10-K 1 d447208d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

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

OR

 

¨ 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):

 

Large accelerated filer   þ    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

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.

 

 

 


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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   

 

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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   

 

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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.

 

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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.

 

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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

 

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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.

 

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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
LOGO    LOGO

 

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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.

 

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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.

 

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Table of Contents

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.

 

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Table of Contents

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   

 

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Table of Contents

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   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

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Table of Contents

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.

 

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Table of Contents

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.

 

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Table of Contents

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
     

 

 

      

 

 

      

 

 

 

 

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Table of Contents

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.”

 

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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.

 

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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;

 

   

plugging and abandoning of wells; and

 

   

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.

 

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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.

 

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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.

 

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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.

 

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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.

 

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ITEM 1A.     RISK FACTORS

We are subject to various risks and uncertainties in the course of our business. The following summarizes 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:

 

   

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

 

   

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

 

   

weather conditions;

 

   

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

 

   

the price and level of foreign imports;

 

   

U.S. domestic and worldwide economic conditions;

 

   

the availability, proximity and capacity of transportation facilities and processing facilities;

 

   

the effect of worldwide energy conservation efforts;

 

   

political conditions in natural gas and oil producing regions; and

 

   

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;

 

   

the revenues and costs associated with that production; and

 

   

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.

 

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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:

 

   

high costs, shortages or delivery delays of drilling rigs, equipment, water for hydraulic fracturing services, labor, or other services;

 

   

unexpected operational events and drilling conditions;

 

   

reductions in natural gas, NGLs and oil prices;

 

   

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

 

   

adverse weather conditions;

 

   

facility or equipment malfunctions;

 

   

equipment failures or accidents;

 

   

title problems;

 

   

pipe or cement failures;

 

   

casing collapses;

 

   

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

 

   

environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, and discharges of toxic gases;

 

   

lost or damaged oilfield drilling and service tools;

 

   

unusual or unexpected geological formations;

 

   

loss of drilling fluid circulation;

 

   

pressure or irregularities in formations;

 

   

fires;

 

   

natural disasters;

 

   

surface craterings and explosions; and

 

   

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.

 

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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:

 

   

we may be required to dedicate a substantial portion of our cash flows from operations to the payment of our indebtedness, reducing the funds available for our operations;

 

   

a portion of our borrowings are at variable rates of interest, making us vulnerable to increases in interest rates;

 

   

we may be more highly leveraged than some of our competitors, which could place us at a competitive disadvantage;

 

   

our degree of leverage may make us more vulnerable to a downturn in our business or the general economy;

 

   

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;

 

   

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

 

   

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

 

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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:

 

   

our production is less than expected;

 

   

the counterparties to our futures contracts fail to perform on their contract obligations; or

 

   

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;

 

   

response to unexpected releases to the environment;

 

   

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

 

   

the spacing of wells;

 

   

unitization and pooling of properties;

 

   

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

 

   

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:

 

   

result in increased costs associated with our operations;

 

   

increase other costs to our business;

 

   

affect the demand for natural gas; and

 

   

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:

 

   

injury or loss of life;

 

   

severe damage to or destruction of property, natural resources and equipment;

 

   

pollution or other environmental damage;

 

   

cleanup responsibilities;

 

   

regulatory investigations and penalties; or

 

   

suspension of operations.

 

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We maintain insurance against some, but not all, of these potential risks and losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. 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.

 

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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

 

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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.

 

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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.

 

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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:

 

   

changes in natural gas, NGLs and oil prices;

 

   

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

 

   

changes in governmental regulation and/or taxation;

 

   

changes in financial estimates by securities analysts;

 

   

changes in market valuations of comparable companies;

 

   

additions or departures of key personnel; or

 

   

future sales of our stock 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.

 

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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.”

 

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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.

 

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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   

 

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(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.

 

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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.

 

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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.

 

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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.

 

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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):

 

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     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:

 

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     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.

 

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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 %) 
  

 

 

    

 

 

    

 

 

     

 

 

    

 

 

    

 

 

   

 

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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.

 

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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
  

 

 

    

 

 

    

 

 

     

 

 

    

 

 

    

 

 

   

 

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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.

 

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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.

 

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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.

 

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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.

 

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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.

 

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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.

 

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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.

 

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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.

 

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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.

 

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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

 

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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