		97.7	%

Gross and Net Acreage

We own interests in developed and undeveloped natural gas and oil acreage. These ownership interests generally take the form of working interests in oil and natural 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, 2012. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary:


	Developed Acres					Undeveloped Acres					Total Acres
	Gross		Net			Gross		Net			Gross		Net
Alabama		—		—			3,176		2,855			3,176		2,855
Illinois		—		—			13,332		7,312			13,332		7,312
Kansas		—		—			42,971		41,031			42,971		41,031
Louisiana		5,673		5,663			410		371			6,083		6,034
Mississippi		5,585		4,401			1,307		1,248			6,892		5,649
New Mexico		6,890		5,869			1,200		1,112			8,090		6,981
Ohio		40		40			—		—			40		40
New York		—		—			10,147		10,147			10,147		10,147
Oklahoma		174,251		112,997			140,713		111,968			314,964		224,965
Pennsylvania		487,136		452,662			610,196		591,008			1,097,332		1,043,670
Texas		206,638		150,856			208,425		158,510			415,063		309,366
Virginia		121,287		78,179			235,455		146,412			356,742		224,591
West Virginia		51,792		51,612			61,485		60,749			113,277		112,361

		1,059,292		862,279			1,328,817		1,132,723			2,388,109		1,995,002

Average working interest				81	%				85	%				84	%

Undeveloped Acreage Expirations

The table below summarizes by year our undeveloped acreage scheduled to expire in the next five years.


	Acres				% of Total
As of December 31,	Gross		Net		Undeveloped
2013		193,573		176,690		22	%
2014		273,191		236,031		29	%
2015		112,314		105,681		13	%
2016		70,711		63,323		8	%
2017		47,713		46,409		6	%

In most cases the drilling of a commercial well will hold acreage beyond the expiration date. We have leased acreage that is subject to lease expiration if initial wells are not drilled within a specified period, generally between three to five 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. The expirations included in the table above do not take into account the fact that we may be able to extend the lease terms. 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 from time to time and expect to allow additional acreage to expire in the future.

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:

•

customary royalty interests;

•

liens incident to operating agreements and for current taxes;

•

obligations or duties under applicable laws;

•

development obligations under oil and gas leases; or

•

net profit interests.

Delivery Commitments

For a discussion of our delivery commitments see “Delivery Commitments” under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Employees

As of January 1, 2013, we had 841 full-time employees, 251 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 currently 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 services, on-site production services and certain accounting functions.

Competition

Intense competition exists in all sectors of the oil and gas industry and in particular, we encounter substantial competition in developing and acquiring natural gas and oil properties, securing and retaining personnel, conducting drilling and field operations and marketing production. Competitors in exploration, development, acquisitions and production include the major oil and gas 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. For additional information, see “Item 1A. Risk Factors.”

Marketing and Customers

We market the majority of our natural gas, NGLs and oil production from the properties we operate for our interest, and that of the other working interest owners. We pay our royalty owners from the sales attributable to our working interest. Natural gas, NGLs and oil purchasers are selected on the basis of price, credit quality and service reliability. For a summary of purchasers of our natural gas, NGLs and oil production that accounted for 10% or more of consolidated revenue, see Note 16 to our consolidated financial statements. Because alternative purchasers of natural gas and oil are usually readily available, we believe that the loss of any of these purchasers would not have a material adverse effect on our operations. Production from our properties is marketed using methods that are consistent with industry practice. Sales prices for natural gas, NGLs and oil production are negotiated based on factors normally considered in the industry, such as index or spot price, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. Our natural gas production is sold to utilities, marketing and mid-stream companies and industrial users. Our NGLs production is typically sold to natural gas processors or users of NGLs. Our oil production is sold to crude oil processors, transporters and refining and marketing companies in the area. Market volatility due to fluctuating weather conditions, international political developments, overall energy supply and demand, economic growth rates and other factors in the United States and worldwide have had, and will continue to have, a significant effect on energy prices.

We enter into derivative transactions with unaffiliated third parties for a varying portion of our production to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in natural gas, NGLs and oil prices. For a more detailed discussion, see the information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

We incur gathering and transportation expense to move our production from the wellhead and tanks to purchaser specified delivery points. These expenses vary based on volume, distance shipped and the fee charged by the third-party gatherers and transporters. In the Southwestern region, our production is transported primarily through purchaser owned or third-party trucks, field gathering systems and transmission pipelines. Transportation capacity on these gathering and transportation systems and pipelines is occasionally constrained. In Appalachia, we own some gas gathering and transportation pipelines, which transport a portion of our Appalachian production and third-party production to transmission lines, directly to end-users and interstate pipelines. Our remaining Appalachian production is transported on third-party pipelines on which, in most cases, we hold long-term contractual capacity. We attempt to balance sales, storage and transportation positions, which can include purchase of commodities from third parties for resale, to satisfy transportation commitments.

We have not experienced significant difficulty to date in finding a market for all of our production as it becomes available or in transporting our production to those markets; however, there is no assurance that we will always be able to transport and market all of our production or obtain favorable prices.

Because there is currently little demand, or existing facilities to create demand, for ethane in the Appalachian region, ethane remains in our Appalachian production natural gas stream. We have entered into three ethane agreements to sell or transport ethane from our Marcellus Shale area. Each of these agreements is contingent on pipeline modifications and/or construction with operations expected to begin in mid to late 2013 through early 2015. For additional information, see “Risk Factors – Our business depends on natural gas and oil transportation and processing facilities, most of which are owned by others and depends on our ability to contract with those parties,” in Item 1A of this report.

Seasonal Nature of Business

Generally, but not always, the demand for natural gas and propane decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial end users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen the seasonality of demand.

Governmental Regulation

Enterprises that sell securities in public markets are subject to regulatory oversight by federal agencies such as the SEC and the NYSE, a private stock exchange which requires us to comply with listing requirements in order to keep our common stock listed there. This regulatory oversight imposes on us the responsibility for establishing and maintaining disclosure controls and procedures and internal controls over financial reporting, and ensuring that the financial statements and other information included in submissions to the SEC do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made in such submissions not misleading. Failure to comply with the listing rules and regulations of the SEC could subject us to litigation from public or private plaintiffs. Failure to comply with the rules of the NYSE could result in the de-listing of our common stock, which could have an adverse effect on the market price of our common stock. Compliance with some of these rules and regulations is costly, and regulations are subject to change or reinterpretation.

Exploration and development and the production and sale of oil and gas are subject to extensive federal, state and local regulations. An overview of these regulations is set forth below. We believe we are in substantial compliance with currently applicable laws and regulations and the continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Please see the discussion under the caption “The natural gas and oil industry is subject to extensive regulation,” in Item 1A of this report. We do not believe we are affected differently by these regulations than others in the industry.

General Overview. Our oil and gas operations are subject to various federal, state, tribal and local laws and regulations. Generally speaking, these regulations relate to matters that include, but are not limited to:

•

leases;

•

acquisition of seismic data;

•

location of wells, pads, roads, impoundments, facilities, right of ways;

•

size of drilling and spacing units or proration units;

•

number of wells that may be drilled in a unit;

•

unitization or pooling of oil and gas properties;

•

drilling and casing of wells;

•

issuance of permits in connection with exploration, drilling and production;

•

well production, maintenance, operations and security;

•

spill prevention plans;

•

emissions permitting or limitations;

•

protection of endangered species;

•

use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

•

surface usage and the restoration of properties upon which wells have been drilled;

•

calculation and disbursement of royalty payments and production taxes;

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plugging and abandoning of wells; and

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transportation of production.

In August 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, the EPAct 2005 amends the Natural Gas Act (“NGA”), to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as Range, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit any such statement necessary to make the statements not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sale or gathering, but does apply to activities or otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to the FERC’s jurisdiction which includes the reporting requirements under Order Nos. 704 and 720, described below. It therefore reflects a significant expansion of the FERC’s enforcement authority. Range has not been affected differently than any other producer of natural gas by this act. Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and gas industry are regularly considered by Congress, the states, the FERC, and the courts. We cannot predict when or whether any such proposals may become effective.

On December 26, 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are now required to report, on May 1 of each year beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with the FERC’s policy statement on price reporting. On November 15, 2012, the FERC issued a Notice of Inquiry seeking comments on whether requiring all market participants engaged in sales of wholesale physical natural gas in interstate commerce to report quarterly to the Commission every natural gas transaction within the Commission’s NGA jurisdiction that entails physical delivery for the next day or for the next month will improve natural gas market transparency. We cannot predict when or whether any such proposals may become effective.

On November 20, 2008, the FERC issued a final rule on the daily scheduled flow and capacity posting requirements (“Order 720”), which was modified on January 21, 2010 (“Order 720-A”) and July 21, 2010 (“Order 720-B”). Under Orders 720, 720-A and 720-B, major non-interstate pipelines, defined as certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtus of gas over the previous three calendar years, are required to post daily certain information regarding the pipeline’s capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtus per day.

Environmental and Occupational Health and Safety Matters

Our operations are subject to numerous stringent federal, state and local statutes and regulations governing occupational health and safety, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines, govern the sourcing and disposal of water used in the drilling and completion process, limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas, require some form of remedial action to prevent or mitigate pollution from existing and former operations such as plugging abandoned wells or closing earthen impoundments and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. These laws and regulations also may restrict the rate of production. Moreover, changes in environmental laws and regulations often occur, and any changes that result in more stringent and costly well construction, drilling, water management or completion activities or more restrictive waste handling storage, transport, disposal or cleanup requirements for any substances used or produced in our operations could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general.

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons may include owners or operators of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, all of these persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties, pursuant to environmental statutes, common law or both, to file claims for personal injury and property damages allegedly caused by the release of hazardous substances or other pollutants into the environment. Although petroleum, including crude oil and natural gas, is not a “hazardous substance” under CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as “hazardous substances” under CERCLA and that releases of such wastes may therefore give rise to liability under CERCLA. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA or comparable state laws. Other state laws regulate the disposal of oil and gas wastes, and new state and federal legislative initiatives that could have a significant impact on us may periodically be proposed and enacted.

We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”) and comparable state laws, which impose requirements related to the handling and disposal of non-hazardous solid wastes and hazardous wastes. Drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy are currently regulated by the United States Environmental Protection Agency (“EPA”) and state agencies under RCRA’s less stringent non-hazardous solid waste provisions. It is possible that these solid wastes could in the future be re-classified as hazardous wastes, whether by amendment of RCRA or adoption of new laws, which could significantly increase our costs to manage and dispose of such wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, may be regulated as hazardous wastes. Although the costs of managing wastes classified, as hazardous waste may be significant, we do not expect to experience more burdensome costs than similarly situated companies in our industry.

We currently own or lease, and have in the past owned or leased, properties that for many years have been used for the exploration and production of crude oil and natural gas. Petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us, or on or under other locations where such materials have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials disposed or released on them may be subject to CERCLA, RCRA and comparable state laws and regulations. Under such laws and regulations, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.

The Federal Water Pollution Control Act, as amended, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws also prohibit the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by permit. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of greater than threshold quantities of oil. We regularly review our natural gas and oil properties to determine the need for new or updated SPCC plans and, where necessary, we will be developing or upgrading such plans, the costs of which are not expected to be substantial.

The Oil Pollution Act of 1990, as amended, “OPA”, contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from an oil spill, including, but not limited to, the costs of responding to a release of oil to surface waters. While we believe we have been in substantial compliance with OPA, noncompliance could result in varying civil and criminal penalties and liabilities.

The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, impose stringent air permit requirements, or use specific equipment or technologies to control emissions. We may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals for emissions of pollutants. For example, on August 16, 2012, the EPA published final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. With regards to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and non-delineation gas wells; and all “other” fractured and refractured gas wells. All three subcategories of wells must route flow back emissions to a gathering line or be captured and combusted using a combustion device such as a flare after October 15, 2012. However, the “other” wells must use reduced emission completions, also known as “green completions,” with or without combustion devices, after January 1, 2015. These regulations also establish specific requirements regarding emissions from production-related wet seal and reciprocating compressors, effective October 15, 2012 and from pneumatic controllers and storage vessels, effective October 15, 2013. Our flow back operations in many of our divisions already meet these requirements by capturing and/or flaring gas emissions and, in many of our divisions, we have also been utilizing vapor recovery units or enclosed burner units on storage vessels which reduce emissions below published levels. We do not believe continuing to implement such requirements will have a material adverse effect on our operations.

In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, the EPA adopted regulations under the existing Clean Air Act establishing Title V and Prevention of Significant Deterioration (“PSD”) permitting requirements for large sources of GHG’s that are potential major sources of GHG emissions. We could become subject to these Title V and PSD permitting requirements and be required to install “best available control technology” to limit emissions of GHG’s from any new or significantly modified facilities that we may seek to construct in the future if such facilities emitted volumes of GHGs in excess of threshold permitting levels. The EPA has also adopted rules requiring the reporting of GHG emissions from specified emission sources in the United States on an annual basis, including certain oil and natural gas production facilities, which include certain of our facilities. We are monitoring GHG emissions from our operations and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the U.S., a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Moreover, if Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emission allowances or comply with new regulatory or reporting requirements including the imposition of a carbon tax. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for oil and natural gas, which could reduce the demand for the oil and natural gas that we produce. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

Hydraulic fracturing, which has been used by the industry for over 60 years, is an important and common practice used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely apply hydraulic fracturing techniques as part of our operations. This process is typically regulated by state oil and natural gas commissions but the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuels under the federal Safe Drinking Water Act and published a draft permitting guidance in May 2012 addressing the performance of such activities. Also, in November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue an Advance Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. Moreover, from time to time, Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. In addition to any actions by Congress, certain states in which we operate, including Pennsylvania and Texas, have adopted, and other states are considering adopting, regulations imposing or that could impose new or more stringent permitting, public disclosure, or well-construction requirements on hydraulic fracturing operations. Local government also may seek to adopt ordinances within their jurisdiction regulating the time, place or manner of drilling activities in general or hydraulic fracturing activities in particular. In the event that new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process is adopted in areas where we currently or in the future plan to operate, we may incur additional, more significant, costs to comply with such requirements and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

In addition, certain government reviews have been conducted or are underway that focuses on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities that it plans to propose as standards by 2014 and the U.S. Department of Energy and U.S. Department of the Interior have evaluated or are evaluating various other aspects of hydraulic fracturing. These studies, depending on any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Act or other regulatory mechanisms.

We believe that our hydraulic fracturing activities follow applicable industry practices and legal requirements for groundwater protection and that our fracturing operations have not resulted in material environmental liabilities. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our existing insurance policies would cover third-party bodily injury and property damage caused by hydraulic fracturing including sudden and accidental pollution coverage.

The federal Endangered Species Act, as amended, restricts activities that may affect endangered and threatened species or their habitats. If endangered species are located in an area where we wish to conduct seismic surveys, development activities or abandonment operations, the work could be prohibited or delayed or expensive mitigation may be required. Moreover, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. For example, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination over the next six years on the listing of more than 250 species as endangered or threatened under the Endangered Species Act prior to the completion of the agency’s 2017 fiscal year. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

The Migratory Bird Treaty Act implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. In accordance with this law, the taking, killing or possessing of migratory birds covered under this act is unlawful without a permit. If there is the potential to adversely affect migratory birds as a result of our operations, we may be required to obtain necessary permits to conduct those operations, which may result in specified operating restrictions on a temporary, seasonal, or permanent basis in affected areas and an adverse impact on our ability to develop and produce our reserves.

In summary, we believe we are in substantial compliance with currently applicable environmental laws and regulations. Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2012, nor do we anticipate that such expenditures will be material in 2013. However, we regularly have expenditures to comply with environmental laws and those costs continue to increase as our operations expand.

We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements.

ITEM 1A.

RISK FACTORS

We are subject to various risks and uncertainties in the course of our business. The following summarizes the known material 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 natural gas, NGLs and oil prices significantly affects our cash flow and capital resources and could hamper our ability to produce natural gas, NGLs and oil economically

Natural gas, NGLs and oil 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 natural gas, NGLs and oil have been volatile. Over the past four years, the average NYMEX monthly settlement price of natural gas has been as high as $5.81 per mcf and as low as $2.04 mcf. During that same time frame, the average NYMEX monthly oil settlement price was as high as $108.15 per barrel and as low as $38.74 per barrel. As of the end of January 2013, natural gas was at $3.23 per mcf and oil was at $96.24 per barrel. Natural gas prices are likely to affect us more than oil prices because approximately 74% of our December 31, 2012 proved reserves are natural gas. Recently, natural gas prices have approached historical lows. Historically, the industry has experienced downturns characterized by oversupply and/or weak demand. Long-term supply and demand for natural gas, NGLs and oil is uncertain and subject to a myriad of factors such as:

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the domestic and foreign supply of natural gas, NGLs and oil;

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the price, availability and demand for alternative fuels and sources of energy;

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weather conditions;

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the level of consumer demand for natural gas, NGLs and oil;

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the price and level of foreign imports;

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U.S. domestic and 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 natural gas and oil producing regions; and

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domestic (federal, state and local) and foreign governmental regulations and taxes.

Lower natural gas, NGLs and oil prices may not only decrease our revenues on a per unit basis but also may reduce the amount of natural gas, NGLs and oil that we can economically produce. A reduction in production could result in a shortfall in expected cash flows and require a reduction in capital spending or require additional borrowing. Without the ability to fund capital expenditures, we would be unable to replace reserves which would negatively affect our future rate of growth.

Producing natural gas, NGLs and oil may involve unprofitable efforts. As of December 31, 2012, the relationship between the price of oil and the price of natural gas continues to be at an unprecedented spread. Normally, natural gas liquids production is a by-product of natural gas production. Due to the current differences in prices, we and other producers may choose to sell natural gas at below cost, or otherwise dispose of natural gas to allow for the sale of only NGLs.

Information concerning our reserves and future net cash flow estimates is uncertain

There are numerous uncertainties inherent in estimating quantities of proved natural gas and oil 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 natural gas and oil 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 natural gas, NGLs and oil 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 natural gas, NGLs and oil 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. 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 (first day of the month) while cost estimates are based on current year-end economic conditions. Actual future prices and costs may be materially higher or lower. In addition, the ten 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 natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record writedowns of our natural gas and oil properties

In the past we have been required to write down the carrying value of certain of our natural gas and oil properties, and there is a risk that we will be required to take additional writedowns in the future. Writedowns may occur when natural gas and oil 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 expected economics.

Accounting rules require that the carrying value of natural gas and oil properties be periodically reviewed for possible impairment. Impairment is recognized for the excess of book value over fair value 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 natural gas and oil prices at the time of the impairment review, or as a result of continuing evaluation of drilling results, production data, economics, divestiture activity, 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.

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. 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 natural gas, NGLs and oil and our success in developing and producing new reserves. If our access to capital were limited due to various factors, which could include a decrease in revenues due to lower natural gas, NGLs 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, at their discretion, taking into account our estimated proved reserves and is subject to periodic redeterminations based on pricing models determined by the lenders at such time. Declines in natural gas, NGLs and oil prices adversely impact 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 natural gas prices) continue to decline, 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 natural gas and oil properties generally declines as reserves are depleted, our future success depends upon our ability to economically find or acquire and produce additional natural gas, NGLs and oil 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 natural gas, NGLs and oil 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.

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.

Drilling is an uncertain and costly 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 natural gas, NGLs and oil 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, water for hydraulic fracturing services, labor, or other services;

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unexpected operational events and drilling conditions;

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reductions in natural gas, NGLs and oil prices;

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limitations in the market for natural gas, NGLs and oil;

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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, or changes in environmental, tax and other governmental requirements;

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environmental hazards, such as natural gas leaks, oil spills, pipeline 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

There have been rapid and significant advancements in technology in the natural gas and oil industry, 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 increase in cost. Further, competitors’ may obtain patents which might prevent us from implementing new technologies. 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.

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.

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 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, 2012, approximately 74% of our debt is at fixed interest rates with the remaining 26% subject to variable interest rates.

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 bank 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.

A worldwide financial downturn, such as the 2008 – 2009 financial crisis, or negative credit market conditions may have lasting effects on our liquidity, business and financial condition that we cannot predict

Liquidity is essential to our business. Our liquidity could be substantially negatively affected by an inability to obtain capital in the long-term or short-term debt capital markets or equity capital markets or an inability to access bank financing. A prolonged credit crisis, including the current sovereign debt crisis in Europe and related turmoil in the global financial system, could materially affect our liquidity, business and financial condition. These conditions have adversely impacted financial markets and have created substantial volatility and uncertainty, and may continue to do so, with the related negative impact on global economic activity and the financial markets. Negative credit market conditions could materially affect our liquidity and may inhibit our lenders from fully funding our bank credit facility or cause them to make the terms of our bank credit facility costlier and more restrictive. We are subject to semiannual reviews, as well as unscheduled reviews, of our borrowing base under our bank credit facility, and we do not know the results of future redeterminations or the effect of then-current oil and

natural gas prices on that process. The economic situation could also adversely affect the collectability of our trade receivables or performance by our suppliers and cause our commodity derivative arrangements to be ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally, negative economic conditions could lead to reduced demand for natural gas, NGLs and oil or lower prices for natural gas and oil, which could have a negative impact on our revenues.

Derivative transactions may limit our potential gains and involve other risks

To manage our exposure to price risk, we currently and may in the future enter into derivative arrangements, utilizing commodity derivatives with respect to a 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 natural gas, NGLs and oil prices rise above the price established by the hedge.

In addition, derivative 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 on their contract obligations; or

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an event materially impacts natural gas, NGLs or oil prices or the relationship between the hedged price index and the natural gas or oil sales price.

We cannot assure you that any derivative transaction we may enter into will adequately protect us from declines in the prices of natural gas, NGLs or oil. On the other hand, where we choose not to engage in derivative transactions in the future, we may be more adversely affected by changes in natural gas, NGLs or oil prices than our competitors who engage in derivative transactions. Lower natural gas and oil prices may also negatively impact our ability to enter into derivative contracts at favorable prices.

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 natural gas, NGLs or oil. 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 natural gas and oil properties

In a rising price environment, such as those experienced in 2007 and early 2008, well service providers and related equipment and personnel were in short supply. This caused escalating prices, the possibility of poor services coupled with potential damage to downhole reservoirs and personnel injuries. Such pressures increased the actual cost of services, extended the time to secure such services and added costs for damages due to accidents sustained from the over use of equipment and inexperienced personnel. In some cases, we may operate in areas where services and infrastructure are limited, or do not exist or in urban areas which are more restrictive. If prices were to escalate to these levels, demand for well service providers and related equipment and personnel could be greater than the supply resulting in escalating prices which could have a negative impact on our financial condition and results of operations.

The natural gas and oil industry is subject to extensive regulation

The natural gas and oil industry is subject to various types of regulations in the United States by local, state and federal agencies. Legislation affecting the industry is under constant review for amendment or expansion, frequently increasing 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 natural gas and oil 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 or natural resource 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 or relate to third party sites where we have taken materials for recycling or disposal. Failure to comply with these laws and regulations may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as corrective actions orders. Matters subject to regulation include:

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the amounts and types of substances and materials that may be released into the environment;

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response to unexpected releases to the environment;

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reports and permits concerning exploration, drilling, production and other operations;

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the spacing of wells;

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unitization and pooling of properties;

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calculating royalties on oil and gas produced under federal and state leases; and

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taxation.

Under these laws and regulations, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs, natural resource damages and other environmental damages. We also could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. If we incur these costs or damages it may reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur losses.

Climate change is receiving increasing attention from scientists, legislators and governmental agencies. There is an ongoing debate 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 (“GHGs”), including carbon dioxide and methane, which has led to significant legislative and regulatory efforts to limit GHG emissions.

There are a number of legislative and regulatory initiatives to address GHG emissions, which are in various phases 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 to control or restrict emissions, taxes or other charges to deter emissions of GHGs, energy efficiency requirements to reduce demand, 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.

Adoption of federal or state requirements mandating a reduction in GHG 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. For more information regarding the environmental regulation of our business, see “Environment and Occupational Health and Safety Matters” in Items 1 and 2 of this report.

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

Natural gas, NGLs and oil 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 gases 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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cleanup 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 natural gas and oil properties are damaged. 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.

Additionally, we rely to a large extent on facilities owned and operated by third parties, and damage to or destruction of those third-party facilities could affect our ability to produce, transport and sell our production. We maintain business interruption insurance related to a third party processing plant in Pennsylvania where we are insured for potential losses from the interruption of production caused by loss of or damage to the processing plant.

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 NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests the 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 the FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by the FERC, the courts, or Congress.

While our natural gas gathering operations are generally exempt from the FERC regulation under the NGA, our gas gathering operations may be subject to certain FERC reporting and posting requirements in a given year. The FERC has issued a final rule 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 to the FERC on the aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to, the formation of price indices. In addition, the FERC has issued a final rule 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. The 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, the FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that the 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 Items 1 and 2 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 Energy Policy Act of 2005, the 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 the FERC under the NGA, the FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdiction facilities to the FERC annual reporting and daily scheduled flow and capacity posting requirements. We also must comply with the anti-market manipulation rules enforced by the FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by the 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 Items 1 and 2 of this report.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation

Legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain U.S. federal income tax benefits 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, 2012, we had a tax basis of $2.0 billion related to prior years capitalized intangible drilling costs, which will be amortized over the next five years.

The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change could negatively affect our financial condition and results of operations.

In February 2012, the state legislature of Pennsylvania passed a new natural gas impact fee in Pennsylvania, where the majority of our acreage in the Marcellus Shale is located. The legislation imposes an annual fee on natural gas and oil operators for each well drilled for a period of fifteen years. The fee is on a sliding scale set by the Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average NYMEX natural gas prices from the last day of each month. The passage of this legislation increases the financial burden on our operations in the Marcellus Shale.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions or delays and adversely affect our production

Hydraulic fracturing involves the injection of water, sand and small amounts of additives under pressure into rock formations to stimulate hydrocarbon (natural gas and oil) 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 Marcellus Shale. The process is typically regulated by state oil and gas commissions. However, the EPA, recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program and published a draft of permitting guidance in May 2012 addressing the performance of such activities. There are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices and the EPA has commenced a study of potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a first progress report outlining work currently underway by the agency released on December 21, 2012 and a final report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review by 2014. In addition, the EPA announced that it is launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. Also, the U.S. Department of Energy has conducted an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods and in August 2011, issued a report on immediate and longer term actions that may be taken to reduce environmental a safety risks of shale gas development while the U.S. Department of the Interior has proposed disclosure, well testing and monitoring requirements for hydraulic fracturing on federal lands. At the same time, legislation has been introduced before Congress from time to time to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process but none of this legislation was adopted. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. For example, Texas, Pennsylvania, Colorado, West Virginia and Wyoming have each adopted a variety of well construction, set back, or disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements and also to possible permitting delays and potential increases in costs that could have an adverse effect on our level of production.

Our business depends on natural gas and oil transportation and NGLs processing facilities, most of which are owned by others and depends on our ability to contract with those parties

Our ability to sell our natural gas, NGLs and oil production depends in part on the availability, proximity and capacity of pipeline systems and processing facilities owned by third parties and our ability to contract with those 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. In some cases, we do not purchase firm transportation on third party facilities and therefore, our production transportation can be interrupted by those having firm arrangements. We have entered into long-term agreements with third parties to provide natural gas gathering and processing services in the Marcellus Shale. However, in some cases, the capacity of gathering systems and transportation pipelines may be

insufficient to accommodate potential production from existing and new wells. Federal and state regulation of natural gas and oil 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 natural gas, NGLs and oil. If any of these third party pipelines and other facilities become partially or fully unavailable to transport or process 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. In particular, the disruption of certain third-party natural gas processing facilities in the Marcellus Shale could materially affect our ability to market and deliver natural gas production in that area. We have no control over when or if such facilities are restored and generally have no control over 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.

Currently, there is little demand, or facilities to supply the existing demand, for ethane in the Appalachian region so, for our Appalachian production volumes, ethane remains in the natural gas stream. We currently have waivers from two transmission pipelines that allow us to leave ethane in the residue natural gas. We believe the limits are sufficient to cover our production through 2014. We have announced three ethane agreements where we have contracted to either sell or transport ethane from our Marcellus Shale area, expected to begin operations in mid to late 2013, early 2014 and early 2015. We cannot assure you that these facilities will become available. If we are not able to sell ethane in 2014, we may be required to curtail production which will adversely affect our revenues.

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.

We may be unable to dispose of nonstrategic assets on attractive terms, and may be required to retain liabilities for certain matters

We regularly review our property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect the ability us to dispose of nonstrategic assets or complete announced dispositions, including the availability of purchasers willing to purchase the nonstrategic assets at prices acceptable to us. Sellers typically retain certain liabilities buyers for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

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 remains strong. 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.

We have limited control over the activities on properties we do not operate

Other companies operate some of the properties in which we have an interest. We operate approximately 89% of our wells, as of December 31, 2012. We have limited ability to influence or control the operation or future development of non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisitions activities and lead to unexpected future costs.

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 business could be negatively affected by security threats, including cybersecurity threats, and other disruptions

As a natural gas and oil producer, we face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

Our financial statements are complex

Due to United States generally accepted accounting principles 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, the accounting for our deferred compensation plans and discontinued operations. 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, 2006 and 2007, we sold 48.3 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 and 2010, we issued 1.1 million 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, 2010 to December 31, 2012, the price of our common stock reported by the New York Stock Exchange ranged from a low of $32.25 per share to a high of $77.24 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 natural gas, NGLs and oil prices;

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variations in quarterly drilling, recompletions, acquisitions and operating results;

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changes in governmental regulation and/or taxation;

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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 and changes in our capital structure.

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

None.

ITEM 3.

LEGAL PROCEEDINGS

James A. Drummond and Chris Parrish v. Range Resources-Midcontinent, LLC et al.; pending in the District Court of Grady County, State of Oklahoma; Case No. CJ-2010-510

Two individuals, one a current royalty owner, filed suit against Range Resources Corporation and two of our subsidiaries, including the proper defendant Range Resources-Midcontinent, LLC, in the District Court of Grady County, Oklahoma. This suit is similar to a number of cases filed in Oklahoma asserting claims that royalty owners are entitled to payment of royalties on several different categories of alleged “deductions” applied by third parties who transport and process natural gas production. The alleged deductions include fuel used by the third party in the transportation and processing of gas; condensate removed by the third party after the point of sale, the contractually agreed natural gas liquids recovery percentages, the percentage of proceeds contracts’ contractually agreed pricing percentages and other similar alleged “deductions.” In addition to the claims made with respect to the alleged categories of deductions, the Plaintiffs in this litigation have alleged fraud and the existence of a fiduciary duty to the royalty owners to attempt to support an argument that no statute of limitations applies, and the Plaintiffs also claim that interest accrues on the alleged damages at 12% compounded annually. Thus while we cannot reasonably estimate our potential exposure at this time, the damages claimed by the Plaintiffs have been estimated by the Plaintiffs’ counsel to be in excess of $140 million. We believe Oklahoma is a “first marketable product” rule state and the current case law in Oklahoma (principally Mittelstaedt v. Santa Fe) allows operators to deduct value enhancing costs for treating, compression, and other post-production expenses incurred to increase the value of a marketable product; however, whether and when gas is a marketable product and the extent to which the deductions are permitted may be fact questions under Oklahoma law. Further, we do not typically transport and process the gas production from wells we operate in Oklahoma but instead sell the gas production to unaffiliated third parties which, in many cases, do transport and process the gas. Range maintains that the alleged “deductions” made the subject of the Plaintiffs’ claims are not deductions at all but the negotiated terms of the contracts with the third parties who buy, transport and process the gas under terms that allow Range and its royalty owners to share in the enhanced downstream value that establishes the purchase price for the production sold by us , and on which we have paid royalty. Range further believes that its production is marketable under Oklahoma law when sold to such unaffiliated third parties. The terms with respect to payment of royalties vary based on the terms of the various oil and gas leases owned by Range for its Oklahoma wells and wells it has owned and operated in Oklahoma in the past, and our subsidiary believes that it has substantially complied with its royalty payment obligations under its leases and we therefore intends to vigorously defend this litigation. On February 19, 2013, the District Court entered an order certifying a class of royalty owners as requested by the Plaintiffs and we intend to appeal the class certification order.

We are the subject of, or party to, a number of other pending or threatened legal actions and claims arising in the ordinary course of our business. While many of these matters involve inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to proceedings or claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources or future annual results of operations. We will continue to evaluate our litigation on a quarter-by-quarter basis and will establish and adjust any litigation reserves as appropriate to reflect our assessment of the then current status of litigation.

Action by the United States Environmental Protection Agency

On December 7, 2010, Region VI of the EPA issued an administrative order under the Safe Drinking Water Act against Range and our subsidiary Range Production Company. The EPA filed suit against us in January 2011 seeking to enforce the order in United States District Court for the Northern District of Texas. We filed an appeal of the December 7, 2010 order with the Fifth Circuit Court of Appeals. Effective March 29, 2012, the EPA withdrew the December 7, 2010 administrative order and the suit seeking enforcement of the order was dismissed by EPA with our concurrence. Our appeal of the December 7, 2010 order, having been mooted by the withdrawal of the order, was dismissed by us.

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market for Common Stock

Our common stock is listed on the New York Stock Exchange (“NYSE”) under the symbol “RRC.” During 2012, trading volume averaged 2.1 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.


	High		Low		Cash Dividends Declared
2011
First quarter	$	59.23	$	44.20	$	0.04
Second quarter		59.64		50.55		0.04
Third quarter		77.24		51.56		0.04
Fourth quarter		74.93		52.21		0.04

2012
First quarter	$	68.50	$	52.34	$	0.04
Second quarter		69.18		53.09		0.04
Third quarter		72.48		56.50		0.04
Fourth quarter		73.94		61.03		0.04

Between January 1, 2013 and February 22, 2013, the common stock traded at prices between $62.05 and $72.49 per share. Our senior subordinated notes are not listed on an exchange, but trade over-the-counter.

Holders of Record

On February 22, 2013, there were approximately 1,283 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 Board of Directors declared quarterly dividends of $0.04 per common share for each of the four quarters of 2012, 2011 and 2010. 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 deems relevant. Dividends on Range common stock are limited to our legally available funds. For more information, see Item 7 of this report “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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, 2012. The graph assumes that $100 was invested in the Company’s common stock and each index on December 31, 2006, and that dividends were reinvested.

LOGO


	2007		2008		2009		2010		2011		2012
Range Resources Corporation	$	100	$	67	$	98	$	89	$	122	$	124
S&P 500 Index		100		63		80		92		94		109
DJ U.S. Expl. & Prod. Index		100		60		84		98		94		100

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 AND RESERVE DATA

The following table shows selected financial information for the five years ended December 31, 2012. Significant producing property acquisitions and dispositions may affect the comparability of year-to-year financial and operating data. In the first half of 2011, we sold our Barnett Shale properties for proceeds of $889.3 million, including certain derivative contracts assumed by the buyer and these operations are reflected as discontinued operations. In the first half of 2010, we sold our Ohio properties for proceeds of $323.0 million. This information should be read in conjunction with Item 7 of this report “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our consolidated financial statements and related notes included elsewhere in this report.


	Year Ended December 31,
	2012			2011			2010			2009			2008
	(in thousands, except per share data)
Statements of Operations Data:
Natural gas, NGLs and oil sales	$	1,351,694		$	1,173,266		$	823,290		$	751,749		$	994,769
Total revenues and other income		1,457,704			1,230,642			961,397			831,095			1,108,038
Total costs and expenses		1,432,648			1,152,379			821,789			746,322			597,765
Income from continuing operations		13,002			42,706			88,698			38,980			329,093
Discontinued operations (net of tax)		—			15,320			(327,954	)		(92,850	)		21,947
Net income (loss)		13,002			58,026			(239,256	)		(53,870	)		351,040
Income from continuing operations per share:
-Basic	$	0.08		$	0.26		$	0.56		$	0.25		$	2.18
-Diluted		0.08			0.26			0.55			0.24			2.11
Net income (loss)
-Basic		0.08			0.36			(1.53	)		(0.35	)		2.32
-Diluted		0.08			0.36			(1.52	)		(0.34	)		2.25

Costs per mcfe: ^(a)
Direct operating expense	$	0.42		$	0.60		$	0.69		$	0.85		$	1.06
Production and ad valorem tax expense		0.24			0.15			0.19			0.22			0.46
General and administrative expense		0.63			0.80			1.01			1.00			0.87
Interest expense		0.61			0.66			0.65			0.65			0.60
Depletion, depreciation and amortization expense		1.62			1.80			1.98			2.32			1.98

	$	3.52		$	4.01		$	4.52		$	5.04		$	4.97

Average Daily Production:
Natural gas (mcf)		591,679			397,825			290,815			248,138			224,477
NGLs (bbls)		19,036			14,664			9,864			4,343			2,820
Oil (bbls)		7,790			5,369			5,300			6,912			8,322
Total mcfe ^(b)		752,637			518,019			381,800			315,668			291,326

Balance Sheets Data:
Current assets ^(c)	$	327,614		$	315,263		$	1,113,570		$	182,810		$	406,557
Current liabilities ^(d)		455,143			511,932			443,690			321,634			355,760
Natural gas and oil properties, net		6,096,184			5,157,566			4,084,013			3,551,635			3,466,028
Total assets		6,728,735			5,845,470			5,511,714			5,403,411			5,554,125
Bank debt		739,000			187,000			274,000			324,000			693,000
Subordinated notes		2,139,185			1,787,967			1,686,536			1,383,833			1,097,562
Stockholders’ equity ^(e)		2,357,392			2,392,420			2,223,761			2,378,589			2,451,342
Weighted average diluted shares outstanding		160,307			159,441			158,428			158,778			155,943
Cash dividends declared per common share		0.16			0.16			0.16			0.16			0.16

Statements of Cash Flows Data:
Net cash provided from operating activities	$	647,099		$	631,637		$	513,322		$	591,675		$	824,767
Net cash used in investing activities		(1,528,558	)		(547,981	)		(798,858	)		(473,807	)		(1,731,777	)
Net cash provided from (used in) financing activities		881,619			(86,412	)		287,617			(117,854	)		903,745

Proved Reserves Data ^(f) (at end of period):
Natural gas (Bcf)		4,793			4,010			3,567			2,615			2,214
NGLs (Mmbbls)		240			142			123			52			24
Oil (Mmbbls)		45			31			23			34			49
Total proved reserves (Bcfe)		6,506			5,054			4,442			3,129			2,654

^(a)	These are costs we believe fluctuate on a unit-of-production, or per mcfe basis.

^(b)	Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs and natural gas prices.

^(c)

2010 includes $877.6 million assets of discontinued operations compared to $43.5 million in 2009. 2009 includes $8.1 million deferred tax assets. 2012 includes $137.6 million of unrealized derivative assets compared to $173.9 million in 2011, $123.3 million in 2010, $21.5 million in 2009 and $221.4 million in 2008.

^(d)	2010 includes $352,000 of unrealized derivative liabilities compared to $14.5 million in 2009 and $10,000 in 2008. 2012 includes a $37.9 million deferred tax liability compared to $56.6 million in 2011, $11.8 million in 2010 and $33.0 million in 2008.

^(e)	Stockholders’ equity includes other comprehensive income (loss) of $83.9 million in 2012 compared to $156.6 million in 2011, $67.5 million in 2010, $6.4 million in 2009 and $77.5 million in 2008.

^(f)	Effective December 31, 2009, we adopted revised authoritative accounting and disclosure requirements for natural gas and oil reserves. As a result, 2008 is not on a comparable basis.

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. Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements contain words such as “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “project,” “target,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions for the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the information under Items 1 and 2. Business and Properties, Item 1A. Risk Factors, Item 6. Selected Financial Data and Item 8. Financial Statements Data in this report. Unless otherwise indicated, the information included herein relates to our continuing operations.

Overview of Our Business

We are an independent natural gas, natural gas liquids (“NGLs”) and oil company engaged in the exploration, development and acquisition of natural gas and crude oil properties in the Appalachian and Southwestern regions of the United States. We operate in one segment and 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 objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy to achieve our objective is to increase reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas, NGLs and crude oil and on our ability to economically find, develop, acquire and produce natural gas, NGLs and oil reserves. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities. Our corporate headquarters is located in Fort Worth, Texas.

Source of Our Revenues

We derive our revenues from the sale of natural gas, NGLs and oil that is produced from our properties. Revenues from product sales are a function of the volumes produced, prevailing market prices, product quality, gas Btu content and transportation costs. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Both types of agreements include transportation charges. One type of agreement is a netback agreement, under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we received from the purchaser. In the case of NGLs, we generally receive a net price from the purchaser (which is net of processing costs) and is also recorded in revenue at the net price we receive from the purchaser. Under the other type of agreement, we sell natural gas or oil at a specific delivery point, pay transportation to a third party and receive proceeds from the purchaser with no transportation deduction. In that case, we record transportation costs as transportation, gathering and compression expense. Also included in natural gas, NGLs and oil sales revenues and derivative fair value income are the effects of derivative accounting. Derivatives included in natural gas, NGLs and oil sales reflect settlements on those derivatives that qualify for hedge accounting. Cash settlements of derivative contracts that are not accounted for as hedges are included in derivative fair value income in the accompanying statements of operations. Brokered natural gas, marketing and other revenues include revenue received from brokered gas, marketing fees we receive from third parties, transportation revenue we receive from gathering lines we own and equity method investments. Discontinued operations include our Barnett Shale properties, which were sold in April 2011. Unless indicated otherwise, the information included herein relates to our continuing operations.

Principal Components of Our Cost Structure

•

Direct operating. These are day-to-day costs incurred to bring hydrocarbons out of the ground along with the daily costs incurred to maintain our producing properties. Such costs include compensation of our field employees, maintenance, repairs and workovers expenses related to our natural gas and oil properties. These costs are expected to remain a function of supply and demand. Direct operating expenses also include stock-based compensation expense (non-cash) associated with the amortization of restricted stock grants as part of the compensation of field employees.

•

Transportation, gathering and compression. Under some of our sales arrangements, we sell natural gas at a specific delivery point, pay transportation, gathering and compression costs to a third party and receive proceeds from the purchaser with no deduction. These costs represent those transportation, gathering and compression costs paid by Range to third parties.

•

Production and ad valorem taxes. Production taxes are paid on produced natural gas and oil based on a percentage of market prices (not hedged prices) or at fixed rates established by the applicable federal, state or local taxing authorities. Ad valorem taxes are generally based on reserve values at the end of each year. The new Pennsylvania impact fee on unconventional natural gas and oil production, which includes the Marcellus Shale, is also included in this category.

•

Brokered natural gas and marketing. These are gas purchase costs for brokered gas and overhead, including payroll and benefits for our marketing staff. Brokered natural gas and marketing also includes stock-based compensation expense (non-cash) associated with the amortization of restricted stock and stock appreciation rights granted as part of our marketing staff compensation.

•

Exploration. 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 also includes stock-based compensation expense (non-cash) associated with the amortization of grants of stock appreciation rights (“SARs”) and restricted stock as part of the compensation of our exploration staff.

•

Abandonment and impairment of unproved properties. This category includes unproved property impairment and expenses associated with lease expirations.

•

General and administrative. 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. Included in this category are overhead expense reimbursements we receive from working interest owners of properties, for which we serve as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life. General and administrative expense also includes stock-based compensation expense (non-cash) associated with grants of SARs and the amortization of restricted stock grants as part of the compensation of our corporate staff.

•

Deferred compensation plan. These costs relate to the increase or decrease in the value of the liability associated with our deferred compensation plan. Our 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 our common stock or make other investments at the individual’s discretion. The assets of this plan are held in a grantor trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency.

•

Interest expense. We typically finance a portion of our cash requirements with borrowings under our bank credit facility and with 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. We currently have no capitalized interest.

•

Depreciation, depletion and amortization. This includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas, NGLs 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.

•

Income taxes. We are subject to state and federal income taxes but are currently not in a cash taxpaying position for federal income taxes, primarily due to the current deductibility and/or faster amortization of intangible drilling costs (“IDC”). At this time, we generally do not pay significant state income taxes due to our state net operating loss carryovers and our ability to follow the federal treatment of deducting IDC in most of the states in which we operate. Currently, substantially all of our federal taxes are deferred and we anticipate using all of our federal net operating loss carryforwards. As of December 31, 2012, we have a $2.0 million valuation allowance on our Pennsylvania net operating loss carryforward due to limitations on utilizing loss carryforwards under Pennsylvania law. For additional information, see “Risk Factors-Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation,” in Item 1A of this report.

Management’s Discussion and Analysis of Results of Operations

Overview of 2012 Results

During 2012, we achieved the following financial and operating results:

•

achieved 45% production growth;

•

achieved 29% proved reserve growth;

•

drilled 256.7 net wells with a 100% success rate;

•

continued expansion of our activities in the Marcellus Shale by growing production, proving up acreage and acquiring additional unproved acreage;

•

reduced direct operating expenses per mcfe 30%;

•

reduced our DD&A rate 10%;

•

continued to focus on financial flexibility by issuing $600.0 million of new 10-year senior subordinated notes, increased our facility amount under our bank credit facility from $1.5 billion to $1.75 billion and achieved a debt per mcfe of proved reserves of $0.44;

•

redeemed all $250.0 million aggregate principal amount of our 7.5% senior subordinated notes due 2017;

•

entered into additional commodity-based derivative contracts for 2013 and 2014;

•

received $135.0 million of proceeds from the sale of our Southern Oklahoma properties and $33.2 million of proceeds from the sale of other assets;

•

realized $647.1 million of cash flow from operating activities;

•

ended the year with stockholders’ equity of $2.4 billion;

•

began transporting propane by rail to Philadelphia for sales to domestic and international customers;

•

entered into a fifteen year contract to transport ethane and propane to terminal/dock facilities near Philadelphia; and

•

entered into a fifteen year ethane sales agreement for delivery at the terminal/dock facilities near Philadelphia.

Operationally, our 2012 performance reflects another year of successfully executing our strategy of growth through drilling. Our success enabled us to increase proved reserves by approximately 1.5 Tcfe, which is more than five times 2012 production. As evidenced by history, the prices to sell our production is volatile and we have no control over them. Therefore, to improve our profitability, we focus our efforts on improving operating efficiency. As reservoirs are depleted and production rates decline, per unit production costs will generally increase. To lessen this effect, we concentrate our production in core areas where we can achieve economies of scale to help manage our operating costs. Our drilling of high quality Marcellus wells has resulted in significantly lower direct operating expense on a per mcfe basis for 2012 when compared to 2011 and 2010.

Acquisitions

During 2012, we spent $188.8 million to acquire unproved acreage compared to $220.6 million in 2011 and $151.6 million in 2010. We continue selective acreage leasing to add to our acreage positions primarily in the Marcellus Shale play in Pennsylvania and the Mississippian play in Oklahoma and Kansas. Also in 2010, we purchased proved and unproved natural gas properties in Virginia for $134.5 million.

Divestitures and Discontinued Operations

Texas. In March 2012, we sold seventy-five percent of a prospect in East Texas which included unproved properties and a suspended exploratory well to a third party for proceeds of $8.6 million and recorded a pre-tax loss of $10.9 million.

In February 2011, we committed to a plan to sell substantially all of our Barnett Shale properties located in North Central Texas. While our Barnett properties did not meet held for sale criteria at December 31, 2010, the undiscounted cash flows for these properties were less than the carrying value so we recognized an impairment charge of $463.2 million in fourth quarter 2010. In April and August 2011, we sold these assets for gross cash proceeds of $889.3 million, including certain derivative contracts assumed by the buyer. The results of operations for these properties are reported as discontinued operations, net of tax for the years ended December 31, 2011 and 2010. We recorded a pretax gain of $4.8 million in the year ended December 31, 2011 in discontinued operations related to this sale.

In December 2012, we announced our plan to offer for sale certain of our Permian and Delaware Basin properties in West Texas and Southeast New Mexico. The data room opened in early January 2013 and on February 26, 2013 we announced we have signed a definitive agreement to sell these assets for a price of $275.0 million, subject to normal post-closing adjustments. The completion of the sale is dependent upon customary buyer due diligence procedures and there can be no assurance the sale will be completed or that there will not be changes to the sales price.

Southern Oklahoma. In November 2012, we sold certain oil and gas properties in Southern Oklahoma to a third party for gross proceeds of $135.0 million, which resulted in a pretax gain of $55.2 million in the year ended December 31, 2012.

Pennsylvania. In fourth quarter 2011, we exchanged unproved property in Ohio for unproved property in Pennsylvania where we received $11.5 million in cash as part of the transaction and recorded a pretax gain of $4.5 million in the year ended December 31, 2011. We recorded an additional $6.8 million gain related to this exchange in the year ended December 31, 2012.

In April and September 2012, we sold unproved properties for proceeds of $15.5 million and recorded a pre-tax gain of $1.2 million. In June 2012, we sold a suspended exploratory well in the Marcellus Shale for proceeds of $2.5 million and recorded a pre-tax loss of $2.5 million on this transaction.

Ohio. In the first six months 2010, we sold our tight gas sand properties in Ohio for proceeds of $323.0 million which resulted in a pretax gain of $77.6 million in the year ended December 21, 2010.

2013 Outlook

For 2013, the board of directors approved a $1.3 billion capital budget for natural gas, NGLs and oil related activities, excluding proved property acquisitions, for which we do not budget. We expect to fund our 2013 capital budget expenditures with cash flows from operations, proceeds from asset sales and borrowings under our bank credit facility as necessary. 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. To the extent our capital requirements exceed our internally generated cash flow, proceeds from asset sales and our committed capacity under our bank credit facility, debt or equity may be issued to fund these requirements. The price risk on a portion of our forecasted natural gas, NGLs and oil production for 2013 is mitigated using commodity derivative contracts and we intend to continue to enter into these transactions. The prices we receive for our natural gas, NGLs and oil production are largely based on current market prices, which are beyond our control.

Market Conditions

Prices for various quantities of natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Prices for commodities, such as hydrocarbons, are inherently volatile. The following table lists average NYMEX prices for natural gas and oil for the year ended December 31, 2012, 2011 and 2010.


	Year Ended December 31,
	2012		2011		2010
Average NYMEX prices ^(a)
Natural gas (per mcf)	$	2.82	$	4.02	$	4.39
Oil (per bbl)	$	93.36	$	95.24	$	79.59

^(a)	Based on average of bid week prompt month prices.

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

Our revenues vary from year to year as a result of changes in realized commodity prices and production volumes. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Natural gas, NGLs and oil sales include netback arrangements where we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, record revenue at the price we receive from the purchaser. Revenues also include arrangements where we sell natural gas or oil at a specific delivery point and receive proceeds from the purchaser with no transportation deduction. Third party transportation costs we incur to get our commodity to the delivery point are reported in transportation, gathering and compression expense. Hedges included in natural gas, NGLs and oil sales reflect settlements on those derivatives that qualify for hedge accounting. Cash settlements of derivative contracts that are not accounted for as hedges are included in derivative fair value income in the accompanying statements of operations. In 2012, natural gas, NGLs and oil sales increased 15% from 2011 with a 45% increase in production partially offset by a 21% decrease in realized prices. In 2011, natural gas, NGLs and oil sales increased 43% from 2010 with a 36% increase in production and a 5% increase in realized prices. The following table illustrates the primary components of natural gas, NGLs and oil sales for each of the last three years (in thousands):


	2012			2011		2010
Natural gas, NGLs and oil sales
Gas wellhead	$	612,354		$	611,864	$	481,564
Gas hedges realized		238,259			123,595		64,749

Total gas revenue	$	850,613		$	735,459	$	546,313

Total NGLs revenue	$	265,072		$	268,846	$	143,132

Oil wellhead	$	237,963		$	168,961	$	133,822
Oil hedges realized		(1,954	)		—		23

Total oil revenue	$	236,009		$	168,961	$	133,845

Combined wellhead	$	1,115,389		$	1,049,671	$	758,518
Combined hedges		236,305			123,595		64,772

Total natural gas, NGLs and oil sales	$	1,351,694		$	1,173,266	$	823,290

Our production continues to grow through drilling success as we place new wells on production and through additions from acquisitions partially offset by the natural decline of our natural gas and oil reserves through production and asset sales. For 2012, our production volumes increased 59% in our Appalachian region and increased 5% in our Southwestern region when compared to 2011. For 2011, our production volumes increased 53% in our Appalachian region and declined 1% in our Southwestern region when compared to 2010. Our production for each of the last three years is set forth in the following table:


	2012		2011		2010
Production ^(a)
Natural gas (mcf)		216,554,689		145,206,124		106,147,511
NGLs (bbls)		6,967,114		5,352,181		3,600,469
Crude oil (bbls)		2,851,312		1,959,608		1,934,417
Total (mcfe) ^(b)		275,465,245		189,076,858		139,356,832

Average daily production ^(a)
Natural gas (mcf)		591,679		397,825		290,815
NGLs (bbls)		19,036		14,664		9,864
Crude oil (bbls)		7,790		5,369		5,300
Total (mcfe) ^(b)		752,637		518,019		381,800

^(a)	Represents volumes sold regardless of when produced.

^(b)	Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil and natural gas, which is not indicative of the relationship of oil, NGLs and natural gas prices.

Our average realized price (including all derivative settlements and third-party transportation costs) received during 2012 was $4.35 per mcfe compared to $5.68 per mcfe in 2011 and $5.71 per mcfe in 2010. Because we record transportation costs on two separate bases, as required by GAAP, we believe computed final realized prices should include the impact of transportation, gathering and compression expense. Our average realized price (including all derivative settlements and third-party transportation costs) calculation also includes all cash settlements for derivatives, whether or not they qualify for hedge accounting, except for the year ended December 31, 2010, in which we excluded from average realized price calculations a $15.7 million gain related to an early settlement of oil collars. Average sales prices (wellhead) do not include any derivative settlements or third party transportation costs which are reported in transportation, gathering and compression expense on the accompanying statements of operations. Average sales prices (wellhead) do include transportation costs where we receive net proceeds. Average realized price calculations for each of the last three years are shown below:


	2012		2011		2010
Average Prices
Average sales prices (wellhead):
Natural gas (per mcf)	$	2.83	$	4.21	$	4.54
NGLs (per bbl)		38.05		50.23		39.75
Crude oil (per bbl)		83.46		86.22		69.18
Total (per mcfe) ^(a)		4.05		5.55		5.44

Average realized prices (including derivatives that qualify for hedge accounting):
Natural gas (per mcf)		3.93		5.06		5.15
NGLs (per bbl)		38.05		50.23		39.75
Crude oil (per bbl)		82.77		86.22		69.19
Total (per mcfe) ^(a)		4.91		6.21		5.91

Average realized prices (including all derivative settlements)
Natural gas (per mcf)		3.95		5.22		5.48
NGLs (per bbl)		42.60		52.03		39.75
Crude oil (per bbl)		83.64		81.34		69.19
Total (per mcfe) ^(a)		5.05		6.32		6.16

Average realized prices (including all derivative settlements and third party transportation costs paid by Range):
Natural gas (per mcf)		3.11		4.43		4.89
NGLs (per bbl)		41.03		50.82		39.75
Crude oil (per bbl)		83.64		81.34		69.19
Total (per mcfe) ^(a)		4.35		5.68		5.71

^(a)	Oil and NGLs are converted at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship of oil, NGLs and natural gas prices.

Derivative fair value income was $41.4 million in 2012 compared to $40.1 million in 2011 and to $51.6 million in 2010. 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 in the accompanying consolidated statements of operations. Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues. At December 31, 2012, all of our derivative contracts were recorded at their fair value, which was a net asset of $144.3 million, a decrease of $107.0 million from the $251.3 million net asset recorded as of December 31, 2011. 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, are marked to market and were a net asset of $993,000 as of December 31, 2012. Hedge ineffectiveness, also included in derivative fair value income, is associated with contracts that qualify for hedge accounting. The ineffective portion is calculated as the difference between the changes in the fair value of the derivative and the estimated change in future cash flows from the item being hedged.

The following table presents information about the components of derivative fair value income for each of the years in the three-year period ended December 31, 2012 (in thousands):


	2012			2011			2010
Change in fair value of derivatives that do not qualify for hedge accounting^(a)	$	5,958		$	15,762		$	(2,086	)
Realized gain (loss) on settlements – natural gas ^{(b) (c)}		131			14,743			35,988
Realized gain (loss) on settlements – oil ^{(b) (c)}		2,486			(9,574	)		—
Realized gain (loss) on settlements – NGLs ^{(b) (c)}		31,737			9,612			—
Realized gain on early settlement of oil derivatives ^(d)		—			—			15,697
Hedge ineffectiveness – realized ^(c)		4,346			7,361			(352	)
– unrealized ^(a)		(3,221	)		2,183			2,387

Derivative fair value income	$	41,437		$	40,087		$	51,634

^(a)	These amounts are unrealized and are not included in average realized 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 and third party transportation costs paid by Range).

^(d)	This early settlement is not included in average realized price calculations.

Gain on the sale of assets was $49.1 million in 2012 compared to $2.3 million in 2011 and $76.6 million in 2010. During 2012, we sold our Ardmore Woodford properties in Southern Oklahoma for proceeds of approximately $135.0 million and recorded a gain of $55.2 million. In addition, in 2012 we recorded a $10.9 million pre-tax loss on the sale of seventy-five percent of an East Texas prospect for proceeds of $8.6 million and an additional $6.8 million gain related to a 2011 unproved acreage transaction. During 2011, we exchanged unproved property in Ohio for unproved property in Pennsylvania and recorded a gain of $4.5 million, which is offset by a $1.7 million loss on sale of certain derivatives assumed by the buyer of our Barnett Shale properties. During 2010, we sold our tight gas sand properties in Ohio for proceeds of approximately $323.0 million and recorded a gain of $77.6 million.

Brokered natural gas, marketing and other revenue was $15.4 million in 2012 compared to $15.0 million in 2011 and $9.8 million in 2010. The 2012 period includes revenue from marketing and the sale of brokered gas of $15.1 million. The 2011 period includes revenue from marketing and the sale of brokered gas of $12.7 million and proceeds from a lawsuit settlement and other income partially offset by a loss from equity method investments of $1.0 million. The 2010 period includes revenue from marketing and the sale of brokered gas of $10.8 million and proceeds of $486,000 from a lawsuit settlement partially offset by a loss from equity method investments of $1.5 million.

Costs and Expenses

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 2012, 2011 and 2010.


	Year Ended December 31,										Year Ended December 31,
	2012		2011		Change			% Change			2011		2010		Change			% Change
Direct operating expense	$	0.42	$	0.60	$	(0.18	)		(30	%)	$	0.60	$	0.69	$	(0.09	)		(13	%)
Production and ad valorem tax expense		0.24		0.15		0.09			60	%		0.15		0.19		(0.04	)		(21	%)
General and administrative expense		0.63		0.80		(0.17	)		(21	%)		0.80		1.01		(0.21	)		(21	%)
Interest expense		0.61		0.66		(0.05	)		(8	%)		0.66		0.65		0.01			2	%
Depletion, depreciation and amortization expense		1.62		1.80		(0.18	)		(10	%)		1.80		1.98		(0.18	)		(9	%)

Direct operating expense was $115.9 million in 2012 compared to $113.0 million in 2011 and $96.3 million in 2010. We experience increases in operating expenses as we add new wells and manage existing properties. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring workovers and repairs. On an absolute basis, our spending for direct operating expenses for 2012 increased 3% from the same period of the prior year with an increase in producing wells offset by lower costs for water hauling and disposal, equipment rental and well services. On an absolute basis, our spending for direct operating expenses for 2011 increased 17% from the same period of 2010 due to an increase in the number of producing wells. We incurred $4.8 million of workover costs in 2012 compared to $3.6 million of workover costs in 2011 and $3.4 million in 2010.

On a per mcfe basis, operating expense for 2012 decreased $0.18 or 30% from the same period of 2011, with the decrease consisting of lower costs for water hauling and disposal, lower equipment rental and well services. On a per mcfe basis, operating expense for 2011 decreased $0.09 or 13% from the same period of 2010, with the decrease consisting of lower well service costs. We expect to continue to experience lower costs per mcfe as we increase production from our Marcellus Shale wells due to their lower operations cost relative to our other operating areas somewhat offset by higher operating costs on our liquids-rich wells. Operating costs in the Mississippian play are higher on a per mcfe basis than the Marcellus Shale play. Stock-based compensation expense represents the amortization of restricted stock as part of the compensation of field employees. The following table summarizes direct operating expenses per mcfe for 2012, 2011 and 2010:


	Year Ended December 31,										Year Ended December 31,
	2012		2011		Change			% Change			2011		2010		Change			% Change
Lease operating expense	$	0.39	$	0.57	$	(0.18	)		(32	%)	$	0.57	$	0.66	$	(0.09	)		(14	%)
Workovers		0.02		0.02		—			—	%		0.02		0.02		—			—	%
Stock-based compensation (non-cash)		0.01		0.01		—			—	%		0.01		0.01		—			—	%

Total direct operating expenses	$	0.42	$	0.60	$	(0.18	)		(30	%)	$	0.60	$	0.69	$	(0.09	)		(13	%)

Production and ad valorem taxes are paid based on market prices, not hedged prices. This expense category also includes the new Pennsylvania impact fee. In February 2012, the Commonwealth of Pennsylvania enacted an “impact fee” on unconventional natural gas and oil production which includes the Marcellus Shale. The year ended 2012 includes a $25.2 million ($0.09 per mcfe) retroactive impact fee which covers all wells drilled prior to 2012 and was paid in September 2012. Also included in the year ended 2012 is a $24.0 million ($0.09 per mcfe) impact fee for wells drilled prior to 2012 and wells drilled in 2012 which will be paid in April 2013. Production and ad valorem taxes (excluding the impact fee) were $17.9 million in 2012 compared to $27.7 million in 2011 and $26.1 million in 2010. On a per mcfe basis, production and ad valorem taxes (excluding the impact fee) decreased to $0.06 in 2012 compared to $0.15 in 2011 due to an increase in production volumes not subject to production or ad valorem taxes. On a per mcfe basis, production and ad valorem taxes decreased to $0.15 in 2011 from $0.19 in 2010 due to an increase in production volumes not subject to production or ad valorem taxes.

General and administrative expense was $173.8 million for 2012 compared to $151.2 million for 2011 and $140.6 million in 2010. The 2012 increase of $22.6 million when compared to 2011 is due to higher salaries and benefits ($11.0 million), an increase in stock-based compensation ($8.3 million) and higher legal and office expenses, including information technology. The 2011 increase of $10.6 million when compared to 2010 is due to higher salaries and benefits ($9.3 million), an increase in stock-based compensation ($2.1 million), an increase in legal fees ($1.4 million) somewhat offset by lower bad debt expense. Our number of employees increased 9% during 2012. 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 and the Mississippian play in Oklahoma. Stock-based compensation expense represents the amortization of restricted stock grants and SARs granted to our employees and directors as part of compensation. The following table summarizes general and administrative expenses per mcfe for 2012, 2011 and 2010:


	Year Ended December 31,										Year Ended December 31,
	2012		2011		Change			% Change			2011		2010		Change			% Change
General and administrative	$	0.47	$	0.61	$	(0.14	)		(23	%)	$	0.61	$	0.76	$	(0.15	)		(20	%)
Stock-based compensation (non-cash)		0.16		0.19		(0.03	)		(16	%)		0.19		0.25		(0.06	)		(24	%)

Total general and administrative expenses	$	0.63	$	0.80	$	(0.17	)		(21	%)	$	0.80	$	1.01	$	(0.21	)		(21	%)

Interest expense was $168.8 million for 2012 compared to $125.1 million for 2011 and $90.7 million in 2010. The following table presents information about interest expense for each of the years in the three-year period ended December 31, 2012 (in thousands):


	2012		2011			2010
Bank credit facility	$	11,822	$	8,856		$	11,420
Subordinated notes		147,552		123,721			111,892
Other		9,424		7,266			7,880
Allocated to discontinued operations		—		(14,791	)		(40,527	)

Total interest expense	$	168,798	$	125,052		$	90,665

The increase in interest expense for 2012 from the same period of 2011 was due to higher interest rates and outstanding debt balances. The increase in interest expense for 2011 from the same period of 2010 was due to an increase in outstanding debt balances. In March 2012, we issued $600.0 million of 5.0% senior subordinated notes due 2022. We used the proceeds for general corporate purposes and to retire outstanding balances on our bank debt which carries a lower interest rate. In May 2011, we issued $500.0 million of 5.75% senior subordinated notes due 2021. We used the proceeds for general corporate purposes and to purchase or redeem $150.0 million of our 6.375% senior subordinated notes due 2015 and $250.0 million of our 7.5% senior subordinated notes due 2016. In August 2010, we issued $500.0 million of 6.75% senior subordinated notes due 2020. The proceeds from this issuance were used to retire bank debt which carried a lower interest rate and to redeem all $200.0 million of our 7.375% senior subordinated notes due 2013. The 2012, 2011 and 2010 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 2012 was $308.0 million compared to $175.6 million for 2011 and $351.1 million for 2010 and the weighted average interest rate on the bank credit facility was 2.2% in each of the years ended December 31, 2012, 2011 and 2010.

Depletion, depreciation and amortization (“DD&A”) was $445.2 million in 2012 compared to $341.2 million in 2011 and $275.2 million in 2010. The increase in 2012 when compared to 2011 is due to a 9% decrease in depletion rates more than offset by a 45% increase in production. The increase in 2011 when compared to 2010 is due to a 7% decrease in depletion rates more than offset by a 36% increase in production.

On a per mcfe basis, DD&A decreased to $1.62 in 2012 compared to $1.80 in 2011 and $1.98 in 2010. Depletion expense, the largest component of DD&A, was $1.54 per mcfe in 2012 compared to $1.69 per mcfe in 2011 and $1.82 per mcfe in 2010. 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. We currently expect our DD&A rate to be approximately $1.50 per mcfe in 2013, based on our current production estimates. In areas where we are actively drilling, such as the Marcellus area, our fourth quarter adjusted 2012 depletion rates were lower than the fourth quarter 2011 and 2010 depletion rates. 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 decrease in the DD&A per mcfe in 2012 when compared to 2011 is due to lower depreciation expense and the mix of our production. The decrease in the DD&A per mcfe in 2011 when compared to 2010 is due to lower depreciation expense and the mix of our production.


	Year Ended December 31,										Year Ended December 31,
	2012		2011		Change			% Change			2011		2010		Change			% Change
Depletion and amortization	$	1.54	$	1.69	$	(0.15	)		(9	%)	$	1.69	$	1.82	$	(0.13	)		(7	%)
Depreciation		0.05		0.08		(0.03	)		(38	%)		0.08		0.12		(0.04	)		(33	%)
Accretion and other		0.03		0.03		—			—	%		0.03		0.04		(0.01	)		(25	%)

Total DD&A expense	$	1.62	$	1.80	$	(0.18	)		(10	%)	$	1.80	$	1.98	$	(0.18	)		(9	%)

Other Operating Expenses

Our total operating expenses also include other expenses that generally do not trend with production. These expenses include stock-based compensation, transportation, gathering and compression, brokered natural gas and marketing, exploration expense, abandonment and impairment of unproved properties, termination costs, deferred compensation plan expenses and loss on early extinguishment of debt. In 2012, stock based compensation was a component of direct operating expense ($2.4 million), brokered natural gas and marketing ($1.8 million), exploration expense ($4.1 million) and general and administrative expense ($44.5 million) for a total of $52.8 million. In 2011, stock-based compensation was a component of direct operating expense ($2.0 million), brokered natural gas and marketing ($1.5 million), exploration expense ($4.1 million) and general and administrative expense ($36.2 million) for a total of $43.8 million. In 2010, stock-based compensation was a component of direct operating expense ($2.0 million), brokered natural gas and marketing ($1.2 million), exploration expense ($4.2 million) and general and administrative expense ($34.2 million) and termination costs ($2.8 million) for a total of $44.4 million. Stock-based compensation includes the amortization of restricted stock grants and SARs grants. This amortization increased from 2011 to 2012 due to accelerated expense for employee retirements and an increase in our employee base and their allocated stock-based grant.

Transportation, gathering and compression expense was $192.4 million in 2012 compared to $120.8 million in 2011 and $62.8 million in 2010. These third party costs are higher in each year due to our production growth in the Marcellus Shale where we have third party gathering and compression agreements. We have included these costs in the calculation of average realized prices (including all derivative settlements and third party transportation expenses paid by Range).

Brokered natural gas and marketing was $20.4 million in 2012 compared to $12.0 million in 2011 and $9.8 million in 2010. The increase in 2012 from 2011 is primarily due to an increase the brokered natural gas purchases. Stock-based compensation included here represents the amortization of restricted stock and SARs as part of the compensation of our marketing staff.

Exploration expense was $69.8 million in 2012 compared to $81.4 million in 2011 and $60.5 million in 2010. Exploration expense was lower in 2012 when compared to 2011 due to lower seismic and dry hole costs. Exploration expense was significantly higher in 2011 when compared to 2010 due to higher seismic and personnel costs. Stock-based compensation represents the amortization of restricted stock and SARs as part of the compensation of our exploration staff. The following table details our exploration related expenses for 2012, 2011 and 2010 (in thousands):


	Year Ended December 31,										Year Ended December 31,
	2012		2011		Change			% Change			2011		2010		Change			% Change
Seismic	$	33,462	$	40,672	$	(7,210	)		(18	%)	$	40,672	$	22,393	$	18,279			82	%
Delay rentals and other		18,286		19,282		(996	)		(5	%)		19,282		19,075		207			1	%
Personnel expense		13,168		13,417		(249	)		(2	%)		13,417		11,129		2,288			21	%
Stock-based compensation expense		4,049		4,108		(59	)		(1	%)		4,108		4,209		(101	)		(2	%)
Dry hole expense		842		3,888		(3,046	)		(78	%)		3,888		3,700		188			5	%

Total exploration expense	$	69,807	$	81,367	$	(11,560	)		(14	%)	$	81,367	$	60,506	$	20,861			34	%

Abandonment and impairment of unproved properties was $125.3 million in 2012 compared to $79.7 million in 2011 and $49.7 million in 2010. We assess individually significant unproved properties for impairment on a quarterly basis and recognize a loss where circumstances indicate impairment in value. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable activity on the property being evaluated and/or adjacent properties, our geologists’ evaluation of the property and the remaining months in the lease term for the property. Impairment of individually insignificant unproved properties is assessed and amortized on an aggregate basis based on our average holding period, expected forfeiture rate and anticipated drilling success. 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. In third quarter 2012, we impaired individually significant unproved properties in the Barnett Shale of North Texas (the last of our unproved properties in the area) for $19.6 million because we chose to not develop the acreage. Also, due to an unproved property transaction in second quarter 2012, we impaired individually significant unproved properties in Pennsylvania for $23.1 million because we will not drill in these areas. The increase from 2010 to 2011 is primarily related to our Marcellus Shale operations and is due, in part, to lower natural gas prices and plans to move towards areas with higher expectations of wet gas.

Termination costs in 2010 includes severance costs of $5.1 million related to the sale of our Ohio properties and $2.8 million of non-cash stock-based compensation expense related to the accelerated vesting of SARs and restricted stock as part of the severance agreement for our Ohio personnel.

Deferred compensation plan expense was a loss of $7.2 million in 2012 compared to a loss of $43.2 million in 2011 and a gain of $10.2 million in 2010. Our stock price increased to $62.83 at December 31, 2012 compared to $61.94 at December 31, 2011. Our stock price increased to $61.94 at December 31, 2011 compared to $44.98 at December 31, 2010. This non-cash item 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.

Loss on early extinguishment of debt was $11.1 million in 2012 compared to $18.6 million in 2011 and $5.4 million in 2010. In December 2012, we redeemed our 7.5% senior subordinated notes due 2017 at a redemption price equal to 103.75%. We recorded a loss on extinguishment of debt of $11.1 million including call premium costs of $9.4 million and expensing of related deferred financing costs on the redeemed debt. In May and June 2011, we purchased or redeemed our 6.375% senior subordinated notes due 2015 at a price equal to 102.31% and we purchased or redeemed our 7.5% senior subordinated notes due 2016 at a price equal to 103.95%. We recorded a loss on extinguishment of debt of $18.6 million, which includes a call premium and other consideration of $13.3 million and expensing of related deferred financing costs on the repurchased debt. In August 2010, we redeemed our 7.375% senior subordinated notes due 2013 at a redemption price equal to 101.229%. We recorded a loss on extinguishment of debt of $5.4 million, which includes call premium costs of $2.5 million and expensing of related deferred financing costs on the redeemed debt.

Impairment of proved properties decreased to $35.6 million in 2012 compared to $38.7 million in 2011 and $6.5 million in 2010. The year ended 2012 includes a $31.1 million impairment related to our Mississippi properties, $3.2 million related to our remaining North Texas assets and $1.3 million related to surface acreage, also in North Texas. The year ended 2011 includes a $31.2 million impairment related to our East Texas properties and $7.5 million related to our Gulf Coast onshore properties. Our analysis of these properties determined that undiscounted cash flows were less than their carrying value. We compared the carrying value to estimated fair value and recognized an impairment charge. These assets were evaluated for impairment due to declining reserves and natural gas prices and, in the case of certain of our North Texas and East Texas properties, the possibility of a sale. The year ended 2010 includes a $6.5 million impairment related to our onshore Gulf Coast properties. In 2010, these assets were reviewed for impairment due to declining reserves and natural gas prices.

Income tax expense was $12.1 million compared to $35.6 million in 2011 and $50.9 million in 2010. The 2012 decrease in income taxes reflects a 68% decrease in income from continuing operations when compared to the same period of 2011. The 2011 decrease in income taxes reflects a 44% decrease in income from continuing operations when compared to the same period of 2010. The effective tax rate was 48.1% in 2012 compared to 45.4% in 2011 and 36.5% in 2010. For the year ended December 31, 2012 the current income tax benefit of $1.8 million is related to state income taxes and includes favorable adjustments to reflect state income tax returns as filed. For the year ended December 31, 2011, the current income tax expense of $637,000 is related to state income taxes. The 2012 and 2011 effective tax rate was different than the statutory tax rate due to state income taxes, an increase in our valuation allowances related to our deferred tax asset for future deferred compensation plan distributions of senior executives to the extent their estimated future compensation (including these distributions) would exceed the $1.0 million deductible limit provided under section 162(m) of the Internal Revenue Code and for 2012, a $2.0 million valuation allowance related to Pennsylvania state net operating loss carryforwards. The year ended December 31, 2012 includes $736,000 deferred tax benefit related to changing state income apportionment rates. The year ended December 31, 2011 also included a favorable adjustment of $3.9 million to reflect updated state tax rates used to establish deferred taxes due to a change in our state apportionment factors. The 2010 effective tax rate was different than the statutory rate of 35% due to an increase in our valuation allowances related to our deferred tax asset for future deferred compensation plan distributions in excess of the $1.0 million deductible limit provided under section 162(m) of the Internal Revenue Code. For the year ended December 31, 2010, the current income tax benefit of $836,000 is related to state income taxes. We expect our effective tax rate to be approximately 40% for 2013, before any discrete tax items.

Discontinued operations include the operating results and impairment losses related to our Barnett properties. Substantially all of these properties were sold in April 2011 for proceeds of $889.3 million including certain derivatives assumed by the buyer and we recorded a gain of $4.8 million on the sale. Discontinued operations in 2011 was income of $15.3 million compared to a loss of $328.0 million in 2010. The year ended 2010 includes an impairment charge of $463.2 million. While these properties did not meet held for sale criteria as of December 31, 2010, our analysis determined that undiscounted cash flows for these properties were less than their carrying value. Therefore, we compared the carrying value to estimated fair value and recognized an impairment charge. See also Note 4 to the accompanying financial statements. Interest expense is allocated to discontinued operations based on the ratio of net assets of discontinued operations to our consolidated net assets plus long-term debt.

Management’s Discussion and Analysis of Financial Condition, Cash Flows, Capital Resources and Liquidity

Cash Flows

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 (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 a large portion of our production at the wellhead under floating market contracts. From time to time, we enter into various derivative contracts to provide an economic hedge of our exposure to commodity price risk associated with anticipated future natural gas, NGLs and oil production. The production we hedge has and will continue to vary from year to year depending on, among other things, our expectation of future commodity prices. As of December 31, 2012, we have hedged approximately 68% of our projected 2013 production. 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 borrowings under the bank credit facility. As of December 31, 2012, we have entered into hedging agreements covering 223.0 Bcfe for 2013 and 153.7 Bcfe for 2014.

Net cash provided from continuing operations in 2012 was $647.1 million compared to $610.2 million in 2011 and $433.9 million in 2010. The increase in cash provided from operating activities from 2011 to 2012 reflects a 45% increase in production somewhat offset by lower realized prices (a decline of 23%) and higher operating costs. The increase in cash provided from operating activities from 2010 to 2011 reflects a 36% increase in production somewhat offset by lower realized prices (a decline of 1%) and higher operating costs. 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 statements of cash flows) for 2012 was a negative $24.5 million compared to a negative $41.0 million for 2011 and negative $6.1 million in 2010. The decrease in negative working capital is primarily due to an increase in the impact fee accrual.

Net cash provided from discontinued operations was $21.4 million in 2011 and $79.4 million in 2010. Discontinued operations is related to the sale of our Barnett Shale properties which were sold in April 2011 with a February 1, 2011 effective date.

Net cash used in investing activities from continuing operations in 2012 was $1.5 billion compared to $1.4 billion in 2011 and $714.7 million in 2010.

During 2012, we:

•

spent $1.5 billion on natural gas and oil property additions;

•

spent $191.1 million on acreage, primarily in the Marcellus Shale and the Mississippian; and

•

received proceeds of $168.2 million which includes $135.0 million from the sale of our Ardmore Woodford properties in Southern Oklahoma.

During 2011, we:

•

spent $1.2 billion on natural gas and oil property additions;

•

spent $226.5 million on acreage, primarily in the Marcellus Shale; and

•

received proceeds of $53.9 million primarily related to the sale of a low pressure pipeline and various proved and unproved properties.

During 2010, we:

•

spent $732.9 million on natural gas and oil property additions;

•

spent $296.5 million on acquisitions, including purchasing unproved and proved properties in Virginia for $134.5 million and Marcellus Shale leaseholds; and

•

received proceeds of $327.8 million primarily from the sale of our Ohio natural gas and oil properties.

Net cash provided from (used in) investing activities from discontinued operations for 2011 was an increase of $840.7 million in 2011 compared to a decrease of $84.2 million in 2010. In 2011, we received proceeds of $849.3 million from the sale of our Barnett Shale assets. We spent $84.2 million on natural gas and oil property additions in 2010.

Net cash provided from (used in) financing activities in 2012 was an increase of $881.6 million compared to a decrease of $86.4 million in 2011 and an increase of $287.6 million in 2010. Historically, sources of financing have been primarily bank borrowings and capital raised through debt offerings.

During 2012, we:

•

borrowed $1.8 billion and repaid $1.2 billion under our bank credit facility, ending the year with $552.0 million higher bank debt;

•

issued $600.0 million aggregate principal amount of 5.0% senior subordinated notes due 2022; and

•

redeemed all $250.0 million aggregate principal amount of 7.5% senior subordinated notes due 2017 including related expenses.

During 2011, we:

•

borrowed $887.8 million and repaid $974.8 million under our bank credit facility; ending the year with $87.0 million lower bank debt;

•

issued $500.0 million aggregate principal amount of 5.75% senior subordinated notes due 2021; and

•

used some of the proceeds from the sale of the 5.75% senior subordinated notes to purchase or redeem all $150.0 million aggregate principal amount of 6.375% senior subordinated notes due 2015 and $250.0 million aggregate principal amount of 7.5% senior subordinated notes due 2016 including related expenses.

During 2010, we:

•

borrowed $1.1 billion and repaid approximately $1.1 billion under our bank credit facility, ending the year with $50.0 million lower bank debt;

•

issued $500.0 million aggregate principal amount of 6.75% senior subordinated notes due 2020; and

•

used some of the proceeds from the sale of 6.75% senior subordinated notes to redeem all $200.0 million aggregate principal amount of 7.375% senior subordinated notes due 2013 including related expense.

Liquidity and Capital Resources

Our main sources of liquidity and capital resources are internally generated cash flow from operations, a bank credit facility with uncommitted and committed availability, asset sales and access to the debt and equity capital markets. We must find new and develop existing reserves to maintain and grow our production and cash flows. We accomplish this primarily through successful drilling programs which requires substantial capital expenditures.

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, unused committed borrowing capacity under the bank credit facility and proceeds from asset sales combined with our natural gas, NGLs and oil derivatives currently in place will be adequate to satisfy near-term financial obligations and liquidity needs. To the extent our capital requirements exceed our internally generated cash flow and proceeds from asset sales, debt or equity may be issued to fund these requirements. 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 natural gas and oil business. A material drop in natural gas, NGLs and oil 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 natural gas, NGLs and oil, 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-A worldwide financial downturn, such as the 2008-2009 financial crisis, or negative credit market conditions may have lasting effects on our liquidity, business and financial condition that we cannot predict” in Item 1A of this report.

Credit Arrangements

Long-term debt at December 31, 2012 totaled $2.9 billion, including $739.0 million of bank credit facility debt and $2.1 billion of senior subordinated notes. Our committed borrowing capacity at December 31, 2012 was $1.75 billion. As of December 31, 2012, we maintained a $2.0 billion bank credit facility, which we refer to as our bank credit facility. The bank credit facility is secured by substantially all of our assets and has a maturity date of February 18, 2016. 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 two thirds of the lenders; increases require 97% approval.

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, 2012.

Capital Requirements

Our primary needs for cash are for exploration, development and acquisition of natural gas and oil properties and repayment of principal and interest on outstanding debt and payment of dividends. During 2012, costs incurred for drilling projects was $1.4 billion. Also in 2012, costs incurred for acquisition of unproved property was $188.8 million, primarily in the Marcellus Shale. Our 2012 capital program, excluding acquisitions, was funded by net cash flow from operations, proceeds from asset sales and borrowings under our credit facility. Our capital expenditure budget for 2013 is currently set at $1.3 billion, excluding acquisitions, for which we do not budget. To the extent capital requirements exceed internally generated cash flow, proceeds from asset sales and our committed capacity under our bank credit facility, then debt or equity may be issued to fund these requirements. We monitor our capital expenditures on an ongoing basis, adjusting the amount up or down and also among 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.

The forward-looking statements about our capital budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for natural gas and oil, actions of competitors, disruptions or interruptions of our production and unforeseen hazards such as weather conditions, acts of war or terrorists acts and the government or military response, and other operating and economic considerations.

Proved Reserves

To maintain and grow production and cash flow, we must continue to develop existing proved reserves and locate or acquire new natural gas, NGLs and oil reserves. The following is a discussion of proved reserves, reserve additions and revisions and future net cash flows from proved reserves.


	Year End December 31,
	2012			2011			2010
	(Mmcfe)
Proved Reserves:
Beginning of year		5,053,961			4,442,290			3,128,739
Reserve additions		1,767,202			1,493,357			1,410,359
Reserve revisions		109,036			224,542			148,558
Purchases		—			—			124,981
Sales		(149,153	)		(903,983	)		(189,558	)
Production		(275,476	)		(202,245	)		(180,789	)

End of year ^(a)		6,505,570			5,053,961			4,442,290

Proved Developed Reserves:
Beginning of year		2,401,274			2,183,488			1,726,696
End of year		3,457,502			2,401,274			2,183,488

^(a)	2010 includes 906,371 Mmcfe related to our Barnett Shale properties which were sold in April 2011.

Our proved reserves at year-end 2012 were 6.5 Tcfe compared to 5.1 Tcfe at year-end 2011 and 4.4 Tcfe at year-end 2010. Natural gas comprised approximately 74%, 79% and 80% of our proved reserves at year-end 2012, 2011 and 2010.

Reserve Additions and Revisions. During 2012, we added 1.8 Tcfe of proved reserves from drilling activities and evaluations of proved areas, primarily in the Marcellus Shale. Approximately 56% of the 2012 reserve additions were attributable to natural gas. We added 307 Bcfe (or 17% of the 2012 reserve additions) of incremental ethane reserves (51.2 Mmbls) as part of NGLs proved reserves associated with initial ethane deliveries under contracts commencing in 2013. Revisions of previous estimates of 109 Bcfe for the year ended December 31, 2012 consists of positive performance revisions for our properties somewhat offset by negative pricing revisions and reserves reclassified to unproved because of a slower pace of development activity beyond the five-year development horizon.

During 2011, we added approximately 1.5 Tcfe of proved reserves from drilling activities and evaluations of proved areas, primarily in the Marcellus Shale. Approximately 87% of the 2011 reserve additions were attributable to natural gas. Revisions of previous estimates of 225 Bcfe for the year ended December 31, 2011 were primarily positive performance revisions for natural gas properties, primarily in the Marcellus Shale.

During 2010, we added approximately 1.4 Tcfe of proved reserves from drilling activities and evaluations of proved areas primarily in the Marcellus Shale and the Barnett Shale. Approximately 77% of reserve additions were attributable to natural gas reserves. Revisions of previous estimates of 148.6 Bcfe for the year ended December 31, 2010 included a positive revision of 40.5 Bcfe due to an increase in the average natural gas price used for the December 31, 2010 reserve estimation as compared to the price used in the previous year estimate. Revisions of previous estimates in 2010 also include positive performance revisions for natural gas properties primarily in the Barnett Shale.

Sales. In 2012, we sold approximately 149.2 Bcfe of reserves primarily related to the sale of our Ardmore Woodford properties in Southern Oklahoma. In 2011, we sold approximately 904.0 Bcfe of reserves primarily related to the sale of our Barnett properties. In 2010, we sold approximately 189.6 Bcfe reserves primarily related to our Ohio properties.

Future Net Cash Flows. At December 31, 2012, the present value (discounted at 10%) of estimated future net cash flows from our proved reserves was $4.0 billion. This present value was calculated based on the unweighted average first-day-of-the-month oil and gas prices for the prior twelve months held flat for the life of the reserves. The present value of our estimated future net cash flows at December 31, 2011 was $6.1 billion. At December 31, 2012, the after tax present value of estimated future net cash flows from our proved reserves was $3.2 billion compared to $4.5 billion at December 31, 2011.

The present value of future net cash flows does not purport to be an estimate of the fair market value of our proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money to the evaluating party and the perceived risks inherent in producing oil and gas.

Capitalization and Dividend Payments

As of December 31, 2012 and 2011, our total debt and capitalization were as follows (in thousands):


	2012			2011
Bank debt	$	739,000		$	187,000
Senior subordinated notes		2,139,185			1,787,967

Total debt		2,878,185			1,974,967
Stockholders’ equity		2,357,392			2,392,420

Total capitalization	$	5,235,577		$	4,367,387

Debt to capitalization ratio		55.0	%		45.2	%

The amount of future dividends is subject to declaration by the Board of Directors and primarily depends on earnings, capital expenditures and various other factors. In 2012, we paid $26.0 million in dividends to our common shareholders ($0.04 per share each quarter). In 2011, we paid $25.8 million in dividends to our common shareholders ($0.04 per share each quarter). In 2010, we paid $25.6 million in dividends to our common shareholders ($0.04 per share each quarter).

Cash Contractual Obligations

Our contractual obligations include long-term debt, operating leases, drilling commitments, derivative obligations, asset retirement obligations and transportation and gathering commitments. As of December 31, 2012, we do not have any capital leases. As of December 31, 2012, we do not have any significant off-balance sheet debt or other such unrecorded obligations and we have not guaranteed any debt of any unrelated party. As of December 31, 2012, we had a total of $84.7 million 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, 2012. In addition to the contractual obligations listed on the table below, our balance sheet at December 31, 2012 reflects accrued interest payable on our bank debt of $2.4 million which is payable in first quarter 2013. We expect to make interest payments of $18.1 million per year on our 7.25% senior subordinated notes, $24.0 million per year on our 8% senior subordinated notes, $33.8 million per year on our 6.75% senior subordinated notes and $28.8 million per year on our 5.75% senior subordinated notes and $30.0 million per year on our 5.0% senior subordinated notes.

The following summarizes our contractual financial obligations at December 31, 2012 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).


	Payment due by period
	2013		2014		2015		2016 and 2017			Thereafter		Total
Bank debt due 2016	$	—	$	—	$	—	$	739,000	^(a)	$	—	$	739,000
7.25% senior subordinated notes due 2018		—		—		—		—			250,000		250,000
8.0% senior subordinated notes due 2019		—		—		—		—			300,000		300,000
6.75% senior subordinated notes due 2020		—		—		—		—			500,000		500,000
5.75% senior subordinated notes due 2021		—		—		—		—			500,000		500,000
5.0% senior subordinated notes due 2022		—		—		—		—			600,000		600,000
Operating leases		13,497		13,645		13,363		16,013			21,628		78,146
Drilling rig commitments		22,088		10,844		6,745		—			—		39,677
Transportation and gathering commitments		184,802		177,027		182,884		367,704			825,717		1,738,134
Hydraulic fracturing services		24,000		—		—		—			—		24,000
Seismic agreements		5,339		3,883		—		—			—		9,222
Other purchase obligations		167		168		74		—			—		409
Derivative obligations ^(b)		4,471		3,463		—		—			—		7,934
Asset retirement obligation liability ^(c)		2,470		22,799		5,920		1,456			113,833		146,478

Total contractual obligations ^(d)	$	256,834	$	231,829	$	208,986	$	1,124,173		$	3,111,178	$	4,933,000

^(a)	Due at termination date of our bank credit facility. Interest paid on our bank credit facility would be approximately $16.3 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, 2012. 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 amount and timing cannot be precisely determined in advance. See Note 9 to our consolidated financial statements.

^(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 2028 to transport or deliver natural gas, ethane and propane production volumes in Appalachia from certain Marcellus Shale wells. The agreements are contingent on certain pipeline modifications and/or pipeline construction and are for 27,452 mcfe per day in 2013, 254,918 mcfe per day in 2014, 417,494 mcfe per day in 2015 and 645,000 mcfe per day for the remainder of the contractual term.

Delivery Commitments

We have various volume delivery commitments that are primarily related to our Midcontinent and Marcellus Shale areas. We may purchase third party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2012, our delivery commitments through 2017 were as follows:


Year Ending December 31,	Natural Gas and NGLs (mcfe per day)
2013		196,532
2014		203,123
2015		147,263
2016		102,318
2017		52,055

Other

We lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally between three to five 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, including the cost of infrastructure to connect production, 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 a significant component of our cost structure 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.

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 as we typically utilize commodity swap and collar 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. In 2011, we also entered into “sold” NGLs derivative swap contracts for the natural gasoline component of natural gas liquids and in 2012 we entered into “re-purchased” derivative swaps for natural gasoline. We entered into these re-purchased swaps to lock in certain natural gasoline derivative gains. In 2012, we also entered into derivative swap contracts for propane. While there is a risk that the financial benefit of rising natural gas, NGLs and oil 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, 2012, we had open swap contracts covering 77.9 Bcf of natural gas at prices averaging $3.64 per mcf, 3.3 million barrels of oil at prices averaging $95.70 per barrel, 2.4 million net barrels of NGLs (the C5 component of NGLs) at prices averaging $92.72 per barrel and 1.8 million barrels of NGLs (the C3 component of NGLs) at prices averaging $35.55 per barrel. We had collars covering 242.7 Bcf of gas at weighted average floor and cap prices of $4.13 to $4.72 per mcf and 1.8 million barrels of oil at weighted average floor and cap prices of $88.58 to $100.00 per barrel. The 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 $144.3 million at December 31, 2012. The contracts expire monthly through December 2014.

At December 31, 2012, the following commodity derivative contracts were outstanding:


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2013	Collars	280,000 Mmbtu/day	$4.59–$ 5.05
2014	Collars	385,000 Mmbtu/day	$3.80–$ 4.48
2013	Swaps	213,384 Mmbtu/day	$3.64

Crude Oil
2013	Collars	3,000 bbls/day	$90.60–$ 100.00
2014	Collars	2,000 bbls/day	$85.55–$ 100.00
2013	Swaps	5,081 bbls/day	$96.59
2014	Swaps	4,000 bbls/day	$94.56

NGLs (Natural Gasoline)
2013	Sold Swaps	8,000 bbls/day	$89.64
2013	Re-purchased Swaps	1,500 bbls/day	$76.30

NGLs (Propane)
2013	Swaps	5,000 bbls/day	$35.55

Interest Rates

At December 31, 2012, we had $2.9 billion of debt outstanding. Of this amount, $2.2 billion bears interest at fixed rates averaging 6.3%. Bank debt totaling $739.0 million bears interest at floating rates, which averaged 2.2% at year-end 2012. The 30-day LIBOR rate on December 31, 2012 was 0.2%. A 1% increase in short-term interest rates on the floating-rate debt outstanding at December 31, 2012 would cost us approximately $7.4 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 which are 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 natural gas, NGLs and oil prices and the costs to produce our reserves. Natural gas, NGLs and oil 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. We expect costs in 2013 to continue to be a function of supply and demand.

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 natural gas and oil 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.

Natural Gas and Oil Properties

We follow the successful efforts method of accounting for natural gas and oil 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 natural gas and oil reserves as estimated by our engineers and audited 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 natural gas, natural gas liquids, condensate and crude oil 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 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 natural gas, NGLs and oil 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 our depletion rates. 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 and Economics who reports directly to our President and Chief Executive Officer. For additional discussion, see “Proved Reserves,” in Item 1 and 2 of this report. To further ensure the reliability of our reserve estimates, we engage independent petroleum consultants to audit our estimates of proved reserves. Independent petroleum consultants audited approximately 93% of our reserves in 2012 compared to 89% in 2011 and 90% in 2010. 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 petroleum engineering staff. Beginning December 31, 2009, reserve estimates are based on an average of prices in the prior 12-month period, using the closing prices on the first day of each month. In previous periods, reserve estimates were based upon prices at December 31. Neither of these prices should be expected to reflect future market conditions.

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 the timing of when depletion expense is recognized. Downward revisions of proved reserves may 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, 2012, we estimate that a 1% change in proved reserves would increase or decrease 2013 depletion expense by approximately $4.9 million (based on current production estimates). Estimated reserves are used as the basis for calculating the expected future cash flows from property asset groups, 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 natural gas and oil 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 was accounted for prospectively.

We monitor our long-lived assets recorded in natural gas and oil properties in our consolidated balance sheets 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 natural gas, NGLs and oil prices, an estimate of the ultimate amount of recoverable natural gas, NGLs and oil reserves that will be produced from the property asset groups future production, future production costs, future abandonment costs, and future inflation. The need to test a property asset group for impairment can be based on several factors, including a significant reduction in sales prices for natural gas, NGLs and/or oil, unfavorable adjustments to reserves, physical damage to production equipment and facilities, a change in costs, or other changes to contracts or environmental regulations. Our natural gas and oil properties 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. All of these factors must be considered when testing a property asset groups 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 inflows from the sale of produced reserves are 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, which is based on proved and risk adjusted probable reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply and the economic and regulatory climates. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of future cash flows. 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 that used by 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 $34.3 million in 2012, $38.7 million in 2011 and $6.5 million in 2010. In 2012, an impairment was recorded on our Mississippi properties of $31.1 million due to lower reserves and lower natural gas prices. Also in 2012, an impairment of $3.2 million was recorded on our remaining North Texas Barnett assets (due to lower natural gas prices and including the possibility of sale). In 2012, we also recorded a $1.3 million impairment of remaining surface acreage in the Barnett. In 2011, an impairment was recorded on our East Texas properties of $31.2 million due to lower reserves, lower natural gas prices and including the possibility of a sale. An impairment of $7.5 million was also recorded in 2011 related to our Gulf Coast onshore properties due to lower reserves and lower natural gas prices. In 2010, an impairment was recorded on our Gulf Coast properties. While our Barnett Shale properties did not meet held for sale criteria as of December 31, 2010, our analysis determined that undiscounted cash flows for these properties were less than their carrying value. We therefore compared the carrying value to the estimated fair value and recognized an impairment charge of $463.2 million in fourth quarter 2010, which is recorded in discontinued operations. Our estimated fair value included an estimate of the potential sales price for the Barnett Shale properties in the estimated future cash flows. On April 29, 2011, we sold substantially all of these assets. 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. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments.

We evaluate our unproved property investment periodically for impairment. The majority of these costs generally relate to the acquisition of leaseholds. 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. Potential impairment of individually significant unproved property is assessed on a property-by-property basis considering a combination of time, geologic and engineering factors. Unproved properties had a net book value of $743.5 million at December 31, 2012 compared to $748.6 million at December 31, 2011. We have recorded abandonment and impairment expense related to unproved properties of $125.3 million in 2012 compared to $79.7 million in 2011 and $49.7 million in 2010.

Natural Gas and Oil Derivatives

All derivative instruments are recorded on our consolidated balance sheets 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 natural gas, NGLs and oil 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. Our third party pricing service uses observable market prices and we do not adjust the valuations. 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. As of December 31, 2012, our counterparties include fifteen financial institutions, of which all but two are secured lenders in our bank credit facility. For those counterparties that are not secured lenders in our bank credit facility or those for which we do not have master netting arrangements, net derivative asset values are determined in part, by reviewing credit default swap spreads for the counterparties. Net derivative liabilities are determined, in part, by using our market credit spread.

Through December 31, 2012, 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 natural gas, NGLs and oil 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 derivative fair value income in the accompanying statements of operations. During 2010, there were gains of $11.6 million reclassified into earnings as a result of the discontinuance of hedge accounting treatment for our derivatives. In 2012 and 2011, we did not transfer any gains or losses into derivative fair value income as a result of discontinuing hedge accounting.

We apply hedge accounting to qualifying derivatives used to manage price risk associated with our natural gas, NGLs and oil production. Accordingly, we record changes in the fair value of our qualifying derivative contracts, including changes associated with time value, in accumulated other comprehensive income (“AOCI”) in the accompanying consolidated balance sheets. Gains or losses on these swap and collar contracts are reclassified out of AOCI and into natural gas, NGLs and oil 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 in income the accompanying consolidated statements 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 derivative fair value income in the accompanying consolidated statements of operations. At times, we have also entered into basis swap agreements which do not qualify for hedge accounting and are marked to market. The price we receive for our natural gas production can be more or less than the NYMEX price because of adjustments for delivery location (“basis”), relative quality and other factors; therefore, at times 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 the accompanying consolidated statements of cash flows.

Asset Retirement Obligations

We have significant obligations to remove tangible equipment and restore land at the end of natural gas and oil 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 natural gas and oil 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 2012, we increased our existing ARO by $48.2 million or approximately 57% of the ARO liability at December 31, 2011. This increase was due to an increase in the estimated costs to plug and abandon our wells and a decrease in the productive life of certain of our natural gas properties due to declining prices. During 2011, we increased our existing estimated ARO by $20.8 million or approximately 34% of the asset retirement obligation at December 31, 2010. This increase was due to an increase in estimated costs to plug and abandon our wells. This decrease was due to a change in the productive lives of our wells. 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 the accompanying consolidated statements 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 and, in certain jurisdictions, we must estimate our expected future taxable income to complete this assessment. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about the timing and realization of deferred tax items, future operating conditions (particularly related to prevailing natural gas, NGLs and oil prices) and the overall condition of the markets we operate in. The estimates or assumptions used in determining future taxable income are consistent with those used in our internal budgets and forecasts.

A valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are more likely than not to be realized. We do not currently have a valuation allowance on our federal net operating carryforwards but have a $2.0 million valuation against our state net operating loss carryforwards.

In determining deferred tax liabilities, accounting rules require AOCI to be considered, even though such income or loss has not yet been earned. At year-end 2012, deferred tax liabilities exceeded deferred tax assets by $736.2 million with $53.6 million of deferred tax liability related to net deferred hedging gains in AOCI. At year-end 2011, deferred tax liabilities exceeded deferred tax assets by $767.1 million with $98.1 million of deferred tax liability related to net deferred hedging gains in AOCI.

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. Actual costs can differ from estimates for many reasons. 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

Natural gas, natural gas liquids and oil sales 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 generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Both types of agreements include transportation charges. We report our gathering and transportation costs in accordance with Financial Accounting Standards Board Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. One type of agreement is a netback arrangement, under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we received from the purchaser. In the case of NGLs, we receive a net price from the purchaser (which is net of processing costs) which is recorded in revenue at the net price. Under the other arrangement, we sell natural gas or oil at a specific delivery point, pay transportation, gathering and compression to a third party and receive proceeds from the purchaser with no deduction. In that case, we record these costs as transportation, gathering and compression expense.

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 (“Liability Awards”) and restricted stock unit awards (“Equity 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. Substantially all Liability Awards are deposited in our deferred compensation plans at the time of grant and are classified as a liability due to the fact that these awards are expected to be settled wholly or partially in cash. The fair value of the Liability Awards is updated at each balance sheet date with changes in the fair value of the vested portion of the awards and recorded as increases or decreases to deferred compensation plan expense on the accompanying statement of operations.

Accounting Standards Not Yet Adopted

In December 2011, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” requiring additional disclosures about offsetting and related arrangements. ASU 2011-11 is effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of ASU 2011-11 is not expected to impact our future financial position, results of operation or liquidity.

ITEM 7A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market-risk exposure. All of our market-risk sensitive instruments were entered into for purposes other than trading. All accounts are US dollar denominated.

Market Risk

We are exposed to market risks related to the volatility of natural gas, NGLs and oil prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. These derivatives instruments apply to a varying portion of our production and provide only partial price protection. These arrangements limit the benefit to us of increases in prices but offer protection in the event of price declines. Further, if our counterparties defaulted, this protection might be limited as we might not receive the benefits of the derivatives. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Natural gas and oil prices have been volatile and unpredictable for many years. Natural gas prices affect us more than oil prices because approximately 74% of our December 31, 2012 proved reserves are natural gas. We are also exposed to market risks related to changes in interest rates. These risks did not change materially from December 31, 2011 to December 31, 2012.

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. Our derivatives program also includes collars, which establishes a minimum floor price and a predetermined ceiling price. At December 31, 2012, our derivatives program includes swaps and collars. As of December 31, 2012, we had open swap contracts covering 77.9 Bcf of natural gas at prices averaging $3.64 per mcf, 3.3 million barrels of oil at prices averaging $95.70 per barrel, 2.4 million net barrels of NGLs (the C5 component of NGLs) at prices averaging $92.72 per barrel and 1.8 million barrels of NGLs (the C3 component of NGLs) at prices averaging $35.55 per barrel. We had collars covering 242.7 Bcf of gas at weighted floor and cap prices of $4.13 to $4.72 per mcf and 1.8 million barrels of oil at weighted average floor and cap prices of $88.58 to $100.00 per barrel. These contracts expire monthly through December 2014. The fair value, represented by the estimated amount that would be realized upon immediate liquidation as of December 31, 2012, approximated a net unrealized pre-tax gain of $144.3 million compared to a gain of $251.3 million at December 31, 2011. This change is primarily related to the settlements of derivative contracts during 2012 and to the natural gas, NGLs and oil futures prices as of December 31, 2012, in relation to the new commodity derivative contracts we entered into during 2012 for 2013 and 2014.

At December 31, 2012, the following commodity derivative contracts were outstanding:


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price	Fair Market Value
				(in thousands)
Natural Gas
2013	Collars	280,000 Mmbtu/day	$4.59–$ 5.05	$110,485
2014	Collars	385,000 Mmbtu/day	$3.80–$ 4.48	$8,307
2013	Swaps	213,384 Mmbtu/day	$3.64	$7,505

Crude Oil
2013	Collars	3,000 bbls/day	$90.60–$ 100.00	$1,764
2014	Collars	2,000 bbls/day	$85.55–$ 100.00	$458
2013	Swaps	5,081 bbls/day	$96.59	$6,162
2014	Swaps	4,000 bbls/day	$94.56	$3,487

NGLs (Natural Gasoline)
2013	Sold Swaps	8,000 bbls/day	$89.64	$6,998
2013	Re-purchased Swaps	1,500 bbls/day	$76.30	$5,920

NGLs (Propane)
2013	Swaps	5,000 bbls/day	$35.55	$(6,746)

We expect our NGLs production to continue to increase. In our Marcellus Shale operations, propane is a large product component of our NGLs production and we believe NGLs prices are somewhat seasonal. Therefore, the percentage of NGLs prices to NYMEX WTI (or West Texas Intermediate) will vary due to product components, seasonality and geographic supply and demand. We sell NGLs in several regional markets.

As of December 31, 2012, the relationship between the price of oil and the price of natural gas is at an unprecedented spread. Normally, natural gas liquids production is a by-product of natural gas production. Due to the current differences in prices, we and other producers may choose to sell natural gas at or below cost or otherwise dispose of natural gas to allow for the sale of only natural gas liquids.

Currently, there is little demand, or facilities to supply the existing demand, for ethane in the Appalachian region so, for our Appalachian production volumes, ethane remains in the natural gas stream. We currently have waivers from two transmission pipelines that allow us to leave ethane in the residue natural gas. We believe the limits are sufficient to cover our production through 2014. We have recently announced three ethane agreements where we have contracted to either sell or transport ethane from our Marcellus Shale area, which are expected to begin operations in mid to late 2013, early 2014 and early 2015. We cannot assure you that these facilities will become available. If we are not able to sell ethane, we may be required to curtail production which will adversely affect our revenues.

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. At times, 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 in the past that effectively fix the basis adjustments. We currently have entered into basis swaps agreements which settle in first quarter 2013 and have a fair value of $993,000 at December 31, 2012.

The following table shows the fair value of our collars, swaps and call options and the hypothetical change in fair value that would result from a 10% and a 25% change in commodity prices at December 31, 2012. 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 (in thousands):


			Hypothetical Change in Fair Value						Hypothetical Change in Fair Value
			Increase in Commodity Price of						Decrease in Commodity Price of
	Fair Value		10%			25%			10%		25%
Collars	$	121,014	$	(90,661	)	$	(227,633	)	$	91,420	$	234,267
Swaps		23,326		(84,846	)		(211,326	)		85,816		214,715
Basis		993		(17	)		(17	)		—		—

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. At December 31, 2012, our derivative counterparties include fifteen financial institutions, of which all but two are secured lenders in our bank credit facility. 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 certain of our counterparties, 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, 2012, we had $2.9 billion of debt outstanding. Of this amount, $2.2 billion bears interest at a fixed rate averaging 6.3%. Bank debt totaling $739.0 million bears interest at floating rates, which was 2.2% on that date. On December 31, 2012, 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, 2012 would cost us approximately $7.4 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):


	Carrying Value		Fair Value
Fixed rate debt:
Senior Subordinated Notes due 2018	$	250,000	$	262,500
(The interest rate is fixed at a rate of 7.25%)

Senior Subordinated Notes due 2019		289,185		332,250
(The interest rate is fixed at a rate of 8.0%)

Senior Subordinated Notes due 2020		500,000		542,500
(The interest rate is fixed at a rate of 6.75%)

Senior Subordinated Notes due 2021		500,000		535,000
(The interest rate is fixed at a rate of 5.75%)

Senior Subordinated Notes due 2022		600,000		627,000
(The interest rate is fixed at a rate of 5.00%)

	$	2,139,185	$	2,299,250

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

Evaluation of 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 Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that 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 upon the evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2012 at the reasonable assurance level.

Changes in Internal Controls over Financial Reporting. There have been no changes in our system of internal control over financial reporting (such as term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Annual Report on Internal Control over Financial Reporting. See “Management’s Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm Internal Control Over Financial Reporting” which appear on pages F-2 and F-3, respectively, under “Item 15. Exhibits, Financial Statements Schedules.”

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 2012 annual stockholders’ meeting. Officers are appointed by our board of directors.


	Age	Office Held Since	Position
Charles L. Blackburn	85	2003	Director
Anthony V. Dub	63	1995	Director
V. Richard Eales	76	2001	Lead Independent Director
Allen Finkelson	66	1994	Director
Jim M. Funk	63	2008	Director
Jonathan S. Linker	64	2002	Director
Kevin S. McCarthy	53	2005	Director
John H. Pinkerton	58	1990	Director, Executive Chairman
Jeffrey L. Ventura	55	2003	Director, President & Chief Executive Officer
Roger S. Manny	55	2003	Executive Vice President & Chief Financial Officer
Alan W. Farquharson	55	2007	Senior Vice President – Reservoir Engineering & Economics
David P. Poole	50	2008	Senior Vice President –General Counsel & Corporate Secretary
Chad L. Stephens	57	1990	Senior Vice President – Corporate Development
Ray N. Walker, Jr.	55	2010	Senior Vice President – Chief Operating Officer
Rodney L. Waller	63	1999	Senior Vice President
Dori A. Ginn	55	2009	Vice President, Controller and Principal Accounting Officer

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. On February 13, 2013, Mr. Blackburn advised the board of directors he did not wish to be nominated for re-election at the 2013 annual meeting of stockholders.

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 degree, magna cum laude, from Princeton University.

V. Richard Eales became a director in 2001 and was elected 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.

Allen Finkelson became a director in 1994. Mr. Finkelson was a partner at Cravath, Swaine & Moore LLP from 1977 to 2011, 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.

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 December 2003 and has been an independent consultant and oil and gas producer since that time. 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 and Sonde Resources Corp., a public company headquartered in Calgary, Alberta. Mr. Funk received an B.A. 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.

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 Pro Petro Services, Inc. and Direct Fuel Partners, L.P, (two 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, Executive Chairman 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 employed by Snyder Oil Corporation, serving in numerous capacities, the last of which was Senior Vice President. Mr. Pinkerton currently serves on the Board of Trustees of Texas Christian University and is a member of the Executive Committee of America’s Natural Gas Alliance (ANGA). 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 Ventura, President & Chief Executive Officer and a director, joined Range in 2003 as Chief Operating Officer and became a director in 2005. Mr. Ventura was named Chief Executive Officer effective January 1, 2012. Previously, Mr. Ventura served as President and Chief Operating Officer of Matador Petroleum Corporation which he joined in 1997. Prior to his service at Matador, 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 Oil Exploration and Production, 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 & Economics, joined Range in 1998. Mr. Farquharson has held the positions of Manager and Vice President of Reservoir Engineering before being promoted to Senior Vice President –Reservoir Engineering in February 2007 and his current position in January 2012 with his assumption of additional responsibilities for strategic allocation of capital. 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.

David P. Poole, Senior Vice President – General Counsel & Corporate Secretary, joined Range in June 2008. Mr. Poole has over 23 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 – Chief Operating Officer, joined Range in 2006 and was elected to his current position in January 2012. Previously, Mr. Walker served as Senior Vice President-Environment, Safety and Regulatory and previously as Senior Vice President-Marcellus Shale where he led the development of the Company’s Marcellus Shale division. Mr. Walker is a Petroleum Engineer with more than 35 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.

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 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 2012 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, 2011, our directors, officers and 10% holders complied with all filing requirements under Section 16(a) of the Exchange Act, with the following exceptions. Mr. Pinkerton had a delinquent Form 4 filing on February 6, 2012 for a transaction occurring on December 29, 2011.

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 President and 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 2013 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 2013 Annual Meeting of stockholders, which is incorporated herein by reference.

NYSE 303A Certification

The President and 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 July 2, 2012.

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 2013 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 2013 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 2013 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 2013 Annual Meeting of stockholders.

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)

Documents filed as part of the report:

Financial Statements:


	Page Number

Index to Financial Statements		F-1

Managements’ Report on Internal Control Over Financial Reporting		F-2

Report of Independent Registered Public Accounting Firm-Internal Control Over Financial Reporting		F-3

Report of Independent Registered Public Accounting Firm – Consolidated Financial Statements		F-4

Consolidated Balance Sheets as of December 31, 2012 and 2011		F-5

Consolidated Statements of Operations for the Year Ended December 31, 2012, 2011 and 2010		F-6

Consolidated Statements of Comprehensive (Loss) Income for the Year Ended December 31, 2012, 2011 and 2010		F-7

Consolidated Statements of Cash Flows for the Year Ended December 31, 2012, 2011 and 2010		F-8

Consolidated Statements of Stockholders’ Equity for the Year Ended December 31, 2012, 2011 and 2010		F-9

Notes to Consolidated Financial Statements		F-10

Selected Quarterly Financial Data (Unaudited)		F-39

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)		F-41

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.

Exhibits:

(a)

See Index of Exhibits on page 68 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 previously found to be productive of oil and gas in another reservoir or to extend a known reservoir.

gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

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 NGLs, 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 (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extracting equipment and infrastructure operational at the time of the reserve estimate if the extraction is by means not involving a well.

proved reserves. The quantities of crude oil, natural gas and NGLs that geological and engineering data can estimate with reasonable certainty to be economically producible within a reasonable time from known reservoirs under existing economic, operating and regulatory conditions prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

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.

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/ JEFFREY L. VENTURA	Director, President and Chief Executive Officer	February 26, 2013
Jeffrey L. Ventura

/s/ JOHN H. PINKERTON	Director, Executive Chairman of the Board	February 26, 2013
John H. Pinkerton

/s/ ROGER S. MANNY	Executive Vice President and Chief Financial Officer	February 26, 2013
Roger S. Manny

/s/ DORI A. GINN	Vice President, Controller and Principal Accounting Officer	February 26, 2013
Dori A. Ginn

/s/ CHARLES L. BLACKBURN	Director	February 26, 2013
Charles L. Blackburn

/s/ ANTHONY V. DUB	Director	February 26, 2013
Anthony V. Dub

/s/ V. RICHARD EALES	Lead Independent Director	February 26, 2013
V. Richard Eales

/s/ ALLEN FINKELSON	Director	February 26, 2013
Allen Finkelson

/s/ JAMES M. FUNK	Director	February 26, 2013
James M. Funk

/s/ JONATHAN S. LINKER	Director	February 26, 2013
Jonathan S. Linker

/s/ KEVIN S. MCCARTHY	Director	February 26, 2013
Kevin S. McCarthy

RANGE RESOURCES CORPORATION

INDEX TO FINANCIAL STATEMENTS


	Page Number

Management’s Report on Internal Control Over Financial Reporting		F-2

Report of Independent Registered Public Accounting Firm – Internal Control Over Financial Reporting		F-3

Report of Independent Registered Public Accounting Firm – Consolidated Financial Statements		F-4

Consolidated Balance Sheets as of December 31, 2012 and 2011		F-5

Consolidated Statements of Operations for the Year Ended December 31, 2012, 2011 and 2010		F-6

Consolidated Statements of Comprehensive (Loss) Income for the Year Ended December 31, 2012, 2011 and 2010		F-7

Consolidated Statements of Cash Flows for the Year Ended December 31, 2012, 2011 and 2010		F-8

Consolidated Statements of Stockholders’ Equity for the Year Ended December 31, 2012, 2011 and 2010		F-9

Notes to Consolidated Financial Statements		F-10

Selected Quarterly Financial Data (Unaudited)		F-39

Supplemental Information on Natural Gas and Oil Exploration, Development and Production Activities (Unaudited)		F-41

F-1

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, 2012. 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, 2012, 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, 2012. This report appears on the following page.



By:	/s/ JEFFREY L. VENTURA	By:	/s/ ROGER S. MANNY
	Jeffrey L. Ventura		Roger S. Manny
	*President and Chief Executive Officer*		*Executive Vice President and Chief Financial Officer*

Fort Worth, Texas

February 26, 2013

F-2

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, 2012, 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, 2012, 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, 2012 and 2011 and the related consolidated statements of operations, comprehensive (loss) income, cash flows and stockholders’ equity, for each of the three years in the period ended December 31, 2012 and our report dated February 26, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Fort Worth, Texas

February 26, 2013

F-3

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, 2012 and 2011, and the related consolidated statements of operations, comprehensive (loss) income, cash flows and stockholders’ equity, for each of the three years in the period ended December 31, 2012. 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, 2012 and 2011, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Range Resources Corporation’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Fort Worth, Texas

February 26, 2013

F-4

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(In thousands, except per share data)


	December 31,
	2012			2011
Assets
Current assets:
Cash and cash equivalents	$	252		$	92
Accounts receivable, less allowance for doubtful accounts of $2,374 and $4,015		167,495			127,180
Unrealized derivative gain		137,552			173,921
Inventory and other		22,315			14,070

Total current assets		327,614			315,263

Unrealized derivative gain		15,715			77,579
Equity method investments		132,449			138,130
Natural gas and oil properties, successful efforts method		8,111,775			6,784,027
Accumulated depletion and depreciation		(2,015,591	)		(1,626,461	)

		6,096,184			5,157,566

Transportation and field assets		117,717			123,349
Accumulated depreciation and amortization		(76,150	)		(70,671	)

		41,567			52,678

Other assets		115,206			104,254

Total assets	$	6,728,735		$	5,845,470

Liabilities
Current liabilities:
Accounts payable	$	234,651		$	311,369
Asset retirement obligations		2,470			5,005
Accrued liabilities		139,379			109,109
Liabilities of discontinued operations		—			653
Deferred tax liability		37,924			56,595
Accrued interest		36,248			29,201
Unrealized derivative loss		4,471			—

Total current liabilities		455,143			511,932

Bank debt		739,000			187,000
Subordinated notes		2,139,185			1,787,967
Deferred tax liability		698,302			710,490
Unrealized derivative loss		3,463			173
Deferred compensation liability		187,604			169,188
Asset retirement obligations and other liabilities		148,646			86,300

Total liabilities		4,371,343			3,453,050

Commitments and contingencies

Stockholders’ Equity
Preferred stock, $1 par, 10,000,000 shares authorized, none issued and outstanding		—			—
Common stock, $0.01 par, 475,000,000 shares authorized, 162,641,896 issued at December 31, 2012 and 161,302,973 issued at December 31, 2011		1,626			1,613
Common stock held in treasury, 127,798 shares at December 31, 2012 and 171,426 shares at December 31, 2011		(4,760	)		(6,343	)
Additional paid-in capital		1,915,627			1,866,554
Retained earnings		360,990			373,969
Accumulated other comprehensive income		83,909			156,627

Total stockholders’ equity		2,357,392			2,392,420

Total liabilities and stockholders’ equity	$	6,728,735		$	5,845,470

See accompanying notes.

F-5

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share data)


	Year Ended December 31,
	2012			2011		2010
Revenues and other income:
Natural gas, NGLs and oil sales	$	1,351,694		$	1,173,266	$	823,290
Derivative fair value income		41,437			40,087		51,634
Gain on the sale of assets		49,132			2,260		76,642
Brokered natural gas, marketing and other		15,441			15,029		9,831

Total revenues and other income		1,457,704			1,230,642		961,397

Costs and expenses:
Direct operating		115,905			112,972		96,274
Transportation, gathering and compression		192,445			120,755		62,837
Production and ad valorem taxes		67,120			27,666		26,107
Brokered natural gas and marketing		20,434			11,986		9,761
Exploration		69,807			81,367		60,506
Abandonment and impairment of unproved properties		125,278			79,703		49,738
General and administrative		173,813			151,191		140,571
Termination costs		—			—		8,452
Deferred compensation plan		7,203			43,209		(10,216	)
Interest expense		168,798			125,052		90,665
Loss on early extinguishment of debt		11,063			18,576		5,351
Depletion, depreciation and amortization		445,228			341,221		275,238
Impairment of proved properties and other assets		35,554			38,681		6,505

Total costs and expenses		1,432,648			1,152,379		821,789

Income from continuing operations before income taxes		25,056			78,263		139,608

Income tax expense (benefit)
Current		(1,778	)		637		(836	)
Deferred		13,832			34,920		51,746

		12,054			35,557		50,910

Income from continuing operations		13,002			42,706		88,698
Discontinued operations, net of taxes		—			15,320		(327,954	)

Net income (loss)	$	13,002		$	58,026	$	(239,256	)

Income (loss) per common share:
Basic-income from continuing operations	$	0.08		$	0.26	$	0.56
-discontinued operations		—			0.10		(2.09	)

-net income (loss)	$	0.08		$	0.36	$	(1.53	)

Diluted-income from continuing operations	$	0.08		$	0.26	$	0.55
-discontinued operations		—			0.10		(2.07	)

-net income (loss)	$	0.08		$	0.36	$	(1.52	)

Weighted average common shares outstanding:
Basic		159,431			158,030		156,874
Diluted		160,307			159,441		158,428

See accompanying notes.

F-6

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(In thousands)


	December 31,
	2012			2011			2010
Net income (loss)	$	13,002		$	58,026		$	(239,256	)
Other comprehensive (loss) income:
Realized loss (gain) on hedge derivative contract settlements reclassified into earnings from other comprehensive income (loss), net of taxes		(144,434	)		(82,196	)		(39,931	)
Change in unrealized deferred hedging gains (losses), net of taxes		71,716			171,353			100,980

Total comprehensive (loss) income	$	(59,716	)	$	147,183		$	(178,207	)

See accompanying notes.

F-7

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Year Ended December 31,
	2012			2011			2010
Operating activities:
Net income (loss)	$	13,002		$	58,026		$	(239,256	)
Adjustments to reconcile net income (loss) to net cash provided from operating activities:
(Gain) loss from discontinued operations		—			(15,320	)		327,954
Loss (gain) from equity method investments, net of distributions		5,670			16,871			(7,366	)
Deferred income tax expense		13,832			34,920			51,746
Depletion, depreciation and amortization and proved property impairment		480,782			379,902			281,743
Exploration dry hole costs		841			3,888			3,700
Mark-to-market on natural gas and oil derivatives not designated as hedges (gain) loss		(5,958	)		(15,762	)		2,086
Abandonment and impairment of unproved properties		125,278			79,703			49,738
Unrealized derivative loss (gain)		3,221			(2,183	)		(2,387	)
Allowance for bad debts		750			946			3,608
Amortization of deferred financing costs, loss on extinguishment of debt and other		23,165			25,458			10,072
Deferred and stock-based compensation		60,136			86,979			34,964
Gain on the sale of assets		(49,132	)		(2,259	)		(76,642	)
Changes in working capital:
Accounts receivable		(48,986	)		(52,112	)		(6,512	)
Inventory and other		(7,376	)		865			(333	)
Accounts payable		13,654			738			2,867
Accrued liabilities and other		18,220			9,540			(2,096	)

Net cash provided from continuing operations		647,099			610,200			433,886
Net cash provided from discontinued operations		—			21,437			79,436

Net cash provided from operating activities		647,099			631,637			513,322

Investing activities:
Additions to natural gas and oil properties		(1,498,628	)		(1,199,545	)		(732,860	)
Additions to field service assets		(4,762	)		(11,607	)		(14,944	)
Acreage and proved property purchases		(191,065	)		(226,500	)		(296,503	)
Investment in equity method investments and other assets		—			—			(45	)
Proceeds from disposal of assets		168,219			53,926			327,765
Purchase of marketable securities held by the deferred compensation plan		(60,406	)		(25,388	)		(17,670	)
Proceeds from the sales of marketable securities held by the deferred compensation plan		58,084			20,410			19,572

Net cash used in investing activities from continuing operations		(1,528,558	)		(1,388,704	)		(714,685	)
Net cash provided from (used in) investing activities from discontinued operations		—			840,723			(84,173	)

Net cash used in investing activities		(1,528,558	)		(547,981	)		(798,858	)

Financing activities:
Borrowing on credit facilities		1,773,000			887,826			1,055,000
Repayment on credit facilities		(1,221,000	)		(974,826	)		(1,105,000	)
Issuance of subordinated notes		600,000			500,000			500,000
Repayment of subordinated notes		(259,375	)		(413,697	)		(202,458	)
Dividends paid		(25,981	)		(25,756	)		(25,574	)
Debt issuance costs		(12,605	)		(22,003	)		(9,600	)
Issuance of common stock		2,073			619			5,903
Change in cash overdrafts		(1,126	)		(51,474	)		64,100
Proceeds from the sales of common stock held by the deferred compensation plan		26,633			12,899			5,246

Net cash provided from (used in) financing activities		881,619			(86,412	)		287,617

Increase (decrease) in cash and cash equivalents		160			(2,756	)		2,081
Cash and cash equivalents at beginning of year		92			2,848			767

Cash and cash equivalents at end of year	$	252		$	92		$	2,848

See accompanying notes.

F-8

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands, except per share data)


	Common stock				Common stock			Additional paid-			Retained			Accumulated other comprehensive
	Shares		Par value		held in treasury			in capital			earnings			income (loss)			Total
Balance as of December 31, 2009		158,336	$	1,583	$	(7,964	)	$	1,772,020		$	606,529		$	6,421		$	2,378,589
Issuance of common stock		1,778		18		—			26,138			—			—			26,156
Stock-based compensation expense		—		—		—			22,797			—			—			22,797
Common dividends declared ($0.16 per share)		—		—		—			—			(25,574	)		—			(25,574	)
Treasury stock issuance		—		—		452			(452	)		—			—			—
Other comprehensive income		—		—		—			—			—			61,049			61,049
Net loss		—		—		—			—			(239,256	)		—			(239,256	)

Balance as of December 31, 2010		160,114		1,601		(7,512	)		1,820,503			341,699			67,470			2,223,761
Issuance of common stock		1,189		12		—			8,870			—			—			8,882
Stock-based compensation expense		—		—		—			26,674			—			—			26,674
Tax benefit of stock compensation		—		—		—			11,676			—			—			11,676
Common dividends declared ($0.16 per share)		—		—		—			—			(25,756	)		—			(25,756	)
Treasury stock issuance		—		—		1,169			(1,169	)		—			—			—
Other comprehensive income		—		—		—			—			—			89,157			89,157
Net income		—		—		—			—			58,026			—			58,026

Balance as of December 31, 2011		161,303		1,613		(6,343	)		1,866,554			373,969			156,627			2,392,420
Issuance of common stock		1,339		13		—			20,251			—			—			20,264
Stock-based compensation expense		—		—		—			30,405			—			—			30,405
Common dividends declared ($0.16 per share)		—		—		—			—			(25,981	)		—			(25,981	)
Treasury stock issuance		—		—		1,583			(1,583	)		—			—			—
Other comprehensive loss		—		—		—			—			—			(72,718	)		(72,718	)
Net income		—		—		—			—			13,002			—			13,002

Balance as of December 31, 2012		162,642	$	1,626	$	(4,760	)	$	1,915,627		$	360,990		$	83,909		$	2,357,392

See accompanying notes.

F-9

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 a Fort Worth, Texas-based independent natural gas and oil company primarily engaged in the exploration, development and acquisition of natural gas properties in the Appalachian and Southwestern regions of the United States. Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. 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 brokered natural gas, marketing and other revenues in the accompanying consolidated statements of operations. All material intercompany balances and transactions have been eliminated.

Discontinued Operations

During February 2011, we entered into an agreement to sell our Barnett Shale assets. In April 2011, we completed the sale of most of these assets and closed the remainder of the sale in August 2011. We have classified the historical results of the operations from such properties as discontinued operations, net of tax, in the accompanying statements of operations. See also Note 3 and Note 4 for more information regarding the sale of our Barnett Shale assets. Unless otherwise indicated, the information in these notes relate to our continuing 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 reporting period. Depletion of natural gas and oil properties is determined using estimates of proved oil and gas reserves. Our assessment of the recoverability of our proved natural gas and oil properties, and any assessment of impairment, is based on estimates of both proved and probable oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved and probable and reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluation for impairment of proved and unproved natural gas and oil properties are subject to numerous uncertainties, including, among others, estimates of future recoverable reserves and commodity price outlook. 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.

Reclassifications

Certain reclassifications have been made to prior years’ reported amounts in order to conform with the current year presentation. This includes the reclassification of gas purchases and other marketing costs to brokered natural gas and marketing expense. These reclassifications did not impact our net income from continuing operations, stockholders’ equity or cash flows (in thousands).


	2011		2010
Other revenues, as previously reported	$	3,043	$	70
Revision of brokered natural gas and marketing		11,986		9,761

Brokered natural gas, marketing and other revenue, reported	$	15,029	$	9,831


Brokered natural gas and marketing expenses, previously reported	$	—	$	—
Revision of brokered natural gas and marketing expenses		11,986		9,761

Brokered natural gas and marketing expenses, reported	$	11,986	$	9,761

F-10

Business Segment Information

We have evaluated how we are organized and managed and have identified only one operating segment, which is the exploration and production of natural gas, NGLs and oil. We consider our gathering, processing and marketing functions as ancillary to our natural gas and oil 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 operating 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.

Revenue Recognition, Accounts Receivable and Gas Imbalances

Natural gas, NGLs and oil sales are recognized when the products are sold and delivery to the purchaser has occurred. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Both types of agreements include transportation charges. We are reporting our gathering and transportation costs in accordance with Financial Accounting Standard Board (“FASB”) Section 605-45-05 of Subtopic 605-45 for Revenue Recognition. One type of agreement is a netback arrangement, under which we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this case, we record revenue at the price we received from the purchaser. In the case of NGLs, we receive a net price from the purchaser (which is net of processing costs) which is also recorded in revenue at the net price we receive from the purchaser. Under the other arrangement, we sell natural gas or oil at a specific delivery point, pay transportation expenses to a third party and receive proceeds from the purchaser with no transportation deduction. In that case, we record revenue at the price received from the purchaser and record the expenses we incur as transportation, gathering and compression expense. We realize brokered margins as a result of buying and selling natural gas utilizing separate purchase and sale transactions, typically with separate counterparties. The amount of brokered margin was immaterial in 2012.

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 $2.4 million at December 31, 2012 compared to $4.0 million at December 31, 2011. During the year ended 2012, we recorded bad debt expense of $750,000 compared to $946,000 in 2011.

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. At December 31, 2012, we had recorded a net liability of $267,000 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

Investments in unaffiliated equity securities held in our deferred compensation plans qualify as trading securities and are recorded at fair value. Investments held in the deferred compensation plans consist of various publicly-traded mutual funds. These funds are made up of investments, which include equity securities and money market instruments.

Inventory

Inventories were comprised of $16.3 million of materials and supplies at December 31, 2012 compared to $10.9 million at December 31, 2011. 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 material and supplies inventory is primarily acquired for use in future drilling operations or repair operations. In 2011, we sold tubular goods and other inventory for proceeds of $8.0 million and recorded a gain of $359,000. At December 31, 2012, we also have $2.6 million of commodity inventory which is carried at lower of average cost or market, on a first in, first out basis.

F-11

Natural Gas and Oil Properties

Property Acquisition Costs

We follow the successful efforts method of accounting for natural gas and oil 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. Due to the capital-intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project’s feasibility is not contingent upon price improvements or advances in technology, but rather our ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies’ production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, our assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found proved reserves to sanction the project or is noncommercial and is charged to exploration expense. See Note 7 for additional information regarding our suspended exploratory well costs.

Depreciation, Depletion and Amortization

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 and other times during the year when circumstances indicate there has been a significant change in reserves or costs. We adopted the new SEC accounting and disclosure regulations for oil and gas companies effective December 31, 2009.

Impairments

Our natural gas and oil 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 produced 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, which is based on proved and risk adjusted probable reserves, has assumptions surrounding the future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climate. In certain circumstances, we also consider potential sales of properties to third parties in our estimates of cash flows. 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 that used by 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 natural gas and oil prices, an estimate of the ultimate amount of recoverable natural gas and oil reserves that will be produced from an asset group, 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. If natural gas, NGLs and oil prices decrease or drilling efforts are unsuccessful, we may be required to record additional impairments. For additional information regarding proved property impairments, see Note 12.

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. Unproved properties had a net book value of $743.5 million in 2012 compared to $748.6 million in 2011. We have recorded abandonment and impairment expense related to unproved properties from continuing operations of $125.3 million in 2012 compared to $79.7 million in 2011 and to $49.7 million in 2010.

F-12

Dispositions

Proceeds from the disposal of natural gas and oil producing properties that are part of an amortization base are credited to the net book value of the amortization group with no immediate effect on income. However, gain or loss is recognized if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

Transportation and Field Assets

Our gas transportation and gathering systems are generally located in proximity to certain of our principal fields. Depreciation on these pipeline systems is provided on the straight-line method based on estimated useful lives of ten to fifteen years. We receive third-party income for providing field service and certain transportation services, which is recognized as earned. Depreciation on the associated assets is calculated on the straight-line method based on estimated useful lives ranging from five to seven years. Transportation and field assets also includes other property and equipment such as buildings, furniture and fixtures, leasehold improvements, data processing and communication equipment. These items are generally depreciated by individual components on a straight line basis over their economic useful life, which is generally from three to fifteen years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases. Depreciation expense was $13.2 million in 2012 compared to $16.2 million in 2011 and $16.1 million in 2010.

Other Assets

The expenses of issuing debt are capitalized and included in other assets in the accompanying consolidated balance sheets. These costs are amortized over the expected life of the related instruments. When debt is retired before maturity or modifications significantly change the cash flows, related unamortized costs are expensed. Other assets at December 31, 2012 include $43.1 million of unamortized debt issuance costs, $57.8 million of marketable securities held in our deferred compensation plans and $14.3 million of other investments including surface acreage. Other assets at December 31, 2011 include $39.4 million of unamortized debt issuance costs, $50.2 million of marketable securities held in our deferred compensation plans and $14.6 million of other investments including surface acreage.

Accounts Payable

Included in accounts payable at December 31, 2012 and 2011, are liabilities of approximately $44.6 million and $45.7 million representing the amount by which checks issued, but not presented to our banks for collection, exceeded balances in our applicable bank accounts.

Stock-based Compensation Arrangements

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. Substantially all Liability Awards are deposited in our deferred compensation plans at the time of grant and are classified as a liability due to the fact that these awards are expected to be settled wholly or partially in cash. The fair value of the Liability Awards is updated at each balance sheet date with changes in the fair value of the vested portion of the awards recorded as increases or decreases to deferred compensation plan expense in the accompanying statement of operations.

Derivative Financial Instruments and Hedging

All of our derivative instruments are issued to manage the price risk attributable to our expected natural gas, NGLs and oil production. While there is risk that the financial benefit of rising natural gas, NGLs and oil 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 in the accompanying consolidated balance sheets as either an asset or a liability measured at its fair value. In most cases, our derivatives are reflected on our consolidated balance sheet on a net basis by brokerage firm,

F-13

when they are governed by master netting agreements. Changes in a derivative’s fair value are recognized in earnings unless specific hedge accounting criteria are met. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.

Through December 2012, 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 natural gas, NGLs and oil sales when the underlying transaction occurs. If it is determined that the designated hedged transaction is probable to not occur, any unrealized gains or losses is recognized immediately in derivative fair value income in the accompanying consolidated statements of operations. During 2010, we recognized pre-tax gains of $11.6 million as a result of the discontinuance of hedge accounting treatment for certain of our derivatives. In 2012 and 2011, we did not transfer any gains or losses into derivative fair value as a result of discontinuing hedge accounting.

We apply hedge accounting to qualifying derivatives (or “hedge derivatives”) used to manage price risk associated with our natural gas, NGLs and oil production. Accordingly, we record changes in the fair value of our hedge derivative contracts, including changes associated with time value, in accumulated other comprehensive income (“AOCI”) in the stockholders’ equity section of the accompanying consolidated balance sheets. Gains or losses on these hedge derivative contracts are reclassified out of AOCI and into natural gas, NGLs and oil sales when the underlying physical transaction occurs and the hedging contract is settled. 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 on the accompanying 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 “non-hedge derivatives”) are accounted for using the mark-to-market accounting method. We recognize all unrealized and realized gains and losses related to these contracts in each period in derivative fair value income in the accompanying consolidated statements of operations. At times, we have also 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 (“basis”), relative quality and other factors; therefore, we have entered into basis swap agreements that effectively fix our basis adjustments.

Concentrations of Credit Risk

As of December 31, 2012, our primary concentrations of credit risk are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations. 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 $2.4 million at December 31, 2012 compared to $4.0 million at December 31, 2011. As of December 31, 2012, our derivative contracts consist of swaps and collars. Our exposure is diversified primarily among major investment grade financial institutions, the majority of which we have master netting agreements which provides for offsetting payables against receivables from separate derivative contracts. To manage counterparty risk associated with our derivatives, we select and monitor our counterparties based on our assessment of their financial strength and or credit ratings. We may also limit the level of exposure with any single counterparty. At December 31, 2012 our derivative counterparties include fifteen financial institutions, of which all but two are secured lenders in our bank credit facility. At December 31, 2012, our net derivative asset includes a receivable from two counterparties not included in our bank credit facility of $7.1 million. For those counterparties that are not secured lenders in our bank credit facility or for which we do not have master netting arrangements, net derivative asset values are determined, in part, by reviewing credit default swap spreads for the counterparties. Net derivative liabilities are determined, in part, by using our market based credit spread. None of our derivative contracts have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement date. We have also entered into the International SWAP Dealers Association Master Agreements (“ISDA Agreements”) with our counterparties. The terms of the ISDA Agreements provide us and our counterparties with rights of set off upon the occurrence of defined acts of default by either us or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.

F-14

Asset Retirement Obligations

The fair value of asset retirement obligations is 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 natural gas and oil 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 of 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.

Environmental Costs

Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. Expenditures that relate to an existing condition caused by past operations that have no future economic benefits are expensed.

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 in the periods before tax credits and operating loss carryforwards expire. We do not recognize a deferred tax asset for excess tax benefits on equity compensation that have not been realized due to our net operating loss tax position for federal or state tax purposes.

Accumulated Other Comprehensive Income

The following details the components of AOCI and related tax effects for the three years ended December 31, 2012. Amounts included in AOCI exclusively relate to our derivative activity (in thousands).


	Gross			Tax Effect			Net of Tax
Accumulated other comprehensive income at December 31, 2009	$	10,192		$	(3,771	)	$	6,421
Contract settlements reclassified to income		(64,772	)		24,841			(39,931	)
Change in unrealized deferred hedging gains		165,642			(64,662	)		100,980

Accumulated other comprehensive income at December 31, 2010		111,062			(43,592	)		67,470
Contract settlements reclassified to income		(132,201	)		50,005			(82,196	)
Change in unrealized deferred hedging gains		275,817			(104,464	)		171,353

Accumulated other comprehensive income at December 31, 2011		254,678			(98,051	)		156,627
Contract settlements reclassified to income		(236,305	)		91,871			(144,434	)
Change in unrealized deferred hedging gains		119,182			(47,466	)		71,716

Accumulated other comprehensive income at December 31, 2012	$	137,555		$	(53,646	)	$	83,909

Accounting Pronouncements Implemented

Recently Adopted

In May 2011, the FASB issued ASU No. 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” This pronouncement was issued to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between U.S. GAAP and International Financial Reporting Standards. ASU No. 2011-04 changes certain fair value measurement principles and enhances the disclosure requirements, particularly for Level 3 fair value measurements. This pronouncement is effective for reporting periods beginning on or after December 15, 2011, with early adoption prohibited. The new guidance requires prospective application. We adopted this new requirement in first quarter 2012 and it did not have a material effect on our consolidated financial statements.

F-15

Accounting Pronouncements Not Yet Adopted

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” requiring additional disclosures about offsetting and related arrangements. ASU 2011-11 is effective retrospectively for annual reporting periods beginning on or after January 1, 2013. The adoption of ASU 2011-11 is not expected to impact our future financial position, results of operation or liquidity.

(3) DISPOSITIONS AND ACQUISITIONS

2012 Dispositions

In October 2012, we entered into an agreement to sell our Ardmore Woodford properties in Southern Oklahoma. We closed this sale in November 2012. The gross cash proceeds were $135.0 million. The agreements had a July 1, 2012 effective date and consequently, operating net revenues after July 2012 were a downward adjustment to the sales price. We recorded a pre-tax gain of $55.2 million related to this sale. In fourth quarter 2011, we exchanged unproved property in Ohio for unproved property in Pennsylvania where we received $11.5 million in cash and recorded a $4.5 million gain in 2011. In 2012, we recorded an additional gain of $6.8 million related to this same transaction.

In September 2012, we sold unproved properties in three counties in Pennsylvania for proceeds of $13.9 million resulting in a pre-tax gain of $746,000. As part of this agreement, we retained an overriding royalty of 1% to 5% on a large portion of the leases. In June 2012, we sold a suspended exploratory well in the Marcellus Shale for proceeds of $2.5 million resulting in a pre-tax loss of $2.5 million. In March 2012, we sold seventy-five percent of a prospect in East Texas which included unproved properties and a suspended exploratory well to a third party for proceeds of $8.6 million resulting in a pre-tax loss of $10.9 million. As part of this agreement, we retained a carried interest on the first well drilled and an overriding royalty of 2.5% to 5.0% in the prospect.

In December 2012, we announced our plan to offer for sale certain of our Permian Basin and Delaware properties in southeast New Mexico and West Texas. The data room opened in early January 2013, and on February 26, 2013, we announced we signed a definitive agreement to sell these assets for a price of $275.0 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 or that there will not be changes to the sales price.

2011 Dispositions

In February 2011, we entered into an agreement to sell substantially all of our Barnett Shale properties located in North Central Texas (Dallas, Denton, Ellis, Hill, Hood, Johnson, Parker, Tarrant and Wise Counties), which also included the assumption of certain derivative contracts by the buyer and was subject to normal post-closing adjustments. We closed substantially all of this sale in April 2011 and closed the remainder in August 2011. The gross cash proceeds were approximately $889.3 million, including certain derivative contracts assumed by the buyer. The agreements had a February 1, 2011 effective date and consequently operating net revenues after February 2011 were a downward adjustment to the sales price. In 2011, we recorded a pretax gain of $4.8 million in discontinued operations related to this sale. In the accompanying December 31, 2010 balance sheet, we have classified these assets and liabilities as discontinued operations. As indicated in Notes 2 and 4, the historic results of our Barnett Shale operations are presented as discontinued operations.

As part of the sale of our Barnett Shale properties, certain derivative contracts were assumed by the buyer. We received proceeds of $40.0 million for these derivative contracts and recorded a loss of $1.7 million in second quarter 2011, which is included in continuing operations. As required by cash flow hedge accounting rules, a $25.1 million pretax gain in AOCI related to these hedges was recognized in earnings during 2011 as the hedged production occurred. The hedges assumed by the buyer as part of the sale were not designated to our Barnett Shale production and were sold to balance our volumes hedged.

In fourth quarter 2011, we exchanged unproved property in Ohio for unproved property in Pennsylvania where we also received $11.5 million in cash as part of the transaction. We recorded a $4.5 million gain related to this transaction. In third quarter 2011, we sold various producing properties located in East Texas for proceeds of $10.5 million. We recognized an impairment charge of $31.2 million in third quarter 2011 related to these East Texas properties. For additional information on this impairment, see Note 12. Also in third quarter 2011, we sold producing properties in Pennsylvania for proceeds of $5.4 million, with no gain or loss recognized, as the sale did not materially impact the depletion rate of the remaining properties in the amortization base. In first quarter 2011, we sold a low pressure pipeline for $14.7 million in proceeds, with no gain or loss recognized.

F-16

2010 Dispositions

In February 2010, we entered into an agreement to sell our tight gas sand properties in Ohio. We closed approximately 90% of the sale in March 2010 and closed the remainder in June 2010. The total proceeds we received were approximately $323.0 million and we recorded a gain of $77.6 million. The agreement had an effective date of January 1, 2010, and consequently operating net revenue after January 1, 2010 was a downward adjustment to the selling price. The proceeds we received were placed in a like-kind exchange account and in June 2010, we used a portion of the proceeds to purchase proved and unproved natural gas properties in Virginia. In September 2010, the like-kind exchange account was closed and the remaining balance of $135.0 million was used to repay amounts outstanding under our credit facility.

Acquisitions

Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying statements 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 June 2010, we purchased proved and unproved natural gas properties in Virginia for approximately $134.5 million. After recording asset retirement obligations, the purchase price allocated $131.3 million to proved property and $3.7 million to unproved property. We used proceeds from our like-kind exchange account to fund this acquisition (see 2010 Dispositions above). No pro forma information has been provided, as the acquisition was not considered significant.

(4) DISCONTINUED OPERATIONS

The following table represents the components of our Barnett Shale operations as discontinued operations for the years ended December 31, 2011 and 2010 (in thousands).


	Year Ended December 31,
	2011		2010
Revenues and other income:
Natural gas, NGLs and oil sales	$	59,185	$	157,778
Gain on the sale of assets		4,771		955
Other		10		67

Total revenues and other income		63,966		158,800

Costs and expenses:
Direct operating		10,080		35,328
Transportation, gathering and compression		5,257		8,624
Production and ad valorem taxes		1,309		7,545
Exploration		37		581
Abandonment and impairment of unproved properties		—		20,233
Interest expense ^(a)		14,791		40,527
Depletion, depreciation and amortization		8,894		88,269
Impairment of proved properties		—		463,244

Total costs and expenses		40,368		664,351

Income (loss) before income taxes		23,598		(505,551	)

Income tax expense (benefit)
Current		—		—
Deferred		8,278		(177,597	)

		8,278		(177,597	)

Net income (loss) from discontinued operations	$	15,320	$	(327,954	)

^(a)	Interest expense is allocated to discontinued operations based on the ratio of net assets of discontinued operations to our consolidated net assets plus long-term debt.

F-17

The carrying values of our Barnett operations were included in discontinued operations in the accompanying consolidated balance sheets, which is comprised of the following (in thousands):


	December 31, 2011
Composition of liabilities of discontinued operations:
Accrued liabilities	$	653

Total current liabilities of discontinued operations	$	653

(5) INCOME TAXES

Our income tax expense from continuing operations was $12.1 million for the year ended December 31, 2012 compared to $35.6 million in 2011 and $50.9 million in 2010. Reconciliation between the statutory federal income tax rate and our effective income tax rate is as follows:


	Year Ended December 31,
	2012			2011			2010
Federal statutory tax rate		35.0	%		35.0	%		35.0	%
State		0.7			7.0			(0.2	)
Non-deductible executive compensation		1.4			3.5			0.2
Valuation allowance		8.8			(0.4	)		1.4
Other		2.2			0.3			0.1

Consolidated effective tax rate		48.1	%		45.4	%		36.5	%

F-18

Income tax provision (benefit) attributable to income from continuing operations before income taxes consists of the following (in thousands):


	2012							2011						2010
	Current			Deferred		Total		Current		Deferred		Total		Current			Deferred		Total
U.S. federal	$	—		$	11,873	$	11,873	$	—	$	30,055	$	30,055	$	—		$	51,280	$	51,280
U.S. state and local		(1,778	)		1,959		181		637		4,865		5,502		(836	)		466		(370	)

Total	$	(1,778	)	$	13,832	$	12,054	$	637	$	34,920	$	35,557	$	(836	)	$	51,746	$	50,910

Significant components of deferred tax assets and liabilities are as follows:


	December 31,
	2012			2011
	(in thousands)
Deferred tax assets:
Current
Deferred compensation	$	6,192		$	8,607
Current portion of asset retirement obligation		961			2,011
Other		8,896			1,423

Total current		16,049			12,041

Non-current
Net operating loss carryforward		56,402			63,568
Deferred compensation		72,904			64,176
Equity compensation		23,363			20,576
AMT credits and other credits		2,761			3,505
Non-current portion of asset retirement obligation		56,764			30,358
Cumulative unrealized mark-to-market (gain) loss		(262	)		2,373
Other		1,379			1,500
Valuation allowance		(9,052	)		(4,534	)

Total non-current		204,259			181,522

Deferred tax liabilities:
Current
Net unrealized gain in AOCI related to hedge derivatives		(49,124	)		(68,636	)
Other		(2,004	)		—
Cumulative unrealized mark-to-market gain		(2,845	)		—

Total current		(53,973	)		(68,636	)

Non-current
Depreciation, depletion and investments		(894,031	)		(862,597	)
Net unrealized gain in AOCI related to hedge derivatives		(4,522	)		(29,415	)
Other		(4,008	)		—

Total non-current		(902,561	)		(892,012	)

Net deferred tax liability	$	(736,226	)	$	(767,085	)

At December 31, 2012, deferred tax liabilities exceeded deferred tax assets by $736.2 million, with $53.6 million of deferred tax liability related to net deferred hedging gains included in AOCI. As of December 31, 2012, we have a $7.1 million valuation allowance on the deferred tax asset related to our deferred compensation plan for planned future distributions to certain 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). As of December 31, 2011, we had a $4.5 million valuation allowance on the deferred tax asset related to our deferred compensation plan.

F-19

At December 31, 2012, we had regular net operating loss (“NOL”) carryforwards of $318.1 million and alternative minimum tax (“AMT”) NOL carryforwards of $292.9 million that expire between 2018 and 2032. Our deferred tax asset related to regular NOL carryforwards at December 31, 2012 was $29.3 million, which is net of the Accounting Standards Codification 718 Stock Compensation reduction for unrealized benefits, related to NOL’s created by excess tax deductions that have not generated current tax benefits. Regular NOLs generally offset taxable income and to such extent, no income tax payments are required. At December 31, 2012, we have AMT credit carryforwards of $665,000 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, 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 2009 and after and we are subject to various state tax examinations for years 2008 and after. We have not extended the statute of limitation period in any income tax jurisdiction. Our 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, 2012. Throughout 2012, our unrecognized tax benefits were not material.

(6) INCOME (LOSS) PER COMMON SHARE

Basic income or loss per share attributable to common shareholders is computed as (i) income or loss attributable to common shareholders (ii) less income allocable to participating securities (iii) divided by weighted average basic shares outstanding. Diluted income or loss per share attributable to common stockholders is computed as (i) basic income or loss attributable to common shareholders (ii) plus diluted adjustments to income allocable to participating securities (iii) divided by weighted average diluted shares outstanding. The following table sets forth a reconciliation of income or loss attributable to common shareholders to basic income or loss attributable to common shareholders and to diluted income or loss attributable to common shareholders (in thousands except per share amounts):


	Year Ended December 31, 2012								Year Ended December 31, 2011									Year Ended December 31, 2010
	Continuing Operations			Discontinued Operations		Total			Continuing Operations			Discontinued Operations			Total			Continuing Operations			Discontinued Operations			Total
Income (loss) as reported	$	13,002		$	—	$	13,002		$	42,706		$	15,320		$	58,026		$	88,698		$	(327,954	)	$	(239,256	)
Participating basic earnings ^(a)		(460	)		—		(460	)		(763	)		(274	)		(1,037	)		(1,574	)		1,120			(454	)

Basic income (loss) attributed to common shareholders		12,542			—		12,542			41,943			15,046			56,989			87,124			(326,834	)		(239,710	)
Reallocation of participating earnings ^(a)		—			—		—			3			2			5			11			(11	)		—

Diluted income (loss) attributed to common shareholders	$	12,542		$	—	$	12,542		$	41,946		$	15,048		$	56,994		$	87,135		$	(326,845	)	$	(239,710	)

Income (loss) per common share:
Basic	$	0.08		$	—	$	0.08		$	0.26		$	0.10		$	0.36		$	0.56		$	(2.09	)	$	(1.53	)
Diluted	$	0.08		$	—	$	0.08		$	0.26		$	0.10		$	0.36		$	0.55		$	(2.07	)	$	(1.52	)

^(a)

Restricted Stock Awards represent participating securities because they participate in nonforfeitable dividends or distributions with common equity owners. Income allocable to participating securities represents the distributed and undistributed earnings attributable to the participating securities. Participating securities, however, do not participate in undistributed net losses.

F-20

The following table provides a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding (in thousands):


	Year Ended December 31,
	2012		2011		2010
Denominator:
Weighted average common shares outstanding – basic		159,431		158,030		156,874
Effect of dilutive securities:
Director and employee stock options and SARs		876		1,411		1,554

Weighted average common shares outstanding – diluted		160,307		159,441		158,428

Weighted average common shares – basic excludes 2.9 million shares at December 31, 2012, 2.9 million shares at December 31, 2011 and 2.8 million shares at December 31, 2010 of restricted stock Liability Awards held in our deferred compensation plans (although all awards are issued and outstanding upon grant). Stock appreciation rights (“SARs”) of 854,000, 795,000 and 2.1 million shares for the years ended December 31, 2012, 2011 and 2010 were outstanding but not included in the computations of diluted net income per share because the grant prices of the SARs were greater than the average market price of the common shares and would be anti-dilutive to the computations.

(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 natural gas and oil properties in the accompanying consolidated balance sheets. If an exploratory well is determined to be impaired, the well costs are charged to exploration expense in the accompanying consolidated statements of operations. The following table reflects the changes in capitalized exploratory well costs for the year ended December 31, 2012, 2011 and 2010 (in thousands except for number of projects):


	2012			2011			2010
Balance at beginning of period	$	93,388		$	23,908		$	19,052
Additions to capitalized exploratory well costs pending the determination of proved reserves		153,250			86,996			28,897
Reclassifications to wells, facilities and equipment based on determination of proved reserves		(184,298	)		(17,516	)		(24,041	)
Divested wells		(4,980	)		—			—
Capitalized exploratory well costs charged to expense		—			—			—

Balance at end of period		57,360			93,388			23,908
Less exploratory well costs that have been capitalized for a period of one year or less		(45,965	)		(83,860	)		(13,181	)

Capitalized exploratory well costs that have been capitalized for a period greater than one year	$	11,395		$	9,528		$	10,727

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year		5			3			4

As of December 31, 2012, the $11.4 million of capitalized exploratory well costs that have been capitalized for more than one year is comprised of two wells waiting on pipelines and three wells not operated by us. Four of the five wells are in our Marcellus Shale area. The following table provides an aging of capitalized exploratory well costs that have been suspended for more than one year as of December 31, 2012 (in thousands):


	Total		2012		2011		2010		2009		2008
Capitalized exploratory well costs that have been capitalized for more than one year	$	11,395	$	970	$	5,946	$	72	$	2,884	$	1,523

F-21

(8) INDEBTEDNESS

We had the following debt outstanding as of the dates shown below (bank debt interest rate at December 31, 2012 is shown parenthetically) (in thousands). No interest was capitalized during 2012, 2011, and 2010:


	December 31,
	2012		2011
Bank debt (2.2%)	$	739,000	$	187,000

Senior subordinated notes:
7.5% senior subordinated notes due 2017		—		250,000
7.25% senior subordinated notes due 2018		250,000		250,000
8.00% senior subordinated notes due 2019, net of $10,815 and $12,033 discount, respectively		289,185		287,967
6.75% senior subordinated notes due 2020		500,000		500,000
5.75% senior subordinated notes due 2021		500,000		500,000
5.00% senior subordinated notes due 2022		600,000		—

Total debt	$	2,878,185	$	1,974,967

Bank Debt

In February 2011, 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, 2012, the facility amount was $1.75 billion and the borrowing base was $2.0 billion. The bank credit facility provides for a borrowing base subject to redeterminations semi-annually and for event-driven unscheduled redeterminations. Our current bank group is comprised of twenty-eight financial institutions, with no one bank holding more than 9% of the total facility. The facility amount may be increased to the borrowing base amount with twenty-day notice, subject to payment of a mutually acceptable commitment fee to those banks agreeing to participate in the facility increase. As of December 31, 2012, the outstanding balance under the bank credit facility was $739.0 million as well as $84.7 million of undrawn letters of credit leaving $926.3 million of borrowing capacity available under the facility amount. The facility matures on February 18, 2016. Borrowings under the bank facility can either be at the Alternate Base Rate (as defined) plus a spread ranging from 0.50% to 1.5% or LIBOR borrowings at the Adjusted LIBO Rate (as defined) plus a spread ranging from 1.5% 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 2.2% for each of the years ended December 31, 2012, 2011 and 2010. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At December 31, 2012, the commitment fee was 0.375% and the interest rate margin was 1.75% on our LIBOR loans and 0.75% on our base rate loans.

Senior Subordinated Notes

In March 2012, we issued $600.0 million aggregate principal amount of 5.00% senior subordinated notes due 2022 (“5.00% Notes”) for net proceeds of $589.5 million after underwriting discounts and commissions of $10.5 million. The 5.00% Notes were issued at par. Interest on the 5.00% Notes is payable semi-annually in February and August and is guaranteed by all of our subsidiary guarantors. We may redeem the 5.00% Notes, in whole or in part, at any time on or after February 15, 2017, at a redemption price of 102.5% of the principal amount as of February 15, 2017, declining to 100% on February 15, 2020 and thereafter. Before February 2015, we may redeem up to 35% of the original aggregate principal amount of the 5.00% Notes at a redemption price equal to 105% of the principal amount thereof, plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings, provided that 65% of the aggregate principal amount of the 5.00% Notes remain outstanding immediately after the occurrence of such redemption and also provided such redemption shall occur within 60 days of the date of closing of the equity offering. The proceeds of the issuance were used to pay down our outstanding credit facility balance and for general corporate purposes.

If we experience a change of control, bondholders may require us to repurchase all or a portion of all of our 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.

F-22

Early Extinguishment of Debt

We called our 7.5% senior subordinated notes due 2017 at 103.75% of par which we redeemed on December 28, 2012. In fourth quarter 2012, we recognized an $11.1 million loss on extinguishment of debt, including transaction call premium cost as well as expensing of deferred financing cost on repurchased debt.

In May 2011, we commenced cash tender offers to purchase the entire outstanding $150.0 million principal amount of our 6.375% senior subordinated notes due 2015 and $250.0 million principal amount of our 7.5% senior subordinated notes due 2016. On May 25, 2011, after the expiration of the tender offers, we accepted for purchase $108.9 million in principal of the 2015 notes at 102.375% of par and $198.8 million in principal of the 2016 notes for 104.00% of par. We subsequently called the remaining 2015 and 2016 notes, redeeming all of the remaining outstanding 2015 notes ($41.1 million) at 102.125% of par on June 24, 2011 and redeeming all of the remaining 2016 notes ($51.2 million) at 103.75% of par on June 24, 2011. During 2011, we recognized an $18.6 million loss on extinguishment of debt, including transaction call premium cost as well as expensing of deferred financing cost on repurchased debt.

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, subject to certain customary release provisions. These circumstances include (i) when a subsidiary guarantor is sold or sells all or substantially all of its assets and (ii) when a subsidiary guarantor is declared “unrestricted” for covenant purposes.

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 4.25 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, 2012.

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, 2012, we were in compliance with these covenants.

Following is the principal maturity schedule for our long-term debt outstanding as of December 31, 2012 (in thousands):


	Year Ended December 31,
2013	$	—
2014		—
2015		—
2016		739,000
2017		—
2018		250,000
Thereafter		1,889,185

	$	2,878,185

(9) ASSET RETIREMENT OBLIGATIONS

Our asset retirement obligations primarily represent the estimated present value of the amounts we will incur to plug, abandon and remediate our producing properties at the end of their productive lives. Significant inputs 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, 2012 and 2011 is as follows (in thousands):

F-23


	2012			2011
Beginning of period	$	84,810		$	60,693
Liabilities incurred		9,802			3,265
Liabilities settled		(3,649	)		(4,717	)
Disposition of wells		(1,457	)		(716	)
Accretion expense		8,793			5,488
Change in estimate		48,179			20,797

End of period		146,478			84,810

Less current portion		(2,470	)		(5,005	)

Long-term asset retirement obligations – continuing operations	$	144,008		$	79,805

Accretion expense is recognized as an increase to depreciation, depletion and amortization expense in the accompanying statements 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 2010:


	Year Ended December 31,
	2012		2011		2010
Beginning balance		161,131,547		159,909,052		158,118,937
Stock options/SARs exercised		926,425		862,774		991,988
Restricted stock grants		354,674		326,591		405,127
Restricted stock units vested		57,824		—		—
Issued for acreage purchases		—		—		380,229
Treasury shares		43,628		33,130		12,771

Ending balance		162,514,098		161,131,547		159,909,052

Common Stock Dividends

The Board of Directors declared quarterly dividends of $0.04 per common share for each of the four quarters of 2012, 2011 and 2010. 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 our Board of Directors deem relevant. Our bank credit facility and our senior subordinated notes allow for the payment of common dividends, with certain limitations. Dividends are limited to our legally available funds.

F-24

(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 as we typically utilize commodity swap or 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. In 2011, we sold NGLs derivative swap contracts (“sold swaps”) for the natural gasoline (or C5) component of natural gas liquids and in 2012, we entered into purchased NGLs derivative swaps (“re-purchased swaps”) for C5 volumes. These re-purchased swaps were, in some cases, with the same counterparties as our sold swaps. We entered into these re-purchased swaps to lock in certain natural gasoline derivative gains. In second quarter 2012, we also entered into NGLs derivative swap contracts for the propane (or C3) component of NGLs. These C5 and C3 derivatives are intended to manage our exposure to NGLs commodity price fluctuations. At December 31, 2012, we had open swap contracts covering 77.9 Bcf of natural gas at prices averaging $3.64 per mcf, 3.3 million barrels of oil at prices averaging $95.70 per barrel, 2.4 million net barrels of NGLs (the C5 component of NGLs) at prices averaging $92.72 per barrel and 1.8 million barrels of NGLs (the C3 component of NGLs) at prices averaging $35.55 per barrel. At December 31, 2012, we had collars covering 242.7 Bcf of gas at weighted average floor and cap prices of $4.13 to $4.72 per mcf and 1.8 million barrels of oil at weighted average floor and cap prices of $88.58 to $100.00 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 $144.3 million at December 31, 2012. These contracts expire monthly through December 2014. The following table sets forth the derivative volumes by year as of December 31, 2012.


Period	Contract Type	Volume Hedged	Weighted Average Hedge Price
Natural Gas
2013	Collars	280,000 Mmbtu/day	$4.59–$ 5.05
2014	Collars	385,000 Mmbtu/day	$3.80–$ 4.48
2013	Swaps	213,384 Mmbtu/day	$3.64

Crude Oil
2013	Collars	3,000 bbls/day	$90.60–$ 100.00
2014	Collars	2,000 bbls/day	$85.55–$ 100.00
2013	Swaps	5,081 bbls/day	$96.59
2014	Swaps	4,000 bbls/day	$94.56

NGLs (Natural Gasoline)
2013	Sold Swaps	8,000 bbls/day	$89.64
2013	Re-purchased Swaps	1,500 bbls/day	$76.30

NGLs (Propane)
2013	Swaps	5,000 bbls/day	$35.55

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 derivatives that qualify for hedge accounting are recorded as a component of AOCI in the stockholders’ equity section of the accompanying consolidated balance sheets, which is later transferred to natural gas, NGLs and oil sales when the underlying physical transaction occurs and the hedging contract is settled. As of December 31, 2012, an unrealized pre-tax derivative gain of $137.6 million was recorded in AOCI. This gain will be reclassified into earnings as a gain of $127.3 million in 2013 and a gain of $10.3 million in 2014 as the contracts are sold but the actual reclassification to earnings will be based on 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.

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 natural gas, NGLs and oil sales in the period the hedged production is sold. Natural gas, NGLs and oil sales include $236.3 million of gains in 2012 compared to gains of $123.6 million in 2011 and gains of $64.8 million in 2010 related to settled hedging transactions. Any ineffectiveness associated with these hedge derivatives are reflected in derivative fair value income in the accompanying statements of operations. The ineffective portion is calculated as the difference between the changes in fair value of the derivative and the estimated change in future cash flows from the item hedged. Derivative fair value income for the year ended December 31, 2012 includes ineffective gains (unrealized and realized) of $1.1 million compared to $9.5 million in 2011 and $2.0 million in 2010.

F-25

Basis Swap Contracts

At December 31, 2012, we had natural gas basis swap contracts that are not designated for hedge accounting which lock in the differential between NYMEX and those of our physical pricing points, which settle in first quarter 2013. The fair value of these contracts was $993,000 on December 31, 2012.

Derivative fair value income

The following table presents information about the components of derivative fair value income in the three-year period ended December 31, 2012 (in thousands):


	2012			2011			2010
Change in fair value of derivatives that do not qualify for hedge accounting ^(a)	$	5,958		$	15,762		$	(2,086	)
Realized gain (loss) on settlement–natural gas ^(a) ^(b)		131			14,743			35,988
Realized gain (loss) on settlement–oil ^{(a) (b)}		2,486			(9,574	)		—
Realized gain (loss) on settlement–NGLs ^{(a) (b)}		31,737			9,612			—
Realized gain on early settlement of oil derivatives		—			—			15,697
Hedge ineffectiveness–realized		4,346			7,361			(352	)
–unrealized		(3,221	)		2,183			2,387

Derivative fair value income	$	41,437		$	40,087		$	51,634

^(a)	Derivatives that do not qualify for hedge accounting.

^(b)	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 the accompanying consolidated balance sheets as of December 31, 2012 and 2011 is summarized below (in thousands). As of December 31, 2012, we are conducting derivative activities with fifteen financial institutions, of which all but two 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 and we have master netting arrangements.


	December 31,
	2012			2011
Derivative assets:
Natural gas–swaps	$	7,504		$	54,162
–collars		122,255			228,228
–basis swaps		993			—
Crude oil–swaps		9,650			(263	)
–collars		2,222			(16,607	)
–call options		—			(29,348	)
NGLs–C5 swaps		10,643			15,328

	$	153,267		$	251,500

Derivative liabilities:
Natural gas–collars	$	(3,463	)	$	—
NGLs–C5 swaps		2,275			(173	)
–C3 swaps		(6,746	)		—

	$	(7,934	)	$	(173	)

F-26

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 the accompanying consolidated balance sheets (in thousands):


	December 31, 2012								December 31, 2011
	Assets		(Liabilities)						Assets		(Liabilities)
	Carrying Value		Carrying Value			Net Carrying Value			Carrying Value		Carrying Value			Net Carrying Value
Derivatives that qualify for cash flow hedge accounting :
Swaps ^(a)	$	22,236	$	(3,242	)	$	18,994		$	54,318	$	(419	)	$	53,899
Collars ^(a)		129,878		(9,721	)		120,157			228,228		(1,954	)		226,274

	$	152,114	$	(12,963	)	$	139,151		$	282,546	$	(2,373	)	$	280,173

Derivatives that do not qualify for hedge accounting :
Sold swaps ^(a)	$	7,316	$	(8,904	)	$	(1,588	)	$	17,949	$	(2,794	)	$	15,155
Re-purchased swaps ^(a)		5,920		—			5,920			—		—			—
Collars ^(a)		857		—			857			—		(14,653	)		(14,653	)
Call options ^(a)		—		—			—			—		(29,348	)		(29,348	)
Basis swaps ^(a)		993		—			993			—		—			—

	$	15,086	$	(8,904	)	$	6,182		$	17,949	$	(46,795	)	$	(28,846	)

^(a)	Included in unrealized derivative gain or loss in the accompanying consolidated balance sheets.

The effects of our cash flow hedges (or those derivatives that qualify for hedge accounting) on accumulated other comprehensive income in the accompanying consolidated balance sheets is summarized below:


	Year Ended December 31,
	Change in Hedge Derivative Fair Value						Realized Gain Reclassified from OCI into Revenue ^(a)
	2012			2011			2012			2011
Swaps	$	46,371		$	51,997		$	78,779		$	—
Put options		(1,955	)		—			(1,955	)		—
Collars		74,766			223,408			159,481			123,594
Collars – discontinued operations		—			412			—			8,607
Income taxes		(47,466	)		(104,464	)		(91,871	)		(50,005	)

	$	71,716		$	171,353		$	144,434		$	82,196

^(a)	For realized gains upon contract settlement, the reduction in AOCI is offset by an increase in natural gas, NGLs and oil sales. For realized losses upon contract settlement, the increase in AOCI is offset by a decrease in natural gas, NGLs and oil sales.

The effects of our non-hedge derivatives (or those derivatives that do not qualify for hedge accounting) and the ineffective portion of our hedge derivatives on our consolidated statements of operations is summarized below:


	Year Ended December 31,
	Gain (Loss) Recognized in Income (Non-hedge Derivatives)									Gain (Loss) Recognized in Income (Ineffective Portion)							Derivative Fair Value Income
	2012			2011			2010			2012			2011		2010		2012			2011			2010
Swaps	$	11,601		$	24,767		$	—		$	(657	)	$	767	$	—	$	10,944		$	25,534		$	—
Re-purchased swaps		9,313			—			—			—			—		—		9,313			—			—
Collars		5,126			5,266			65,996			1,782			8,777		2,035		6,908			14,043			68,031
Call options		13,178			553			(15,895	)		—			—		—		13,178			553			(15,895	)
Put options		(30	)		—			—			—			—		—		(30	)		—			—
Basis swaps		1,124			(43	)		(502	)		—			—		—		1,124			(43	)		(502	)

Total	$	40,312		$	30,543		$	49,599		$	1,125		$	9,544	$	2,035	$	41,437		$	40,087		$	51,634

F-27

The United States Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivative market and entities, such as Range, that participate in that market. The new regulation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act required the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation. In July 2012 certain definitions were adopted by the SEC and the CFTC and based on those definitions, we believe we will qualify for the end-user exception related to the clearing requirement for swaps but we will be required to adhere to new reporting requirements.

(12) FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

•

Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

•

Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

•

Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities 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.

F-28

Fair Values-Recurring

We use a market approach for our recurring 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 tables present the fair value hierarchy table for assets and liabilities measured at fair value, on a recurring basis (in thousands):


	Fair Value Measurements at December 31, 2012 Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2012
Trading securities held in the deferred compensation plans	$	57,776	$	—	$	—	$	57,776
Derivatives–swaps		—		23,326		—		23,326
–collars		—		121,014		—		121,014
–basis swaps		—		993		—		993


	Fair Value Measurements at December 31, 2011 Using:
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total Carrying Value as of December 31, 2011
Trading securities held in the deferred compensation plans	$	50,237	$	—		$	—	$	50,237
Derivatives–swaps		—		69,054			—		69,054
–collars		—		211,621			—		211,621
–call options		—		(29,348	)		—		(29,348	)

Our trading securities in Level 1 are exchange-traded and measured at fair value with a market approach using December 31, 2012 market values. 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 other assets in the accompanying consolidated balance sheets. 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 deferred compensation plan expense in the accompanying statement of operations. For the year ended December 31, 2012, interest and dividends were $1.4 million and mark-to-market was a gain of $4.7 million. For the year ended December 31, 2011, interest and dividends were $1.4 million and mark-to-market was a loss of $2.3 million. For the year ended December 31, 2010, interest and dividends were $864,000 and the mark-to-market was a gain of $11.5 million.

Fair Values-Non recurring

We review our long-lived assets to be held and used for impairment, including proved natural gas and oil properties, whenever events or circumstances indicate the carrying value of those assets may not be recoverable. During the year ended December 31, 2012, we recognized charges for impairment of oil and gas properties in continuing operations of $34.3 million compared to $38.7 million in 2011 and $6.5 million in 2010. Also in 2012, we evaluated certain surface property we own which included a consideration for the potential sale of the assets and we recognized an impairment charge of $1.3 million. Discontinued operations includes an impairment charge related to our Barnett Shale assets of $463.2 million in 2010.

F-29

Continuing Operations

Due to declines in commodity prices and estimated reserves over the last three years, there were indications that the carrying values of certain of our oil and gas properties may be impaired and undiscounted future cash flows attributed to these assets indicated their carrying amounts were not expected to be recovered. Their fair value was measured using an income approach based upon internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. In some cases, we also considered the potential sale of certain of these properties. We recorded non-cash charges during 2012 of $31.1 million related to our Mississippi natural gas and oil properties and $3.2 million related to oil and natural gas properties in North Texas. We recorded non-cash charges during 2011 of $31.2 million related to our East Texas natural gas and oil properties and $7.5 million related to our Gulf Coast onshore properties. 2010 includes impairment charges of $6.5 million related to our Gulf Coast onshore properties.

The following table presents the value of these assets measured at fair value on a nonrecurring basis (in thousands):


	Year Ended December 31,
	2012				2011				2010
	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Natural gas and oil properties – continuing operations	$	12,604	$	34,273	$	24,388	$	38,681	$	16,075	$	6,505
Natural gas and oil properties – discontinued operations		—		—		—		—		835,913		463,244
Surface property		6,269		1,281		—		—		—		—

Discontinued Operations

Our Barnett properties did not meet held for sale criteria as of December 31, 2010 but our analysis determined that undiscounted cash flows for these properties were less than their carrying value. We compared the carrying value to the estimated fair value and recognized an impairment charge of $463.2 million in fourth quarter 2010, which is reflected in discontinued operations. The fair value of our Barnett properties considered the potential sale of these properties in addition to using an income approach with internal estimates which included reserve quantities, forward natural gas prices, anticipated drilling and operating costs and discount rates, which are Level 3 inputs.

F-30

Fair Values – Reported

The following table presents the carrying amounts and the fair values of our financial instruments as of December 31, 2012 and 2011 (in thousands):


	December 31, 2012						December 31, 2011
	Carrying Value			Fair Value			Carrying Value			Fair Value
Assets:
Commodity swaps, collars, basis swaps, call and put options	$	153,267		$	153,267		$	251,500		$	251,500
Marketable securities^(a)		57,776			57,776			50,237			50,237
Liabilities:
Commodity swaps, collars and call options		(7,934	)		(7,934	)		(173	)		(173	)
Bank credit facility^(b)		(739,000	)		(739,000	)		(187,000	)		(187,000	)
Deferred compensation plan^(c)		(187,604	)		(187,604	)		(169,188	)		(169,188	)
7.5% senior subordinated notes due 2017^(b)		—			—			(250,000	)		(265,625	)
7.25% senior subordinated notes due 2018^(b)		(250,000	)		(262,500	)		(250,000	)		(267,500	)
8.00% senior subordinated notes due 2019^(b)		(289,185	)		(332,250	)		(287,967	)		(334,500	)
6.75% senior subordinated notes due 2020^(b)		(500,000	)		(542,500	)		(500,000	)		(555,000	)
5.75% senior subordinated notes due 2021^(b)		(500,000	)		(535,000	)		(500,000	)		(541,250	)
5.00% senior subordinated notes due 2022^(b)		(600,000	)		(627,000	)		—			—

^(a)	Marketable securities are held in our deferred compensation plans that are actively traded on major exchanges.

^(b)	The book value of our bank debt approximates fair value because of its floating rate structure. The fair value of our senior subordinated notes is based on end of period market quotes, which are Level 2 inputs.

^(c)	The fair value of our deferred compensation plan is updated based on the closing price on the balance sheet date.

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 current assets and liabilities 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.

Concentrations of Credit Risk

As of December 31, 2012, our primary concentration of credit risks are the risks of collecting accounts receivable and the risk of counterparties’ failure to perform under derivative obligations. See Note 2 for information regarding our accounts receivable and derivative assets and liabilities by counterparty and Note 16 for information regarding our major customers.

(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 have been 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 Director Plan.

Stock-Based Awards

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 expired five years from the date they are granted. Beginning in 2005, we began granting SARs to reduce the dilutive impact of our equity plans. Similar to stock options, SARs represent the right to receive a payment equal to the excess of the fair market value of shares of common stock on the date the right is exercised over the value of the stock on the date of grant. All SARs granted under the 2005 Plan will be settled in shares of stock, vest over a three-year period and have a maximum term of five years from the date they are granted.

F-31

Beginning in first quarter 2011, the compensation committee also began granting restricted stock units under our equity-based stock compensation plans. These restricted stock units, which we refer to as restricted stock Equity Awards, vest over a three-year period. All awards granted have been issued at prevailing market prices at the time of grant and the vesting of these shares is based upon an employee’s continued employment with us.

The Compensation Committee also 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 (by the trustee) and receive dividends thereon. Upon grant of these restricted shares, which we refer to as restricted stock Liability Awards, the shares are placed in our deferred compensation plan and, upon vesting, employees are allowed to take withdrawals either in cash or in stock. These Liability Awards are classified as a liability and are remeasured at fair value each reporting period. This mark-to-market amount is reported in deferred compensation plan expense in the accompanying consolidated statements of operations. Historically, we have used authorized but unissued shares of stock when restricted stock is granted. However, we also utilize treasury shares when available.

Total Stock-Based Compensation Expense

Stock-based compensation represents amortization of restricted stock grants and SARs expense. In 2012, stock-based compensation was allocated to operating expense ($2.4 million), exploration expense ($4.1 million), brokered natural gas and marketing ($1.8 million) and general and administrative expense ($44.5 million) for a total of $52.8 million. In 2011, stock-based compensation was allocated to operating expense ($2.0 million), exploration expense ($4.1 million), brokered natural gas and marketing ($1.5 million) and general and administrative expense ($36.2 million) for a total of $43.8 million. In 2010, stock-based compensation was allocated to operating expense ($2.0 million), exploration expense ($4.2 million), brokered natural gas and marketing ($1.2 million), general and administrative expense ($34.2 million) and termination costs ($2.8 million) for a total of $44.4 million. Unlike the other forms of stock-based compensation mentioned above, the mark-to-market of the liability related to 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, 2012, cash received upon exercise of stock options/SARs awards was $2.1 million. For the year ended December 31, 2012 and 2010, tax benefits realized for deductions that were in excess of the stock-based compensation expense were not recognized due to our net operating loss position. In 2011, as a result of realizing federal taxable income, a tax benefit of $11.7 million has been recognized in our net operating loss carryforward for the excess tax deduction over our stock-based compensation expense.

Stock and Option Plans

We have two active equity-based stock plans, the 2005 Plan and the Director Plan. Under these plans, incentive and non-qualified stock options, stock appreciation rights, restricted stock units and various other 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. Of the 3.4 million grants outstanding at December 31, 2012, grants of 32,000 relate to stock options with the remainder of the 3.4 million outstanding grants relating to SARs. Information with respect to stock option and SARs activities is summarized below.


	Shares			Weighted Average Exercise Price
Outstanding at December 31, 2009		7,154,712		$	31.38
Granted		1,394,136			46.09
Exercised		(1,883,091	)		20.49
Expired/forfeited		(203,918	)		48.18

Outstanding at December 31, 2010		6,461,839			37.20
Granted		843,485			51.17
Exercised		(2,511,989	)		32.69
Expired/forfeited		(234,726	)		52.65

Outstanding at December 31, 2011		4,558,609			41.47
Granted		754,471			64.14
Exercised		(1,860,367	)		30.20
Expired/forfeited		(19,351	)		48.00

Outstanding at December 31, 2012		3,433,362		$	52.52

F-32

The following table shows information with respect to stock options and SARs outstanding and exercisable at December 31, 2012:


	Outstanding						Exercisable
Range of Exercise Prices	Shares		Weighted Average Remaining Contractual Life (in years)		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
$1.29–$ 9.99		17,015		0.67	$	2.36		17,015	$	2.36
10.00–19.99		15,435		2.73		19.63		15,435		19.63
20.00–29.99		—		—		—		—		—
30.00–39.99		226,838		1.19		34.30		223,458		34.23
40.00–49.99		1,543,269		2.15		45.38		903,347		44.22
50.00–59.99		534,922		3.09		52.86		222,686		53.59
60.00–69.99		767,013		4.01		64.17		96,534		64.57
70.00–75.00		328,870		0.35		75.00		328,870		75.00

Total		3,433,362		2.47	$	52.52		1,807,345	$	50.22

Stock Appreciation Right Awards

During 2012, 2011 and 2010, 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:


	2012			2011			2010
Weighted average exercise price per share	$	64.14		$	51.17		$	46.09
Expected annual dividends per share		0.25	%		0.31	%		0.35	%
Expected life in years		3.7			3.7			3.6
Expected volatility		45	%		47	%		49	%
Risk-free interest rate		0.5	%		1.4	%		1.6	%
Weighted average grant date fair value	$	21.32		$	18.22		$	17.01

The expected dividend yield is based on the current annual dividend at the time of grant. The expected life was based on the historical exercise activity. The expected 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, 2012 was $61.0 million compared to $62.5 million in 2011 and $50.6 million in 2010. As of December 31, 2012, the aggregate intrinsic value of the awards outstanding was $40.4 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option/SARs awards currently exercisable was $27.0 million and 1.62 years. As of December 31, 2012, the number of fully vested awards and awards expected to vest was 3.3 million. The weighted average exercise price and weighted average remaining contractual life of these awards were $52.45 and 2.43 years and the aggregate intrinsic value was $39.0 million. As of December 31, 2012, unrecognized compensation cost related to the awards was $16.7 million, which is expected to be recognized over a weighted average period of 1.8 years.

Restricted Stock Awards

Equity Awards

In 2012, we granted 364,000 restricted stock Equity Awards to employees which generally vest over a three-year period. We recorded compensation expense for these awards of $11.8 million in the year ended December 31, 2012. In 2011, we granted 331,000 restricted stock Equity Awards to employees and recorded compensation expense of $4.2 million. As of December 31, 2012, there was $15.4 million of unrecognized compensation related to Equity Awards expected to be recognized over a weighted average period of 2.0 years. Equity Awards are not issued to employees until such time they are vested and the employees do not have the option to receive cash.

F-33

Liability Awards

In 2012, we granted 381,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $64.06. This grant included 14,700 issued to non-employee directors, which vest immediately and 366,300 to employees with vesting generally over a three-year period. In 2011, we granted 352,000 shares of restricted stock Liability Awards as compensation to directors and employees at an average price of $51.17. This grant included 18,000 issued to non-employee directors, which vest immediately and 334,000 to employees with vesting generally over a three-year period. In 2010, we granted 413,000 shares of Liability Awards as compensation to directors and employees at an average price of $45.83. This grant included 21,000 issued to non-employee directors, which vest immediately, and 392,000 to employees with vesting generally over a three-year period. We recorded compensation expense for these Liability Awards of $21.5 million in the year ended December 31, 2012 compared to $19.1 million in 2011 and $20.5 million in 2010. As of December 31, 2012, there was $21.6 million of unrecognized compensation related to Liability Awards expected to be recognized over a weighted average period of 1.9 years. Substantially all of these awards are held in our deferred compensation plan, are classified as liability 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 $26.6 million in 2012.

A summary of the status of our non-vested restricted stock outstanding at December 31, 2012 is summarized below:


	Equity Awards					Liability Awards
	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2009		—		$	—		627,189		$	45.64
Granted		—			—		413,422			45.83
Vested		—			—		(439,361	)		46.90
Forfeited		—			—		(18,499	)		46.04

Outstanding at December 31, 2010		—			—		582,751			44.81
Granted		331,209			49.56		352,419			51.17
Vested		(88,854	)		49.37		(418,634	)		45.55
Forfeited		(20,746	)		49.45		(29,292	)		45.04

Outstanding at December 31, 2011		221,609			49.64		487,244			48.76
Granted		364,082			63.44		380,808			64.06
Vested		(208,802	)		56.73		(438,283	)		52.17
Forfeited		(27,733	)		58.65		(6,291	)		54.54

Outstanding at December 31, 2012		349,156		$	59.08		423,478		$	58.91

401(k) Plan

We maintain a 401(k) benefit plan that allows employees to contribute up to 75% 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. Beginning in 2013, vesting of our contributions will be immediate. In 2012, we contributed $4.0 million to the 401(k) Plan compared to $3.3 million in 2011. Employees have a variety of investment options in the 401(k) benefit plan.

Deferred Compensation Plan

Our 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 partial matching contribution which vests over three years. The assets 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 in the accompanying consolidated balance sheets and is adjusted to fair value each reporting period by a charge or credit to deferred compensation plan expense on our consolidated statements 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 in the accompanying consolidated balance sheets. The deferred compensation liability reflects the vested

F-34

market value of the marketable securities and Range stock held in the Rabbi Trust. Changes in the market value of the marketable securities and changes in the fair value of the deferred compensation plan liability are charged or credited to deferred compensation plan expense each quarter. We recorded a mark-to-market loss of $7.2 million in 2012 compared to mark-to-market loss of $43.2 million in 2011 and mark-to-market gain of $10.2 million in 2010. The Rabbi Trust held 2.7 million shares (2.3 million of vested shares) of Range stock at December 31, 2012 compared to 2.8 million shares (2.3 million of vested shares) at December 31, 2011.

(14) SUPPLEMENTAL CASH FLOW INFORMATION


	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Net cash provided from operating activities included:
Income taxes paid (refunded from) to taxing authorities	$	386	$	675	$	(1,359	)
Interest paid		153,249		133,103		116,766

Non-cash investing and financing activities included:
Asset retirement costs (removed) capitalized, net		57,982		24,061		(6,370	)
Unproved property purchased with stock		—		—		20,000

(15) COMMITMENTS AND CONTINGENCIES

Litigation

James A. Drummond and Chris Parrish v. Range Resources-Midcontinent, LLC et al.

Two individuals, one a current royalty owner, filed suit against Range Resources Corporation and two of our subsidiaries, including the proper defendant Range Resources-Midcontinent, LLC, in the District Court of Grady County, Oklahoma. This suit is similar to a number of cases filed in Oklahoma asserting claims that royalty owners are entitled to payment of royalties on several different categories of alleged “deductions” applied by third parties who transport and process natural gas production. The alleged deductions include fuel used by the third party in the transportation and processing of gas; condensate removed by the third party after the point of sale, the contractually agreed natural gas liquids recovery percentages, the percentage of proceeds contracts’ contractually agreed pricing percentages and other similar alleged “deductions.” In addition to the claims made with respect to the alleged categories of deductions, the Plaintiffs in this litigation have alleged fraud and the existence of a fiduciary duty to the royalty owners to attempt to support an argument that no statute of limitations applies, and the Plaintiffs also claim that interest accrues on the alleged damages at 12% compounded annually. Thus while we cannot reasonably estimate our potential exposure at this time, the damages claimed by the Plaintiffs have been estimated by the Plaintiffs’ counsel to be in excess of $140 million. We believe Oklahoma is a “first marketable product” rule state and the current case law in Oklahoma (principally Mittelstaedt v. Santa Fe) allows operators to deduct value enhancing costs for treating, compression, and other post-production expenses incurred to increase the value of a marketable product; however, whether and when gas is a marketable product and the extent to which the deductions are permitted may be fact questions under Oklahoma law. Further, we do not typically transport and process the gas production from wells we operate in Oklahoma but instead sell the gas production to unaffiliated third parties which, in many cases, do transport and process the gas. Range maintains that the alleged “deductions” made the subject of the Plaintiffs’ claims are not deductions at all but the negotiated terms of the contracts with the third parties who buy, transport and process the gas under terms that allow Range and its royalty owners to share in the enhanced downstream value that establishes the purchase price for the production sold by us, and on which we have paid royalty. Range further believes that its production is marketable under Oklahoma law when sold to such unaffiliated third parties. The terms with respect to payment of royalties vary based on the terms of the various oil and gas leases owned by Range for its Oklahoma wells and wells it has owned and operated in Oklahoma in the past, and our subsidiary believes that it has substantially complied with its royalty payment obligations under its leases and we therefore intend to vigorously defend this litigation. On February 19, 2013, the District Court entered an order certifying a class of royalty owners as requested by the Plaintiffs and we intend to appeal the class certification order.

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 and amounts related to discontinued operations) totaled $13.8 million in 2012 compared to $18.6 million in 2011 and $18.5 million in 2010. Commitments related to these lease payments are not recorded in the accompanying 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):


	Operating Lease Obligations
2013	$	13,497
2014		13,645
2015		13,363
2016		10,090
2017		5,923
Thereafter		21,628

	$	78,146

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Transportation and Gathering Contracts

We have entered firm transportation and gathering contracts with various pipeline carriers for the future transportation and gathering of natural gas, NGLs and oil production primarily from our properties in Pennsylvania. Under these contracts, we are obligated to transport or gather minimum daily natural 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, 2012, future minimum transportation and gathering fees under our commitments are as follows (in thousands):


	Transportation and Gathering Contracts
2013	$	184,802
2014		177,027
2015		182,884
2016		185,709
2017		181,995
Thereafter		825,717

	$	1,738,134

In addition to the amounts included in the above table, we have contracted with several pipeline companies through 2028 to transport natural gas, ethane and propane production volumes from certain Marcellus Shale wells. These agreements and related fees, which are contingent on certain pipeline modifications and/or pipeline construction, are for 12,329 mcfe per day in 2013, 164,918 mcfe per day in 2014, 254,836 mcfe per day in 2015 and 435,000 mcfe per day until the end of the contractual term.

Drilling Contracts

As of December 31, 2012, we have contracts with drilling contractors to use three drilling rigs with terms of up to three years and minimum future commitments of $22.1 million in 2013, $10.8 million in 2014 and $6.7 in 2015. Early termination of these contracts at December 31, 2012 would have required us to pay maximum penalties of $20.6 million. We do not expect to pay any early termination penalties related to these contracts.

Delivery Commitments

We have various volume delivery commitments that are primarily related to our Midcontinent and Marcellus areas. We expect to be able to fulfill our contractual obligations from our own production, however; we may purchase third party volumes to satisfy our commitments or pay demand fees for commitment shortfalls, should they occur. As of December 31, 2012, our delivery commitments through 2017 were as follows:


Year Ending December 31,	Natural Gas and Ethane (mcfe per day)
2013		196,532
2014		203,123
2015		147,263
2016		102,318
2017		52,055

In addition to the amounts included in the above table, we have contracted with several pipeline companies through 2028 to deliver ethane production volumes in Appalachia from our Marcellus Shale wells. These agreements and related fees, which are contingent upon pipeline construction and/or modification, are for 15,123 mcfe per day in 2013, 90,000 mcfe per day in 2014, 162,658 mcfe per day in 2015 and 210,000 mcfe per day until the end of the contractual terms.

Other

We have agreements in place for hydraulic fracturing including related equipment, material and labor for $24.0 million in 2013. We also have agreements to purchase seismic data for $5.3 million in 2013 and $3.9 million in 2014. We also have lease acreage that is generally subject to lease expiration if initial wells are not drilled within a specified period, generally between three to five 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 a significant component of our cost structure and is 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.

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(16) MAJOR CUSTOMERS

We sell our share of our production to various purchasers. We record allowance for doubtful accounts based on the age of the accounts receivable, the financial condition of the purchasers and we may require purchasers to provide collateral or otherwise secure their account. For the years ended December 31, 2012 and 2011, we had two customers that accounted for 10% or more of total natural gas, NGLs and oil sales. For the year ended December 31, 2010, we had no customers that accounted for 10% or more of total natural gas, NGLs and oil sales. We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, NGLs and oil production.

(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 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.

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 brokered natural gas, marketing and other revenue in the accompanying statements of operations for 2012, 2011 and 2010. 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, 2012, our equity in the income of Whipstock totaled $818,000 compared to losses of $481,000 in 2011 and losses of $2.2 million in 2010. In 2012, equity in the losses of Whipstock was reduced by $14,000 to eliminate the profit on services provided to us compared to $6,000 in 2011 and $1.1 million in 2010. Our net book value in this equity investment was $2.0 million at December 31, 2012. 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 (“EQT”). 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. In 2012, 2011 or 2010, Range and EQT made no additional contributions 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 brokered natural gas, marketing and other revenue in the accompanying statements of operations for 2012, 2011 and 2010. There were no dividends or partnership distributions received from NGLLC in the year ended December 31, 2010. In 2011, we received partnership distributions of $23.5 million and in 2012, we received partnership distributions of $12.8 million. 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, 2012, our equity in losses of NGLLC of $1.2 million reflects a reduction of $7.5 million to eliminate the profit on the gathering and transportation fees charged to us. For the year ended December 31, 2011, our equity in the losses of NGLLC of $563,000 reflects a reduction of $7.7 million to eliminate the profit on the gathering and transportation fees charged to us. For the year ended December 31, 2010, our equity in the income of NGLLC of $684,000 reflects a reduction of $8.8 million to eliminate the profit on gathering and transportation fees charged to us. Our net book value in this equity investment was $130.5 million at December 31, 2012.

F-37

(18) OFFICE CLOSING AND EXIT ACTIVITIES

In February 2010, we entered into an agreement to sell our natural gas and oil properties in Ohio. First quarter 2010 includes $5.1 million accrued severance costs, which is reflected in termination costs in the accompanying consolidated statements of operations. As part of their severance agreement, our Ohio employees’ vesting of SARs and restricted stock grants was accelerated, increasing termination costs for stock compensation expense by approximately $2.8 million.


	2012			2011			2010
Beginning balance	$	52		$	1,092		$	1,568
Accrued one-time termination costs		—			—			5,138
Office lease		—			—			514
Payments		(52	)		(1,040	)		(6,128	)

Ending balance	$	—		$	52		$	1,092

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(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. We have reclassified prior period other revenue and total expenses as discussed in Note 2. Income (loss) from continuing operations did not change because the offsetting amounts are included in brokered natural gas and marketing expense. Abandonment and impairment of unproved properties in the fourth quarter 2011 includes $3.0 million related to prior years. In addition, deferred tax expense in fourth quarter 2011 includes $3.1 million related to prior years.


	2012
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	317,617		$	298,349		$	337,040		$	398,688		$	1,351,694
Derivative fair value (loss) income		(60,833	)		148,569			(40,728	)		(5,571	)		41,437
(Loss) gain on the sale of assets		(10,426	)		(3,227	)		949			61,836			49,132
Brokered natural gas, marketing and other		4,597			5,240			2,519			3,085			15,441

Total revenue and other income		250,955			448,931			299,780			458,038			1,457,704

Costs and expenses:
Direct operating		29,022			27,041			29,628			30,214			115,905
Transportation, gathering and compression		40,820			44,744			51,600			55,281			192,445
Production and ad valorem taxes		36,634			11,786			8,819			9,881			67,120
Brokered natural gas marketing		4,062			6,491			4,887			4,994			20,434
Exploration		21,516			15,517			14,752			18,022			69,807
Abandonment and impairment of unproved properties		20,289			43,641			40,118			21,230			125,278
General and administrative		38,729			44,005			44,497			46,582			173,813
Deferred compensation plan		(7,830	)		9,333			20,052			(14,352	)		7,203
Interest expense		37,205			42,888			43,997			44,708			168,798
Loss on early extinguishment of debt		—			—			—			11,063			11,063
Depletion, depreciation and amortization		100,151			108,802			123,059			113,216			445,228
Impairment of proved properties and other		—			—			1,281			34,273			35,554

Total costs and expenses		320,598			354,248			382,690			375,112			1,432,648

(Loss) income from continuing operations before income taxes		(69,643	)		94,683			(82,910	)		82,926			25,056

Income tax (benefit) expense
Current		—			—			—			(1,778	)		(1,778	)
Deferred		(27,843	)		39,007			(29,074	)		31,742			13,832

		(27,843	)		39,007			(29,074	)		29,964			12,054

Net (loss) income	$	(41,800	)	$	55,676		$	(53,836	)	$	52,962		$	13,002

(Loss) income per common share:
Basic	$	(0.26	)	$	0.34		$	(0.34	)	$	0.33		$	0.08
Diluted	$	(0.26	)	$	0.34		$	(0.34	)	$	0.32		$	0.08

F-39


	2011
	March			June			September			December			Total
Revenues and other income:
Natural gas, NGLs and oil sales	$	251,963		$	285,353		$	304,230		$	331,720		$	1,173,266
Derivative fair value (loss) income		(40,834	)		53,039			65,761			(37,879	)		40,087
Gain (loss) on the sale of assets		139			(1,622	)		203			3,540			2,260
Brokered natural gas, marketing and other		3,911			1,506			3,775			5,837			15,029

Total revenue and other income		215,179			338,276			373,969			303,218			1,230,642

Costs and expenses:
Direct operating		28,717			28,509			29,828			25,918			112,972
Transportation, gathering and compression		25,082			28,666			32,431			34,576			120,755
Production and ad valorem taxes		6,879			7,550			7,317			5,920			27,666
Brokered natural gas and marketing		2,521			2,981			3,333			3,151			11,986
Exploration		27,187			11,592			17,606			24,982			81,367
Abandonment and impairment of unproved properties		16,537			18,900			16,627			27,639			79,703
General and administrative		33,959			39,120			35,907			42,205			151,191
Deferred compensation plan		30,630			(5,778	)		8,717			9,640			43,209
Interest expense		24,779			31,383			34,181			34,709			125,052
Loss on early extinguishment of debt		—			18,580			(4	)		—			18,576
Depletion, depreciation and amortization		72,216			78,294			93,619			97,092			341,221
Impairment of proved properties		—			—			38,681			—			38,681

Total costs and expenses		268,507			259,797			318,243			305,832			1,152,379

(Loss) income from continuing operations before income taxes		(53,328	)		78,479			55,726			(2,614	)		78,263

Income tax (benefit) expense
Current		—			8			(7	)		636			637
Deferred		(19,897	)		32,695			22,547			(425	)		34,920

		(19,897	)		32,703			22,540			211			35,557

(Loss) income from continuing operations		(33,431	)		45,776			33,186			(2,825	)		42,706
Discontinued operations, net of taxes		8,398			5,517			1,569			(164	)		15,320

Net (loss) income	$	(25,033	)	$	51,293		$	34,755		$	(2,989	)	$	58,026

(Loss) income per common share:
Basic-(loss) income from continuing operations	$	(0.21	)	$	0.28		$	0.21		$	(0.02	)	$	0.26
-discontinued operations		0.05			0.04			0.01			—			0.10

-net (loss) income	$	(0.16	)	$	0.32		$	0.22		$	(0.02	)	$	0.36

Diluted-(loss) income from continuing operations	$	(0.21	)	$	0.28		$	0.20		$	(0.02	)	$	0.26
-discontinued operations		0.05			0.04			0.01			—			0.10

-net (loss) income	$	(0.16	)	$	0.32		$	0.21		$	(0.02	)	$	0.36

F-40

(20) SUPPLEMENTAL INFORMATION ON NATURAL GAS AND OIL EXPLORATION, DEVELOPMENT

AND PRODUCTION ACTIVITIES (UNAUDITED)

Our gas natural 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)


	December 31,
	2012			2011			2010
	(in thousands)
Natural gas and oil properties:
Properties subject to depletion	$	7,368,308		$	6,035,429		$	4,742,248
Unproved properties		743,467			748,598			648,143

Total		8,111,775			6,784,027			5,390,391
Accumulated depreciation, depletion and amortization		(2,015,591	)		(1,626,461	)		(1,306,378	)

Net capitalized costs	$	6,096,184		$	5,157,566		$	4,084,013

^(a)	Includes capitalized asset retirement costs and the associated accumulated amortization.

Costs Incurred for Property Acquisition, Exploration and Development ^(a)


	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Acquisitions:
Unproved leasehold	$	—	$	—	$	3,697
Proved oil and gas properties		—		—		130,767
Asset retirement obligations		—		—		556
Acreage purchases		188,843		220,576		151,572
Development		1,049,129		1,007,049		727,720
Exploration:
Drilling		309,816		226,920		50,433
Expense		65,758		77,259		56,298
Stock-based compensation expense		4,049		4,108		4,209
Gas gathering facilities:
Development		41,035		53,387		19,627

Subtotal		1,658,630		1,589,299		1,144,879
Asset retirement obligations		57,982		24,061		(6,370	)

Total – continuing operations		1,716,612		1,613,360		1,138,509
Discontinued operations		—		3,241		73,369

Total costs incurred	$	1,716,612	$	1,616,601	$	1,211,878

^(a)	Includes cost incurred whether capitalized or expensed.

F-41

Estimated Quantities of Proved Oil and Gas Reserves (Unaudited)

Reserves of natural gas, NGLs, crude oil and condensate are estimated by our petroleum engineering staff 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 natural gas and oil company reserves reporting requirements. We adopted the rules effective December 31, 2009 and the rule changes, including those related to pricing and technology, are included in our reserve estimates for the three years ended December 31, 2012.

Reserve Audit

All reserve information in this report is based on estimates prepared by our petroleum engineering staff. At year-end 2012, the following independent petroleum consultants conducted an audit of our reserves: DeGolyer and MacNaughton (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, 2012, these consultants collectively audited approximately 93% of our proved reserves. Copies of the summary reserve reports prepared by each of these independent petroleum consultants are 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 audit 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 significant changes to our proved reserves. We provide historical information to our consultants for our largest producing properties such as ownership interest; natural gas and oil 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 and Economics. 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%. All of our reserve estimates are reviewed and approved by our Senior Vice President of Reservoir Engineering and Economics, who reports directly to our President and Chief Executive Officer. Mr. Alan Farquharson, our Senior Vice President of Reservoir Engineering and Economics, 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 natural gas, NGLs, crude oil and condensate 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 when 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.

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.

F-42

The average realize prices used at December 31, 2012 to estimate reserve information were $86.91 per barrel of oil, $32.23 per barrel of NGLs and $2.75 per mcf for gas, using benchmark (NYMEX) of $95.05 per barrel and $2.76 per MMbtu. The average realized prices used at December 31, 2011 to estimate reserve information were $85.59 per barrel of oil, $49.24 per barrel for NGLs and $3.55 per mcf for gas, using benchmark (NYMEX) of $95.61 per barrel and $4.12 per Mmbtu. The average realized prices used at December 31, 2010 to estimate reserve information were $72.51 per barrel of oil, $39.14 per barrel for NGLs and $3.70 per mcf for gas, using benchmark prices (NYMEX) of $79.81 per barrel and $4.38 per Mmbtu. The average realized prices used to estimate reserves is net of third party transportation, gathering and compression expense.


	Natural Gas			NGLs			Crude Oil			Natural Gas Equivalents ^(a)
	(Mmcf)			(Mbbls)			(Mbbls)			(Mmcfe)
Proved developed and undeveloped reserves:

Balance, December 31, 2009		2,614,717			51,588			34,082			3,128,739
Revisions		3,599			26,832			(2,672	)		148,558
Extensions, discoveries and additions		1,089,632			48,792			4,663			1,410,359
Purchases		124,981			—			—			124,981
Property sales		(124,369	)		—			(10,865	)		(189,558	)
Production		(142,034	)		(4,490	)		(1,969	)		(180,789	)

Balance, December 31, 2010 ^(b)		3,566,526			122,722			23,239			4,442,290
Revisions		73,643			18,627			6,522			224,542
Extensions, discoveries and additions		1,304,324			26,591			4,915			1,493,357
Purchases		—			—			—			—
Property sales		(777,816	)		(19,852	)		(1,176	)		(903,983	)
Production		(157,001	)		(5,573	)		(1,968	)		(202,245	)

Balance, December 31, 2011		4,009,676			142,515			31,532			5,053,961
Revisions		76,925			3,036			2,316			109,036
Extensions, discoveries and additions		996,059			113,392			15,131			1,767,202
Purchases		—			—			—			—
Property sales		(73,429	)		(11,575	)		(1,046	)		(149,153	)
Production		(216,555	)		(6,969	)		(2,851	)		(275,476	)

Balance, December 31, 2012		4,792,676			240,399			45,082			6,505,570

Proved developed reserves:
December 31, 2010		1,762,766			53,071			17,050			2,183,488

December 31, 2011		1,907,209			64,472			17,872			2,401,274

December 31, 2012		2,373,604			154,984			25,667			3,457,502

Proved undeveloped reserves:
December 31, 2010		1,803,760			69,651			6,189			2,258,802

December 31, 2011		2,102,467			78,043			13,660			2,652,687

December 31, 2012		2,419,072			85,415			19,415			3,048,068

^(a)	Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

^(b)	Total proved reserves at December 31, 2010 includes 906,371 Mmcfe related to discontinued operations of which 408,710 Mmcfe is proved undeveloped.

F-43

During 2012, we added approximately 1.8 Tcfe of proved reserves from drilling activities and evaluation of proved areas primarily in the Marcellus Shale. Approximately 56% of the 2012 reserve additions were attributable to natural gas. Also included in 2012 additions is 307 Bcfe of ethane reserves (51.2 Mmbbls) in the Marcellus Shale associated with initial ethane deliveries under contracts commencing in 2013. Revisions of previous estimates of a net 109 Bcfe includes positive performance revisions primarily for our Marcellus Shale natural gas properties partially offset by negative pricing revisions.

During 2011, we added approximately 1.5 Tcfe of proved reserves from drilling activities and evaluations of proved areas, primarily in the Marcellus Shale. Approximately 87% of the 2011 reserve additions were attributable to natural gas. Revisions of previous estimates of 225 Bcfe were primarily positive performance revisions for natural gas properties, primarily in the Marcellus Shale.

During 2010, we added approximately 1.4 Tcfe of proved reserves from drilling activities and evaluations of proved areas primarily in the Marcellus Shale and the Barnett Shale. Approximately 77% of 2010 reserve additions were attributable to natural gas. Revisions of previous estimates of 148.6 Bcfe for the year ended December 31, 2010 included a positive revision of 40.5 Bcfe due to an increase in the average natural gas price used for the December 31, 2010 reserve estimation as compared to the price used in the previous year estimate. Revisions of previous estimates in 2010 also include positive performance revisions for natural gas properties primarily in the Barnett Shale.

The following details the changes in proved undeveloped reserves for 2012 (Mmcfe):


Beginning proved undeveloped reserves at December 31, 2011	2,652,687
Undeveloped reserves transferred to developed	(412,502	)
Revisions	(119,430	)
Purchases/sales	—
Extension and discoveries	927,313

Ending proved undeveloped reserves at December 31, 2012	3,048,068

Approximately $451.9 million was spent during 2012 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 $453.7 million in 2013, $506.1 million in 2014 and $1.1 billion in 2015. Included in proved undeveloped reserves at December 31, 2012 are approximately 10,888 Mmcfe of reserves (less than 1% of total proved undeveloped reserves) that have been reported for five or more years. All proved undeveloped drilling locations are scheduled to be drilled prior to the end of 2017.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following summarizes the policies we used in the preparation of the accompanying natural gas, NGLs and oil reserve disclosures, standardized measures of discounted future net cash flows from proved natural gas, NGLs 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 natural gas and oil properties as of December 31 of the years presented. These estimates were prepared by our petroleum engineering staff. Proved reserves are estimated quantities of natural gas, NGLs 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:

Estimates are made of quantities of proved reserves and future amounts expected to be produced based on current year-end economic conditions.

For the year ended 2012, 2011 and 2010, estimated future cash inflows are calculated by applying a twelve-month average price of natural gas, NGLs and oil relating to our proved reserves to the quantities of those reserves produced in each future year.

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 natural gas, NGLs and oil properties, other deductions, credits and allowances relating to our proved natural gas and oil reserves.

The resulting future net cash flows are discounted to present value by applying a discount rate of 10%.

F-44

The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of our natural gas, NGLs and oil reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.

The standardized measure of discounted future net cash flows relating to proved natural gas, NGLs and oil reserves is as follows and excludes cash flows associated with derivatives outstanding at each of the respective reporting dates. Future cash inflows are net of third party transportation, gathering and compression expense.


	As of December 31,
	2012			2011
	(in thousands)
Future cash inflows	$	24,851,589		$	23,954,048
Future costs:
Production		(10,028,359	)		(5,113,902	)
Development		(3,667,672	)		(3,230,577	)

Future net cash flows before income taxes		11,155,558			15,609,569
Future income tax expense		(3,081,918	)		(5,040,104	)

Total future net cash flows before 10% discount		8,073,640			10,569,465
10% annual discount		(4,849,835	)		(6,054,568	)

Standardized measure of discounted future net cash flows	$	3,223,805		$	4,514,897

The following table summarizes changes in the standardized measure of discounted future net cash flows.


	As of December 31,
	2012			2011			2010
	(in thousands)
Revisions of previous estimates:
Changes in prices	$	(2,498,616	)	$	422,080		$	957,994
Revisions in quantities		88,190			326,240			190,874
Changes in future development costs		(354,766	)		(346,378	)		(474,058	)
Accretion of discount		608,381			464,735			259,280
Net change in income taxes		832,830			(400,690	)		(666,517	)
Purchases of reserves in place		—			—			160,580
Additions to proved reserves from extensions, discoveries and improved recovery		1,429,340			2,169,706			1,812,077
Production		(976,224	)		(911,873	)		(744,354	)
Development costs incurred during the period		562,329			513,551			298,624
Sales of natural gas and oil		(120,637	)		(1,313,401	)		(243,551	)
Timing and other		(861,919	)		111,801			(162,912	)

Net change for the year		(1,291,092	)		1,035,771			1,388,037
Beginning of year		4,514,897			3,479,126			2,091,089

End of year	$	3,223,805		$	4,514,897		$	3,479,126

F-45

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 May 20, 2010)

4.1		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)

4.2		Indenture dated May 6, 2008 by and among Range, as issuer, the subsidiary Guarantors (as defined therein), as guarantors and The Bank of New York Trust Company, N.A. 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)

4.3		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)

4.4		Indenture dated May 14, 2009 by and among Range, as issuer, the Subsidiary Guarantors (as defined therein), as guarantors and The Board of New York Trust Company, N.A. 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)

4.5		Form of 6.75% Senior Subordinated Notes due 2020 (incorporated by reference to Exhibit A to Exhibit 4.2 on Form 8-K (File No. 001-12209) as filed with the SEC on August 12, 2010)

4.6		Indenture dated August 12, 2010 by and among Range, as issuer, the Subsidiary Guarantors (as defined therein), as guarantors and The Board of New York Trust Company, N.A. as trustee (incorporated by reference to Exhibit 4.1 on Form 8-K (File No. 001-12209) as filed with the SEC on August 12, 2010)

4.7		Form of 5.75% Senior Subordinated Notes due 2021 (incorporated by reference to Exhibit A to Exhibit 4.2 on Form 8-K (File No. 001-12009) as filed with the SEC on May 25, 2011)

4.8		Indenture dated May 25, 2011 by and among Range, as issuer, the Subsidiary Guarantors (as defined therein), as guarantors and The Bank of New York Mellon Trust Company, N.A., 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 25, 2011)

4.9		Tenth Supplemental Indenture, dated as of May 25, 2011, by and among Range Resources Corporation, the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 on Form 8-K (File No. 001-12209) as filed with the SEC on May 25, 2011)

4.10		Tenth Supplemental Indenture, dated as of May 25, 2011, by and among Range Resources Corporation, the subsidiary guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.4 on Form 8-K (File No. 001-12209) as filed with the SEC on May 25, 2011)


Exhibit Number		Exhibit Description

4.11		Form of 5.00% Senior Subordinated Notes due 2022 (incorporated by reference to Exhibit A to Exhibit 4.1 on our Form 8-K (File No. 001-12009) as filed with the SEC on March 9, 2012)

4.12		Indenture dated March 9, 2012 by and among Range, as issuer, the Subsidiary Guarantors (as defined therein), as guarantors and The Bank of New York Mellon Trust Company, N.A., 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 9, 2012)

10.01		Fourth Amended and Restated Credit Agreement as of February 18, 2011 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 8-K (File No. 001-12209) as filed with the SEC February 22, 2011)

10.02		First Amendment to the Fourth Amended and Restated Credit Agreement on February 21, 2012 among Range (as borrower) 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 8-K (File No. 001-12209) as filed with the SEC on February 24, 2012)

10.03		Second Amendment to the Fourth Amended and Restated Credit Agreement on April 9, 2012 among Range (as borrower) 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-Q (File No. 001-12209) as filed with the SEC on April 25, 2012)

10.04		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)

10.05		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)

10.06		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)

10.07		First Amendment to the 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 May 20, 2010)

10.08		Second Amendment to the 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 May 19, 2011)

10.09		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)

10.10		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)

10.11		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)

10.12		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)

10.13		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)

10.14		Form of Indemnification Agreement (incorporated by reference to Exhibit 10.6 to our Form 8-K (File No. 001-12209) as filed with the SEC on February 17, 2009)


Exhibit Number		Exhibit Description

10.15		Purchase and Sale Agreement between Range Texas Production LLC, Energy Assets Company, LLC and Range Corporation as Seller and Legend Natural Gas IV, LP as Buyer dated February 28, 2011 (incorporated by reference to Exhibit 10.1 to our Form 10-Q (File No. 001-12209) as filed with the SEC on April 27, 2011)

10.16*		Separation agreement between Range Production Company and Mark Whitley

21.1*		Subsidiaries of Registrant

23.1*		Consent of Independent Registered Public Accounting Firm

23.2*		Consent of DeGoyler and MacNaughton, independent consulting engineers

23.3*		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 DeGoyler and MacNaughton, independent consulting engineers

99.2*		Report of Wright and Company, independent consulting engineers

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

*	Filed herewith.

**	Furnished herewith.