10-K 1 rrc-10k_20131231.htm 10-K

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

 

(Mark one)

x

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

For the fiscal year ended December 31, 2013

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 each exchange on which registered

Common Stock, $.01 par value

 

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x     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  x

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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    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

 

x

  

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 Rule 12b-2 of the Act).    Yes  ¨    No  x

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2013 was $12,297,478,000. 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 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 24, 2014, there were 163,687,012 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 2014 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates, are incorporated by reference in Part III, Items 10-14 of this report.

 

 

 

 

 


 

RANGE RESOURCES CORPORATION

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

TABLE OF CONTENTS

PART I

 

 

 

Page

ITEMS 1 & 2.

 

Business and Properties

2

 

 

General

 2

 

 

Available Information

 2

 

 

Our Business Strategy

 3

 

 

Significant Accomplishments in 2013

 4

 

 

Industry Operating Environment

 5

 

 

Segment and Geographical Information

 5

 

 

Outlook for 2014

 5

 

 

Production, Price and Cost History

 6

 

 

Proved Reserves

 7

 

 

Property Overview

 9

 

 

Producing Wells

 12

 

 

Drilling Activity

 12

 

 

Gross and Net Acreage

 12

 

 

Undeveloped Acreage Expirations

 13

 

 

Title to Properties

 13

 

 

Delivery Commitments

 14

 

 

Employees

 14

 

 

Competition

 14

 

 

Marketing and Customers

 14

 

 

Seasonal Nature of Business

 15

 

 

Governmental Regulation

 15

 

 

Environmental and Occupational Health and Safety Matters

 16

 

 

 

 

ITEM 1A.

 

Risk Factors

20

 

ITEM 1B.

 

Unresolved Staff Comments

 32

 

ITEM 3.

 

Legal Proceedings

32

 

ITEM 4.

 

Mine Safety Disclosures

 32

 

PART II

 

 

 

ITEM 5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 33

 

 

Market for Common Stock

 33

 

 

Holders of Record

 33

 

 

Dividends

 33

 

 

Stockholders Return Performance Presentation

 34

 

ITEM 6.

 

Selected Financial Data and Reserve Data

34

i


 

 

TABLE OF CONTENTS (continued)

 

 

 

 

Page

 

ITEM 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 36

 

 

Overview of Our Business

 36

 

 

Sources of Our Revenues

 36

 

 

Principal 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 Flow, Capital Resources and Liquidity

 46

 

 

Management’s Discussion of Critical Accounting Estimates

 52

 

ITEM 7A.

 

Quantitative and Qualitative Disclosures about Market Risk

 56

 

 

Market Risk

 56

 

 

Commodity Price Risk

 56

 

 

Other Commodity Risk

 57

 

 

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

 64

 

 

Financial Statements

 64

 

 

Financial Statement Schedules

 64

 

 

Exhibits

 64

GLOSSARY OF CERTAIN DEFINED TERMS

 65

SIGNATURES

 67

 

 

 

ii


 

Disclosures Regarding Forward-Looking Statements

This Annual Report on Form 10-K, particularly Item 1. and 2. 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. For a description of known material factors that could cause our actual results to differ from those in the forward-looking statements, see “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.

 

 

 

1


 

PART I

 

ITEMS  1 AND 2. BUSINESS AND PROPERTIES

General

Range Resources Corporation, a Delaware corporation, is 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. 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 (the “NYSE”) under the symbol “RRC.” At December 31, 2013, we had 163.4 million shares outstanding.

Our 2013 average production from operations consisted of the following:

·

total production of 939.8 Mmcfe per day, an increase of 25% from 2012;

77% natural gas;

natural gas production volume of 264.5 Bcf, an increase of 22% from 2012;

NGLs production volume of 9.3 Mmbbls, an increase of 33% from 2012; and

crude oil production volume of 3.8 Mmbbls, an increase of 34% from 2012.

At year-end 2013, our proved reserves had the following characteristics:

8.2 Tcfe of proved reserves;

69% natural gas;

51% proved developed;

85% operated;

a reserve life index of 22 years (based on fourth quarter 2013 production);

a pre-tax present value of $7.9 billion of future net cash flows attributable to our proved reserves, discounted at 10% per annum (“PV-10”(a)); and

a standardized after-tax measure of discounted future net cash flows of $5.9 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 $2.0 billion at December 31, 2013.

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 U.S. Securities and Exchange Commission (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 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 Chief 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.

2


 

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 and divestiture of non-core assets. 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 operational and financial flexibility; and

provide employee equity ownership and incentive compensation.

Concentrate in Core Operating Areas. We currently operate in two regions: the Appalachian (which includes Pennsylvania, Virginia, and West Virginia) and Southwestern (which includes the Permian Basin of West Texas, the Texas Panhandle, the Nemaha Uplift in Northern Oklahoma and Kansas and the Anadarko Basin of Western Oklahoma). Concentrating our drilling and producing activities in these core areas allows us to develop the regional expertise needed to interpret specific geological and operating trends and develop economies of scale. Operating in a number of core areas allows us to create a portfolio to assist in our goal of consistent production and reserve growth at attractive returns.

Maintain Multi-Year Drilling Inventory. We focus on areas with multiple prospective, productive horizons and development opportunities. We use our technical expertise to build and maintain a multi-year drilling inventory. We believe that a large, multi-year inventory of drilling projects increases our ability to efficiently plan for the economic growth of production and reserves. Currently, we have over 12,000 proven and unproven drilling locations in inventory. Our focus is to grow year-over-year production by 20-25%  by focusing on developing fields in our operating regions.

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 one of the lowest cost structures in the industry. We operate a significant portion of our total net production and believe that our extensive knowledge of the geologic and operating conditions in the areas where we operate provides us with the ability to achieve operational efficiencies.

Commit to Environmental Protection, Health and Safety and Community Stewardship. We strive to implement the latest technologies and best commercial practices to minimize potential impacts from the development of our 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. We encourage every employee to maintain safe operations, minimize environmental impact and conduct their daily business with the highest of ethical standards.

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 drilling, divestiture and acquisition activities to assist in executing this strategy.

Maintain Operational and Financial 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 cash flows and financial results.

3


 

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, 2013, our employees owned equity securities in our benefit plans (vested and unvested) that had an aggregate market value of approximately $413.0 million.

Significant Accomplishments in 2013

Production growth – In 2013, our production averaged 939.8 Mmcfe per day, an increase of 25% from 2012. Targeted drilling in the Marcellus Shale play in Pennsylvania drove our production growth.

Reserve growth – Total proved reserves increased 26% in 2013 to 8.2 Tcfe, marking the twelfth 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 2013 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 2013, we drilled 219 gross natural gas and oil wells plus an additional 6 service wells. We replaced 505% of our production through drilling in 2013 and our overall drilling success rate was 99%. 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 2013. We have 5 large unconventional and prospective plays – the Marcellus, Utica/Point Pleasant and Upper Devonian shales in Pennsylvania, the Huron Shale in Virginia and the Cline Shale in West Texas. These plays cover expansive areas, provide multi-year drilling opportunities and, collectively, have sustainable lower risk growth profiles. The economics of these plays have been enhanced by continued advancements in drilling and completion technologies. We have expanded into the conventional horizontal Mississippian play in Northern Oklahoma and Kansas. We have leased 1.3 million net acres in these 5 shale plays and approximately 160,000 net acres in the Mississippian. We also have approximately 155,000 net acres in our coal bed methane plays in Virginia.

Continued development of processing and pipeline takeaway capacity and marketing of NGLs – We continue to ensure we have sufficient processing capacity and marketing agreements in place for our production. In 2011, we entered into an ethane sales contract where a third party will transport ethane from the tailgate of a third-party processing and fractionation facility to the international border for further delivery into Canada. Initial deliveries under this agreement commenced in second half 2013. Also in 2011, we entered into an agreement to transport ethane to the Gulf Coast for which initial deliveries also commenced in late 2013. We also transport propane by rail to the Philadelphia harbor for sales to domestic and international customers. During the year, we entered into additional firm transportation agreements to provide gas gathering and transportation from southwestern and northeastern Pennsylvania. At December 31, 2013, our agreements provide commitments that total 1.3 Bcfe per day.

Focus on financial flexibility – Debt per mcfe of proved reserves was $0.38 at December 31, 2013 compared to $0.44 at December 31, 2012. In March 2013, we issued $750.0 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. 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 May 2013, we redeemed all $250.0 million aggregate principal amount of our 7.25% senior subordinated notes due 2018 with borrowings under our bank credit facility. As of December 31, 2013, we maintain a $2.0 billion bank credit facility and our committed borrowing capacity on that date was $1.75 billion.

Successful land acquisitions completed – In 2013, we leased or renewed $137.5 million of acreage located in our core areas, primarily in the Marcellus Shale and the conventional horizontal Mississippian play in Northern Oklahoma and Kansas. We continued to see outstanding results in the Marcellus Shale. Production in the Marcellus Shale increased 39% while we continue to prove up acreage, acquire additional acreage and gain access to additional pipeline and processing capacity.

Successful dispositions completed – In April 2013, we sold our Delaware Basin and Permian Basin properties in Southeast New Mexico and West Texas for gross proceeds of $275.0 million. We also received $40.5 million of additional proceeds primarily related to the sale of miscellaneous proved and unproved properties.

4


 

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 if located in the core area of each play. 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 emission 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. The impact of these factors is extremely difficult to accurately predict or anticipate.  Although it is difficult for us to predict the occurrence of events that may affect commodity prices or the degree to which these prices will be affected, the prices for any commodity we produce will generally approximate current market prices in the geographic region of the production.

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 $3.67 per mcf in 2013, with a high of $4.19 per mcf in June and a low of $3.32 per mcf in February. 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. This decrease in demand is somewhat offset by an increase in the use of natural gas for power generation.

Significant factors that will impact 2014 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 $98.20 per barrel in 2013, with a high of $106.54 per barrel in August and a low of $92.07 per barrel in April.

NGLs prices are generally determined by North American supply and demand. We expect NGLs prices in 2014 to continue to be under pressure due to concerns over excess supply and variable weather patterns.

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 69% 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 2014

Our capital expenditure budget for 2014 has been initially set at approximately $1.52 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

5


 

success and markets for our products. At December 31, 2013, approximately 80% of our expected 2014 natural gas, NGLs and oil production is hedged. For a complete discussion of our hedging activities, a listing of open contracts at December 31, 2013 and the estimated fair value of these contracts as of that date, see Note 11 to our consolidated financial statements. Our estimated 2014 capital expenditure budget detail and budget by area are shown below:

logo

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 more information, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

 

Year Ended December 31,

 

 

2013

 

  

2012

 

  

2011

 

Production

 

 

 

  

 

 

 

  

 

 

 

Natural gas (Mmcf)

 

264,528

 

  

 

216,555

  

  

 

145,206

  

Natural gas liquids (Mbbls)

 

9,255

 

  

 

6,967

  

  

 

5,352

  

Crude oil and condensate (Mbbls)

 

3,827

 

  

 

2,851

  

  

 

1,960

  

Total (Mmcfe) (a)

 

343,022

 

  

 

275,465

  

  

 

189,077

  

Average sales prices (wellhead)

 

 

 

  

 

 

 

  

 

 

 

Natural gas (per mcf)

$

3.61

  

  

$

2.83

  

  

$

4.21

  

Natural gas liquids (per bbl)

 

34.07

 

  

 

38.05

  

  

 

50.23

  

Crude oil and condensate (per bbl)

 

86.00

 

  

 

83.46

  

  

 

86.22

  

Total (per mcfe) (a)

 

4.66

 

  

 

4.05

  

  

 

5.55

  

Average realized prices (including derivatives that qualify for hedge accounting):

 

 

 

  

 

 

 

  

 

 

 

Natural gas (per mcf)

$

4.03

  

  

$

3.93

  

  

$

5.06

  

Natural gas liquids (per bbl)

 

34.07

 

  

 

38.05

  

  

 

50.23

  

Crude oil and condensate (per bbl)

 

87.47

 

  

 

82.77

  

  

 

86.22

  

Total (per mcfe) (a)

 

5.00

 

  

 

4.91

  

  

 

6.21

  

Average realized prices (including all derivative settlements and third party transportation costs)

 

 

 

  

 

 

 

  

 

 

 

Natural gas (per mcf)

$

3.08

  

  

$

3.11

  

  

$

4.43

  

Natural gas liquids (per bbl)

 

31.29

 

  

 

41.03

  

  

 

50.82

  

Crude oil and condensate (per bbl)

 

84.70

 

  

 

83.64

  

  

 

81.34

  

Total (per mcfe) (a)

 

4.16

 

  

 

4.35

  

  

 

5.68

  

Production costs

 

 

 

  

 

 

 

  

 

 

 

Lease operating (per mcfe)

$

0.34

  

  

$

0.39

  

  

$

0.57

  

Workovers (per mcfe)

 

0.02

 

  

 

0.02

  

  

 

0.02

  

Stock-based compensation (per mcfe)

 

0.01

  

  

 

0.01

  

  

 

0.01

  

Total (per mcfe)

$

0.37

 

 

$

0.42

 

 

$

0.60

 

(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 necessarily indicative of the relationship of oil and natural gas prices.

6


 

Proved Reserves

The following table sets forth our estimated proved reserves for 2013, 2012 and 2011 based on the average of prices on the first day of each month of the given calendar year, in accordance with the SEC rules that became effective on December 31, 2009. Oil includes both crude oil and condensate. 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 of Fiscal Year-End
Based on Average Fiscal-Year Prices

 

Reserve Category

  

Natural Gas
(Mmcf)

 

  

NGLs
(Mbbls)

 

  

Oil
(Mbbls)

 

  

Total
(Mmcfe) (a)

 

  

%

 

2013:

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

Proved

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

  

 

 

 

Developed

  

 

2,797,483

 

  

 

206,477

 

  

 

26,054

 

  

 

4,192,666

 

  

 

51

%

Undeveloped

  

 

2,868,162

  

  

 

167,935

  

  

 

22,306

  

  

 

4,009,608

  

  

 

49

%

Total Proved

  

 

5,665,645

  

  

 

374,412

  

  

 

48,360

  

  

 

8,202,274

  

  

 

100

%

 

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

(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 and natural gas prices.

The following table sets forth summary information by area with respect to estimated proved reserves at December 31, 2013:

 

 

Reserve Volumes

 

 

PV-10 (a)

 

 

Natural Gas
(Mmcf)

 

  

NGLs
(Mbbls)

 

  

Oil
(Mbbls)

 

  

Total
(Mmcfe)

 

  

%

 

 

Amount
(In thousands)

 

  

%

 

Appalachian Region

 

5,327,652

 

  

 

340,834

 

  

 

27,757

 

  

 

7,539,201

 

  

 

92

 

$

6,916,206

  

  

 

88

Southwestern Region

 

337,993

  

  

 

33,578

  

  

 

20,603

  

  

 

663,073

  

  

 

8

 

 

981,338

  

  

 

12

Total

 

5,665,645

  

  

 

374,412

  

  

 

48,360

  

  

 

8,202,274

  

  

 

100

 

$

7,897,544

  

  

 

100

(a) 

PV-10 was prepared using the twelve-month average prices for 2013, 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 $2.0 billion at December 31, 2013. Included in the $7.9 billion pre-tax PV-10 is $5.4 billion 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. The proved reserve audits performed for 2013, 2012 and 2011, in the aggregate represented 96%, 93% and 89% of our proved reserves. The reserve audits performed for 2013, 2012 and 2011, in the aggregate represented 97%, 88% and 87% of our 2013, 2012 and 2011 associated pre-tax present value of proved reserves discounted at ten percent. 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

7


 

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, NGLs 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. The reserve auditor estimates of proved reserves and the pre-tax present value of such reserves discounted at 10% did not differ from our estimates by more than 10% in the aggregate. However, when compared on a lease-by-lease, field-by-field or area-by-area basis, some of our estimates may be greater than those of the auditors and some may be less than the estimates of the reserve auditors.  When such differences do not exceed 10% in the aggregate, our reserve auditors are satisfied that the proved reserves and pre-tax present value of such reserves discounted at 10% are reasonable and will issue an unqualified opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analysis.

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, 2013 with any federal authority or agency with respect to our estimate of natural gas and oil reserves.

Reserve Technologies

Proved reserves are those quantities of natural gas, natural gas liquids and oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. The term “reasonable certainty” implies a high degree of confidence that the quantities of natural gas, NGLs and oil actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal technical staff employs technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, empirical evidence through drilling results and well performance, well logs, geologic maps and available downhole and production data, seismic data, well test data and reservoir simulation modeling.

Reporting of Natural Gas Liquids

We produce natural gas liquids, or NGLs, as part of the processing of our natural gas. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. At December 31, 2013, NGLs represented approximately 27% of our total proved reserves on an mcf equivalent basis. NGLs are products priced by the gallon (and sold by the barrel) to the end-user. In reporting proved reserves and production of NGLs, we have included production and reserves in barrels. Prices for a barrel of NGLs in 2013 averaged approximately 60% 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. As of December 31, 2013, we have 676 Bcfe of ethane reserves (112.6 Mmbbls) associated with our Marcellus Shale, which are included in NGLs proved reserves.

Proved Undeveloped Reserves (PUDs)

As of December 31, 2013, our PUDs totaled 22.3 Mmbbls of crude oil, 167.9 Mmbbls of NGLs and 2.9 Tcfe of natural gas, for a total of 4.0 Tcfe. Costs incurred in 2013 relating to the development of PUDs were approximately $504.1 million. Approximately 90% of our PUDs at year-end 2013 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 2018 with more than 75% 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 434 Bcfe of PUDs into proved developed reserves;

new PUDs added consisting of 1,185 Bcfe;

8


 

234 Bcfe positive revision with improved recovery partially offset by reserves reclassified to unproved because of a slower pace of development activity beyond the five-year development horizon; and

23 Bcfe reduction from the sale of properties.

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 expenses (in millions, except prices):

 

 

2013

 

  

2012

 

  

2011

 

  

2010

 

 

 

2009

Future net cash flows

$

21,029

 

 

$

11,156

 

 

$

15,610

 

 

$

12,516

 

$

6,721

 

Present value

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Before income tax

 

7,898

 

 

 

3,960

 

 

 

6,084

 

 

 

4,647

 

 

2,593

 

After income tax (Standardized Measure)

 

5,862

 

 

 

3,224

 

 

 

4,515

 

 

 

3,479

 

 

2,091

 

Benchmark prices (NYMEX)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas price (per mcf)

 

3.67

 

 

 

2.76

 

 

 

4.12

 

 

 

4.38

 

 

3.87

 

Oil price (per barrel)

 

97.33

 

 

 

95.05

 

 

 

95.61

 

 

 

79.81

 

 

60.85

 

Wellhead prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas price (per mcf)

 

3.75

 

 

 

2.75

 

 

 

3.55

 

 

 

3.70

 

 

3.19

 

Oil price (per barrel)

 

86.66

 

 

 

86.91

 

 

 

85.59

 

 

 

72.51

 

 

54.65

 

NGLs price (per barrel)

 

25.93

 

 

 

32.23

 

 

 

49.24

 

 

 

39.14

 

 

34.05

 

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) and revenues are based on a twelve-month unweighted average of the first day of the month pricing, without escalation. 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, production or development 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, crude oil and condensate 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. 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, 2013.

 

Region

 

 

Average
Daily
Production
(mcfe per day)

 

 

 

Production
(mmcfe)

 

 

 

Percentage of
Production

 

 

 

Proved
Reserves
(mmcfe)

 

 

 

Percentage of
Proved
Reserves

 

Appalachian

  

 

814,369

 

  

 

297,245

 

  

 

87

 

 

7,539,201

 

  

 

92

Southwestern

  

 

125,417

  

  

 

45,777

  

  

 

13

 

 

663,073

  

  

 

8

Total

  

 

939,786

  

  

 

343,022

  

  

 

100

 

 

8,202,274

  

  

 

100

9


 

The following table summarizes our costs incurred by operating region for the year ended December 31, 2013 (in thousands):

 

 

Acreage
Purchases

 

  

Development
Costs

 

  

Exploration
Costs

 

  

Gathering
Facilities

 

  

Asset
Retirement
Obligations

 

  

Total

 

Appalachian

$

127,892

  

  

$

720,832

  

  

$

234,673

  

  

$

37,625

  

  

$

69,412

  

  

$

1,190,434

  

Southwestern

 

9,646

  

  

 

217,836

  

  

 

19,478

  

  

 

9,461

  

  

 

6,961

  

  

 

263,382

  

Total costs incurred

$

137,538

  

  

$

938,668

  

  

$

254,151

  

  

$

47,086

  

  

$

76,373

  

  

$

1,453,816

  

Approximately 83% of our proved reserves at December 31, 2013 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, 2013, is our only field in which reserves are greater than 15% of our total proved reserves.

 

Marcellus Shale Field

2013

 

  

2012

 

  

2011

 

Production:

 

 

 

  

 

 

 

  

 

 

 

Natural gas (Mmcf)

 

203,926

 

  

 

149,589

 

  

 

80,554

 

NGLs (Mbbls)

 

7,213

 

  

 

5,034

 

  

 

3,423

 

Crude oil and condensate (Mbbls)

 

2,529

 

  

 

1,564

 

  

 

695

 

Total Mmcfe (a)

 

262,377

 

  

 

189,178

 

  

 

105,264

 

Sales Prices: (b)

 

 

 

  

 

 

 

  

 

 

 

Natural gas (per mcf)

$

2.59

 

  

$

1.86

 

  

$

3.17

 

NGLs (per bbl)

 

33.19

 

  

 

38.48

 

  

 

51.83

 

Crude oil and condensate (per bbl)

 

82.11

 

  

 

78.56

 

  

 

74.84

 

Total (per mcfe)

 

3.72

 

  

 

3.14

 

  

 

4.60

 

Production Costs:

 

 

 

  

 

 

 

  

 

 

 

Lease operating (per mcfe)

 $

0.16

 

  

 $

0.18

 

  

$

0.33

 

Production and ad valorem tax (per mcfe) (c)

 

0.11

 

  

 

0.26

 

  

 

¾

 

(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 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 6,136 net producing wells, 84% of which we operate. Our average working interest in this region is 75%. We have approximately 1.6 million gross (1.3 million net) acres under lease, which includes 305,000 acres in which we also own a royalty interest.

Reserves at December 31, 2013 were 7.5 Tcfe, an increase of 1.8 Tcfe, or 31%, from 2012 with drilling additions, a favorable reserve revision for performance, price and improved recovery were partially offset by production and downward revisions for proved undeveloped reserves no longer in our current five year development plan. Annual production increased 31% from 2012. During 2013, we spent $955.5 million in this region to drill 121 (117.8 net) development wells and 39 (35.2 net) exploratory wells, of which 159 (152.9 net) were productive. At December 31, 2013, the Appalachian region had an inventory of over 950 proven drilling locations and 600 proven recompletions. During the year, the Appalachian region drilled 115 proven locations, added 255 new proven drilling locations and deleted 214 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. During the year, the region achieved a 99.9% drilling success rate.

10


 

Marcellus Shale

We began operations in the Marcellus Shale in Pennsylvania during 2004. The Marcellus Shale is a unconventional reservoir, which produces natural gas, NGLs, crude oil and condensate. This has been our largest investment area over the last five years. We had over 586 proven drilling locations at December 31, 2013. Our 2013 production from the Marcellus Shale increased 39% from 2012. During 2013, we drilled 104 (101 net) development wells and 39 (35.2 net) exploratory wells, of which 142 (135.9 net) were successful. In 2014, we plan to drill 161.9 net wells. During 2013, we had approximately 8 drilling rigs in the field and expect to run an average of 9 rigs throughout 2014.

We have long-term agreements with third parties to provide gathering and processing services and infrastructure assets in the Marcellus Shale, which includes gathering and residue gas pipelines, compression, cryogenic processing and liquid fractionation. Pursuant to these agreements, in mid-2013, MarkWest Liberty Midstream, L.L.C. expanded its natural gas liquids infrastructure at one location to include new de-ethanization capacity at two of its complexes where we hold contracted capacity.

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 commenced in the second half 2013. Also in 2011, we entered into an agreement to transport ethane to the Gulf Coast where initial deliveries also commenced in late 2013.

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, since 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 from the same terminal near Philadelphia which is expected to begin in mid-2015.  

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, 2013 provide commitments for 1.3 Bcfe per day. Some of our agreements, which extend to 2030, 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 two drilling rigs through 2015, and agreements for hydraulic fracturing services, including related equipment, material and labor, through 2015 in Pennsylvania.

Southwestern Region

The Southwestern region includes drilling, production and field operations in the Permian Basin of West Texas, the Texas Panhandle, as well as in the Anadarko Basin of western Oklahoma, Nemaha Uplift of northern Oklahoma and Kansas, the East Texas Basin and Mississippi. In the Southwestern region, we own 1,538 net producing wells, 96% of which we operate. Our average working interest is 80%. We have approximately 710,000 gross (508,000 net) acres under lease.

Total proved reserves in the Southwestern region decreased 97.0 Bcfe, or 13%, at December 31, 2013, when compared to year-end 2012. Drilling additions (162.1 Bcfe) and positive pricing revisions were offset by production, property sales (142.1 Bcfe) and negative performance revisions. Annual production volumes decreased 4% from 2012. During 2013, this region spent $237.3 million to drill 58.0 (55.1 net) development wells and 1.0 (0.5 net) exploratory wells, of which 58 (54.6 net) were productive. During the year, the region achieved a 98% drilling success rate. The region also drilled 6 service wells in 2013.

At December 31, 2013, the Southwestern region had a development inventory of over 125 proven drilling locations and over 200 proven recompletions. During the year, the Southwestern region drilled 19 proven locations, added 64 new proven locations and deleted 39 proven drilling locations primarily due to the sale of properties. 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 reticulations and refracturing operations.

In December 2013, we announced our plans to offer for sale certain of our properties in the Permian Basin. These properties include approximately 90,000 (70,000 net) acres, almost all of which are held by production in Glasscock and Sterling Counties. The data room opened in January 2014 and we expect to receive bids in late February. However, the completion of the sale is dependent upon prospective buyer due diligence procedures and there can be no assurance the sale will be completed.

11


 

Producing Wells

The following table sets forth information relating to productive wells at December 31, 2013. We also own royalty interests in an additional 1,591 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
Interest

 

Gross

 

 

Net

 

 

Natural gas

 

9,387

 

 

 

7,023

 

 

 

75

%

Crude oil

 

719

 

 

 

651

 

 

 

91

%

Total

 

10,106

 

 

 

7,674

 

 

 

76

%

The day-to-day operations of natural gas and oil properties are the responsibility of the operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs or contracts for field personnel and performs other functions. An operator receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged by unaffiliated third parties. The charges customarily vary with the depth and location of the well being operated.

Drilling Activity

The following table summarizes drilling activity for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. As of December 31, 2013, we were in the process of drilling 14 (10.8 net) wells. In 2013, we also drilled 6 (6 net) service wells.

 

 

2013

 

 

2012

 

 

2011

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

178.0

 

 

 

171.9

 

 

 

226.0

  

 

 

202.3

  

 

 

262.0

  

 

 

236.5

  

Dry

 

1.0

 

 

 

1.0

 

 

 

  

 

 

  

 

 

  

 

 

  

Exploratory wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

39.0

 

 

 

35.5

 

 

 

72.0

  

 

 

54.5

  

 

 

38.0

  

 

 

28.2

  

Dry

 

1.0

 

 

 

0.2

 

 

 

  

 

 

  

 

 

1.0

  

 

 

1.0

  

Total wells

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

217.0

 

 

 

207.4

 

 

 

298.0

  

 

 

256.8

  

 

 

300.0

  

 

 

264.7

  

Dry

 

2.0

  

 

 

1.2

  

 

 

  

 

 

  

 

 

1.0

  

 

 

1.0

  

Total

 

219.0

  

 

 

208.6

  

 

 

298.0

  

 

 

256.8

  

 

 

301.0

  

 

 

265.7

  

 

Success ratio

 

99.1

 

 

99.4

 

 

100

 

 

100

 

 

99.7

 

 

99.6

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.

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The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2013. 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

 

 

 

 

 

  

 

 

 

 

 

 

 

  

 

 

 

 

 

 

 

  

 

 

 

Illinois

 

¾ 

 

  

 

¾ 

 

 

 

13,332

 

  

 

7,312

 

 

 

13,332

 

  

 

7,312

 

Kansas

 

¾ 

 

  

 

¾ 

 

 

 

43,059

 

  

 

41,171

 

 

 

43,059

 

  

 

41,171

 

Louisiana

 

5,673

 

  

 

1,376

 

 

 

410

 

  

 

147

 

 

 

6,083

 

  

 

1,523

 

Mississippi

 

5,592

 

  

 

3,321

 

 

 

1,264

 

  

 

690

 

 

 

6,856

 

  

 

4,011

 

New York

 

¾ 

 

 

 

¾ 

 

 

 

3,900

 

 

 

1,423

 

 

 

3,900

 

 

 

1,423

 

Ohio

 

40

 

  

 

40

 

 

 

¾ 

 

  

 

¾ 

 

 

 

40

 

  

 

40

 

Oklahoma

 

184,457

 

  

 

126,840

 

 

 

212,432

 

  

 

152,110

 

 

 

396,889

 

  

 

278,950

 

Pennsylvania

 

514,141

 

  

 

476,476

 

 

 

509,247

 

  

 

437,702

 

 

 

1,023,388

 

  

 

914,178

 

Texas

 

163,062

 

  

 

120,617

 

 

 

80,338

 

  

 

54,623

 

 

 

243,400

 

  

 

175,240

 

Virginia

 

121,157

 

  

 

79,097

 

 

 

241,899

 

  

 

148,722

 

 

 

363,056

 

  

 

227,819

 

West Virginia

 

51,792

 

  

 

50,229

 

 

 

61,421

 

  

 

60,524

 

 

 

113,213

 

  

 

110,753

 

Wyoming

 

¾

  

  

 

¾

  

 

 

9,565

 

 

 

9,565

 

 

 

9,565

 

 

 

9,565

 

 

 

1,045,914

 

 

 

857,996

 

 

 

1,176,867

 

 

 

913,989

 

 

 

2,222,781

 

 

 

1,771,985

  

Average working interest

 

 

 

  

 

82

%

 

 

 

 

  

 

78

%

 

 

 

 

  

 

80

%

Undeveloped Acreage Expirations

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

 

As of December 31,

  

Acres

  

% of Total

 

  

Gross

  

Net

  

Undeveloped

 

2014

  

217,568 

  

179,624 

  

 

26

2015

  

106,102 

  

96,603 

  

 

14

2016

  

156,439 

  

110,682 

  

 

16

2017

  

32,309 

  

29,478 

  

 

4

2018

  

38,994 

  

27,122 

  

 

 4

%

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.

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Delivery Commitments

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

Employees

As of January 1, 2014, we had 867 full-time employees, 320 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 more information, see “Item 1A. Risk Factors.”

Marketing and Customers

We market the majority of our natural gas, NGLs, crude oil and condensate 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 and condensate 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 “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.

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We have entered into three ethane agreements to sell or transport ethane from our Marcellus Shale area. Initial deliveries commenced in late 2013 on two of these agreements. The remaining agreement is contingent on pipeline modifications and/or construction with operations expected to begin in mid-2015. For more information, see “Item 1A. Risk Factors – 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.”

Seasonal Nature of Business

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

Governmental Regulation

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

Exploration and development and the production and sale of oil and gas are subject to extensive federal, state and local regulations. An overview of these regulations is set forth below. We believe we are in substantial compliance with currently applicable laws and regulations and the continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. See Item 1A. Risk Factors The natural gas and oil industry is subject to extensive regulation.” 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, rights of way;

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, casing and completion 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;

15


 

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 No. 704, 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 natural gas industry are regularly considered by Congress, the states, the FERC, and the courts. We cannot predict when or whether any such proposals may become effective.

On December 26, 2007, the FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are now required to report, on May 1 of each year beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with the FERC’s policy statement on price reporting. On November 15, 2012, in docket No. RM13-1, 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 in order to improve natural gas market transparency. We cannot predict when or whether any such proposals may become effective.

Environmental and Occupational Health and Safety Matters

Our operations are subject to numerous stringent federal, state and local laws 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 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 natural 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 hazardous substance 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

16


 

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 natural gas wastes, and new state and federal regulatory initiatives that could have a significant adverse impact on us may periodically be proposed and enacted.

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

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

The Federal Water Pollution Control Act, as amended, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural 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, in 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. 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 and from pneumatic controllers and storage vessels, effective as early as

17


 

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 as compared to other similarly situated operators.

In 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 some of the GHG emissions from our operations and believe that our monitoring activities are in substantial compliance with applicable reporting obligations.

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

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

Hydraulic fracturing, which has been used by the industry for over 60 years, is an important and common practice used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We routinely apply hydraulic fracturing techniques as part of our operations. This process is typically regulated by state oil and natural gas commissions but the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuels under the federal Safe Drinking Water Act and issued revised permitting guidance in February 2014 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 in the Semi-Annual Regulatory Agenda published on July 3, 2013, the agency continued to project the issuance of 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, Texas and West Virginia 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 governments 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. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nevertheless, if 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.

18


 

In addition, certain government reviews have been conducted or are underway 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. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with 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 in 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 in 2014.  Also, in May 2013, the federal Bureau of Land Management ("BLM") published a supplemental notice of proposed rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of appropriate plans for managing flowback water returning to the surface. These existing or any future 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.

Oil and natural gas exploration, development and production activities on federal lands, including Indian lands and lands administered by the BLM, are subject to the National Environmental Policy Act, as amended (“NEPA”). NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Currently, we have minimal exploration and production activities on federal lands. However, for those current activities as well as for future or proposed exploration and development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are required. This process has the potential to delay or limit, or increase the cost of, the development of oil and natural gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.

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 on the listing of numerous 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 2013, nor do we anticipate that such expenditures will be material in 2014. 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. These risks are not the only risks we face. 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, crude oil and condensate 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 we expect the volatility to continue. Over the past four years, the average NYMEX monthly settlement price of natural gas has been as high as $5.27 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 $68.01 per barrel. As of the end of January 2014, natural gas was at $5.56 per mcf and oil was at $94.99 per barrel. Natural gas prices are likely to affect us more than oil prices because approximately 69% of our December 31, 2013 proved reserves are natural gas. 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, 2013, 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 profitable sale of only NGLs and condensate. Over the past three years, the average Mont Belvieu NGL composite has been as high as $1.31 per gallon and as low as $0.70 per gallon.

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:

the amount and timing of natural gas, NGLs and oil production;

the revenues and costs associated with that production;

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the amount and timing of future development expenditures; and

future commodity prices.

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 m