10-K 1 swn-20131231x10k.htm SWN 2013 FORM 10-K SWN 2013 Form 10-K

 

 

 

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

 

Form 10-K

 

 

 

 

[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

Commission file number 1-08246

 

 

 

 

Southwestern Energy Company

(Exact name of registrant as specified in its charter)

 

 

 

 

Delaware

71-0205415

(State or other jurisdiction of

(I.R.S. Employer

incorporation or organization)

Identification No.)

 

 

 

 

2350 North Sam Houston Parkway East, Suite 125,

Houston, Texas

77032

(Address of principal executive offices)

(Zip Code)

 

 

 

 

(281) 618-4700

(Registrant’s telephone number, including area code)

 

 

 

 

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

Title of each class

Name of each exchange on which registered

Common Stock, Par Value $0.01

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. Yesx     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     Nox

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. Yesx   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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesx   No   

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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.

Large accelerated filer x

Accelerated filer

Non-accelerated filer

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 stock held by non-affiliates of the registrant was $12,840,843,498 based on the New York Stock Exchange – Composite Transactions closing price on June 28, 2013 of $36.53. For purposes of this calculation, the registrant has assumed that its directors and executive officers are affiliates.

As of February 24, 2014, the number of outstanding shares of the registrant’s Common Stock, par value $0.01, was 352,930,217.

Document Incorporated by Reference

Portions of the registrant’s definitive proxy statement to be filed with respect to the annual meeting of stockholders to be held on or about May 20, 2014 are incorporated by reference into Part III of this Form 10-K.

 

 

 

 


 

 

 

 

 

 

 

 

 

SOUTHWESTERN ENERGY COMPANY

ANNUAL REPORT ON FORM 10-K

For Fiscal Year Ended December 31, 2013

 

TABLE OF CONTENTS

 

 

Page

PART I

 

 

Item 1.

Business 

3

 

Glossary of Certain Industry Terms

25

Item 1A.

Risk Factors

30

Item 1B.

Unresolved Staff Comments

36

Item 2.

Properties

36

Item 3.

Legal Proceedings

41

Item 4.

Mine Safety Disclosures

42

 

 

 

PART II

 

 

Item 5.

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

43

 

Stock Performance Graph

44

Item 6.

Selected Financial Data

45

Item 7.

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

47

 

Overview

47

 

Results of Operations

49

 

Liquidity and Capital Resources

53

 

Critical Accounting Policies and Estimates

57

 

Cautionary Statement about Forward-Looking Statements

60

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

62

Item 8.

Financial Statements and Supplementary Data

64

 

Index to Consolidated Financial Statements

64

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

110

Item 9A.

Controls and Procedures

110

Item 9B.

Other Information

110

 

 

 

PART III

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

111

Item 11.

Executive Compensation

112

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

112

Item 13.

Certain Relationships and Related Transactions, and Director Independence

112

Item 14.

Principal Accounting Fees and Services

113

 

 

 

PART IV

 

 

Item 15.

Exhibits, Financial Statement Schedules

113

 

 

 

EXHIBIT INDEX

 

115

 

 

 

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This Annual Report on Form 10-K includes certain statements that may be deemed to be “forward-looking” within the meaning of Section 27A of the Securities Act of 1933, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, or the Exchange Act. We refer you to “Risk Factors” in Item 1A of Part I and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a discussion of factors that could cause actual results to differ materially from any such forward-looking statements. The electronic version of this Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those forms filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are available free of charge as soon as reasonably practicable after they are filed with the Securities and Exchange Commission, or SEC, on our website at www.swn.com.  Our corporate governance guidelines and the charters of the Audit, the Compensation, and the Nominating and Governance Committees of our Board of Directors are available on our website, and are available in print free of charge to any stockholder upon request.  Information on our website is not incorporated into this report.

 

We file periodic reports and proxy statements with the SEC. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of the SEC’s website is www.sec.gov. 

 

2

 


 

 

 

ITEM 1. BUSINESS

 

Southwestern Energy Company is an independent energy company engaged in natural gas and oil exploration, development and production (E&P).  We are also focused on creating and capturing additional value through our natural gas gathering and marketing businesses, which we refer to as Midstream Services.  We conduct substantially all of our business through subsidiaries.

 

Exploration and Production - Our primary business is the exploration for and production of natural gas and oil, with our current operations principally focused within the United States on the development of two unconventional natural gas reservoirs located in Arkansas and Pennsylvania.  Our operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale, and our operations in Pennsylvania are focused on the unconventional natural gas reservoir known as the Marcellus Shale.  To a lesser extent, we have exploration and production activities ongoing in Texas and in Arkansas and Oklahoma in the Arkoma Basin.  We also actively seek to find and develop new oil and natural gas plays with significant exploration and exploitation potential, which we refer to as “New Ventures,” and through acquisitions.  We conduct our exploration and production operations primarily through our wholly owned subsidiaries SEECO, Inc. (“SEECO”), and Southwestern Energy Production Company (“SEPCO”).  SEECO operates exclusively in Arkansas, where it holds a large base of both developed and undeveloped natural gas reserves, and conducts the Fayetteville Shale drilling program and the conventional Arkoma Basin operations.  SEPCO conducts development drilling, exploration programs and production operations primarily in Pennsylvania, Oklahoma, Texas, Arkansas and Louisiana.  DeSoto Drilling Company, a wholly owned subsidiary of SEPCO, operates drilling rigs in Arkansas and Pennsylvania, as well as in other operating areas.  We also provide oilfield products and services through SWN Well Services, L.L.C., an indirect wholly owned subsidiary.  We have smaller Canadian operations conducted by our subsidiary SWN International, L.L.C. and its subsidiary, SWN Canada Resources Inc. 

 

Midstream Services - We engage in natural gas gathering activities in Arkansas, Texas and Pennsylvania through our subsidiaries DeSoto Gathering Company, L.L.C. (“DeSoto Gathering”), and Angelina Gathering Company, L.L.C. (“Angelina Gathering”).  DeSoto Gathering and Angelina Gathering primarily support our E&P operations and generate revenue from fees associated with the gathering of natural gas. Our natural gas marketing subsidiary, Southwestern Energy Services Company (“SES”), captures downstream opportunities that arise through the marketing and transportation of the natural gas produced in our E&P operations. 

 

The vast majority of our operating income and earnings before interest, taxes, depreciation, depletion and amortization and any non-cash impairment of natural gas and oil properties or (gain) loss on derivatives, net of settlement (“Adjusted EBITDA”), are derived from our E&P business.  In 2013, 73% of our operating income and 81% of our Adjusted EBITDA were generated from our E&P business, compared to 65% of our operating income, absent our $1,939.7 million, or $1,192.4 million net of taxes, non-cash ceiling test impairment of our natural gas and oil properties, and 79% of our Adjusted EBITDA in 2012, and 77% of our operating income and 84% of our Adjusted EBITDA in 2011.  The remainder of our consolidated operating income and Adjusted EBITDA in each of these years was generated from Midstream Services.  Adjusted EBITDA is a non-GAAP measure.  We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles Adjusted EBITDA to net income (loss).  

 

Our Business Strategy

Since 1999, our management has been guided by our formula, which represents the essence of our corporate philosophy and how we operate our business:

swn_formulaLogo.jpg

Our formula, which stands for “The Right People doing the Right Things, wisely investing the cash flow from our underlying Assets will create Value+,” also guides our business strategy.  We are focused on providing long-term growth in the net asset value of our business.  In our E&P business, we prepare an economic analysis for each investment opportunity based upon the expected net present value added for each dollar to be invested, which we refer to as Present Value Index, or PVI.  The PVI for each project is determined using a 10% discount rate.  We target creating an average of at least $1.30 of pre-tax PVI for each dollar we invest in our E&P projects.  Our actual PVI results are utilized to help determine the allocation of our future capital investments. The key elements of our business strategy are:

·

Exploit and Develop Our Positions in the Fayetteville Shale and the Marcellus Shale.  A key focus of the Company is to maximize the value of our significant acreage position in the Fayetteville Shale, which has provided significant

3

 


 

 

 

production and reserve growth since we began drilling in 2004. As of December 31, 2013, we held approximately 905,684 net acres in the Fayetteville Shale, accounting for approximately 69% of our total proved oil and natural gas reserves and approximately 74% of our total oil and natural gas production during 2013.  Additionally, we are actively drilling on portions of our 292,446 net acres in the Marcellus Shale and believe our production and reserves from the Marcellus Shale will grow substantially over the next few years.  We intend to develop further our acreage positions in the Fayetteville Shale and the Marcellus Shale and to improve our well results through the use of advanced technologies and detailed technical analysis of our properties.

·

Grow through New Exploration and Development Activities Focusing on Emerging Unconventional Plays.  We actively seek to find and develop new oil and natural gas plays with significant exploration and exploitation potential.  Our New Ventures prospects are evaluated based on repeatability, multi-well potential and land availability as well as other criteria, and can be located both inside and outside of the United States.  In addition to having E&P employees specifically focused on New Ventures activities, we also have a robust staff of employees focused on strategic business development activities.  As of December 31, 2013, we held 3,972,732 net undeveloped acres in connection with our New Ventures prospects, of which 2,518,518 net acres are located in New Brunswick, Canada. 

·

Maximize Efficiency through Vertical Integration and Economies of Scale.  In our key operating areas, the concentration of our properties allows us to achieve economies of scale that result in lower costs.  We seek to serve as the operator of the wells in which we have a significant interest.  As the operator, we are better positioned to control the drilling, completing and producing of wells and the marketing of production to minimize costs and maximize both production volumes and realized price.  In the Fayetteville Shale and the Marcellus Shale, we have achieved significant cost savings through our ownership of a sand mine, that is a source of proppant for our well completions, and through our ownership and operation of other associated oilfield services, including a fleet of drilling rigs and two pressure pumping equipment spreads used for well completions.  

·

Enhance the Value of Our Midstream Operations.  We have continued to design and improve our gas gathering infrastructure to manage better the physical movement of our production.  As of December 31, 2013, we have invested approximately $1,096 million in the 1,947 mile gas gathering system built for our Fayetteville Shale asset, which was gathering approximately 2.3 Bcf per day at year-end, and have invested approximately $213 million in 124 miles of gas gathering lines in Pennsylvania, Louisiana and East Texas.  Our gathering systems in the Fayetteville Shale and the Marcellus Shale have developed into strategic assets that not only support our E&P operations but also have improved our overall returns on a stand-alone basis.

Significant Accomplishments in 2013

Production and Reserve Growth.  In 2013, our production was 656.8 Bcfe, or approximately 1.8 Bcfe per day, an increase of 16% from 2012 levels.  This increase was driven primarily by our production growth of 181% from the Marcellus Shale.  Additionally, in 2013 our total proved reserves increased to the highest level in our company’s history, growing by 74% to approximately 7.0 Tcfe. 

Low Cost Structure.  Our cost structure continues to be one of the lowest in the industry, with an all-in cash operating cost of $1.25 per Mcfe in 2013, compared to $1.20 per Mcfe in 2012.  All-in cash operating cost per Mcfe is defined as the per Mcfe sum of our E&P segment’s lease operating expenses, taxes (other than income taxes), general and administrative expenses, and net interest expense.  We have included information concerning this ratio because it measures the cost efficiency of a company’s oil and gas producing operations and is a measure commonly used in our industry.   

Marcellus Shale Achieves Significant Growth.  Our Marcellus Shale division drove our overall production growth in 2013, with gross operated production reaching nearly 700 MMcf per day at year-end 2013 compared to 300 MMcf per day at year-end 2012.  Production nearly tripled to 150.6 Bcf in 2013, compared to 53.6 Bcf in 2012, while total proved reserves more than doubled to approximately 2.0 Tcf, compared to 816 Bcf in 2012.

 

Fayetteville Shale Continues to Deliver.  In 2013, our Fayetteville Shale division had one of its best years ever.  The division not only surpassed the milestone of 3 Tcf of cumulative gross operated production, but it also achieved its highest average initial production rate per well, all the while achieving its lowest average cost per well since we announced the Fayetteville Shale in 2004.  Total proved reserves for the Fayetteville Shale increased in 2013 to approximately 4.8 Tcf, from 3.0 Tcf in 2012, and 2013 production of 486.0 Bcf was flat compared to 2012 levels.

 

Financial Flexibility.  We ended 2013 with a capital structure that consisted of 35% debt and 65% equity and had approximately $1.7 billion of borrowing capacity available under our principal credit facility.  At December 31, 2013, our debt was rated as investment grade by all three of the major rating agencies: “BBB-” with a stable outlook by Standard and

4

 


 

 

 

Poor’s (S&P), “BBB-” with a stable outlook by Fitch Ratings (Fitch) and “Baa3” with a stable outlook by Moody’s Investors Service (Moody’s).

Recent Developments

2014 Planned Capital Investments and Production Guidance.  Our planned capital investment program for 2014 is approximately $2.3 billion, which includes approximately $2.0 billion for our E&P segment, $140 million for our Midstream Services segment and $150 million for E&P Services and corporate, $95 million of which is for the purchase of drilling rigs.  Our 2014 capital program is expected to be funded primarily by our cash flow from operations assuming current market prices.  The planned capital program for 2014 is flexible, and we will reevaluate our proposed investments as needed to take into account prevailing market conditions.  Based on our capital program, we are targeting 2014 natural gas and oil production of approximately 740 to 752 Bcfe, an increase of approximately 14% over our 2013 production, using midpoints.

Credit Facility Expansion.  In December 2013, we entered into a new Credit Agreement with JPMorgan Chase Bank, N.A., as Administrative Agent, and other lenders (the “Credit Facility”). Under the Credit Facility, we have a borrowing capacity of $2.0 billion and a maturity date of December 14, 2018 with options for two one-year extensions with the approval of participating lenders.  The amount available under the Credit Facility can be increased by up to an additional $500 million in the future upon the agreement between us and participating lenders. The Credit Facility is unsecured, is not guaranteed by any subsidiaries of the Company, and replaced the Company’s $1.5 billion unsecured revolving credit facility that was due to expire in February 2016.

Exploration and Production

Overview

Operations in our E&P segment are primarily in the Fayetteville Shale and the Marcellus Shale assets.  We also intend to conduct additional exploration and production activities in the Lower Smackover Brown Dense, or LSBD, conventional and unconventional operations targeting various formations as part of our New Ventures projects and exploration activities in New Brunswick, Canada.  We continue to actively seek to acquire and develop both conventional and unconventional natural gas and oil resource plays with significant exploration and exploitation potential.

 

Our E&P segment recorded operating income of $878.7 million in 2013, an operating loss of $1,396.3 million in 2012 as a result of the recognition of a $1,939.7 million, or $1,192.4 million net of taxes, non-cash ceiling test impairment of our United States natural gas and oil properties, and operating income of $823.6 million in 2011.  Operating income for 2013 increased $335.2 million compared to 2012 (excluding the $1,939.7 million non-cash ceiling test impairment recorded in 2012) as a result of an increase in revenue of $315.6 million from higher natural gas production volumes, an increase in revenue of $118.0 million from increased prices realized from the sale of our natural gas production and an increase in revenues of $5.6 million from higher oil volumes, offset by an increase in operating costs and expenses of $105.8 million associated with the expansion of our operations and higher activity levels in the Fayetteville Shale and the Marcellus Shale.    Operating income for 2012 (excluding the $1,939.7 million non-cash ceiling test impairment recorded in 2012) decreased $280.1 million compared to 2011 as the revenue impact of our 13% increase in production was more than offset by the 18% decline in our average realized gas prices and an increase in operating costs and expenses that resulted from our higher activity levels.  Adjusted EBITDA from our E&P segment was $1.6  billion in 2013, compared to $1.3 billion in 2012 and $1.5 billion in 2011.  Our Adjusted EBITDA increased in 2013 as higher realized gas prices and production volumes more than offset increased total operating costs and expenses due to increased activity levels.  Our Adjusted EBITDA decreased in 2012 as our increased production was more than offset by lower average realized gas prices and increased operating costs and expenses that resulted from our higher activity levels.  Adjusted EBITDA is a non-GAAP measure. We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a reconciliation of Adjusted EBITDA to net income (loss). 

 

Oilfield Services Vertical Integration

We seek to provide oilfield services internally that are strategic and economically beneficial for our E&P operations.  This vertical integration lowers our net well costs, allows us to operate safely and efficiently and mitigates certain operational environmental risks.  Among others, these services include drilling, hydraulic fracturing and the mining of proppant used for our well completions. 

5

 


 

 

 

Sand Mine

 

Since 2009, we have owned and operated a sand mine to provide a reliable supply of proppant primarily used for the completion of our wells that we operate in the Fayetteville Shale.  As of December 31, 2013, our sand mine is comprised of 570 acres and produces 30/70 and 100 mesh sized sand.  In 2013, we provided sand for the completion of 382 wells operated by us in the Fayetteville Shale and were able to reduce our well completion costs on average by 12% per well for the wells for which we provided sand.

 

Hydraulic Fracturing

 

SWN Well Services, L.L.C. provides pressure pumping services for a portion of our operated wells.  As of December 31, 2013, we operated two leased pressure pumping spreads with a total capacity of approximately 81,000 horsepower to conduct a variety of completion services designed to stimulate natural gas production.  In 2013, we provided pressure pumping services for 155 wells that we operated in the Fayetteville Shale and were able to reduce our well completion costs on average by 9% per well for the wells we completed. 

 

 Drilling Services

 

Our wholly owned subsidiary Desoto Drilling conducts drilling operations for our operated wells.  It sometimes conducts business under the registered assumed name SWN Drilling Company.  As of December 31, 2013, we operated 11 re-entry rigs and 2 spudder rigs which were operating in Arkansas, Pennsylvania and Louisiana.  In 2013, we provided drilling services for 414 and 41 wells that we operate in the Fayetteville Shale and the Marcellus Shale, respectively, and were able to reduce our drilling costs on average by 4% and 2% per well for the wells we drilled in the Fayetteville Shale and the Marcellus Shale, respectively.

 

Our Proved Reserves

 

Our estimated proved natural gas and oil reserves were 6,976 Bcfe at year-end 2013, compared to 4,018 Bcfe at year-end 2012 and 5,893 Bcfe at year-end 2011.  The significant increase in our reserves in 2013 was primarily due to our successful development drilling programs in the Fayetteville Shale and the Marcellus Shale and the higher natural gas price environment compared to 2012.  Because our proved reserves are primarily natural gas, our reserve estimates and the after-tax PV-10 measure, or standardized measure of discounted future net cash flows relating to proved natural gas and oil reserve quantities, are highly dependent upon the natural gas price used in the after-tax PV-10 calculation.  The average prices utilized to value our estimated proved natural gas and oil reserves as of December 31, 2013 were $3.67 per MMBtu for natural gas, $93.42 per barrel for oil and $43.45 per barrel for NGLs compared to $2.76 per MMBtu for natural gas and $91.21 per barrel for oil at December 31, 2012 and $4.12 per MMBtu for natural gas and $92.71 per barrel for oil at December 31, 2011.

 

Our after-tax PV-10 was $3.7 billion at year-end 2013, $2.1 billion at year-end 2012, and $3.5 billion at year-end 2011.  The increase in our after-tax PV-10 value in 2013 was primarily caused by an increase in our reserves and higher average natural gas prices in 2013.  The decrease in our after-tax PV-10 value in 2012 over 2011 was principally due to price revisions, primarily due to lower average natural gas prices in 2012. The difference in after-tax PV-10 and pre-tax PV-10 (a non-GAAP measure which is reconciled in the 2013 Proved Reserves by Category and Summary Operating Data table below) is the discounted value of future income taxes on the estimated cash flows.  Our year-end 2013 estimated proved reserves had a present value of estimated future net cash flows before income tax, or pre-tax PV-10, of $5.1 billion, compared to $2.3 billion at year-end 2012 and $4.8 billion at year-end 2011. 

 

We believe that the pre-tax PV-10 value of the estimated cash flows related to our estimated proved reserves is a useful supplemental disclosure to the after-tax PV-10 value.  While pre-tax PV-10 is based on prices, costs and discount factors that are comparable from company to company, the after-tax PV-10 is dependent on the unique tax situation of each individual company.  We understand that securities analysts use pre-tax PV-10 as one measure of the value of a company’s current proved reserves and to compare relative values among peer companies without regard to income taxes.  We refer you to Note 4 in the consolidated financial statements for a discussion of our standardized measure of discounted future cash flows related to our proved gas and oil reserves, to the risk factor “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate” in Item 1A of Part I of this Form 10-K, and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.

 

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Virtually 100% of our year-end 2013 estimated proved reserves were natural gas and 61% were classified as proved developed, compared to 100% and 80%, respectively, in 2012 and 100% and 55%, respectively in 2011.  We operate or if operations have not commenced, plan to operate, approximately 98% of our reserves, based on the pre-tax PV-10 value of our proved developed producing reserves, and our reserve life index approximated 10.6 years at year-end 2013.  Natural gas sales accounted for nearly 100% of total operating revenues for the E&P segment in 2013, 2012 and 2011.

 

The following table provides an overall and categorical summary of our oil and natural gas reserves, as of fiscal year-end 2013 based on average fiscal year prices, and our well count, net acreage and PV-10 as of December 31, 2013 and sets forth 2013 annual information related to production and capital investments for each of our operating areas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2013 PROVED RESERVES BY CATEGORY AND SUMMARY OPERATING DATA

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ark-La-Tex

 

 

 

 

 

 

 

Fayetteville

 

Marcellus

 

East

 

Arkoma

 

New

 

 

 

 

Shale

 

Shale

 

Texas

 

Basin

 

Ventures

 

Total

Estimated Proved Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (Bcf):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed (Bcf)

 

3,140 

 

 

888 

 

 

56 

 

 

152 

 

 

 

 

4,237 

Undeveloped (Bcf)

 

1,655 

 

 

1,075 

 

 

 

 

 

 

– 

 

 

2,737 

 

 

4,795 

 

 

1,963 

 

 

58 

 

 

157 

 

 

 

 

6,974 

Crude Oil (MMBbls):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed (MMBbls)

 

–  

 

 

–  

 

 

0.1 

 

 

–  

 

 

0.3 

 

 

0.4 

Undeveloped (MMBbls)

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

– 

 

 

– 

 

 

–  

 

 

–  

 

 

0.1 

 

 

–  

 

 

0.3 

 

 

0.4 

Total Proved Reserves (Bcfe)(1):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed (Bcfe)

 

3,140 

 

 

888 

 

 

56 

 

 

152 

 

 

 

 

4,239 

Undeveloped (Bcfe)

 

1,655 

 

 

1,075 

 

 

 

 

 

 

– 

 

 

2,737 

 

 

4,795 

 

 

1,963 

 

 

58 

 

 

157 

 

 

 

 

6,976 

Percent of Total

 

69% 

 

 

28% 

 

 

1% 

 

 

2% 

 

 

 –

 

 

100% 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Percent Proved Developed

 

65% 

 

 

45% 

 

 

97% 

 

 

97% 

 

 

100% 

 

 

61% 

Percent Proved Undeveloped

 

35% 

 

 

55% 

 

 

3% 

 

 

3% 

 

 

 –

 

 

39% 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production (Bcfe)

 

486 

 

 

151 

 

 

 

 

12 

 

 

 

 

657 

Capital Investments (millions)(2)

$

907 

 

$

872 

 

$

 

$

 

$

191 

 

$

1,977 

Total Gross Producing Wells(3)

 

3,539 

 

 

334 

 

 

173 

 

 

1,164 

 

 

 

 

5,213 

Total Net Producing Wells(3)

 

2,432 

 

 

171 

 

 

109 

 

 

566 

 

 

 

 

3,281 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Net Acreage

 

781,464 
(4)

 

292,446 
(5)

 

50,451 
(6)

 

226,706 
(7)

 

3,976,002 
(8)

 

5,327,069 

Net Undeveloped Acreage

 

291,360 
(4)

 

246,838 
(5)

 

172 
(6)

 

60,375 
(7)

 

3,972,732 
(8)

 

4,571,477 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PV-10:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pre-tax (millions)(9)

$

3,690 

 

$

1,202 

 

$

62 

 

$

163 

 

$

12 

 

$

5,129 

PV of taxes (millions)(9)

 

1,002 

 

 

327 

 

 

17 

 

 

44 

 

 

 

 

1,393 

After-tax (millions)(9)

$

2,688 

 

$

875 

 

$

45 

 

$

119 

 

$

 

$

3,736 

Percent of Total

 

72% 

 

 

24% 

 

 

1% 

 

 

3% 

 

 

 –

 

 

100% 

Percent Operated(10)

 

98% 

 

 

99% 

 

 

97% 

 

 

88% 

 

 

100% 

 

 

98% 

 

 (1)We have no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil.  We used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis offset statistical analogy of performance data, volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors.

7

 


 

 

 

(2)Our Total and Fayetteville Shale capital investments exclude $76 million related to our drilling rig related equipment, sand facility and other equipment. 

(3)Represents all producing wells, including wells in which we only have an overriding royalty interest, as of December 31, 2013.

(4)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 22,092 net acres in 2014, 16,305 net acres in 2015, and 1,803 net acres in 2016 (excluding 155,852 net acres held on federal lands which are currently suspended by the Bureau of Land Management). 

(5)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 65,537 net acres in 2014, 32,637 net acres in 2015 and 19,233 net acres in 2016.

(6)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 27 net acres in 2014, 64 net acres in 2015 and zero net acres in 2016.

(7)Includes 123,442 net developed acres and 778 net undeveloped acres in the Arkoma Basin that are also within our Fayetteville Shale focus area but not included in the Fayetteville Shale acreage in the table above.  Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 262 net acres in 2014, 7,437 net acres in 2015 and 574 net acres in 2016.

(8)Assuming successful wells are not drilled to develop the acreage and leases are not extended, our leasehold expiring over the next three years, excluding New Brunswick, Canada and the LSBD area, will be 65,628 net acres in 2014, 143,708 net acres in 2015 and 273,306 net acres in 2016.  With regard to the Company’s acreage in New Brunswick, Canada, 2,518,518 net acres will expire in March 2015.  We are in the process of applying for an additional 1-year option to extend our exploration license agreements and, if granted by the Province of New Brunswick, this would extend our exploration license agreements until March 2016.  With regard to our acreage in the LSBD, assuming successful wells are not drilled and leases are not extended, leasehold expiring over the next three years will be 245,793 net acres in 2014, 151,667 net acres in 2015 and 25,891 net acres in 2016.

(9)Pre-tax PV-10 (a non-GAAP measure) is one measure of the value of a company’s proved reserves that we believe is used by securities analysts to compare relative values among peer companies without regard to income taxes.  The reconciling difference in pre-tax PV-10 and the after-tax PV-10, or standardized measure, is the discounted value of future income taxes on the estimated cash flows from our proved oil and natural gas reserves.

(10) Based upon pre-tax PV-10 of proved developed producing properties.

 

We refer you to Note 4 in our consolidated financial statements for a more detailed discussion of our proved gas and oil reserves as well as our standardized measure of discounted future net cash flows related to our proved gas and oil reserves.  We also refer you to the risk factor “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate” in Item 1A of Part I of this Form 10-K and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.

8

 


 

 

 

   

Proved Undeveloped Reserves

 

Presented below is a summary of changes in our proved undeveloped reserves for 2013, 2012 and 2011. 

 

 

 

 

 

 

 

 

 

 

 

 

Changes in Proved Undeveloped Reserves (Bcfe)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Ark-La-Tex

 

 

 

Fayetteville

 

Marcellus

 

East

 

Arkoma

 

 

 

 

Shale

 

Shale

 

Texas

 

Basin

 

Total

December 31, 2010

 

2,132 

 

27 

 

55 

 

29 

 

2,243 

Extensions, discoveries and other additions

 

688 

 

155 

 

 

–  

 

848 

Total revision attributable to performance and

  production

 

(28)

 

14 

 

(5)

 

(7)

 

(26)

Price revisions

 

(1)

 

(4)

 

(1)

 

(1)

 

(7)

Developed

 

(376)

 

(22)

 

(6)

 

–  

 

(404)

Disposition of reserves in place

 

–  

 

–  

 

(21)

 

–  

 

(21)

Acquisition of reserves in place

 

–  

 

–  

 

–  

 

–  

 

–  

December 31, 2011

 

2,415 

 

170 

 

27 

 

21 

 

2,633 

Extensions, discoveries and other additions

 

32 

 

305 

 

–  

 

–  

 

337 

Total revision attributable to performance and

  production

 

(239)

 

16 

 

–  

 

–  

 

(223)

Price revisions

 

(1,401)

 

 

(26)

 

(7)

 

(1,433)

Developed

 

(443)

 

(50)

 

–  

 

–  

 

(493)

Disposition of reserves in place

 

–  

 

–  

 

–  

 

–  

 

–  

Acquisition of reserves in place

 

–  

 

–  

 

–  

 

–  

 

–  

December 31, 2012

 

364 

 

442 

 

 

14 

 

821 

Extensions, discoveries and other additions (1)

 

1,530 

 

810 

 

–  

 

–  

 

2,340 

Total revision attributable to performance and

  production

 

(115)

 

(33)

 

–  

 

(9)

 

(157)

Price revisions

 

18 

 

26 

 

 

–  

 

45 

Developed

 

(142)

 

(170)

 

–  

 

–  

 

(312)

Disposition of reserves in place

 

–  

 

–  

 

–  

 

–  

 

–  

Acquisition of reserves in place

 

–  

 

–  

 

–  

 

–  

 

–  

December 31, 2013

 

1,655 

 

1,075 

 

 

 

2,737 

 

 

(1)

The 2013 PUD additions are primarily associated with the increase in gas prices.

 

As of December 31, 2013, we had 2,737 Bcfe of proved undeveloped reserves, all of which we expect will be developed within five years of the initial disclosure as the starting reference date.  During 2013, we invested $248 million in connection with converting 312.3 Bcfe or 38% of our proved undeveloped reserves as of December 31, 2012, into proved developed reserves and added 2,340 Bcfe of proved undeveloped reserve additions in the Fayetteville Shale and the Marcellus Shale.    As of December 31, 2012, we had 821 Bcfe of proved undeveloped reserves, all of which we expect will be developed within five years of the initial disclosure as the starting reference date.  During 2012, we invested $518 million in connection with converting 493.2 Bcfe or 19% of our proved undeveloped reserves as of December 31, 2011 into proved developed reserves and added 336.8 Bcfe of proved undeveloped reserve additions in the Fayetteville Shale and the Marcellus Shale.

The development of our proved undeveloped reserves will require us to make significant additional investments.  We expect that the development costs for our proved undeveloped reserves of 2,737 Bcfe as of December 31, 2013 will require us to invest an additional $3.1 billion for those reserves to be brought to production.  Our ability to make the necessary

9

 


 

 

 

investments to generate these cash inflows is subject to factors that may be beyond our control.  A significant decrease in price levels for an extended period of time could result in certain reserves no longer being economic to produce, leading to both lower proved reserves and cash flows.  We refer you to the risk factors “A substantial or extended decline in natural gas and oil prices would have a material adverse effect on us,” “We may have difficulty financing our planned capital investments, which could adversely affect our growth” and “Our level of indebtedness and the terms of our financing arrangements may adversely affect operations and limit our growth” in Item 1A of Part I of this Form 10-K and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a more detailed discussion of these factors and other risks.

Our Reserve Replacement

 

The reserve replacement ratio measures the ability of an exploration and production company to add new reserves to replace the reserves that are being depleted by its current production volumes.  The reserve replacement ratio, which we discuss below, is an important analytical measure used by investors and peers in the E&P industry to evaluate performance results and long-term prospects.  There are limitations as to the usefulness of this measure, as it does not reflect the type of reserves or the cost of adding the reserves or indicate the potential value of the reserve additions. 

 

In 2013, we replaced 550% of our production volumes with 3,285 Bcfe of proved reserve additions, net upward revisions of 326 Bcfe, and 4 Bcfe of proved reserve additions as a result of acquisitions.  Of the reserve additions, 945 Bcfe were proved developed and 2,340 Bcfe were proved undeveloped.  In 2013, upward reserve revisions resulting from higher gas prices totaled 191 Bcf, 35 Bcf and 21 Bcf in the Fayetteville Shale, the Marcellus Shale and our Ark-La-Tex division, respectively.  We also had upward performance revisions in 2013 of 16 Bcf, 62 Bcf and 1 Bcf in the Fayetteville Shale, the Marcellus Shale, and our New Ventures division, respectively.  Additionally, our reserves increased by 4 Bcf in 2013 as a result of our acquisition of natural gas leases and wells.

 

In 2012, we replaced our production volumes with 920 Bcfe of proved reserve additions as a result of our drilling and acquisition program but also incurred net downward revisions of 2,088 Bcfe principally due to a decrease in the price of natural gas and to a lesser extent due to downward performance revisions of 336 Bcfe.  Of the reserve additions, 583 Bcfe were proved developed and 337 Bcfe were proved undeveloped. The total downward reserve revisions were primarily impacted by the low commodity price environment in 2012 and to a lesser extent by downward performance revisions.  In 2012, downward reserve revisions resulting from lower gas prices totaled 1,684 Bcf, 9 Bcf and 59 Bcf in the Fayetteville Shale, the Marcellus Shale, and our Ark-La-Tex division, respectively.  We also had a net downward performance revision in 2012 of 362 Bcf and 10 Bcf in the Fayetteville Shale and our Ark-La-Tex division, respectively.  We had a net positive performance revision in 2012 of 36 Bcf in the Marcellus Shale.  Additionally, our reserves decreased by 141 Bcf in 2012 as a result of our disposition of natural gas leases and wells.

 

In 2011, we replaced 299% of our production volumes with an increase of 1,459 Bcfe of proved gas and oil reserves as a result of our drilling program and net upward revisions of 34 Bcfe.  Of the reserve additions, 612 Bcfe were proved developed and 847 Bcfe were proved undeveloped. The upward reserve revisions during 2011 were primarily comprised of 103 Bcf in upward revisions related to the improved performance of our wells in the Marcellus Shale, partially offset by downward performance revisions of 28 Bcfe and 18 Bcfe in our East Texas and conventional Arkoma Basin operating areas, respectively.  We also had downward performance revisions in the Fayetteville Shale of 14 Bcfe.  Additionally, our reserves decreased by 9 Bcfe due to a drop in the average gas price for 2011 as compared to 2010.  In addition, our reserves decreased by 37 Bcfe as a result of our sale of oil and natural gas leases and wells in 2011.

 

For the period ending December 31, 2013, our three-year average reserve replacement ratio, including revisions and acquisitions, was 229%. Our reserve replacement ratio for 2013, excluding the effect of reserve revisions, was 501%, compared to 163% in 2012 and 292% in 2011. Excluding reserve revisions and acquisitions, our three-year average reserve replacement ratio was 329%.

 

Since 2005, the substantial majority of our reserve additions have been generated from our Fayetteville Shale.  However, over the past several years the Marcellus Shale has also contributed to an increasing amount of our reserve additions, totaling 1,200 Bcf, 500 Bcf and 229 Bcf in 2013, 2012 and 2011, respectively.  We expect our drilling programs in the Fayetteville Shale and the Marcellus Shale to continue to be the primary source of our reserve additions in the future; however, our ability to add reserves depends upon many factors that are beyond our control.  We refer you to the risk factors “Our drilling plans for the Fayetteville Shale and the Marcellus Shale are subject to change” and “Our exploration, development and drilling efforts and our operation of our wells may not be profitable or achieve our targeted returns” in Item 1A of Part I of this Form 10-K and to “Management’s Discussion and Analysis of Financial Condition and Results of

10

 


 

 

 

Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a more detailed discussion of these factors and other risks.

 

Our Operations

 

Fayetteville Shale

 

Our Fayetteville Shale properties are one of the two primary focus areas of our exploration and production business.  The Fayetteville Shale is a Mississippian-age unconventional gas reservoir located on the Arkansas side of the Arkoma Basin, ranging in thickness from 50 to 550 feet and ranging in depth from 1,500 to 6,500 feet.  As of December 31, 2013, we held leases for approximately 905,684 net acres in the play area (291,360 net undeveloped acres, 490,104 net developed acres held by Fayetteville Shale production, 123,442 net acres held by conventional production in the Arkoma Basin, and 778 net undeveloped acres in the Arkoma Basin), compared to approximately 913,502 net acres at year-end 2012 and 925,842 net acres at year-end 2011.

 

Approximately 4,795 Bcf of our reserves at year-end 2013 were attributable to our Fayetteville Shale properties, compared to approximately 2,988 Bcf at year-end 2012 and 5,104 Bcf at year-end 2011.  Our reserves in the Fayetteville Shale increased by 1,807 Bcf in 2013, which included reserve additions of 2,087 Bcf, net upward price revisions of 190 Bcf, 16 Bcf of net upward revisions due to well performance, offset by production of 486 Bcf.  Our net production from the Fayetteville Shale was 486 Bcf in 2013, compared to 486 Bcf in 2012 and 437 Bcf in 2011.  In 2014, we estimate our net production from the Fayetteville Shale will be in the range of 479 to 484 Bcf.

 

At year-end 2013, after excluding our acreage in the conventional Arkoma Basin and the federal acreage we hold in the Ozark Highlands Unit, approximately 80% of our 628,975 total net leasehold acres remaining in the Fayetteville Shale was held by production.  For more information about our acreage and well count, we refer you to “Properties” in Item 2 of Part 1 of this Form 10-K.  Excluding our acreage in the conventional Arkoma Basin, our acreage position was obtained at an average cost of approximately $320 per acre and has an average royalty interest of 15%.  In 2014, we expect to earn 11 sections, or approximately 3,969 net acres, representing 2% of our drilling program.  As of December 31, 2013, excluding our acreage in the conventional Arkoma Basin and our federal acreage, the undeveloped portion of our acreage had an average remaining lease term of 1 year.  We refer you to the risk factor “If we fail to drill all of the wells that are necessary to hold our acreage, the initial lease terms could expire, which would result in the loss of certain leasehold rights” in Item 1A of Part I of this Form 10-K. 

 

Following the commencement of two court actions, now consolidated, alleging deficiencies in the Environmental Impact Statement issued in connection with the grant of the leases by the Bureau of Land Management (BLM) in the Ozark National Forest, the BLM has discontinued approval of operational permits in the forest, including permits to drill, pending resolution of the litigation.  The Ozark Highlands Unit lies entirely within the Ozark National Forest.  Although the Company is not a party to the litigation and the plaintiffs’ complaints do not seek invalidation of the leases, we currently are unable to obtain permits to drill on the 195,619 acres we have leased in the unit and the national forest. The period to drill to maintain leases has been extended pending resolution of this litigation on all but 2,832 of these net acres.

 

As of December 31, 2013, we had spud a total of 4,110 wells in the Fayetteville Shale since its commencement in 2004, of which 3,538 were operated by us and 572 were outside-operated wells.  Of these wells, 527 were spud in 2013, 491 in 2012 and 650 in 2011.  Of the wells spud in 2013, 525 were designated as horizontal wells.  At year-end 2013, 3,288 wells operated by the Company had been drilled and completed overall, including 3,197 horizontal wells.  Of the 3,197 horizontal wells, 3,179 wells were fracture stimulated using either slickwater or crosslinked gel stimulation treatments, or a combination thereof.

 

Over the past several years, we have seen continuous improvement in our drilling practices in the Fayetteville Shale.  In 2013, the horizontal wells we drilled as operator had an average completed well cost of $2.4 million per well, average horizontal lateral length of 5,356 feet, and an average time to drill to total depth of 6.2 days from re-entry to re-entry.  This compares to an average completed operated well cost of $2.5 million per well, average horizontal lateral length of 4,833 feet and average time to drill to total depth of 6.7 days from re-entry to re-entry during 2012.  In 2011, our average completed operated well cost was $2.8 million per well with an average horizontal lateral length of 4,836 feet and average time to drill to total depth of 7.9 days from re-entry to re-entry.  The operated wells we placed on production during 2013 averaged initial production rates of 4,041 Mcf per day, compared to average initial production rates of 3,629 Mcf per day in 2012 and 3,330 Mcf per day in 2011.  In 2013, our initial production rates increased, compared to initial production rates in 2012 as a result of longer lateral lengths, improved well bore placement, and further refined completion and flowback techniques.  The increase in initial production rates for 2012, compared to the initial production rates of the preceding year, is primarily due to the optimization of our drilling plan toward areas in the field with the highest-return wells.  During

11

 


 

 

 

2013, we placed 91 operated wells on production with initial production rates that exceeded 5.0 MMcf per day, compared to 60 wells in 2012 and 51 wells in 2011.

 

Our total proved net reserves booked in the Fayetteville Shale at year-end 2013 were from a total of 4,631 locations, of which 3,511 were proved developed producing, 59 were proved developed non-producing and 1,061 were proved undeveloped.  Of the 4,631 locations, 4,614 were horizontal.  The average gross proved reserves for the undeveloped wells included at year-end 2013 was approximately 2.5 Bcf per well, compared to 2.8 Bcf per well at year-end 2012, and 2.4 Bcf per well at year-end 2011.  The decrease in average gross proved reserves for our undeveloped wells in 2013 was primarily due to the addition of over 800 proven undeveloped locations with lower estimated ultimate recoveries that were added due to the higher gas price environment.  The increase in average gross proved reserves for our undeveloped wells in 2012 was primarily due to the estimated ultimate recoveries of those locations which remained economic at the average prices utilized during 2012. Total proved net natural gas reserves booked in the Fayetteville Shale in 2012 were approximately 2,988 Bcf from a total of 3,508 locations, of which 3,175 were proved developed producing, 123 were proved developed non-producing and 210 were proved undeveloped.  Total proved net natural gas reserves booked in the play in 2011 totaled approximately 5,104 Bcf from a total of 4,376 locations, of which 2,735 were proved developed producing, 59 were proved developed non-producing and 1,582 were proved undeveloped. 

 

In 2013, we invested approximately $907 million in the Fayetteville Shale, which included approximately $804 million to spud 527 wells, 504 of which we operate.  Included in our total capital investments in the Fayetteville Shale during 2013 was $97 million in capitalized costs and other expenses and $6 million for acquisition of properties.  In 2012, we invested approximately $991 million in the Fayetteville Shale, which included $877 million to spud 491 wells, 453 of which we operate, $4 million for acquisition of properties, and $110 million in capitalized costs and other expenses.  In 2011, we invested approximately $1.3 billion in the Fayetteville Shale, which included $1.2 billion to spud 650 wells, $10 million for acquisition of properties and $132 million in capitalized costs and other expenses.  As of December 31, 2013, we had acquired approximately 1,324 square miles of 3-D seismic data, which provides us with seismic data on approximately 65% of our net acreage position in the Fayetteville Shale, excluding our acreage in the Arkoma Basin.

 

In 2014, we plan to invest approximately $900 million in our Fayetteville Shale properties, which includes participating in approximately 460 to 470 gross wells, all of which we plan to operate. 

 

We believe that our Fayetteville Shale acreage continues to have significant development potential.  Our strategy is to continue our development drilling, increase the amount of acreage we hold by production and determine the economic viability of the undrilled portion of our acreage.  Our drilling program with respect to our Fayetteville Shale properties is flexible and will be impacted by a number of factors, including the results of our horizontal drilling efforts, our ability to determine the most effective and economic fracture stimulation methods and well spacing, the extent to which we can replicate the results of our most successful Fayetteville Shale wells in other Fayetteville Shale acreage and the natural gas commodity price environment.  As we continue to gather data about the Fayetteville Shale, it is possible that additional information may cause us to alter our drilling schedule or determine that prospects in some portion of our acreage position should not be pursued at all. We refer you to the risk factor “Our drilling plans for the Fayetteville Shale and the Marcellus Shale are subject to change” in Item 1A of Part I of this Form 10-K.

 

Marcellus Shale

 

We began leasing acreage in northeastern Pennsylvania in 2007 in an effort to participate in the emerging Marcellus Shale.  As of December 31, 2013, we had approximately 292,446 net acres in Pennsylvania under which we believe the Marcellus Shale is present (246,838 net undeveloped acres and 45,608 net developed acres held by production), compared to approximately 176,298 net acres at year-end 2012 and 186,893 net acres at year-end 2011.  Our undeveloped acreage position as of December 31, 2013 had an average remaining lease term of 3 years and an average royalty interest of 15% and was obtained at an average cost of approximately $1,232 per acre.  Included in the acreage numbers above is approximately 162,000 net acres in the Marcellus Shale that we acquired in 2013 for approximately $93 million.  The acquired acreage is near our existing acreage in the Marcellus Shale.   

 

As of December 31, 2013, we had spud 269 wells operated by the Company, 172 of which were on production and 261 of which will be horizontal wells.  In 2013, we invested approximately $872 million in the Marcellus Shale and spud 108 operated wells, resulting in reserve additions and revisions of 1,297 Bcf.  Of these 108 horizontal wells, 57 wells are located in our Price and Range Trust areas in Susquehanna County, 43 wells are located in our Greenzweig area in Bradford County, 6 wells are located in Lycoming County, and the remaining 2 wells are located in Sullivan County.  In 2013, our operated horizontal wells had an average completed well cost of $7.0 million per well, average horizontal lateral length of 4,982 feet and an average of 18 fracture stimulation stages.  This compares to an average completed operated well cost of $6.1 million per well, average horizontal lateral length of 4,070 feet and an average of 12 fracture stimulation

12

 


 

 

 

stages in 2012.  In 2011, our average completed operated well cost was $7.0 million per well with an average horizontal lateral length of 4,223 feet and an average of 14 fracture stimulation stages.  Included in our total capital investments in the Marcellus Shale during 2013 was approximately $676 million for drilling and completions, $111 million for acquisition of properties, $9 million for seismic and $76 million in facilities, capitalized costs and other expenses.  In 2012, we invested approximately $507 million in the Marcellus Shale and spud 92 operated wells, resulting in net reserve additions and revisions of 500 Bcf.  In 2011, we invested approximately $332 million in the Marcellus Shale and spud 43 operated wells, resulting in net reserve additions and revisions of 327 Bcf.

 

Approximately 1,963 Bcf of our total proved net reserves at year-end 2013 were attributable to the Marcellus Shale.  The Company had a total of 171 horizontal and one vertical well that the Company operated and that were on production as of December 31, 2013, resulting in net production from this area of 151 Bcf in 2013, compared to 54 Bcf in 2012 and 23 Bcf in 2011.  Our 2013 year-end reserves booked in the Marcellus Shale include a total of 522 locations, of which 333 were proved developed producing, and 189 were proved undeveloped.  At year-end 2012, we had approximately 816 Bcf in proved reserves in the Marcellus Shale from a total of 203 locations, of which 129 were proved developed producing, 1 was proved developed non-producing and 73 were proved undeveloped.  At year-end 2011, we had approximately 342 Bcf of proved reserves in the Marcellus Shale from a total of 60 locations, of which 30 were proved developed producing, 2 were proved developed non-producing and 28 were proved undeveloped.  The average gross proved reserves for the undeveloped wells included in our year-end reserves for 2013 was approximately 6.9 Bcf per well, compared to 7.6 Bcf per well at year-end 2012 and 7.5 Bcf per well in 2011. 

 

In 2014, we plan to invest approximately $760 million in the Marcellus Shale and expect to participate in a total of 80 to 85 gross wells in 2014, the vast majority of which will be operated by us.  In 2014, we estimate our net production from the Marcellus Shale will be in the range of 244 to 249 Bcf.  Our ability to bring our Marcellus Shale production to market will depend on a number of factors including the construction of and/or the availability of capacity on gathering systems and pipelines that we do not own.  We refer you to “Midstream Services — Gas Marketing” for a discussion of our gathering and transportation arrangements for the Marcellus Shale production and to the risk factor “Our ability to sell our natural gas and oil and to receive market prices for our production may be adversely affected by constraints or interruptions on gathering systems, pipelines, processing and transportation systems owned or operated by us or others.” in Item 1A of Part I of this Form 10-K. 

   

We believe that our Marcellus Shale acreage has significant development potential.  Our drilling program with respect to the Marcellus Shale is flexible and will be impacted by a number of factors, including the results of our horizontal drilling efforts, our ability to determine the most effective and economic fracture stimulation methods, transportation capacity and well spacing and the natural gas commodity price environment.  As we continue to gather data about the Marcellus Shale, it is possible that additional information may cause us to alter our drilling schedule or determine that prospects in some portion of our acreage position should not be pursued at all.  We refer you to the risk factor “Our drilling plans for the Fayetteville Shale and the Marcellus Shale are subject to change” in Item 1A of Part I of this Form 10-K.

 

Ark-La-Tex

 

Our Ark-La-Tex division includes our conventional assets in the Arkoma Basin in Arkansas and Oklahoma and our conventional and unconventional assets in East Texas.  Production from these assets was 18 Bcfe in 2013, compared to 26 Bcfe in 2012 and 40 Bcfe in 2011.  The decline in production from these areas during 2013 and 2012 was primarily driven by asset dispositions as well as natural field production declines and lower capital investments in these areas since 2009.  In May 2012, we sold our oil and natural gas leases, wells and gathering equipment in approximately 19,800 net acres in the Overton Field in East Texas for approximately $164 million.  We expect our planned level of capital investments and the natural production decline in existing wells to decrease our net production from the Ark-La-Tex division in 2014.  In 2013, we invested approximately $7 million in our Ark-La-Tex division and added new reserves of 0.2 Bcfe.  Total proved net reserves from these areas were approximately 215 Bcfe as of December 31, 2013, compared to 213 Bcfe at year-end 2012 and 447 Bcfe at year-end 2011.  In 2014, we expect to invest approximately $7 million in our Ark-La-Tex division.

 

New Ventures

 

We actively seek to find and develop new oil and natural gas plays with significant exploration and exploitation potential, which we refer to as “New Ventures.”  We have been focusing on both oil and natural gas unconventional plays, and the technological methods best suited to developing these plays, such as horizontal drilling and fracture stimulation techniques.  New Ventures prospects are evaluated based on multi-well potential and land availability as well as other criteria and may be located both inside and outside of the United States.  As of December 31, 2013, we held 3,972,732 net undeveloped acres in connection with our New Ventures prospects, of which 2,518,518 net acres were located in New

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Brunswick, Canada. This compares to 3,819,128 net undeveloped acres held at year-end 2012 and 3,600,314 net undeveloped acres held at year-end 2011.

 

Although we believe that our New Ventures projects have significant exploration and exploitation potential, there can be no assurance that any prospects will result in viable projects or that we will not abandon our initial investments.  We refer you to the risk factors “The success of our New Ventures projects is subject to drilling and completion technique risks and enhanced recovery methods.  Our drilling results may not meet our expectations for reserves or production and the value of our undeveloped New Venture acreage could decline,” and “Our exploration, development and drilling efforts and our operation of our wells may not be profitable or achieve our targeted returns” in Item 1A of Part I of this Form 10-K.

 

Lower Smackover Brown Dense.  In July 2011, we announced that we would begin testing a new unconventional liquids rich play targeting the Lower Smackover Brown Dense formation, an unconventional reservoir that ranges in vertical depths from 8,000 to 11,000 feet and appears to be laterally extensive over a large area ranging in thickness from 300 to 550 feet.  As of December 31, 2013, we held approximately 459,321 net undeveloped acres in the area, obtained at an average cost of $483 per acre.  Our leases currently have an approximate 81% average net revenue interest and an average primary lease term of approximately three years, which may be extended for approximately three to four additional years.

 

As of December 31, 2013, we had drilled 11 operated wells in the play area, 5 of which were currently testing or producing, 1 is waiting on completion and 1 is drilling.  We are continuing to analyze our results to date.

 

New Brunswick, Canada.  In March 2010, we successfully bid for exclusive licenses from the Department of Natural Resources of New Brunswick to search and conduct an exploration program covering 2,518,518 net acres in the province in order to test new hydrocarbon basins.  As a condition under our licenses, we are required to make investments of approximately $47 million Canadian dollars in the province by March 31, 2015 (March 31, 2013 prior to extension).  In December 2012, we received two one-year extensions to our exploration license agreements which expire on March 16, 2014 and March 16, 2015, respectively.  In December 2013, we completed our seismic program which was started in 2010 and included airborne gravity and magnetic surveys, surface geochemistry surveys, and the acquisition of 617 kilometers of 2-D seismic data.  Through December 31, 2013, we have invested approximately $39.2 million Canadian dollars, or $36.9 million USD, in our New Brunswick exploration program towards our commitment.  This is our first venture outside of the United States.

 

Denver-Julesburg Basin. We have approximately 302,243 net acres in the Denver-Julesburg Basin in eastern Colorado where we have begun testing an unconventional oil play targeting middle and late Pennsylvanian to Permian-age carbonates and shales.  We have drilled two test wells to test multiple intervals and will continue to test the concept with additional wells in early 2014. 

 

Other. In 2013, we drilled an operated horizontal well and re-entered an existing well to test the Bakken, the Three Forks and the Nisku objectives in Sheridan County, Montana.  Our results were not commercial and we have discontinued our operations in the area.  In 2013, we acquired undeveloped acreage and drilled a horizontal well in the Paradox Basin in Utah which tested the Cane Creek, Gothic and Hovenweep formations that was a dry hole. As of December 31, 2013, excluding acreage located in our New Brunswick, Lower Smackover Brown Dense, and Denver-Julesburg Basin prospects, our New Ventures operations held acreage totaling 692,650 net acres in other prospective areas located throughout multiple geographic regions. 

 

Acquisitions and Divestitures

 

In April 2013, we acquired approximately 162,000 net acres in the Marcellus Shale for approximately $93 million.  The acquired acreage is near our existing acreage in the Marcellus Shale. 

In May 2012, we sold certain oil and natural gas leases, wells and gathering equipment in the Overton Field in East Texas for approximately $164 million.  The sale included approximately 19,800 net acres in Smith County, Texas.  Net production from the field was approximately 24 MMcfe per day as of the closing date and proved net reserves were approximately 143 Bcfe as of year-end 2011.

Capital Investments

 

During 2013, we invested a total of approximately $2.1 billion in our E&P business and participated in drilling 653 wells, 340 of which were successful and 309 of which were in progress at year-end.  Of the 309 wells in progress at year-end, 227 and 77 were located in our Fayetteville Shale and the Marcellus Shale operating areas, respectively.  Of the

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approximately $2.1 billion invested in our E&P business in 2013, approximately $907 million was invested in the Fayetteville Shale, $872 million in the Marcellus Shale, $3 million in East Texas, $4 million in our conventional Arkoma Basin program and $191 million in New Ventures projects, which includes $84 million in the Lower Smackover Brown Dense.

 

Of the $2.1 billion invested in 2013, approximately $1.5 billion was invested in exploratory and development drilling and workovers, $224 million in capitalized interest and other expenses,  $159 million for acquisition of properties, and $28 million for seismic expenditures.  Additionally, we invested approximately $76 million in our drilling rigs and related equipment, sand facility and other equipment, and $18 million in pond and water facilities.  In 2012, we invested approximately $1.9 billion in our primary E&P business activities and participated in drilling 595 wells. Of the $1.9 billion invested in 2012, approximately $1.4 billion was invested in exploratory and development drilling and workovers, $186 million for acquisition of properties, $10 million for seismic expenditures and $254 million in capitalized interest and other expenses.  Additionally, we invested approximately $15 million in our drilling rigs and  related equipment, sand facility and other equipment.  In 2011, we invested approximately $2.0 billion in our primary E&P business activities and participated in drilling 708 wells.  Of the $2.0 billion invested in 2011, approximately $1.5 billion was invested in exploratory and development drilling and workovers, $227 million for acquisition of properties, $30 million for seismic expenditures and $199 million in capitalized interest and expenses and other technology-related expenditures.  Additionally, we invested approximately $21 million in our drilling rig related equipment, sand facility and other equipment.   

 

In 2014, we plan to invest approximately $2.0 billion in our E&P program and participate in drilling 563 to 578 gross wells, the vast majority of which will be operated by us.  The Fayetteville Shale and the Marcellus Shale will be the primary focus of our capital investments, with planned investments of approximately $900 and $760 million, respectively.  Our planned 2014 capital investments also include approximately $190 million in unconventional exploration and New Ventures projects, $178 million for our Lower Smackover Brown Dense exploration program, and $7 million in our Ark-La-Tex division. 

Of the $2.0 billion allocated to our 2014 E&P capital budget, approximately $1.6 billion currently is planned to be invested in development and exploratory drilling, $47 million in seismic and other geological and geophysical expenditures, $159 million in acquisition of properties and $278 million in capitalized interest and expenses as well as equipment, facilities and technology-related expenditures.  The planned capital program for 2014 is flexible and can be modified.  We will reevaluate our proposed investments as needed to take into account prevailing market conditions and, if natural gas prices change significantly in 2014, we could change our planned investments.    We refer you to “Managements Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Investments” for additional discussion of the factors that could impact our planned capital investments in 2014.

 

Sales, Delivery Commitments and Customers

Sales. Our daily natural gas equivalent production averaged 1,800 MMcfe in 2013, compared to 1,544 MMcfe in 2012 and 1,370 MMcfe in 2011.  Total natural gas equivalent production was 657 Bcfe in 2013, up from 565 Bcfe in 2012 and 500 Bcfe in 2011.  Our natural gas production was 656 Bcf in 2013, compared to 565 Bcf in 2012 and 499 Bcf in 2011.  The increase in production in 2013 resulted primarily from a 97 Bcf increase in net production from our Marcellus Shale properties, a 1 Bcfe increase in net production from our New Ventures plays, and a 1 Bcf increase in net production from our Fayetteville Shale properties, which more than offset a combined 7 Bcfe decrease in net production from our East Texas and Arkoma Basin properties.  The increase in production in 2012 resulted primarily from a 49 Bcf increase in production from the Fayetteville Shale and a 30 Bcf increase in our Marcellus Shale production, which more than offset a combined 14 Bcfe decrease in net production from our East Texas and Arkoma Basin properties.  We produced 138,000 barrels of oil in 2013, compared to 83,000 barrels of oil in 2012 and 97,000 barrels of oil in 2011.  Our oil production has increased between 2013 and 2012 primarily due to our exploration activities in the Lower Smackover Brown Dense.  In 2013, we produced 50,000 barrels of natural gas liquids, compared to no barrels of natural gas liquids in 2012, as a result of our exploration activities in the Lower Smackover Brown Dense.  For 2014, we are targeting total net natural gas and oil production of approximately 740 to 752 Bcfe, which represents a growth rate of approximately 14% over our 2013 production volumes, using midpoints.

 

Sales of natural gas and oil production are conducted under contracts that reflect current prices and are subject to seasonal price swings.  We are unable to predict changes in the market demand and price for natural gas, including changes that may be induced by the effects of weather on demand for our production.  We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas and oil production to support certain desired levels of cash flow and to minimize the impact of price fluctuations.  Our policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings. As of December 31, 2013, we

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had New York Mercantile Exchange, or NYMEX, commodity price hedges in place on 382 Bcf, or approximately 51% of our targeted 2014 natural gas production.  We intend to hedge additional future production volumes to the extent natural gas prices rise to levels that we believe will achieve certain desired levels of cash flow.  We refer you to Item 7A of this Form 10-K, “Quantitative and Qualitative Disclosures about Market Risks,” for further information regarding our hedge position as of December 31, 2013.

 

Including the effect of hedges, we realized an average wellhead price of $3.65 per Mcf for our natural gas production in 2013, compared to $3.44 per Mcf in 2012 and $4.18 per Mcf in 2011.  Our hedging activities increased our average realized natural gas sales price by $0.48 per Mcf in 2013, $1.10 per Mcf in 2012 and $0.62 per Mcf in 2011.  Our average oil price realized was $103.32 per barrel in 2013, compared to $101.54 per barrel in 2012 and $94.08 per barrel in 2011.  None of our oil production was hedged during 2013, 2012 or 2011.  Our oil production is not material. 

During 2013, the average price received for our natural gas production, excluding the impact of hedges, was approximately $0.48 per Mcf lower than average NYMEX prices.  Differences between NYMEX and price realized are due primarily to locational differences and transportation cost.  Assuming a NYMEX commodity price for 2014 of $3.75 per Mcf of natural gas, we expect to receive an average sales price for our natural gas production $0.55 to $0.60 per Mcf below the NYMEX Henry Hub average settlement price, excluding the impact of hedges, which includes average third-party transportation charges in the range of $0.35 to $0.40 per Mcf and average fuel charges in the range of .50% to 1.0% of our sales price for natural gas and basis differential.  As of December 31, 2013, we have attempted to mitigate the volatility of basis differentials by protecting basis on approximately 242.0 Bcf of our 2014 expected natural gas production through financial hedging activities and physical sales arrangements at a basis differential to NYMEX natural gas prices of approximately ($0.09) per Mcf.

 

Delivery Commitments. As of December 31, 2013, we had natural gas delivery commitments of 393 Bcf in 2014 and 81 Bcf in 2015 under existing agreements.  These commitments require the delivery of natural gas in Arkansas, Pennsylvania and Texas. These amounts are well below our forecasted 2014 natural gas production of approximately 723 to 733 Bcf from our Fayetteville Shale and the Marcellus Shale and anticipated 2015 production from our available reserves in our Fayetteville Shale, Marcellus Shale and Ark-La-Tex operations, which are not subject to any priorities or curtailments that may affect quantities delivered to our customers or any priority allocations or price limitations imposed by federal or state regulatory agencies, or any other factors beyond our control that may affect our ability to meet our contractual obligations other than those discussed in Item 1A. “Risk Factors.”  We expect to be able to fulfill all of our short-term or long-term contractual obligations to provide natural gas from our own production of available reserves; however, if we are unable to do so, we may have to purchase natural gas at market to fulfill our obligations.

Customers.  Our customers include major energy companies, utilities and industrial purchasers of natural gas.  During the years ended December 31, 2013, 2012 and 2011, no single third-party purchaser accounted for 10% or more of our consolidated revenues.

 

Competition

All phases of the oil and natural gas industry are highly competitive.  We compete in the acquisition of properties, the search for and development of reserves, the production and sale of natural gas and oil and the securing of labor and equipment required to conduct our operations.  Our competitors include major oil and natural gas companies, other independent oil and natural gas companies and individual producers and operators.  Many of these competitors have financial and other resources that substantially exceed those available to us.

Competition in Arkansas has increased in recent years due largely to the development of improved access to interstate pipelines and our discovery of the Fayetteville Shale. Although improved intrastate and interstate pipeline transportation in Arkansas has increased our access to markets for our natural gas production, these markets are also served by a number of other suppliers.  Consequently, we will encounter competition that may affect both the price we receive and contract terms we must offer. Outside Arkansas, we are less established and face competition from a larger number of other producers.  We also face competition for pipeline and other services to transport our product in to market, particularly in the Northeastern United States.

We cannot predict whether and to what extent any market reforms initiated by the FERC or any new energy legislation will achieve the goal of increasing competition, lessening preferential treatment and enhancing transparency in markets in which our natural gas is sold.  However, we do not believe that we will be disproportionately or regulatory affected as compared to other natural gas and oil producers and marketers by any action taken by the FERC or any other legislative body.

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Regulation

The exploration and development natural gas and oil resources and the transportation and sale of production   historically have been heavily regulated.  For example, state governments regulate the location of wells and establish the minimum size for spacing units.  Permits typically are required before drilling.  State and local governments also zoning and land use regulations also may limit the locations for drilling and production.  Similar regulations also can affect the location, construction and operation of gathering and other pipelines needed to transport production to market.  In addition, various suppliers of goods and services may require licensing.

Currently in the United States, the price at which natural gas or oil may be sold is not regulated.  Congress has imposed price regulation from time to time, and there can be no assurance that the current, less stringent regulatory approach will continue.  The federal government prohibits the export of crude oil with limited exceptions and requires permits to export natural gas.  Broader freedom to export could lead to higher prices.  In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act and the rules that the Commodities Futures Trading Commission, the CFTC, and the SEC have issued under it regulate certain futures and options contracts in the major energy markets, including for natural gas and oil.  These regulations require us to comply with margin requirements and with certain clearing and trade execution requirements in connection with our derivative activities.

The exploration and development of natural gas and oil is also subject to extensive environmental regulation.  We refer you to “Other Items — Environmental Regulation” and the risk factor “We incur substantial costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future” in Item 1A of Part I of this Form 10-K for a discussion of the impact of environmental regulation on our business.

Midstream Services

We believe our Midstream Services segment is well-positioned to complement our E&P initiatives and to compete with other midstream providers for unaffiliated business.  We generate revenue from gathering fees associated with the transportation of natural gas to market and through the marketing of natural gas.  Our gathering assets support our E&P operations and are currently concentrated in the Fayetteville Shale in Arkansas and the Marcellus Shale in Pennsylvania.

Our operating income from this segment was $325 million on revenues of $3.3 billion in 2013, compared to $294 million on revenues of $2.4 billion in 2012 and $248 million on revenues of $2.9 billion in 2011.  Revenues increased in 2013 primarily due to an increase in the prices received for volumes marketed and an increase in volumes marketed.  Revenues decreased in 2012 from a decrease in the prices received for volumes marketed, which was partially offset by an increase in volumes marketed.  Adjusted EBITDA generated by our Midstream Services segment was $376 million in 2013, compared to $339 million in 2012 and $285 million in 2011.  The increases in 2013 and 2012 operating income and Adjusted EBITDA were primarily due to increased gathering revenues and margins, and increased marketing margins, partially offset by increased operating costs and expenses.  We expect that the operating income and Adjusted EBITDA of our Midstream Services segment will be stable over the next few years as we continue to develop our Fayetteville Shale and Marcellus Shale acreage positions.  Adjusted EBITDA is a non-GAAP measure.  We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles Adjusted EBITDA to net income (loss). 

 

Gas Gathering

 

We engage in gas gathering activities through our gathering subsidiaries, DeSoto Gathering and Angelina Gathering. DeSoto Gathering engages in gathering activities in Arkansas primarily related to the development of our Fayetteville Shale asset.  In 2013, we invested approximately $158 million related to these activities and had gathering revenues of $516 million, compared to $165 million invested and revenues of $474 million in 2012 and $161 million invested and revenues of $408 million in 2011. 

 

DeSoto Gathering continues to expand its network of gathering lines and facilities throughout the Fayetteville Shale area. During 2013, DeSoto Gathering gathered approximately 790 Bcf of natural gas in the Fayetteville Shale area, including 62 Bcf of natural gas from third-party operated wells.  During 2012, DeSoto Gathering gathered approximately 781 Bcf of natural gas volumes in the Fayetteville Shale area, including 56 Bcf of natural gas from third-party operated wells.  In 2011, DeSoto Gathering gathered approximately 704 Bcf of natural gas volumes in the Fayetteville Shale area, including 57 Bcf of natural gas from third-party wells.  The increase in volumes gathered over the past three years was primarily due to our growing production volumes from the Fayetteville Shale.  At the end of 2013, DeSoto Gathering had approximately 1,947 miles of pipe from the individual wellheads to the transmission lines and compression equipment

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representing in aggregate approximately 558,155 horsepower had been installed at 62 central point gathering facilities in the field. 

 

Angelina Gathering currently engages in gathering activities in Pennsylvania and in East Texas.  Angelina Gathering is expanding its network of gathering lines and facilities throughout the Marcellus Shale area. During 2013, Angelina Gathering gathered approximately 110 Bcf of natural gas volumes in the Marcellus Shale, Louisiana and East Texas areas.  During 2012, Angelina Gathering gathered approximately 65 Bcf of natural gas in the Marcellus Shale and East Texas areas.  In 2011, Angelina Gathering gathered approximately 42 Bcf of natural gas in the Marcellus Shale and East Texas areas.  The increase in volumes gathered over the past three years was primarily due to our growing production volumes from the Marcellus Shale.  At year-end 2013, Angelina Gathering had approximately 90 miles of pipe in Pennsylvania, 25 miles of pipe in Texas and 9 miles of pipe in Louisiana.  As of December 31, 2013, compression equipment representing in aggregate approximately 44,755 horsepower had also been installed at 5 central point gathering facilities in Pennsylvania. 

 

Gas Marketing

 

Our gas marketing subsidiary, SES, allows us to capture downstream opportunities related to marketing and transportation of natural gas. Our current marketing operations primarily relate to the marketing of our own natural gas production and some third-party natural gas.  SES also purchases natural gas and sells it to end-users, manages basis risk and marketing portfolio and acquires transportation rights on third-party pipelines.  During 2013, we marketed 800 Bcf of natural gas, compared to 676 Bcf in 2012 and 611 Bcf in 2011.  Of the total volumes marketed, production from our affiliated E&P operations accounted for 96% in 2013, compared to 95% in 2012 and 94% in 2011.

 

SES is a “foundation shipper” on two pipeline projects serving the Fayetteville Shale.  The Fayetteville Express Pipeline LLC, or FEP, is a 2.0 Bcf per day pipeline that is jointly owned by Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P.  FEP was placed in service in January 2011.  SES has a maximum aggregate commitment of 1,200,000 Dekatherms per day for an initial term of ten years from the in-service date.  Texas Gas Transmission, LLC or Texas Gas, a subsidiary of Boardwalk Pipeline Partners, LP, constructed two pipeline laterals called the Fayetteville and Greenville Laterals, which also provide transportation for our Fayetteville Shale gas.  SES has maximum aggregate commitments of 800,000 MMBtu per day on the Fayetteville Lateral and 640,000 MMBtu per day on the Greenville Lateral.

 

The Fayetteville and the Greenville Laterals and the FEP allow us to transport our natural gas to interconnecting pipelines that offer connectivity and marketing options to the eastern half of the United States.  These interconnecting pipelines include Centerpoint, Natural Gas Pipeline, Mississippi River Transmission, Gulf South, Texas Gas, Tennessee Gas Pipeline, Trunkline, ANR, Columbia Gulf, Texas Eastern, and Sonat.  We rely in part upon the Fayetteville and Greenville Laterals and the FEP to service our production from the Fayetteville Shale.    

 

During 2011 and 2012, SES entered into a number of short- and long-term firm transportation service agreements in support of our growing Marcellus Shale operations in Pennsylvania. In March 2011, SES entered into a precedent agreement with Millennium Pipeline Company, L.L.C. pursuant to which it will enter into short- and long-term firm natural gas transportation services on Millennium’s existing system.  Expansions of the system were placed in-service in the second quarter of 2013.  Further expansions are expected to be in-service by the second quarter of 2014.  In June 2011, SEPCO entered into separate 15-year agreements with each of Bluestone Pipeline Company of Pennsylvania, LLC (“Bluestone Gathering”), and Susquehanna Gathering Company I, LLC, both wholly owned subsidiaries of DTE Pipeline Company, an affiliate of DTE Energy Company. Bluestone Gathering committed to build and operate a natural gas gathering system in Susquehanna County, Pennsylvania and Broome County, New York, and provide gathering services to SEPCO in support of a portion of our future Marcellus Shale natural gas production.  This gathering system was initially placed into service in November 2012 and was completed in May 2013. Susquehanna Gathering Company I, LLC committed to build and operate gathering infrastructure from well pad receipt locations for deliveries into the Bluestone Gathering system as well as other potential field delivery points. This system was first placed into service November 2012 and will be constructed as necessary to support the company’s activities primarily in Susquehanna County. 

 

SES also has executed firm transportation agreements with Tennessee Gas Pipeline Company (“TGP”), a subsidiary of Kinder Morgan Energy Partners, L.P., that increase our ability to move our Marcellus Shale natural gas production in the short term to market as well as a precedent agreement for an expansion project that was placed in-service in November 2013 pursuant to which SES has subscribed for 100,000 Dekatherms per day of capacity.  TGP’s expansion project will expand its 300 Line in Pennsylvania to provide natural gas transportation from the Marcellus Shale supply area to existing delivery points on the TGP system.  In March 2012, SES entered into a precedent agreement with Constitution Pipeline Co. LLC for a proposed 121-mile pipeline connecting to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in Schoharie County, New York. Subject to the receipt of regulatory approvals and satisfaction of other conditions, SES

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agreed to enter a 15-year firm transportation agreement with a total capacity of 150 MMcf per day on this project.  Constitution Pipeline Co. LLC has extended the range for the pipeline’s target in-service date to late 2015 through 2016 as a result of a longer than expected regulatory and permitting process.  We have provided certain guarantees of a portion of SES’s obligations under these agreements.  We refer you to the risk factor “If our Fayetteville Shale and Marcellus Shale drilling programs fail to produce our projected supply of natural gas, our investments in our gathering operations could be lost.  In addition, our commitments for transportation on third-party pipelines and gathering systems could make the sale of our natural gas uneconomic, which could have an adverse effect on our results of operations financial condition and cash flows.

 

In May 2013, SES entered into a precedent agreement with Columbia Gas Transmission, LLC for a project that will expand their existing system from Chester County, Pennsylvania to various interconnects throughout Pennsylvania, New Jersey, Maryland, and Virginia.  SES’s volume is 72,000 MMcf per day and is expected to be in service by the third quarter of 2015.      

 

As of December 31, 2013, the Company’s obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $3.5 billion and the Company has guarantee obligations of up to $100 million of that amount.   

 

Competition

Our gas gathering and marketing activities compete with numerous other companies offering the same services, many of which possess larger financial and other resources than we have.  Some of these competitors are other producers and affiliates of companies with extensive pipeline systems that are used for transportation from producers to end-users. Other factors affecting competition are the cost and availability of alternative fuels, the level of consumer demand and the cost of and proximity to pipelines and other transportation facilities.  We believe that our ability to compete effectively within the marketing segment in the future depends upon establishing and maintaining strong relationships with producers and end-users.

Regulation

The transportation and sale of natural gas and oil are heavily regulated.  Interstate pipelines must obtain authorization from the Federal Energy Regulatory Commission, or the FERC, to operate in interstate commerce, and state governments typically must authorize the construction of pipelines for intrastate service.  The FERC currently allows interstate pipelines to adopt market-based rates; however, in the past the FERC has regulated pipeline tariffs and could do so again in the future.  State tariff regulations vary.  Currently, all the Company’s pipelines are intrastate.

State and local permitting, zoning and land use regulations can affect the location, construction and operation of gathering and other pipelines needed to transport production to market.  In addition, various suppliers of goods and services to our midstream business may require licensing.

Currently in the United States, the price at which natural gas or oil may be sold is not regulated.  Congress has imposed price regulation from time to time, and there can be no assurance that the current, less stringent regulatory approach will continue.  The federal government prohibits the export of crude oil with limited exceptions and requires permits to export natural gas.  Broader freedom to export could lead to higher prices.  In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act and the rules that the Commodities Futures Trading Commission, the CFTC, and the SEC have issued under it regulate certain futures and options contracts in the major energy markets, including for natural gas and oil.  These regulations require us to comply with margin requirements and with certain clearing and trade execution requirements in connection with our derivative activities.

 

The transportation of natural gas and oil is also subject to extensive environmental regulation.  We refer you to “Other Items — Environmental Regulation” and the risk factor “We incur substantial costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future” in Item 1A of Part I of this Form 10-K for a discussion of the impact of environmental regulation on our business.

Other

In 2013, we started construction on a corporate office complex located in Spring, Texas on 26 acres of commercial land that we purchased in 2012.  The Company financed the construction of this complex through a construction agreement and lease arrangement.  We are currently obligated for the construction costs incurred, which approximated $38 million at December 31, 2013.  Upon completion of construction, a lease term of approximately five years will commence.

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Our other operations have primarily consisted of real estate development activities concentrated on tracts of land located in Arkansas.  During 2012, we sold our office complex in Fayetteville, Arkansas and our interest in approximately 9.5 acres of real estate near the Fayetteville complex.  In 2012, we also sold our office complex in Conway, Arkansas for approximately $32 million and subsequently leased back our Conway complex from the buyer for a 15-year term.  There were no sales of commercial real estate in 2013 or 2011.

Our sand mining operations, in support of our E&P business, are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.106) is included in Exhibit 95.1 to this Form 10-K.

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Other Items

Reconciliation of Non-GAAP Measures

Adjusted EBITDA is defined as net income (loss) plus interest, income tax expense, non-cash impairment of natural gas and oil properties, (gain) loss on derivatives, net of settlements, and depreciation, depletion and amortization.  We have included information concerning Adjusted EBITDA in this Form 10-K because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in our industry.  Adjusted EBITDA should not be considered in isolation or as a substitute for net income (loss), net cash provided by operating activities or other income or cash flow data prepared in accordance with GAAP, or as a measure of our profitability or liquidity.  Adjusted EBITDA as defined above may not be comparable to similarly titled measures of other companies.

We believe that net income (loss) is the financial measure calculated and presented in accordance with GAAP that is most directly comparable to Adjusted EBITDA as defined.  The following table reconciles Adjusted EBITDA, as defined, with net income (loss) for the years-ended December 31, 2013, 2012 and 2011:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Midstream

 

 

 

 

 

 

 

 

E&P

 

 

Services

 

 

Other

 

 

Total

 

 

 

 

 

(in thousands)

 

 

 

 

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

$

508,548 

 

$

196,072 

 

$

(1,117)

 

$

703,503 

Depreciation, depletion and amortization expense

 

735,215 

 

 

50,940 

 

 

457 

 

 

786,612 

Impairment of natural gas and oil properties

 

–  

 

 

–  

 

 

–  

 

 

–  

Gain on derivatives, net of settlement

 

(20,898)

 

 

(480)

 

 

(2)

 

 

(21,380)

Net interest expense

 

30,244 

 

 

10,619 

 

 

731 

 

 

41,594 

Provision for income taxes

 

368,320 

 

 

119,223 

 

 

(669)

 

 

486,874 

Adjusted EBITDA

$

1,621,429 

 

$

376,374 

 

$

(600)

 

$

1,997,203 

 

 

 

 

 

 

 

 

 

 

 

 

2012

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

$

(884,126)

 

$

175,570 

 

$

1,492 

 

$

(707,064)

Depreciation, depletion and amortization expense

 

765,368 

 

 

44,395 

 

 

1,190 

 

 

810,953 

Impairment of natural gas and oil properties

 

1,939,734 

 

 

–  

 

 

–  

 

 

1,939,734 

Loss on derivatives, net of settlement

 

2,154 

 

 

–  

 

 

–  

 

 

2,154 

Net interest expense

 

20,315 

 

 

14,341 

 

 

1,001 

 

 

35,657 

Provision for income taxes

 

(548,556)

 

 

104,522 

 

 

895 

 

 

(443,139)

Adjusted EBITDA

$

1,294,889 

 

$

338,828 

 

$

4,578 

 

$

1,638,295 

 

 

 

 

 

 

 

 

 

 

 

 

2011

 

 

 

 

 

 

 

 

 

 

 

Net income

$

493,726 

 

$

142,591 

 

$

1,452 

 

$

637,769 

Depreciation, depletion and amortization expense

 

666,125 

 

 

37,261 

 

 

1,125 

 

 

704,511 

Impairment of natural gas and oil properties

 

–  

 

 

–  

 

 

–  

 

 

–  

Gain on derivatives, net of settlement

 

(5,600)

 

 

–  

 

 

–  

 

 

(5,600)

Net interest expense

 

9,026 

 

 

15,049 

 

 

–  

 

 

24,075 

Provision for income taxes

 

322,714 

 

 

90,221 

 

 

286 

 

 

413,221 

Adjusted EBITDA

$

1,485,991 

 

$

285,122 

 

$

2,863 

 

$

1,773,976 

 

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Environmental Regulation

General.  Our operations are subject to environmental regulation in the jurisdictions in which we operate.  These laws and regulations require permits for drilling wells and the maintenance of bonding requirements to drill or operate wells and also regulate the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the prevention and cleanup of pollutants and other matters.  We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks.  Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

 

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief.  Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those in the natural gas and oil industry in general.  Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, there can be no assurance that this will continue in the future.  

 

Certain U.S. Statutes.  CERCLA, also known as the “Superfund law,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment.  These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 

 

The Resource Conservation and Recovery Act, as amended, or RCRA, generally does not regulate wastes generated by the exploration and production of natural gas and oil.  RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy.”  However, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general.  Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

 

The Clean Air Act, as amended, restricts emissions into the atmosphere.  Various activities in our operations, such as drilling, pumping and the use of vehicles, can release matter subject to regulation.  We must obtain permits, typically from local authorities, to conduct various activities.  Federal and state governmental agencies are looking to the issues associated with methane and other emissions from oil and natural gas activities, and further regulation could increase our costs or restrict our ability to produce.  Although methane emissions are not currently regulated at the federal level, we are required to report emissions of various greenhouse gases, including methane.

 

The Oil Pollution Act, as amended, or the OPA, and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States’ waters.  A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located.  OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages.  Although liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation.  If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply.  Few defenses exist to the liability imposed by OPA.  OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.  In 2013, oil accounted for less than 1% of the Company’s total production.

 

We own or lease, and have in the past owned or leased, onshore properties that for many years have been used for or associated with the exploration and production of natural gas and oil.  Although we have utilized operating and disposal

22

 


 

 

 

practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of wastes was not under our control.  These properties and the wastes disposed on them may be subject to CERCLA, the Clean Water Act, RCRA and analogous state laws.  Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.

 

The Federal Water Pollution Control Act, as amended, or the FWPCA, imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters.  Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands.  The FWPCA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations and the Federal National Pollutant Discharge Elimination System general permits issued by the EPA prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters.  Although the costs to comply with zero discharge mandates under federal or state law may be significant, the entire industry is expected to experience similar costs and we believe that these costs will not have a material adverse impact on our results of operations or financial position. The EPA has adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.

 

Canada.  Our activities in Canada have to date been limited to certain geological and geophysical activities that are not subject to extensive environmental regulation.  If and when we begin exploration activities in New Brunswick, we will be subject to federal, provincial and local environmental regulations that we believe require compliance efforts comparable to those required in the United States.

 

Hydraulic Fracturing.  We utilize hydraulic fracturing in drilling wells as a means of maximizing their productivity.  It is an essential and common practice in the oil and gas industry used to stimulate production of oil, natural gas, and associated liquids from dense and deep rock formations. The knowledge and expertise in fracturing techniques we have developed through our operations in the Fayetteville Shale and the Marcellus Shale are being utilized in our other operating areas, including our Lower Smackover Brown Dense acreage and, in the future, may include our exploration program in New Brunswick, Canada.  Successful hydraulic fracturing techniques are also expected to be critical to the development of other New Venture areas.  Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. In our Fayetteville Shale and Marcellus Shale plays, the fracturing fluids we use are comprised of approximately 99.9% water and sand on a percentage volume basis.  The remaining 0.1% is comprised of small quantities of additives which contain chemical compounds such as hydrochloric acid, phosphoric acid, glutaraldehyde and sodium chloride.

 

In the past few years, there has been an increased focus on environmental aspects of hydraulic fracturing practice, both in the United States and abroad.  In the United States, hydraulic fracturing is typically regulated by state oil and natural gas commissions, but there have recently been a number of regulatory initiatives at the federal and local levels as well as by other state agencies.  New York State currently has a moratorium on hydraulic fracturing, and some local governments also ban this procedure.  We currently do not have material properties in these areas.

The Environmental Protection Agency, or EPA, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and released guidance documents on February 11, 2014 related to this newly asserted regulatory authority. In addition, the EPA issued final rules effective as of October 15, 2012 that subject oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS programs. The EPA final rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion, or REC techniques developed in the EPA's Natural Gas STAR program. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the final regulations under NESHAPS include maximum achievable control technology, or MACT, standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. Based on our current operations and practices, management believes, such newly promulgated rules will not have a material adverse impact on our financial position, results of operations or cash flows but these matters are subject to inherent uncertainties and management’s view may change in the future.

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In October 2011, the EPA also announced a schedule for development of standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works or POTWs. The regulations will be developed under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. The EPA anticipates issuing the proposed rules in 2014.

In addition to the EPA’s efforts, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, and although initial results were expected to be available by late 2012 and final results by 2014, to date the EPA has not released any results from the study.    In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. The U.S. Department of the Interior also is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.

Some states in which we operate have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling and/or completion of wells.

In New Brunswick there presently are no hydraulic fracturing regulations. The provincial government has been working on a new comprehensive regulatory framework that it expects to release to the public in late 2014.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil, natural gas, and associated liquids including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows. We refer you to the risk factor “Our financial condition and results of operation could be adversely affected by legislative and regulatory initiatives in the United States and Canada relating to hydraulic fracturing that could result in increased costs and additional operating restrictions or delays or prevent us from realizing the value of undeveloped acreage” in Item 1A of Part I of this Form 10-K.

Employees

 

As of December 31, 2013, we had 2,621 total employees. None of our employees were covered by a collective bargaining agreement at year-end 2013.  We believe that our relationships with our employees are good.  In 2013, we were named a Top Workplace by the Houston Chronicle for the fourth consecutive year.

24

 


 

 

 

GLOSSARY OF CERTAIN INDUSTRY TERMS

 

The definitions set forth below apply to the indicated terms as used in this Form 10-K. All natural gas reserves and production reported in this Form 10-K are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit.  All currency amounts are in U.S. dollars unless specified otherwise.

Acquisition of properties  Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties. For additional information, see the SEC’s definition in Rule 4-10(a) (1) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Adjusted EBITDA  Net income (loss) plus interest, taxes, depreciation, depletion and amortization and any non-cash impairment of natural gas and oil properties or (gain) loss on derivatives, net of settlement.  We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles Adjusted EBITDA with our net income (loss) from our audited financial statements.

Analogous reservoir”  Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i)

Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii)

Same environment of deposition;

(iii)

Similar geological structure; and

(iv)

Same drive mechanism.

For additional information, see the SEC’s definition in Rule 4-10(a) (2) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Available reserves”  Estimates of the amounts of oil and natural gas which the registrant can produce from current proved developed reserves using presently installed equipment under existing economic and operating conditions and an estimate of amounts that others can deliver to the registrant under long-term contracts or agreements on a per-day, per-month, or per-year basis.  For additional information, see the SEC’s definition in Item 1207(d) of Regulation S-K, a link for which is available at the SEC's website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Bbl”  One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf”  One billion cubic feet of natural gas.

Bcfe”  One billion cubic feet of natural gas equivalent. Determined using the ratio of one barrel of oil to six Mcf of natural gas.

Btu”  One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Dekatherm”  One million British thermal units (Btus).

Deterministic estimate”   The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. For additional information, see the SEC’s definition in Rule 4-10(a) (5) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Developed oil and gas reserves  Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered:

(i)

Through existing wells with existing equipment and operating methods or in which the cost of the required    equipment is relatively minor compared to the cost of a new well; and

(ii)

Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

25

 


 

 

 

For additional information, see the SEC’s definition in Rule 4-10(a) (6) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

 

Development costs”   Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i)

Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii)

Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii)

Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv)

Provide improved recovery systems.

For additional information, see the SEC’s definition in Rule 4-10(a) (7) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Development project”   A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. For additional information, see the SEC’s definition in Rule 4-10(a) (8) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Development well”  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. For additional information, see the SEC’s definition in Rule 4-10(a) (9) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Downspacing  The process of drilling additional wells within a defined producing area to increase recovery of natural gas and oil from a known reservoir.

E&P”  Exploration for and production of natural gas and oil.

Economically producible”   The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities. For additional information, see the SEC’s definition in Rule 4-10(a) (10) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Estimated ultimate recovery (EUR)”   Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. For additional information, see the SEC’s definition in Rule 4-10(a) (11) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Exploitation”   The development of a reservoir to extract its gas and/or oil.

Exploratory well”   An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.  For additional information, see the SEC’s definition in Rule 4-10(a) (13) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Field  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. For additional information, see the

26

 


 

 

 

SEC’s definition in Rule 4-10(a) (15) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Fracture stimulation  A process whereby fluids mixed with proppants are injected into a wellbore under pressure in order to fracture, or crack open, reservoir rock, thereby allowing oil and/or natural gas trapped in the reservoir rock to travel through the fractures and into the well for production.

Gross well or acre”  A well or acre in which the registrant owns a working interest. The number of gross wells is the total number of wells in which the registrant owns a working interest. For additional information, see the SEC's definition in Item 1208(c)(1) of Regulation S-K, a link for which is available at the SEC's website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Gross working interest”  Gross working interest is the working interest in a given property plus the proportionate share of any royalty interest, including overriding royalty interest, associated with the working interest.

Infill drilling”  Drilling wells in between established producing wells to increase recovery of natural gas and oil from a known reservoir.

MBbls”  One thousand barrels of oil or other liquid hydrocarbons.

Mcf    One thousand cubic feet of natural gas.

Mcfe”  One thousand cubic feet of natural gas equivalent, with liquids converted to an equivalent volume of natural gas using the ratio of one barrel of oil to six Mcf of natural gas.

MMBbls”  One million barrels of oil or other liquid hydrocarbons.

MMBtu”  One million British thermal units (Btus).

MMcf”  One million cubic feet of natural gas.

MMcfe”  One million cubic feet of natural gas equivalent, with liquids converted to an equivalent volume of natural gas using the ratio of one barrel of oil to six Mcf of natural gas.

Net revenue interest”  Economic interest remaining after deducting all royalty interests, overriding royalty interests and other burdens from the working interest ownership.

Net well or “Net acre”  The number of net wells or acres is the sum of the fractional working interests owned in individual wells or tracts. For additional information, see the SEC's definition in Item 1208(c)(2) of Regulation S-K, a link for which is available at the SEC's website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.  

NGL”  Natural gas liquids.

NYMEX”  The New York Mercantile Exchange.

Operating interest”  An interest in natural gas and oil that is burdened with the cost of development and operation of the property.

Overriding royalty interest”  A fractional, undivided interest or right to production or revenues, free of costs, of a lessee with respect to an oil or natural gas well, that overrides a working interest.

Play”  A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and natural gas reserves.

Present Value Index” or “PVI”  A measure that is computed for projects by dividing the dollars invested into the PV-10 resulting or expecting to result from the investment by the dollars invested.  

Probabilistic estimate  The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to

27

 


 

 

 

generate a full range of possible outcomes and their associated probabilities of occurrence. For additional information, see the SEC’s definition in Rule 4-10(a) (19) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Producing property”  A natural gas and oil property with existing production.

Productive wells”  Producing wells and wells mechanically capable of production. For additional information, see the SEC's definition in Item 1208(c)(3) of Regulation S-K, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Proppant”  Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.  In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used.  Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

Proved developed producing”   Proved developed reserves that can be expected to be recovered from a reservoir that is currently producing through existing wells.

Proved developed reserves”  Proved gas and oil that are also developed gas and oil reserves.

Proved oil and gas reserves”   Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Also referred to as “proved reserves.” For additional information, see the SEC’s definition in Rule 4-10(a) (22) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Proved reserves”  See “proved oil and gas reserves.”

Proved undeveloped reserves”  Proved oil and gas reserves that are also undeveloped oil and gas reserves.

PV-10”  When used with respect to natural gas and oil reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.  Also referred to as “present value.” After-tax PV-10 is also referred to as “standardized measure” and is net of future income tax expense.

Reserve life index”  The quotient resulting from dividing total reserves by annual production and typically expressed in years.

Reserve replacement ratio”  The sum of the estimated net proved reserves added through discoveries, extensions, infill drilling and acquisitions (which may include or exclude reserve revisions of previous estimates) for a specified period of time divided by production for that same period of time.

Reservoir”   A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. For additional information, see the SEC’s definition in Rule 4-10(a) (27) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Royalty interest”  An interest in a natural gas and oil property entitling the owner to a share of oil or natural gas production free of production costs. 

Tcf”  One trillion cubic feet of natural gas.

Tcfe”  One trillion cubic feet of natural gas equivalent, with liquids converted to an equivalent volume of natural gas using the ratio of one barrel of oil to six Mcf of natural gas.

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Unconventional play  A play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds, or (3) shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery processes in order to produce economic flow rates.

 

Undeveloped acreage”   Those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves. For additional information, see the SEC's definition in Item 1208(c)(4) of Regulation S-K, a link for which is available at the SEC's website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Undeveloped oil and natural gas reserves  Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  Also referred to as “undeveloped reserves.”  For additional information, see the SEC’s definition in Rule 4-10(a) (31) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

Undeveloped reserves”   See “undeveloped oil and natural gas reserves.”

USD  United States Dollar.

Well spacing  The regulation of the number and location of wells over an oil or natural gas reservoir, as a conservation measure.  Well spacing is normally accomplished by order of the regulatory conservation commission in the applicable jurisdiction.  The order may be statewide in its application (subject to change for local conditions) or it may be entered for each field after its discovery. In the operational context, “well spacing” refers to the area attributable between producing wells within the scope of what is permitted under a regulatory order.

Working interest”   An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.

Workovers”   Operations on a producing well to restore or increase production.

WTI”   West Texas Intermediate, the benchmark oil price in the United States.

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ITEM 1A. RISK FACTORS

 

In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating our business and future prospects.  The risk factors described below represent what we believe are the most significant risk factors with respect to us and our business.  In assessing the risks relating to our business, investors should also read the other information included in this Form 10-K, including our financial statements and the related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Cautionary Statement about Forward-Looking Statements.”


Our revenues and the value of our assets are highly dependent on the prices for natural gas and, to a lesser extent, oil.  These prices are volatile, and a substantial or extended decline in natural gas and oil prices would have a material adverse effect on us.

Our financial results and the value of our assets correlate closely to the prices we can and do obtain for what we produce, in particular natural gas, which accounts for almost 100% of our production.  Prices for natural gas and oil are highly volatile and unpredictable.  The following factors, among others, affect the supply of and demand for natural gas and oil:

·

Changes in consumption patterns, including those resulting from population changes and migrations, new technologies and grown in emerging markets

·

Global and local economic conditions

·

Inventory  levels

·

Ability and cost of transporting product to markets, including the ability to connect resources to pipelines or other means of transportation, bottlenecks in pipeline or other transportation capacity such as many are experiencing in the Marcellus and the Utica Shales, export and import controls and other constraints

·

Production  disruptions

·

Actions of governments and multinational groups, such as the Organization of Petroleum Exporting Countries (OPEC)

·

Currency exchange rates

·

Competition from other producers and from other energy sources, including renewables, which affects the level of supply

·

Technological developments

·

Weather, earthquakes and other natural events

·

Market perceptions of future prices, whether due to the foregoing factors or others

A significant or extended decline in natural gas and oil prices, such as the one from 2008 into 2012 when the NYMEX natural gas price dropped from $13.58 to $1.91 per MMBtu, would have a material adverse effect on our financial position, our results of operations, our access to capital and the quantities of natural gas and oil that we can produce economically, including the following:

·

The cash flows from our operations would be reduced, decreasing funds available for capital investments employed to replace reserves or increase production.

·

Lower prices would reduce the value of our natural gas and oil assets and, in some cases, make them no longer be economic to produce.  This could result in impairments to the values of our assets, such as occurred in 2012.

·

Access to other sources of capital, such as equity or debt markets, could be severely limited or unavailable.

·

We could fail to meet financial or other covenants in the documentation governing our debt, leading to mandatory prepayments or defaults.

·

Locational price differentials change, making it difficult to predict the best locations to conduct our activities.

·

Varying perceptions of future prices can lead to difficulties in agreeing on the value of assets in acquisitions or dispositions.

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We endeavor to mitigate against these risks through hedging a significant portion of our production.  Hedging also presents risks, including our failure to project the appropriate volumes and price points for hedges and the creditworthiness of our counterparties.  For a discussion of our hedging activities, we refer you to Note 5 to the consolidated financial statements included in this Form 10-K.  Additionally, we mitigate these risks, in part, through our Midstream Services business, which generates cash flow that is largely fee-based and thus not directly impacted by commodity price volatility.

Our ability to sell our natural gas and oil and/or to receive market prices for our production may be adversely affected by constraints or interruptions on gathering systems, pipelines, processing and transportation systems owned or operated by us or others.

The marketability of our natural gas and oil production depends in part on the availability, proximity, and capacity of gathering systems, processing and pipeline and other transportation systems owned or operated by third parties. The lack of available capacity in these systems and facilities can result in shutting in producing wells, delaying or discontinuing the development plans for our properties or receiving lower prices. Although we have some contractual control over the transportation and gathering of our production, material changes in these business relationships could materially affect our operations. Federal and state regulation of natural gas and oil production, processing and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, and transport natural gas. In particular, continued development of the Marcellus Shale by us and others could overtax the capacity of existing gathering and pipeline system, and new or expanded capacity may not be in place in time. 

The vast majority of our current operations and production are in two areas, the Fayetteville Shale and the Marcellus Shale, and significant events or circumstances affecting one or both of these areas could have a material and adverse effect on our operations in those areas and thus our overall performance.

Production from the Fayetteville Shale and the Marcellus Shale accounted for 74% and 23%, respectively, of our consolidated production and, when considering both our E&P and Midstream Services business, essentially all of our operating income in 2013.  Our current Fayetteville Shale operations are almost entirely in Arkansas, and our current Marcellus Shale operations currently are only in Pennsylvania.  Significant events or circumstances of the types described elsewhere in these Risk Factors or otherwise that affect one or both of these areas would affect a very large part of our operations simultaneously and, if they do not affect the industry generally, would affect us disproportionately compared to other companies,.  Those events and circumstances include changes in local laws and regulations, constraints on transportation, natural events, localized price changes and availability of water, skilled personnel, equipment, services and supplies, among others.

If we fail to find or acquire additional reserves, our reserves and production will decline materially from their current levels.

The rate of production from natural gas and oil properties generally declines as reserves are depleted.  Unless we acquire additional properties containing proved reserves, conduct successful exploration and development activities, successfully apply new technologies or identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline materially as reserves are produced.  Future natural gas and oil production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.

Our business could be adversely affected by competition with other companies. 

The natural gas and oil industry is highly competitive, and our business could be adversely affected by companies that are in a better competitive position.  As an independent natural gas and oil company, we frequently compete for reserve acquisitions, exploration leases, licenses and concessions, marketing agreements, transportation, equipment and labor against companies with financial and other resources substantially larger than those we possess.  Many of our competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can.  Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.  In addition, many of our competitors have been operating in some of our core areas for a much longer time than we have or have established strategic long-term positions in geographic regions in which we may seek new entry.

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Natural gas and oil exploration and production is an inherently risky business with many uncertainties and potential liabilities.  The results of our activities may not be what we project, and not all our liabilities and other exposures may be covered by insurance.

By its nature, exploring for and producing natural gas and oil involves substantial capital investment with no assurance of return, or returns at expected levels, and the risk of environmental and other liability.  Among other things:

·

Although we utilize sophisticated geological and geophysical tools to determine where to drill, these do not predict with certainty the presence of natural gas or oil or the rate at which they can be produced.  Some wells will result in no production, production that does not cover costs or production at lower levels than expected.

·

During drilling we can face difficulties in landing our wellbore in the desired zones, staying in the desired zones while drilling horizontally, penetrating rock formations, controlling well pressure, stimulating reservoirs through fracturing and cleaning the wellbore following fracturing and running casing the entire length of the wellbore.  These circumstances can delay completion, increase costs and possibly lead to the abandonment of the particular location.

·

When we acquire properties or businesses through acquisitions, including properties already producing, we may fail to assess correctly the potential of the properties, the costs of integration and development, matters affecting legal title and thus the right to drill and ownership of production, the liabilities that we assume as part of the acquisition and the risks associated with ownership, development and operation.

·

Equipment can fail or not be available and pipelines can rupture.

·

We can encounter well blowouts, cratering, explosions, pipeline failure, fires, brine or other fluids, drainage of production from neighboring properties and other hazards.

·

Earthquakes and hurricanes, storms and other weather events can interfere with drilling activities and operations.

·

Although we believe we maintain a robust health, safety and environmental program, incidents can occur, whether due to natural events, the actions of third parties or our own errors or oversights.  Spills, injuries or other calamities can result in liability for our Company, damage to our properties and interruption of our operations.

We maintain insurance against many potential losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that we believe to be prudent.  Our insurance does not protect us against all operational risks; for example, we generally do not maintain business interruption insurance, and pollution and environmental risks generally are not fully insurable.  These risks could give rise to significant costs not covered by insurance that could have a material adverse effect upon our financial results.

Our business strategy depends on executing extensive drilling programs and controlling costs to improve our overall return.  Shortages of oilfield equipment, services, supplies, raw materials and qualified personnel could adversely affect our ability to implement our programs or to achieve our desired levels of costs.

We are engaged in large-scale programs to develop our assets, particularly in the Fayetteville Shale and the Marcellus Shale.  We are achieving economies of scale through our sizeable operations in these two areas and, in some cases, vertical integration in certain oilfield services, such as drilling, sand mining and pressure control.  We nonetheless compete with other companies for oilfield equipment, services, supplies, raw materials and qualified personnel.  In particular, the demand for qualified and experienced field personnel to drill wells and conduct field operations and for geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. These factors also cause significant increases in costs for equipment, services, personnel and raw materials (such as sand, cement, manufactured proppants and other materials utilized in the provision of the oilfield services).  Higher natural gas and oil prices generally stimulate increased demand and result in increased costs for professional personnel, drilling rigs, crews and associated supplies, equipment, services and raw materials.  In addition, our E&P operations also require local access to large quantities of water supplies and disposal services for produced water in connection with our hydraulic fracture stimulations due to prohibitive transportation costs. We cannot be certain when we will experience shortages or cost increases, which could adversely affect our profit margin, cash flow and operating results or restrict our ability to drill wells and conduct ordinary operations.

Our announced drilling plans can change due to various factors.

Our drilling plans are flexible and are dependent upon a number of factors, including the extent to which we can replicate the results of our most successful wells in addition to the natural gas and oil commodity price environment.  The

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determination as to whether we continue to drill wells in our operating areas may depend on any one or more of the following factors:

·

Our ability to determine the most effective and economic fracture stimulation

·

Our ability to transport our production to the most favorable markets

·

Material changes in natural gas prices (including location differentials)

·

Changes in the costs to drill, complete or operate wells and our ability to reduce drilling risks

·

The extent of our success in drilling and completing horizontal wells

·

The costs and availability of oilfield personnel services and drilling supplies, raw materials, and equipment and services

·

Success or failure of wells drilled in similar formations or which would use the same production facilities

·

Receipt of additional seismic or other geologic data or reprocessing of existing data

·

The extent to which we are able to effectively perform our vertically integrated services, including operating our own rigs, fracture stimulation fleet, sand plant, field services and supply chain management

·

The failure or unwillingness of co-owners of working interests to pay for their share of the costs of new wells or operations

·

Availability and cost of capital

·

The impact of federal, state and local government regulation, including any increase in severance taxes

Our ability to produce natural gas and oil could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules.

Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our E&P operations, could adversely impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas.  Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse effect on our operations and financial condition.

 

Our financial condition and results of operation could be adversely affected by legislative and regulatory initiatives in the United States and elsewhere relating to environmental matters, particularly hydraulic fracturing and climate change, which could result in increased costs and additional operating restrictions or delays or prevent us from realizing the value of undeveloped acreage.

As described more fully under “Other Items — Environmental Regulation,” our operations are subject to extensive environmental regulation.  New regulations can increase costs or delay or prevent us from achieving our goals.  In particular, we often utilize hydraulic fracturing in our drilling activities, and it forms a critical part of our cost structure and success.  As also described there, various governmental and non-governmental groups are advocating restrictions and, in some instances, outright bans on the use of hydraulic fracturing.  

Our E&P operations are currently focused on the production of hydrocarbons from unconventional sources, and we expect to continue to focus on such resources in the future. The production of hydrocarbons from these sources has an energy intensity that is a number of times higher than that for production from conventional sources. Therefore, we expect that the greenhouse gas intensity of our production will increase in the long-term. We actively seek to reduce the environmental impact of our operations by pursuing more efficient use of natural resources such as hydrocarbons and water and managing and mitigating the emissions to the air, water and soil, with a focus on the reduction of greenhouse gas emissions. With the efforts of our Health, Safety and Environmental Department, we have been able to plan for and comply with environmental initiatives without materially altering our operating strategy. We anticipate making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment that will increase the cost of equipment, materials and services whose production utilizes hydrocarbons.

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We may also face increased competition from alternative energy sources that do not rely on hydrocarbons. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters and if we are unable to find solutions to environmental initiatives as they arise, including reducing the greenhouse gas emissions for our existing projects, we may have additional costs as well as compliance and operational risks with respect to our existing operations as well as facing difficulties in pursuing new projects.

 

Although our estimated natural gas and oil reserve data is independently audited, our estimates are only estimates and thus may prove to be inaccurate.

As described in more detail under “Critical Accounting Policies and Estimates – Natural Gas and Oil Properties,” our reserve data represents the estimates of our reservoir engineers made under the supervision of our management, and our reserve estimates are audited each year by Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm. Natural gas and oil reserves cannot be measured exactly, however, and our estimates of natural gas and oil reserves requires extensive judgments of reservoir engineering data and projections of cost that will be incurred in developing and producing reserves, along with pricing.   Recovery of undeveloped reserves generally requires significant capital investments and successful drilling operations.  Actual reserves, costs and prices may differ dramatically from our estimates.

Our operations can be impacted by events beyond our control, adversely affecting our cash flows and results of operations.

A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, earthquakes, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes or voluntarily curtailment in response to market conditions. Further, although we operate most of the wells in which we have interests, some are operated by third parties.  Although we endeavor to assure that third parties conduct their activities with rigorous regard for health, safety, environment and cost, we do not control them and therefore cannot be sure they will operate to the same standards that we would.  If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flows and results of operations. Counterparties to contracts, whether those providing us with goods or services or those owing us payments for production or services, may breach their obligations.

We may have difficulty financing our planned capital investments, which could adversely affect our growth.

We have experienced and expect to continue to experience substantial capital investment and working capital needs to implement our drilling program.  Our planned capital investments for 2014 are expected to exceed the net cash generated by our operations under current natural gas prices.  We expect to be able to borrow under our revolving credit facility to fund capital investments to the extent they exceed our net cash flow and cash on hand.  Our ability to borrow under our revolving credit facility is subject to certain conditions.  As of December 31, 2013, we would satisfy those conditions; however, if conditions were not satisfied and we were not otherwise able to borrow funds, we would need to curtail our drilling, development and other activities or be forced to sell some of our assets on a possibly unfavorable basis.  Any such curtailment or sale could have a material adverse effect on our results and future operations.

We have made significant investments in pipelines and gathering systems and contracts and in oilfield service businesses, including our drilling rig, pressure pumping equipment and sand mine operations, to lower costs and secure inputs for our operations and transportation for our production.  If our exploration and production activities are curtailed or disrupted, we may not recover our investment in these activities, which could adversely impact our results of operations.  In addition, our continued expansion of these operations may adversely impact our relationships with third-party providers. 

Through December 31, 2013, we had invested approximately $1,096 million in our gas gathering system built for the Fayetteville Shale and approximately $213 million in our gas gathering system built for the Marcellus Shale.  To the extent necessary to gather our production, we may make further substantial investments in the expansion of our gas gathering systems.  We have also entered into multiple firm transportation agreements relating to natural gas volumes produced from the Fayetteville Shale as well as a number of firm transportation and gathering agreements relating to the Marcellus Shale. As of December 31, 2013, our aggregate demand charge commitments under these firm transportation agreements and gathering agreements were approximately $3.5 billion. Our gas gathering business will largely rely on natural gas sourced from our operations.  If our Fayetteville Shale and Marcellus Shale programs fail to produce significant quantities of natural gas within expected timeframes, our investments in our gas gathering operations could be lost, and we could be forced to pay demand or other charges for transportation on pipelines and gathering systems that we would not be using.

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We also have made significant investments to meet certain of our oilfield services needs, including establishing our own drilling rig operation, sand mine and pressure pumping capability.  If our level of operations is reduced, we may not be able to recover these investments.  Further, entering into these service and supply sectors, including competing with them for qualified personnel and supplies, may have an adverse effect on our relationships with our existing third-party service and resource providers or our ability to secure these services and resources from other providers.

If we fail to drill all of the wells that are necessary to hold our acreage, the lease terms could expire, which would result in the loss of certain leasehold rights.

 

Leases on approximately 196,052 net acres of our Fayetteville Shale acreage will expire in the next three years if we do not drill successful wells to develop the acreage or otherwise take action to extend the leases.  Approximately 117,407 net acres of our Marcellus Shale acreage will expire in the next three years if we do not drill successful wells to develop the acreage or otherwise take action to extend the leases.  As discussed above under “Our drilling plans for the Fayetteville Shale and the Marcellus Shale are subject to change,” our ability to drill wells depends on a number of factors, including certain factors that are beyond our control.  With the exception of the Ozark Highlands Unit, which is federally leased, the current rules in Arkansas relating to the Fayetteville Shale provide that each drilling unit would consist of a governmental section of approximately 640 acres and operators are permitted to drill up to 16 wells per drilling unit for each unconventional source of supply.  In Pennsylvania, the location of our Marcellus Shale acreage, there are currently no rules establishing requirements for drilling units.  However, current rules in Arkansas may change and rules may be implemented in Pennsylvania that could impair our ability to drill or maintain our acreage position.  In addition, other E&P operator drilling activity could impair our ability to drill and maintain acreage positions.  To the extent that any field rules prevent us from successfully drilling wells in certain areas, we may not be able to drill the wells required to maintain our leasehold rights and our leasehold investments could be lost.

We depend upon our management team and our operations require us to attract and retain experienced technical personnel. 

The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our business strategy depends, in part, on our experienced management team, as well as certain key geoscientists, geologists, engineers and other professionals employed by us.  The success of our technological initiatives that support our business enterprise is also dependent upon attracting and retaining experienced technical professionals.  The loss of key members of our management team or other highly qualified technical professionals could have a material adverse effect on our business, financial condition and operating results.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.

The elimination of certain key U.S. federal income tax deductions currently available to oil and natural gas exploration and production companies has been proposed in recent years. These changes have included, among other proposals:

·

Repeal of the percentage depletion allowance for oil and natural gas properties

·

Elimination of current deductions for intangible drilling and development costs

·

Elimination of the deduction for certain domestic production activities

·

Extension of the amortization period for certain geological and geophysical expenditures

It is unclear whether these or similar changes will be enacted. The passage of these or any similar changes in federal income tax laws to eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development could have an adverse effect on our financial position, results of operations and cash flows.

Cyber attacks or terrorist attacks could affect our assets, cash flows and results of operations.

Cyber attacks on businesses are occurring with greater frequency, and natural gas and oil infrastructure and systems could become targets of terrorists.  We rely on electronic systems and networks to control and manage our exploration and production, pipeline and marketing operations and have multiple layers of security to mitigate risks of cyber attack.  We also have security in place around our physical operations.   If we nonetheless were to experience an attack and our security measures failed, the potential consequences to our businesses and the communities in which they operate could be significant.

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Our certificate of incorporation and, bylaws contain provisions that could make it more difficult for someone to either acquire us or affect a change of control.

Certain provisions of our certificate of incorporation and bylaws, together with any stockholder rights plan that we might have in place, could discourage an effort to acquire all or a controlling interest in the Company or replace directors or members of our executive management team. These provisions could potentially deprive our stockholders of opportunities to sell shares of our common stock at above-market prices.

 

Our Canadian exploration and production activities are subject to different risks and uncertainties, different from or in addition to those we face in our U.S. operations.

 

In addition to the various risks associated with our U.S. operations, we are subject to risks and uncertainties related to our Canadian exploration and production activities, including risks related to increases in taxes and governmental royalties, changes in laws and policies governing operations of foreign-based companies, restrictions on imports and exports, expropriation of property, cancellation of contract rights, environmental protection controls, environmental compliance requirements and laws pertaining to workers’ health and safety. Consequently, our exploration, development and production activities in Canada could be substantially affected by factors beyond our control. In addition, the rights of aboriginal peoples, called First Nations in Canada, are not clear.  Our operations in New Brunswick have been subject to local protests, causing several temporary interruptions to our exploration activities.

 

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

 

ITEM 2.  PROPERTIES

The summary of our oil and natural gas reserves as of fiscal year-end 2013 based on average fiscal-year prices, as required by Item 1202 of Regulation S-K, is included in the table headed “2013 Proved Reserves by Category and Summary Operating Data” in “Business – Exploration and Production – Our Proved Reserves” in Item 1 of this Form 10-K and incorporated by reference into this Item 2.  Our proved reserves are based upon estimates prepared for each of our properties annually by the reservoir engineers assigned to the asset management team in the geographic locations in which the property is located. These estimates are reviewed by senior engineers who are not part of the asset management teams and by our Manager – Capital Budgeting & Reserves, who is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Manager – Capital Budgeting & Reserves has 12 years of experience in petroleum engineering, including the estimation of oil and natural gas reserves, and holds a Bachelor of Science in Petroleum Engineering. Prior to joining us in 2009, our Manager – Capital Budgeting & Reserves served in various reservoir engineering roles for Kinder Morgan CO2 and Citation Oil & Gas and is a member of the Society of Petroleum Engineers. He reports to our Executive Vice President – Corporate Development who has more than 32 years of experience in reservoir engineering including the estimation of oil and natural gas reserves in multiple basins both in the United States and internationally. Prior to joining Southwestern in 2008, our Executive Vice President – Corporate Development served in various engineering and senior management roles for Tenneco Oil Company, Enron Oil & Gas Company, Enron Global Exploration & Production, El Paso Energy and The Houston Exploration Company, and is a member of the Society of Petroleum Engineers, IPAA, TIPRO and the Houston Producer’s Forum. On our behalf, the Executive Vice President – Corporate Development engages NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the two technical persons primarily responsible for auditing our proved reserves estimates (1) have over 32 years and over 12 years of practical experience in petroleum geosciences and petroleum engineering, respectively; (2) have over 22 years and over 12 years of experience in the estimation and evaluation of reserves, respectively; (3) each has a college degree; (4) each is a Licensed Professional Geoscientist in the State of Texas or a Licensed Professional Engineer in the State of Texas; (5) each meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; and (6) each is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The financial data included in the reserve estimates are also separately reviewed by our accounting staff. Our proved reserves estimates, as internally reviewed and audited by NSAI, are submitted for review and approval to our Chief Executive Officer.  Finally, upon his approval, NSAI reports the results of its reserve audit to the Board of Directors with whom final authority over the estimates of our proved reserves rests.  A copy of NSAI's report has been filed as Exhibit 99.1 to this Form 10-K. 

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The information regarding our proved undeveloped reserves required by Item 1203 of Regulation S-K is included under the heading “Proved Undeveloped Reserves” in “Business – Exploration and Production – Our Proved Reserves” in Item 1 of this Form 10-K.

The information regarding delivery commitments required by Item 1207 of Regulation S-K is included under the heading “Sales, Delivery Commitments and Customers” in the “Business – Exploration and Production – Our Operations” in Item 1 of this Form 10-K and incorporated by reference into this Item 2. For additional information about our natural gas and oil operations, we refer you to Note 4 to the consolidated financial statements.  For information concerning capital investments, we refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Investments.”  We also refer you to Item 6, “Selected Financial Data” in Part II of this Form 10-K for information concerning natural gas and oil produced.

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The information regarding oil and gas properties, wells, operations and acreage required by Item 1208 of Regulation S-K is set forth below:

 

Leasehold acreage as of December 31, 2013:  

 

 

 

 

 

 

 

 

 

 

 

Undeveloped

 

Developed

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

Fayetteville Shale (1)

495,510 

 

291,360 

 

816,840 

 

490,104 

Marcellus Shale (2)

307,330 

 

246,838 

 

45,871 

 

45,608 

Ark-La-Tex:

 

 

 

 

 

 

 

Conventional Arkoma (3)

67,084 

 

60,375 

 

184,812 

 

166,331 

East Texas (4)

411 

 

172 

 

71,310 

 

50,279 

New Ventures:

 

 

 

 

 

 

 

USA New Ventures – LSBD (5)

669,191 

 

459,321 

 

3,619 

 

3,270 

USA New Ventures – Other (6)

1,058,277 

 

796,653 

 

–  

 

–  

Canada New Ventures (7)

2,716,758 

 

2,716,758 

 

–  

 

–  

 

5,314,561 

 

4,571,477 

 

1,122,452 

 

755,592 

 

 (1)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 22,092 net acres in 2014, 16,305 net acres in 2015, and 1,803 net acres in 2016 (excluding 155,852 net acres held on federal lands which are currently suspended by the Bureau of Land Management).

(2)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 65,537 net acres in 2014, 32,637 net acres in 2015 and 19,233 net acres in 2016.

(3)Includes 123,442 net developed acres and 778 net undeveloped acres in the Arkoma Basin that are also within our Fayetteville Shale focus area but not included in the Fayetteville Shale acreage in the table above.  Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 262 net acres in 2014, 7,437 net acres in 2015 and 574 net acres in 2016.

(4)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 27 net acres in 2014, 64 net acres in 2015 and 0 net acres in 2016. 

(5)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 245,793 net acres in 2014, 151,667 net acres in 2015 and 25,891 net acres in 2016.

(6)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 65,628 net acres in 2014, 143,708 net acres in 2015 and 224,346 net acres in 2016.

(7)Assuming successful wells are not drilled to develop the acreage and our exploration license agreements are not extended, leasehold expiring over the next three years will be 0 net acres in 2014, 2,518,518 net acres in 2015, and 48,960 net acres in 2016.

 

Producing wells as of December 31, 2013:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

Oil

 

Total

 

Gross Wells

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Operated

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fayetteville Shale (1)

3,539 

 

2,432 

 

–  

 

–  

 

3,539 

 

2,432 

 

3,051 

Marcellus Shale (2)

334 

 

171 

 

–  

 

–  

 

334 

 

171 

 

172 

Ark-La-Tex:

 

 

 

 

 

 

 

 

 

 

 

 

 

Conventional Arkoma(3)

1,164 

 

566 

 

–  

 

–  

 

1,164 

 

566 

 

550 

East Texas(4)

166 

 

105 

 

 

 

173 

 

109 

 

134 

New Ventures

–  

 

–  

 

 

 

 

 

 

5,203 

 

3,274 

 

10 

 

 

5,213 

 

3,281 

 

3,910 

 

 (1)   As of December 31, 2013, this includes 1 gross natural gas well in which we own an overriding royalty interest.

(2)  As of December 31, 2013, this includes 143 gross natural gas wells in which we own an overriding royalty interest.

(3)  As of December 31, 2013, this includes 146 gross natural gas wells in which we own an overriding royalty interest.

(4)  As of December 31, 2013, this includes 1 gross oil well and 12 gross natural gas wells in which we own an overriding royalty interest.

38

 


 

 

 

The information regarding drilling and other exploratory and development activities required by Item 1205 of Regulation S-K is set forth below:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Exploratory(1)

 

 

 

 

 

 

 

 

 

Productive Wells

 

Dry Wells

 

Total

Year

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

2013

 

3.0 

 

2.5 

 

1.0 

 

1.0 

 

4.0 

 

3.5 

2012

 

7.0 

 

7.0