10-K 1 swn20161231x10k.htm SWN 2016 FORM 10-K SWN 2016 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, 2016

Commission file number 001-08246



Picture 2

 

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.)



 

 

 

10000 Energy Drive,  

Spring, Texas

77389

(Address of principal executive offices)

(Zip Code)



 

 

 

(832)  796-1000

(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

Depositary Shares, each representing a 1/20th ownership interest in a share of 6.25% Series B Mandatory Convertible Preferred Stock

New York Stock Exchange



 

 

 

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



 

 

 

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes   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). Yes   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

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  

The aggregate market value of the voting stock held by non-affiliates of the registrant was $4,913,492,123 based on the New York Stock Exchange – Composite Transactions closing price on June 30, 2016 of $12.58. For purposes of this calculation, the registrant has assumed that its directors and executive officers are affiliates.

As of February 21, 2017, the number of outstanding shares of the registrant’s Common Stock, par value $0.01, was 497,953,968

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 23, 2017 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, 2016



TABLE OF CONTENTS



 

Page

PART I

 

 

Item 1.

Business 

3



Glossary of Certain Industry Terms

24

Item 1A.

Risk Factors

28

Item 1B.

Unresolved Staff Comments

38

Item 2.

Properties

39

Item 3.

Legal Proceedings

43

Item 4.

Mine Safety Disclosures

43



 

 

PART II

 

 

Item 5.

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

44



Stock Performance Graph

45

Item 6.

Selected Financial Data

46

Item 7.

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

48



Overview

48



Results of Operations

50



Liquidity and Capital Resources

55



Critical Accounting Policies and Estimates

61



Cautionary Statement about Forward-Looking Statements

66

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

67

Item 8.

Financial Statements and Supplementary Data

68



Index to Consolidated Financial Statements

68

Item 9.

Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

115

Item 9A.

Controls and Procedures

115

Item 9B.

Other Information

115



 

 

PART III

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

116

Item 11.

Executive Compensation

116

Item 12.

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

117

Item 13.

Certain Relationships and Related Transactions, and Director Independence

117

Item 14.

Principal Accounting Fees and Services

117



 

 

PART IV

 

 

Item 15.

Exhibits, Financial Statement Schedules

117

Item 16.

Summary

117



 

 

EXHIBIT INDEX

 

119







1

 


 

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 Annual Report 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, the Health, Safety, Environment and Corporate Responsibility and the Nominating and Governance Committees of our Board of Directors are available on our website, and, upon request, in print free of charge to any stockholder.  Information on our website is not incorporated into this report.

We file periodic reports, current reports and proxy statements 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.  The public may also 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.

 

2

 


 

ITEM 1. BUSINESS



Southwestern Energy Company (including its subsidiaries, collectively, “we”, “Southwestern” or the “Company”) is an independent natural gas and oil company engaged in development and production activities, including related natural gas gathering and marketing.  Southwestern is a holding company whose assets consist of direct and indirect ownership interests in, and whose business is conducted substantially through, its subsidiaries.  Currently we operate only in the United States.  Southwestern’s common and preferred stock are listed and traded on the NYSE under the ticker symbols “SWN” and “SWNC”, respectively.



Southwestern, which was incorporated in Arkansas in 1929 and reincorporated in Delaware in 2006, has its executive offices located at 10000 Energy Drive, Spring, Texas 77389, and can be reached by phone at 832-796-1000.  The Company also maintains offices in Conway, Arkansas; Tunkhannock, Pennsylvania; and Jane Lew, West Virginia. 



Our Business Strategy



We aim to deliver sustainable and assured industry-leading returns through excellence in exploration and production and midstream performance from our extensive resource base and targeted expansion of our activities and assets along the hydrocarbon value chain.  Our Company’s formula embodies our corporate philosophy and guides how we operate our business:

swn20161231x10kg2.jpg

Our formula, “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 always strive to attract and retain strong talent, to work safely and act ethically with unwavering vigilance for the environment and the communities in which we operate, and to creatively apply technical and financial skills, which we believe will grow long-term value.  The arrow in our formula is not a straight line: we acknowledge that factors may adversely affect quarter-by-quarter results, but the path over time points to value creation.

In applying these core principles, we concentrate on:

·

Financial Strength.  We are committed to rigorously managing our balance sheet and risks.  We budget to invest only from our net cash flow (along with the remaining portion of proceeds from our equity issuance in 2016 that we previously earmarked for capital investment), protect our projected cash flows through hedging, and continue to ensure strong liquidity while de-levering the Company. 

·

Increasing Margins.  We apply strong technical, operational, commercial and marketing skills to reduce cost, improve the productivity of our wells and pursue commercial arrangements that extract greater value from them.  We believe our demonstrated ability to improve margins, especially by levering the scale of our large assets, gives us a competitive advantage as we move into the future. 

·

Dynamic Management of Assets Throughout Life Cycle.  We own large-scale, long-life assets in various phases of development.  In early stages, we ramp up development through technical, operational and commercial skills, and as they grow we look for ways to maximize their value, through efficient operating practices along with commercial and marketing expertise.

·

Deepening Our Inventory.  We continue to expand the inventory of properties that we can develop profitably by converting our extensive resources into proved reserves, targeting additions whose productivity largely has been demonstrated and improving efficiencies in production.

·

The Hydrocarbon Value Chain.  We often expand our activities vertically when we believe this will enhance our margins or otherwise provide us competitive advantages.  For example, the Company developed and operates the largest gathering system in the Fayetteville Shale area.  We operate drilling rigs and own a sand mine that provides a low cost proppant in hydraulic fracturing.  These activities help protect our margin, minimize the risk of unavailability of these resources from third parties, diversify our cash flows and capture additional value.

·

The Next Chapter of Unconventionals.  Our company grew dramatically in the 2000s by harnessing and enhancing the newfound combination of hydraulic fracturing and horizontal drilling technologies.  Our people constantly search for the next revolutionary technology and other operational advancements to capture greater value in unconventional hydrocarbon resource development.  These developments – whether single, step-changing technologies or a combination of several incremental ones – can reduce finding and development costs and thus increase our margins.

3

 


 

·

Innovative Environmental Solutions and Policy Formation.  Our Company is a leader in identifying and implementing innovative solutions to unconventional hydrocarbon development to minimize the environmental and community impacts of our activities.  We work extensively with governmental, non-governmental and industry stakeholders to develop responsible and cost-effective programs.  We demonstrate that a company can operate responsibly and profitably, putting us in a better position to comply with new regulations as they evolve.



During 2016, we executed on our business strategy by:

·

Investing within our cash flow plus a portion of the proceeds from our successful equity offering earmarked for this purpose, with the remainder to debt reduction

·

Investing in only those projects that meet our rigorous economic hurdles at strip pricing

·

Rearranging and extending our bank credit facilities and successfully tendering for approximately $700 million of near-term senior notes, which enhanced and stabilized our liquidity and eliminated the overhang of near-term debt maturities

·

Generating cash flow from operations of about $500 million, which reflects the impact of an aggressive assault on costs and improved drilling and completion performance

·

Intelligently managing our portfolio, including disposing of acreage we were not planning to develop until well into the next decade and using the over $400 million of proceeds to reduce debt



Our predominant operations, which we refer to as Exploration and Production (“E&P”), are focused on the finding and development of natural gas, oil and natural gas liquid (“NGL”) reserves.  We are also focused on creating and capturing additional value through our natural gas gathering and marketing segment, which we refer to as Midstream Services.  We conduct substantially all of our business through subsidiaries.



Exploration and Production – Our largest business is the exploration for and production of natural gas, oil and NGLs, with our current operations principally focused within the United States on development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia and Arkansas.  Our operations in northeast Pennsylvania are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale (herein referred to as “Northeast Appalachia”), our operations in West Virginia are also focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas, oil and NGL reservoirs (herein referred to as “Southwest Appalachia”) and our operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale. Collectively, our properties located in Pennsylvania and West Virginia are herein referred to as the “Appalachian Basin.”  We have smaller holdings in Colorado and Louisiana along with other areas in which we are testing potential new resources, including New Brunswick, Canada whose development is subject to a moratorium.  We also have drilling rigs located in Pennsylvania, West Virginia and Arkansas and provide oilfield products and services, principally serving our production operations.



 Midstream Services –  Through our affiliated midstream subsidiaries, we engage in natural gas gathering activities in Arkansas and Louisiana.  These activities primarily support our E&P operations and generate revenue from the gathering of natural gas.  Our marketing activities capture opportunities that arise through the marketing and transportation of the natural gas, oil and NGLs produced in our E&P operations. 



Historically, the vast majority of our cash flow from operations has been derived from our E&P business.  In 2016 and 2015, depressed commodity prices significantly decreased our E&P results.  In 2016, our E&P segment generated cash flow from operations of $297 million, which constituted 60% of our total cash flow from operations.  This compares to E&P-generated cash flow from operations of $1.1 billion and $2.1 billion in 2015 and 2014, respectively.  Our E&P segment constituted 71% and 89% of our total cash flow from operations in 2015 and 2014, respectively.  The remainder of our consolidated cash flow from operations in each of these years was primarily generated from our Midstream Services segment.



4

 


 

Exploration and Production



Overview



Operations in our E&P segment are primarily in the Appalachian Basin and Arkansas.  We also are conducting activities in other basins targeting various formations as potential new resources. 



Our E&P segment recorded operating losses of $2.4 billion and $7.1 billion in 2016 and 2015, respectively, and operating income of $1.0 billion in 2014.  The operating losses in 2016 and 2015 were primarily the result of $2.3 billion, or $1.4 billion net of taxes, and $7.0 billion, or $4.3 billion net of taxes, respectively, of non-cash impairments of natural gas and oil properties due to decreased commodity prices.  In May 2015, we divested of our East Texas and Arkoma properties, previously referred to as the Ark-La-Tex division.



Cash flow from operations from our E&P segment was $297 million in 2016, compared to $1.1 billion in 2015 and $2.1 billion in 2014.  Our cash flow from operations decreased in 2016 as the effects of lower realized natural gas prices and decreased natural gas production more than offset our reduction in operating expenses.  Our cash flow from operations decreased in 2015 as lower realized natural gas prices and increased total operating costs and expenses, due to increased activity levels, more than offset the revenue impacts of higher production volumes.



Oilfield Services Vertical Integration



We provide some oilfield services that are strategic and economically beneficial for our E&P operations when our E&P activity levels and market pricing support these activities and we can do so more efficiently or cost-effectively.  This vertical integration lowers our net well costs, allows us to operate efficiently and helps us to mitigate certain operational environmental risks.  Among others, these services have included drilling, hydraulic fracturing and the mining of sand used as proppant for certain of our well completions in the Fayetteville Shale from a 570-acre complex in Arkansas. 



We have conducted drilling operations for a majority of our operated wells.  As of December 31, 2016, we had a total of five rigs drilling in Pennsylvania, West Virginia and Arkansas.  In 2016, we provided drilling services for all of the wells that we operate in Northeast Appalachia, Southwest Appalachia and the Fayetteville Shale.  Our drilling and completion services, along with our sand mine servicing our operated wells in the Fayetteville Shale, were inactive during our suspension of drilling and completion activities in the first half of 2016, but resumed, in part, as these activities were reinitiated during the third quarter of 2016.



We ceased providing hydraulic fracturing services in early 2016 at the same time as we suspended drilling and completion activities.  To date, we have not resumed the provision of hydraulic fracturing services ourselves and instead are utilizing third parties who are offering lower costs.  This may change as industry activity resumes, should that lead to higher prices or lower dependability from third-party providers of these services.



5

 


 

Our Proved Reserves



Our estimated proved natural gas, oil and NGL reserves were 5,253 Bcfe at year-end 2016, compared to 6,215 Bcfe at year-end 2015 and 10,747 Bcfe at year-end 2014.  The decrease in our reserves in 2016 was primarily due to our production in 2016 and downward price revisions associated with decreased commodity prices, partially offset by upward performance revisions in Northeast Appalachia, Southwest Appalachia and the Fayetteville Shale.  The significant decrease in our reserves in 2015 was primarily due to downward price revisions in our proved undeveloped reserves associated with decreased commodity prices and our production, partially offset by upward performance revisions in Northeast Appalachia and Southwest Appalachia and our successful development programs in the Northeast Appalachia, Southwest Appalachia and the Fayetteville Shale.  The significant increase in our reserves in 2014 was primarily due to the acquisition of approximately 413,000 net acres in Southwest Appalachia, our successful development drilling programs in Northeast Appalachia and the Fayetteville Shale and upward performance revisions in Northeast Appalachia. 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, oil and NGL reserve quantities, are highly dependent upon the natural gas price used in our reserve and after-tax PV-10 calculations.  In order to value our estimated proved natural gas, oil and NGL reserves as of December 31, 2016, we utilized average prices from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.48 per MMBtu for natural gas, West Texas Intermediate oil of $39.25 per barrel for oil and $6.74 per barrel for NGLs, compared to $2.59 per MMBtu for natural gas, $46.79 per barrel for oil and $6.82 per barrel for NGLs at December 31, 2015 and $4.35 per MMBtu for natural gas, $91.48 per barrel for oil and $23.79 per barrel for NGLs at December 31, 2014.



Our after-tax PV-10 was $1.7 billion at year-end 2016, $2.4 billion at year-end 2015 and $7.5 billion at year-end 2014.  The decrease in our after-tax PV-10 value in 2016 compared to 2015 was primarily due to lower reserve levels.  The decrease in 2015 compared to 2014 was primarily due to comparatively lower average commodity prices.  The difference in after-tax PV-10 and pre-tax PV-10 (a non-GAAP measure which is reconciled in the 2016 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 2016 estimated proved reserves had a present value of estimated future net cash flows before income tax, or pre-tax PV-10, of $1.7 billion, compared to $2.4 billion at year-end 2015 and $9.5 billion at year-end 2014.  Our year-end 2016 and 2015 after-tax PV-10 computations do not have future income taxes because our tax basis in the associated oil and gas properties exceeded expected pre-tax cash inflows, and thus do not differ from the pre-tax values. 



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.  Pre-tax PV-10 is based on prices, costs and discount factors that are comparable from company to company, while 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 “Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report for a discussion of our standardized measure of discounted future cash flows related to our proved natural gas, oil and NGL reserves, to the risk factor “Our proved natural gas, oil and NGL reserves are estimates.  Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A of Part I of this Annual Report, 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 Annual Report for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.



At year-end 2016, 93% of our estimated proved reserves were natural gas and 99% of total estimated proved reserves were classified as proved developed, compared to 95% and 93%, respectively, in 2015 and 91% and 55%, respectively in 2014.  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 6.0 years at year-end 2016.  In 2016, natural gas sales accounted for 89% of total operating revenues, compared to 93% and nearly 100% in 2015 and 2014, respectively.



6

 


 

The following table provides an overall and categorical summary of our natural gas, oil and NGL reserves, as of fiscal year-end 2016 based on average fiscal year prices, and our well count, net acreage and PV-10 as of December 31, 2016, and sets forth 2016 annual information related to production and capital investments for each of our operating areas:







 

 

 

 

 

 

 

 

 

 

 

 

 

 

2016 PROVED RESERVES BY CATEGORY AND SUMMARY OPERATING DATA



 

 

 

 

 

 

 

 

 

 

 

 

 

 



Appalachia

 

 

 

 

 

 

 

 



Northeast

 

Southwest

 

Fayetteville Shale

 

Other (1)

 

Total

Estimated Proved Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (Bcf):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed (Bcf)

 

1,540 

 

 

293 

 

 

2,954 

 

 

 

 

4,789 

Undeveloped (Bcf)

 

34 

 

 

 –  

 

 

43 

 

 

–  

 

 

77 



 

1,574 

 

 

293 

 

 

2,997 

 

 

 

 

4,866 

Crude Oil (MMBbls):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed (MMBbls)

 

–  

 

 

10.2 

 

 

–  

 

 

0.3 

 

 

10.5 

Undeveloped (MMBbls)

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  



 

–  

 

 

10.2 

 

 

–  

 

 

0.3 

 

 

10.5 

Natural Gas Liquids (MMBbls):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed (MMBbls)

 

–  

 

 

53.8 

 

 

–  

 

 

0.1 

 

 

53.9 

Undeveloped (MMBbls)

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  



 

–  

 

 

53.8 

 

 

–  

 

 

0.1 

 

 

53.9 

Total Proved Reserves (Bcfe) (2):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed (Bcfe)

 

1,540 

 

 

677 

 

 

2,954 

 

 

 

 

5,176 

Undeveloped (Bcfe)

 

34 

 

 

 –  

 

 

43 

 

 

–  

 

 

77 



 

1,574 

 

 

677 

 

 

2,997 

 

 

 

 

5,253 

Percent of Total

 

30% 

 

 

13% 

 

 

57% 

 

 

0% 

 

 

100% 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Percent Proved Developed

 

98% 

 

 

100% 

 

 

99% 

 

 

100% 

 

 

99% 

Percent Proved Undeveloped

 

2% 

 

 

0% 

 

 

1% 

 

 

0% 

 

 

1% 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production (Bcfe)

 

350 

 

 

148 

 

 

375 

 

 

 

 

875 

Capital Investments (in millions) (3)

$

204 

 

$

288 

 

$

86 

 

$

19 

 

$

597 

Total Gross Producing Wells (4)

 

820 

 

 

306 

 

 

4,217 

 

 

16 

 

 

5,359 

Total Net Producing Wells (4)

 

439 

 

 

216 

 

 

2,932 

 

 

13 

 

 

3,600 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Net Acreage

 

245,805 

 (5)

 

321,563 

 (6)

 

918,535 

 (7)

 

3,023,386 

 (8)

 

4,509,289 

Net Undeveloped Acreage

 

146,096 

 (5)

 

161,607 

 (6)

 

285,692 

 (7)

 

3,010,908 

 (8)

 

3,604,303 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

PV-10:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pre-Tax (in millions) (9)

$

183 

 

$

163 

 

$

1,325 

 

$

(6)

 

$

1,665 

PV of Taxes (in millions) (9)

 

–  

 

 

–  

 

 

–  

 

 

–  

 

 

–  

After-Tax (in millions) (9)

$

183 

 

$

163 

 

$

1,325 

 

$

(6)

 

$

1,665 

Percent of Total

 

11% 

 

 

10% 

 

 

79% 

 

 

0% 

 

 

100% 

Percent Operated (10)

 

95% 

 

 

100% 

 

 

99% 

 

 

100% 

 

 

98% 



(1)    Other consists primarily of properties in Canada, Colorado and Louisiana.

(2)    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.

(3)    Total and Other capital investments excludes $26 million related to our E&P service companies.

(4)    Represents all producing wells, including wells in which we only have an overriding royalty interest, as of December 31, 2016.

(5)    Assuming successful wells are not drilled to develop the acreage and leases are not extended in Northeast Appalachia, leasehold expiring over the next three years will be 63,900 net acres in 2017, 16,066 net acres in 2018 and 11,413 net acres in 2019. 

(6)    Assuming successful wells are not drilled to develop the acreage and leases are not extended in Southwest Appalachia, leasehold expiring over the next three years will be 39,429 net acres in 2017, 12,267 net acres in 2018 and 10,824 net acres in 2019.  Of this acreage, 21,760 net acres in 2017, 3,767 net acres in 2018 and 8,150 net acres in 2019 can be extended for an average of 4.8 years.

7

 


 

(7)    Assuming successful wells are not drilled to develop the acreage and leases are not extended in the Fayetteville Shale, leasehold expiring over the next three years will be 453 net acres in 2017, 60 net acres in 2018 and 432 net acres in 2019 (excluding 158,231 net acres held on federal lands which are currently suspended by the Bureau of Land Management).

(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 the Lower Smackover Brown Dense area, the Sand Wash Basin and New Brunswick, Canada, will be 68,556 net acres in 2017, 21,982 net acres in 2018 and 103,172 net acres in 2019.  With regard to our acreage in the Lower Smackover Brown Dense, assuming successful wells are not drilled and leases are not extended, leasehold expiring over the next three years will be 50,778 net acres in 2017, 83,021 net acres in 2018 and 5,793 net acres in 2019.  With regard to our acreage in the Sand Wash Basin, assuming successful wells are not drilled and leases are not extended, leasehold expiring over the next three years will be 36,527 net acres in 2017, 51,260 net acres in 2018, and 12,810 net acres in 2019.  With regard to our acreage in New Brunswick, Canada, exploration licenses for 2,518,519 net acres were extended through 2021.

(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 natural gas, oil and NGL reserves.

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



We refer you to “Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report for a more detailed discussion of our proved natural gas, oil and NGL reserves as well as our standardized measure of discounted future net cash flows related to our proved natural gas, oil and NGL reserves.  We also refer you to the risk factor “Our proved natural gas, oil and NGL reserves are estimates.  Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in Item 1A of Part I of this Annual Report 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 Annual Report for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.



Proved Undeveloped Reserves



Presented below is a summary of changes in our proved undeveloped reserves for 2014, 2015 and 2016:







 

 

 

 

 

 

 

 

 

 

CHANGES IN PROVED UNDEVELOPED RESERVES (BCFE)



 

 

 

 

 

 

 

 

 

 



 

Appalachia

 

 

 

 

 

 



 

Northeast

 

Southwest

 

Fayetteville Shale

 

Other (1)

 

Total

December 31, 2013

 

1,075 

 

– 

 

1,655 

 

 

2,737 

Extensions, discoveries and other additions (2)

 

589 

 

– 

 

573 

 

– 

 

1,162 

Total revision attributable to performance and production (3)

 

307 

 

– 

 

(130)

 

(6)

 

171 

Price revisions

 

11 

 

– 

 

24 

 

– 

 

35 

Developed

 

(384)

 

– 

 

(406)

 

– 

 

(790)

Disposition of reserves in place

 

– 

 

– 

 

 – 

 

– 

 

– 

Acquisition of reserves in place (4)

 

– 

 

1,481 

 

 – 

 

– 

 

1,481 

December 31, 2014

 

1,598 

 

1,481 

 

1,716 

 

 

4,796 

Extensions, discoveries and other additions

 

138 

 

 

34 

 

– 

 

176 

Total revision attributable to performance and production (3)

 

513 

 

158 

 

62 

 

– 

 

733 

Price revisions

 

(1,447)

 

(1,413)

 

(1,357)

 

– 

 

(4,217)

Developed

 

(488)

 

(226)

 

(330)

 

– 

 

(1,044)

Disposition of reserves in place

 

– 

 

– 

 

 – 

 

(1)

 

(1)

Acquisition of reserves in place

 

– 

 

– 

 

 – 

 

– 

 

– 

December 31, 2015

 

314 

 

 

125 

 

– 

 

443 

Extensions, discoveries and other additions

 

 – 

 

 

 

25 

 

– 

 

25 

Total revision attributable to performance and production (3)

 

204 

 

 

(1)

 

– 

 

203 

Price revisions

 

(303)

 

(4)

 

(67)

 

– 

 

(374)

Developed

 

(181)

 

 –  

 

(39)

 

– 

 

(220)

Disposition of reserves in place

 

– 

 

 –

 

– 

 

 –   

 

 –   

Acquisition of reserves in place

 

– 

 

 –

 

– 

 

– 

 

– 

December 31, 2016

 

34 

 

–  

 

43 

 

 –   

 

77 



(1)

Other includes properties principally in Colorado and Louisiana along with Ark-La-Tex properties divested in May 2015.

(2)

Primarily associated with the undeveloped locations that were added throughout the year in 2014 due to our successful drilling program.

(3)

Primarily due to changes associated with the analysis of updated data collected in the year and decreases related to current year production.

(4)

Our acquisition of reserves in place is attributable to the purchase of undeveloped locations in West Virginia and southwest Pennsylvania.

8

 


 



As of December 31, 2016, we had 77 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 2016, we invested $103 million in connection with converting 220 Bcfe, or 50%, of our proved undeveloped reserves as of December 31, 2015 into proved developed reserves and added 25 Bcfe of proved undeveloped reserve additions in the Fayetteville Shale.  As a result of the commodity price environment in 2016, we had downward price revisions of 374 Bcfe which were slightly offset by a 203 Bcfe increase due to performance revisions.  As of December 31, 2015, we had 443 Bcfe of proved undeveloped reserves.  During 2015, we invested $869 million in connection with converting 1,044 Bcfe, or 22%, of our proved undeveloped reserves as of December 31, 2014 into proved developed reserves and added 176 Bcfe of proved undeveloped reserve additions in the Appalachian Basin and the Fayetteville Shale. As a result of the depressed commodity price environment in 2015, we had downward price revisions of 4,217 Bcfe which were slightly offset by a 733 Bcfe increase due to performance revisions.  As of December 31, 2014, we had 4,796 Bcfe of proved undeveloped reserves.  During 2014, we invested $767 million in connection with converting 790 Bcfe, or 29%, of our proved undeveloped reserves as of December 31, 2013 into proved developed reserves and added 2,643 Bcfe of proved undeveloped reserve additions in the Appalachian Basin and the Fayetteville Shale.



Our December 31, 2016 proved reserves include 77 Bcfe of proved undeveloped reserves from 15 locations that have a positive present value on an undiscounted basis in compliance with proved reserve requirements but do not have a positive present value when discounted at 10%. These properties have a negative present value of $11 million when discounted at 10%. We have made a final investment decision and are committed to developing these reserves within five years from the date of initial booking.



We expect that the development costs for our proved undeveloped reserves of 77 Bcfe as of December 31, 2016 will require us to invest an additional $42 million for those reserves to be brought to production.  Our ability to make the necessary investments to generate these cash inflows is subject to factors that may be beyond our control.  The decreased commodity price environment has resulted, and could continue to 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 “Natural gas, oil and natural gas liquids prices greatly affect our business, including our revenues, profits, liquidity, growth, ability to repay our debt and the value of our assets” and “Significant capital expenditures are required to replace our reserves and conduct our business” in Item 1A of Part I of this Annual Report 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 Annual Report for a more detailed discussion of these factors and other risks.



Our Reserve Replacement



Since 2005, the substantial majority of our reserve additions have been generated from our Fayetteville Shale division.  However, over the past several years, Northeast Appalachia has also contributed to an increasing amount of our reserve additions as a result of increased development activity, totaling 81 Bcf, 420 Bcf and 835 Bcf in 2016, 2015 and 2014, respectively.  Additionally, we added 157 Bcfe and 123 Bcfe of reserves in 2016 and 2015, respectively, as a result of our drilling program in Southwest Appalachia, which was acquired in December 2014.  We expect our drilling programs in Northeast Appalachia, Southwest Appalachia and the Fayetteville 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 “Significant capital expenditures are required to replace our reserves and conduct our business” and “If we are not able to replace reserves, we may not be able to grow or sustain production.” in Item 1A of Part I of this Annual Report 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 Annual Report for a more detailed discussion of these factors and other risks.



9

 


 

Our Operations



Northeast Appalachia



We began leasing acreage in northeast Pennsylvania in 2007 in an effort to participate in the emerging Marcellus Shale.  As of December 31, 2016, we had approximately 245,805 net acres in Northeast Appalachia and had spud or acquired 568 operated wells, 447 of which were on production and 536 of which are horizontal wells.  Northeast Appalachia represents 40% of our total net production and 30% of our total reserves as of December 31, 2016.  Below is a summary of Northeast Appalachia’s operating results for the last three years:    









 

 

 

 

 

 

 

 

 



For the years ended December 31,

 



2016

 

2015

 

2014

 

Acreage

 

 

 

 

 

 

 

 

 

Net undeveloped acres

 

146,096 

(1)

 

174,826 

 

 

205,491 

 

Net developed acres

 

99,709 

 

 

95,509 

 

 

60,582 

 

Total net acres

 

245,805 

 

 

270,335 

 

 

266,073 

 



 

 

 

 

 

 

 

 

 

Net Production (Bcf)

 

350 

 

 

360 

 

 

254 

 



 

 

 

 

 

 

 

 

 

Reserves

 

 

 

 

 

 

 

 

 

Reserves (Bcf)

 

1,574 

 

 

2,319 

 

 

3,192 

 

Locations:

 

 

 

 

 

 

 

 

 

Proved developed

 

820 

 

 

767 

 

 

524 

 

Proved developed non-producing

 

39 

 

 

23 

 

 

13 

 

Proved undeveloped

 

 

 

36 

 

 

200 

 

Total locations

 

861 

 

 

826 

 

 

737 

 



 

 

 

 

 

 

 

 

 

Gross Operated Well Count Summary

 

 

 

 

 

 

 

 

 

Spud or acquired

 

32 

 

 

177 

(2)

 

106 

(3)

Completed

 

33 

 

 

92 

 

 

104 

 

Wells to sales

 

24 

 

 

100 

 

 

88 

 



 

 

 

 

 

 

 

 

 

Capital Investments (in millions)

 

 

 

 

 

 

 

 

 

Exploratory and development drilling, including workovers

$

160 

 

$

472 

 

$

571 

 

Acquisition and leasehold

 

 

 

172 

 

 

28 

 

Seismic and other

 

 

 

 

 

30 

 

Capitalized interest and expense

 

39 

 

 

58 

 

 

66 

 

Total capital investments

$

204 

 

$

710 

 

$

695 

 



 

 

 

 

 

 

 

 

 

Average completed well cost (in millions)

$

5.3 

 

$

5.4 

 

$

6.1 

 

Average lateral length (feet)

 

6,142 

 

 

5,403 

 

 

4,752 

 



(1)    Our undeveloped acreage position as of December 31, 2016 had an average royalty interest of 14% and was obtained at an average cost of approximately $1,127 per acre.

(2)    Includes 86 horizontal and 2 vertical acquired wells.

(3)    Includes 5 horizontal and 2 vertical acquired wells.



In 2016, our reserves in Northeast Appalachia decreased by 745 Bcf, which included net downward price revisions of 794 Bcf and production of 350 Bcf, partially offset by net upward performance revisions of 318 Bcf and additions of 81 Bcf.

 

Our ability to bring our Northeast Appalachia production to market depends 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” in Item 1 of Part I of this Annual Report for a discussion of our gathering and transportation arrangements for Northeast Appalachia production.



10

 


 

Southwest Appalachia



In late 2014 and early 2015, we closed two transactions to acquire natural gas and oil assets in West Virginia and southwest Pennsylvania for approximately $5.4 billion. This acreage has at least three drilling objectives, namely the Marcellus, Utica and Upper Devonian Shales.  In 2016 we disposed of a portion of this acreage that we did not expect to drill for several years.  As of December 31, 2016, we had approximately 321,563 net acres in Southwest Appalachia and had a total of 299 horizontal and 4 vertical wells that we operated and that were on production.  Southwest Appalachia represents 17% of our total net production and 13% of our total reserves as of December 31, 2016.  Below is a summary of Southwest Appalachia’s operating results for the last three years:







 

 

 

 

 

 

 

 

 



For the years ended December 31,

 



2016

 

2015

 

2014

 

Acreage

 

 

 

 

 

 

 

 

 

Net undeveloped acres

 

161,607 

(1)

 

193,582 

 

 

188,244 

 

Net developed acres

 

159,956 

 

 

231,516 

 

 

225,132 

 

Total net acres

 

321,563 

 

 

425,098 

 

 

413,376 

 



 

 

 

 

 

 

 

 

 

Net Production (Bcfe)

 

148 

 

 

143 

 

 

 



 

 

 

 

 

 

 

 

 

Reserves

 

 

 

 

 

 

 

 

 

Reserves (Bcfe)

 

677 

 

 

611 

 

 

2,297 

 

Locations:

 

 

 

 

 

 

 

 

 

Proved developed

 

306 

(2)

 

1,028 

 

 

1,034 

 

Proved developed non-producing

 

44 

(2)

 

400 

 

 

124 

 

Proved undeveloped

 

–  

 

 

 

 

344 

 

Total locations

 

350 

(2)

 

1,429 

 

 

1,502 

 



 

 

 

 

 

 

 

 

 

Gross Operated Well Count Summary

 

 

 

 

 

 

 

 

 

Spud or acquired

 

17 

 

 

48 

 

 

1,334 

(3)

Completed

 

17 

 

 

38 

 

 

–  

 

Wells to sales

 

18 

 

 

47 

 

 

–  

 



 

 

 

 

 

 

 

 

 

Capital Investments (in millions)

 

 

 

 

 

 

 

 

 

Exploratory and development drilling, including workovers

$

111 

 

$

248 

 

$

 

Acquisition and leasehold

 

18 

 

 

409 

 

 

5,007 

 

Seismic and other

 

 

 

 

 

–  

 

Capitalized interest and expense

 

158 

 

 

198 

 

 

 

Total capital investments

$

288 

 

$

857 

 

$

5,012 

 



 

 

 

 

 

 

 

 

 

Average completed well cost (in millions)  (4)

$

6.5 

 

$

6.9 

 

$

–  

 

Average lateral length (feet) (4)

 

5,499 

 

 

6,985 

 

 

–  

 



(1)    Our undeveloped acreage position as of December 31, 2016 had an average royalty interest of 14%.

(2)    Includes the impact of legacy assets divested in 2016.

(3)    Includes 323 horizontal and 1,011 vertical wells acquired in CHK and STO acquisitions.

(4)    Includes wells only drilled by SWN.



In 2016, our reserves in Southwest Appalachia increased by 66 Bcfe, which included 199 Bcfe of net upward performance revisions and additions of 157 Bcfe, partially offset by production of 148 Bcfe, net downward price revisions of 127 Bcfe and dispositions of 15 Bcfe.  

 

Our ability to bring our Southwest Appalachia 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” within Item 1 of Part I of this Annual Report for a discussion of our gathering and transportation arrangements for Southwest Appalachia production.



11

 


 

Fayetteville Shale



As of December 31, 2016, we held leases for approximately 918,535 net acres in the Fayetteville Shale, an unconventional gas reservoir located on the Arkansas side of the Arkoma Basin, and had spud a total of 4,741 wells in the play since our commencement of activities there in 2004, of which 4,161 were operated by us and 580 were outside-operated wells.  At year-end 2016, 4,037 wells operated by the Company had been drilled and completed overall, including 3,946 horizontal wells.  The Fayetteville Shale represents 43% of our total net production and 57% of our total reserves as of December 31, 2016.  Below is a summary of the Fayetteville Shale’s operating results for the last three years:

   





 

 

 

 

 

 

 

 

 



For the years ended December 31,

 



2016

 

2015

 

2014

 

Acreage

 

 

 

 

 

 

 

 

 

Net undeveloped acres (2)

 

285,692 

(1)

 

288,569 

 

 

267,888 

 

Net developed acres (3)

 

632,843 

 

 

669,072 

 

 

620,273 

 

Total net acres

 

918,535 

 

 

957,641 

 

 

888,161 

 



 

 

 

 

 

 

 

 

 

Net Production (Bcf)

 

375 

 

 

465 

 

 

494 

 



 

 

 

 

 

 

 

 

 

Reserves

 

 

 

 

 

 

 

 

 

Reserves (Bcf)

 

2,997 

 

 

3,281 

 

 

5,069 

 

Locations:

 

 

 

 

 

 

 

 

 

Proved developed

 

4,217 

 

 

4,268 

 

 

4,045 

 

Proved developed non-producing

 

311 

 

 

231 

 

 

187 

 

Proved undeveloped

 

13 

 

 

61 

 

 

1,213 

 

Total locations

 

4,541 

 

 

4,560 

 

 

5,445 

 



 

 

 

 

 

 

 

 

 

Gross Operated Well Count Summary

 

 

 

 

 

 

 

 

 

Spud or acquired

 

 

 

155 

 

 

465 

 

Completed

 

34 

 

 

262 

 

 

458 

 

Wells to sales

 

43 

 

 

260 

 

 

455 

 



 

 

 

 

 

 

 

 

 

Capital Investments (in millions)

 

 

 

 

 

 

 

 

 

Exploratory and development drilling, including workovers

$

63 

 

$

484 

 

$

838 

 

Acquisition and leasehold

 

 

 

 

 

 

Seismic and other

 

  

 

 

 

 

 

Capitalized interest and expense

 

21 

 

 

69 

 

 

95 

 

Total capital investments

$

86 

 

$

565 

 

$

944 

 



 

 

 

 

 

 

 

 

 

Average completed well cost (in millions)

$

3.2 

 

$

2.8 

 

$

2.6 

 

Average lateral length (feet)

 

5,717 

 

 

5,729 

 

 

5,440 

 



(1)

Our undeveloped acreage position as of December 31, 2016 had an average royalty interest of 13% and was obtained at an average cost of approximately $335 per acre.

(2)

Includes 86,631, 31,413 and 432 net undeveloped acres in the Arkoma Basin that have been previously reported as a component of our conventional Arkoma acreage as of December 31, 2016, 2015 and 2014, respectively.  We sold our conventional Arkoma properties in 2015 but retained the acreage located within the Fayetteville Shale area.

(3)

Includes 141,025, 170,743 and 123,442 net developed acres in the Arkoma Basin that have been previously reported as a component of our conventional Arkoma acreage as of December 31, 2016, 2015 and 2014, respectively.  We sold our conventional Arkoma properties in 2015 but retained the acreage located within the Fayetteville Shale area.



In 2016, our reserves in the Fayetteville Shale decreased by 284 Bcf, which included production of 375 Bcf and net downward price revisions of 116 Bcf, partially offset by 163 Bcf of net upward revisions due to well performance and reserve additions of 44 Bcf



Of the acreage we hold in the Fayetteville Shale, the Ozark Highlands Unit accounts for 158,231 acres and lies entirely within the Ozark National Forest.  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.  Although we are 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 158,231 acres we have leased in the unit and the national forest.  At year-end 2016, after excluding our acreage in the conventional Arkoma Basin and the federal acreage we hold in the Ozark Highlands Unit, approximately 87% of our 532,648 total net leasehold acres remaining in the Fayetteville Shale was held by production.  For more information about our acreage and well count,

12

 


 

we refer you to “Properties” in Item 2 of Part I of this Annual Report.  We refer you to the risk factor “Certain of our undeveloped assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage” in Item 1A of Part I of this Annual Report.



Other



As of December 31, 2016, we held 3,010,908 net undeveloped acres for the potential development of new resources, of which 2,518,519 net acres were located in New Brunswick, Canada.  This compares to 3,661,375 net undeveloped acres held at year-end 2015 and 4,170,687 net undeveloped acres held at year-end 2014.



We limited our activities in areas beyond our assets in the Appalachian Basin and the Fayetteville Shale during 2016 and 2015 as a result of the commodity price environment as we focused on these more proven development plays.  There can be no assurance that any prospects outside of our development plays will result in viable projects or that we will not abandon our initial investments. 



Sand Wash Basin. In 2014, we acquired acreage in northwest Colorado targeting crude oil, NGLs and natural gas contained in the Sand Wash Basin, with the target zone ranging in vertical depth from 6,500 to 12,500 feet.  Our leases currently have an approximate 83% average net revenue interest.  As of December 31, 2016, we held approximately 127,943 net acres in the area.

 

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 8,500 to 11,400 feet and appears to be laterally extensive over a large area ranging in thickness from 450 to 700 feet.  As of December 31, 2016, we held approximately 146,677 net acres in the area, obtained at an average cost of $466 per acre.  Our leases currently have an approximate 80% average net revenue interest.  As of December 31, 2016, we had drilled 14 operated wells in the area, 6 of which were currently producing.



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 2,518,519 net acres in the province in order to test new hydrocarbon basins.  In 2015, the provincial government in New Brunswick imposed a moratorium on hydraulic fracturing until it is satisfied with a list of conditions.  In response to this moratorium, the Company requested and was granted an extension of its licenses to March 2021.  In May 2016, the provincial government announced that the moratorium would continue indefinitely.  Unless and until the moratorium is lifted, we will not be able to develop these assets.  Given this development, we recognized an impairment of $39 million, net of tax, associated with our investment in New Brunswick in the second quarter of 2016.



Acquisitions and Divestitures



In September 2016, the Company sold approximately 55,000 net acres in West Virginia for approximately $422 million, subject to customary post-closing adjustments.  As of December 2015, these assets included approximately 11 Bcfe of proved reserves.



In May 2015, the Company sold conventional oil and gas assets located in East Texas and the Arkoma Basin for approximately $211 million.  As of December 2014, these assets included approximately 184 Bcf of proved reserves.



In April 2015, the Company sold its gathering assets located in Bradford and Lycoming counties in northeast Pennsylvania for approximately $489 million.  The assets included approximately 100 miles of natural gas gathering pipelines with nearly 600 million cubic feet per day of capacity. 



In January 2015, we acquired approximately 46,700 net acres in northeast Pennsylvania for $270 million. As part of this transaction, we also received firm transportation capacity of 260 million cubic feet per day predominately on the Millennium pipeline.



In December 2014, we acquired approximately 413,000 net acres in West Virginia and southwest Pennsylvania with plans to target the Marcellus, Utica and Upper Devonian Shales for approximately $5.0 billion.  Additionally, in January 2015, we acquired an additional approximate 30,000 net acres in this area for $357 million.    



13

 


 

Capital Investments



During 2016, we invested a total of approximately $623 million in our E&P business, including $239 million in capital interest and expenses.  In 2016, we spudded 53 wells, completed 84 wells, placed 85 wells to sales and had 135 wells in progress at year-end.  Of the 135 wells in progress at year-end, 73,  42 and 20 were located in our Northeast Appalachia, Southwest Appalachia and Fayetteville Shale operating areas, respectively, and 35 of these wells are waiting on pipeline or production facilities.    





 

 

 

 

 

 

 

 



For the years ended December 31,



2016

 

2015

 

2014



 

 

(in millions)

 

 

E&P Capital Investments by Type

 

 

 

 

 

 

 

 

Exploratory and development drilling, including workovers

$

358 

 

$

1,226 

 

$

1,514 

Acquisition and leasehold

 

23 

 

 

607 

 

 

5,328 

Seismic expenditures

 

 

 

 

 

56 

Drilling rigs, sand facility and other

 

 

 

40 

 

 

116 

Capitalized interest and other expenses

 

239 

 

 

379 

 

 

240 

Total E&P capital investments

$

623 

 

$

2,258 

 

$

7,254 



 

 

 

 

 

 

 

 

E&P Capital Investments by Area

 

 

 

 

 

 

 

 

Northeast Appalachia

$

165 

 

$

652 

 

$

629 

Southwest Appalachia

 

130 

 

 

659 

 

 

5,010 

Fayetteville Shale

 

65 

 

 

496 

  

 

849 

Other

 

24 

 

 

72 

 

 

526 

Capitalized interest and other expenses

 

239 

 

 

379 

 

 

240 

Total E&P capital investments

$

623 

 

$

2,258 

 

$

7,254 



We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Investments” within Item 7 of Part II of this Annual Report for additional discussion of the factors that could impact our planned capital investments in 2017.



Sales, Delivery Commitments and Customers



Sales. Our daily natural gas equivalent production averaged 2,391 MMcfe in 2016, compared to 2,675 MMcfe in 2015 and 2,105 MMcfe in 2014.  Total natural gas equivalent production was 875 Bcfe in 2016, down from 976 Bcfe in 2015 and up from 768 Bcfe in 2014.  Our natural gas production was 788 Bcf in 2016, compared to 899 Bcf in 2015 and 766 Bcf in 2014.  The decrease in production in 2016 resulted primarily from normal declines in production from existing wells that were not fully offset by production from new wells, given our reduced drilling activities.  In particular, we experienced a 90 Bcf decrease in net production from our Fayetteville Shale properties,  a  10 Bcf decrease in net production from our Northeast Appalachia properties and a 6 Bcfe decrease in other properties, which was partially offset by a 5 Bcfe increase in net production from our Southwest Appalachia properties.  The increase in production in 2015 resulted primarily from a 106 Bcf increase in net production from our Northeast Appalachia properties and a 140 Bcfe increase in net production from our Southwest Appalachia properties, which more than offset a 29 Bcf decrease in net production from our Fayetteville Shale properties and a combined 9 Bcfe decrease in net production from our East Texas and Arkoma Basin properties, which were divested in the first half of 2015.  We produced 2,192 MBbls of oil in 2016, compared to 2,265 MBbls of oil in 2015 and 235 MBbls of oil in 2014.  Our oil production has increased from 2014 levels primarily due to the acquisition of natural gas and oil properties in Southwest Appalachia in December 2014.  In 2016, we produced 12,372 MBbls of NGLs, compared to 10,702 MBbls and 231 MBbls of NGLs in 2015 and 2014, respectively, primarily due to the December 2014 acquisition of natural gas and oil properties in Southwest Appalachia.



Sales of natural gas, oil and NGL 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 regularly enter into various derivative and other financial arrangements with respect to a portion of our projected natural gas 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, 2016, we had New York Mercantile Exchange, or NYMEX, commodity price derivatives in place on 560 Bcf, 240 Bcf and 62 Bcf of our targeted 2017, 2018 and 2019 natural gas production, respectively.  We also had commodity derivatives in places on 365 MBbls of our targeted ethane production for 2017 through 2018.  As of February 21, 2017, we had NYMEX commodity price derivatives in place on 515 Bcf, 272 Bcf and 80 Bcf of our targeted 2017, 2018 and 2019 natural gas production, respectively.  We intend to financially protect pricing on a large portion of expected future production volumes designed to assure certain desired levels

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of cash flow.  We refer you to Item 7A of Part II of this Annual Report, “Quantitative and Qualitative Disclosures about Market Risks,” for further information regarding our derivatives and risk management as of December 31, 2016.



Including the effect of settled derivatives, we realized an average price of $1.64 per Mcf for our natural gas production in 2016, compared to $2.37 per Mcf in 2015 and $3.72 per Mcf in 2014. Our derivative activities increased our average realized natural gas sales price by $0.05 per Mcf in 2016, compared to an increase of $0.46 per Mcf in 2015 and a decrease of $0.02 per Mcf in 2014.  Our average oil price realized was $31.20 per barrel in 2016, compared to $33.25 per barrel in 2015 and $79.91 per barrel in 2014. Our average realized NGL price was $7.46 per barrel in 2016, compared to $6.80 per barrel in 2015 and $15.72 per barrel in 2014.  We did not use derivatives to financially protect our 2016, 2015 or 2014 oil and NGL production.



During 2016, the average price we received for our natural gas production, excluding the impact of derivatives, was approximately $0.87 per Mcf lower than average NYMEX prices.  Differences between NYMEX and price realized are due primarily to locational differences and transportation cost. As of December 31, 2016, we have partially mitigated the volatility of basis differentials by protecting basis on approximately 277 Bcf and 78 Bcf of our expected 2017 and 2018 natural gas production, respectively, through physical sales arrangements and financial derivatives at a basis differential to NYMEX natural gas prices of approximately ($0.50) per Mcf and ($0.34) per Mcf for 2017 and 2018, respectively.  We refer you to Note 4 to our consolidated financial statements for additional discussion about our derivatives and risk management activities.



Delivery Commitments. As of December 31, 2016, we had natural gas delivery commitments of 394 Bcf in 2017 and 126 Bcf in 2018 under existing agreements. These amounts are well below our expected 2017 natural gas production from our Northeast Appalachia, Southwest Appalachia and Fayetteville Shale divisions and expected 2018 production from our available reserves, 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” of Part I of this Annual Report.  We expect to be able to fulfill all of our short-term and 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, 2016, 2015 and 2014, no single third-party purchaser accounted for 10% or more of our consolidated revenues.



Competition



All phases of the natural gas and oil 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, its gathering and transportation (whether we are shipping or operate the transmission facilities) 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, individual producers and operators and developers of gathering and transportation systems.  Many of these competitors have financial and other resources that substantially exceed those available to us. Consequently, we will encounter competition that may affect both the price we receive and contract terms we must offer. We also face competition in accessing pipeline and other services to transport our product to market, particularly in the northeastern United States, where potential production levels exceed currently available capacity.



We cannot predict whether and to what extent any market reforms initiated by the Federal Energy Regulatory Commission, or the FERC, or any new energy legislation or regulations will achieve the goal of increasing competition, lessening preferential treatment and enhancing transparency in markets in which our natural gas production is sold.  Similarly, we cannot predict whether legal constraints that have hindered the development of new transportation infrastructure, particularly in the northeastern United States, will continue.  However, we do not believe that we will be disproportionately affected as compared to other natural gas and oil producers and marketers by any action taken by the FERC or any other legislative or regulatory body or the status of the development of transportation facilities.



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Regulation



Producing natural gas and oil resources and transporting and selling 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 government zoning and land use regulations may also limit the locations for drilling and production.  Similar regulations can also 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.  In December 2015, the federal government repealed a 40-year ban on the export of crude oil.  The export of natural gas continues to require federal permits.  Broader freedom to export could lead to higher prices.  In addition, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) and the rules that the U.S. Commodity Futures Trading Commission, or the CFTC, the SEC, and certain other regulators have issued thereunder regulate certain swaps, futures, and options contracts in the major energy markets, including for natural gas and oil.

 

Producing and transporting natural gas and oil is also subject to extensive environmental regulation.  We refer you to “Other — Environmental Regulation” in Item 1 of Part 1 of this Annual Report and the risk factor “We are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities” in Item 1A of Part I of this Annual Report for a discussion of the impact of environmental regulation on our business.



Midstream Services



Our Midstream Services segment complements our E&P initiatives and, in some areas, competes 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, oil and NGLs.  Our gathering assets support our E&P operations and are currently concentrated in the Fayetteville Shale in Arkansas since the sale of our gathering assets in northeast Pennsylvania and Texas in 2015



Our operating income from this segment was $209 million on revenues of $2.6 billion in 2016, compared to $583 million on revenues of $3.1 billion in 2015 and $361 million on revenues of $4.4 billion in 2014Operating income in 2015 includes a $277 million net gain related to the sale of our northeast Pennsylvania and East Texas gathering assets.  Excluding the gain on sales, operating income decreased $97 million in 2016 primarily due to a decrease in volumes gathered, resulting from lower production volumes in the Fayetteville Shale and the sale of our northeast Pennsylvania and East Texas gathering assets in 2015. Revenues decreased in 2016 primarily due to a decrease in the price received for volumes marketed, a decrease in volumes marketed and a decrease in volumes gathered.  Excluding the gains on sales, operating income decreased to $306 million in 2015 primarily due to a decrease in volumes gathered resulting from lower production volumes in the Fayetteville Shale and the sale of our northeast Pennsylvania gathering assets in 2015.   Revenues decreased in 2015 from 2014 levels primarily due to the prices received for volumes marketed. Cash flow from operations generated by our Midstream Services segment was $222 million in 2016, compared to $540 million in 2015 and $172 million in 2014.  The decrease in 2016 was primarily due to decreased revenues, partially offset by a decrease in operating costs and expenses.  During the years ended December 31, 2016, 2015 and 2014, no single third-party customer in our Midstream Services segment accounted for 10% or more of our consolidated revenues.



Gas Gathering



Currently, our gas gathering activities are located predominantly in Arkansas and are related to the operation of our Fayetteville Shale asset.  We invested approximately $21 million related to our gathering activities in 2016 and had gathering revenues of $378 million, compared to $58 million invested and revenues of $491 million in 2015 and $144 million invested and revenues of $562 million in 2014.  During 2015, we divested our gathering assets in northeast Pennsylvania and East Texas. The divested gathering assets accounted for $21 million and $67 million of our gathering revenues for the years ended December 31, 2015 and 2014, respectively.  



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In 2016, we gathered approximately 600 Bcf of natural gas in the Fayetteville Shale area, including 42 Bcf of natural gas from third-party operated wells.  During 2015, we gathered approximately 750 Bcf of natural gas in the Fayetteville Shale area, including 55 Bcf of natural gas from third-party operated wells.  In 2014, we gathered approximately 812 Bcf of natural gas volumes in the Fayetteville Shale area, including 62 Bcf of natural gas from third-party operated wells.  At the end of 2016, we had approximately 2,045 miles of pipe from the individual wellheads to the transmission lines and compression equipment representing in aggregate approximately 477,095 horsepower had been installed at 58 central point gathering facilities in the Fayetteville Shale. 



Marketing



We attempt to capture opportunities related to the marketing and transportation of natural gas, oil and NGLs primarily involving the marketing of our own natural gas production and that of royalty owners in our wells.  Additionally, we manage portfolio and basis risk, acquire transportation rights on third-party pipelines and in limited circumstances, purchase third-party natural gas to fulfill commitments specific to a geographic location.  During 2016, we marketed 1,062 Bcfe, compared to 1,127 Bcfe in 2015 and 904 Bcf in 2014.  Of the total gas volumes marketed, production from our affiliated E&P operations accounted for 93% in 2016, compared to 97% in 2015 and 2014.  Our Midstream Services segment also marketed approximately 65% of our combined oil and NGL production for the year ended December 31, 2016, compared to 60% in 2015.



Northeast Appalachia



In January 2015, we completed the purchase of certain natural gas and oil assets in northeast Pennsylvania and assumed short and long-term natural gas transportation agreements with Millennium Pipeline Company, L.L.C. with a total capacity of approximately 260,000 Mcf per day.



In January 2014, we entered into a precedent agreement with Transcontinental Gas Pipeline Company LLC that will provide additional firm transportation capacity for supplies of natural gas from northern Pennsylvania to markets along the Transco pipeline system stretching from the northeastern US in Transco’s Zone 6, to Zone 5 and terminating in Zone 4.  Subject to the receipt of regulatory approvals and satisfaction of other conditions, we agreed to enter a 15-year firm transportation agreement with a total capacity of approximately 44,000 Mcf per day on this project which is expected to be in service by mid-2018.



In May 2013, we entered into a precedent agreement with Columbia Gas Transmission, LLC for a project that expanded their existing system from Chester County, Pennsylvania to various interconnects throughout Pennsylvania, New Jersey, Maryland, and Virginia.  Our volume on this project, which was placed in service October 2015, is 72,000 Mcf per day.

  

In March 2012, we 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, we agreed to enter a 15-year firm transportation agreement with a total capacity of approximately 150,000 Mcf per day on this project.  Constitution Pipeline Co. LLC has extended the range for the pipeline’s target in-service date to late 2018 as a result of a longer than expected regulatory and permitting process.



During 2011 and 2012, we entered into a number of short- and long-term firm transportation service agreements in support of our growing Northeast Appalachia operations in Pennsylvania. In March 2011, we entered into a precedent agreement with Millennium Pipeline Company, L.L.C. pursuant to which we entered 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 and the second quarter of 2014.



We have also 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 Northeast Appalachia 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 we have subscribed for approximately 100,000 Mcf per day of capacity.  TGP’s expansion project will expand its 300 Line in Pennsylvania to provide natural gas transportation from the Northeast Appalachia supply area to existing delivery points on the TGP system. 



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Southwest Appalachia



As part of our December 2014 acquisition of natural gas and oil assets in West Virginia and southwest Pennsylvania, we were assigned approximately 92,000 Mcf per day of capacity on the Columbia Gas Transmission pipeline, which was later reduced to 76,900 Mcf per day as a result of the sale of a portion of our West Virginia assets.  Additionally, we were assigned a precedent agreement with ET Rover Pipeline LLC for approximately 200,000 Mcf per day of capacity.  ET Rover Pipeline LLC is constructing a new interstate pipeline to receive and transport natural gas from Marcellus and Utica production outlets to points of interconnection with Panhandle Eastern Pipe Line Company and ANR Pipeline, to interconnections in Michigan, to the Union Gas Dawn Hub and to certain off-system delivery points on Trunkline Zone 1A, and is anticipated to be in service by mid to late 2017.



In December 2014, we also were assigned certain ethane transportation agreements that allow for the transport of our ethane production to both domestic and international markets.



In March 2015, we entered into a precedent agreement with Columbia Pipeline Group, Inc. that secured capacity of 500,000 Mcf per day on the Mountaineer XPress pipeline, with a portion of these volumes going to the Gulf Coast on the Gulf Xpress pipeline.  The project is expected to be in service by late 2018 and will be routed through much of our core Southwest Appalachia acreage located in West Virginia.



At December 31, 2016, we had 475,000 Mcf per day of firm processing capacity with multiple processing providers located near our core acreage position in West Virginia.  In the future, we have the option to increase our firm processing capacity by exercising options for the construction of incremental processing trains, the use of interruptible processing capacity, or consummating new processing agreements with new or existing service providers.



Fayetteville Shale



We are 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.  We have a maximum aggregate commitment of approximately 1,200,000 Mcf 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.  We have maximum aggregate commitments of approximately 800,000 Mcf per day on the Fayetteville Lateral and 640,000 Mcf per day on the Greenville Lateral, with initial terms ending in 2019 and 2020, respectively.



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 premium Gulf Coast and southeastern United States markets.  These interconnecting pipelines include Natural Gas Pipeline, Mississippi River Transmission, 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.



Demand Charges



As of December 31, 2016, our obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $8.4 billion, $3.4 billion of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. We also have guarantee obligations of up to $862 million of that amount. 



We refer you to Note 8,  “Commitments and Contingencies” in the consolidated financial statements for further details on our demand charges and the risk factor “We have made significant investments in pipelines and gathering systems and contracts and in oilfield service businesses, including our drilling rigs, 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” in Item 1A of Part I of this Annual Report.



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Competition



Our 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 of natural gas and oil are heavily regulated.  Interstate pipelines must obtain authorization from 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 pipelines we own 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.



The transportation of natural gas and oil is also subject to extensive environmental regulation.  We refer you to “Other – Environmental Regulation” in Item 1 of Part I of this Annual Report and the risk factor “We are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities” in Item 1A of Part I of this Annual Report for a discussion of the impact of environmental regulation on our business.



Other



Our other operations have historically consisted of limited real estate development activities and a natural gas vehicles (“NGV”) fueling station in Damascus, Arkansas, which was sold in May 2016.  We currently have no significant business activity outside of our E&P and Midstream Services segments.



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 may result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements.  We do not expect continued compliance with existing requirements to have a material adverse impact on us, but there can be no assurance that this will continue in the future.  



The following is a summary of the more significant existing environmental and worker health and safety laws and regulations to which we are subject.



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

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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, legislative and regulatory initiatives have been considered 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 measures were to be enacted, it could have a significant impact on our operating costs.  Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.



The Clean Water Act, as amended, or CWA, and analogous state laws, impose restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into regulated waters.  Permits must be obtained to discharge pollutants to regulated waters and to conduct construction activities in waters and wetlands. The CWA 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.  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.



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 regulated 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 2016 oil accounted for 2% of our total production, compared to less than 1% of our total production for 2015 and 2014, although we expect this percentage to increase as we continue to develop our Southwest Appalachia assets.



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 for and production of natural gas and oil.  Although we have utilized operating and disposal 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 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 into 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 Endangered Species Act and comparable state laws protect species threatened with possible extinction.  Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining drilling and other permits and may include restrictions on road building and other activities in areas containing the affected species or their habitats.  Based on the species that have been identified to date, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our operations at this time.



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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 Northeast Appalachia are being utilized in our other operating areas, including Southwest Appalachia, the Sand Wash Basin and 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 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 federal agencies have started to assert regulatory authority over certain aspects of the process.  For example, the Environmental Protection Agency, or 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.  In May 2016, the EPA finalized additional regulations to control methane and volatile organic compound emissions from certain oil and gas equipment and operations.  The EPA also recently finalized pretreatment standards that would prohibit the indirect discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned treatment works.  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.

In addition, there are 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.  For example, in December 2016, the EPA released its final report regarding the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances such as water withdrawals for fracturing in times or areas of low water availability, surface spills during the management of fracturing fluids, chemicals or produced water, injection of fracturing fluids into wells with inadequate mechanical integrity, injection of fracturing fluids directly into groundwater resources, discharge of inadequately treated fracturing wastewater to surface waters and disposal or storage of fracturing wastewater in unlined pits.  The results of these studies could lead federal and state governments and agencies to develop and implement additional regulations.

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 2015, the provincial government in New Brunswick announced a moratorium on hydraulic fracturing until it is satisfied with a list of conditions.  In May 2016, the provincial government announced that the moratorium would continue in effect indefinitely.  Unless and until the moratorium is lifted, we will not be able to continue our activities on our assets in New Brunswick.



Increased regulation and attention given to the hydraulic fracturing process has led 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 “We are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities” in Item 1A of Part I of this Annual Report.



In addition, concerns have been raised about the potential for earthquakes to occur from the use of underground injection control wells, a predominant method for disposing of waste water from oil and gas activities.  We operate injection wells and utilize injection wells owned by third parties to dispose of waste water associated with our operations, subject to regulatory restrictions relating to seismicity.   New rules and regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in others.

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Greenhouse Gas Emissions.  In response to findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources.  Facilities required to obtain PSD permits for their greenhouse gas emissions also will be required to meet “best available control technology” standards that will be established on a case-by case basis.  One of our subsidiaries operates compressor stations, which are facilities that are required to adhere to the PSD or Title V permit requirements.  EPA rulemakings related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

The EPA also has adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations.  Although Congress from time to time has considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years.  In the absence of such federal climate legislation, a number of states, including states in which we operate, have enacted or passed measures to track and reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and regional greenhouse gas cap-and-trade programs.  Most of these cap-and-trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved.  These reductions may cause the cost of allowances to escalate significantly over time.

The adoption and implementation of regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions or install new equipment to reduce emissions of greenhouse gases associated with our operations.  In addition, these regulatory initiatives could drive down demand for our products by stimulating demand for alternative forms of energy that do not rely on combustion of fossil fuels that serve as a major source of greenhouse gas emissions, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.  At the same time, new laws and regulations are prompting power producers to shift from coal to natural gas, which is increasing demand.

Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions.  The agreement entered into effect in November 2016 after more than 70 nations, including the United States, ratified or otherwise indicated their intent to be bound by the agreement.  To the extent that the United States and other countries implement this agreement or impose other climate change regulations on the oil and gas industry, it could have an adverse effect on our business.



Employee health and safety. Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.



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 drilling and development activities in New Brunswick, we will be subject to federal, provincial and local environmental regulations.



Employees



As of December 31, 2016, we had 1,469 total employeesNone of our employees were covered by a collective bargaining agreement at year-end 2016.  We believe that our relationships with our employees are good.



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Executive Officers of the Registrant





 

 

Name

Age (1)

Officer Position

William J. Way

57

President and Chief Executive Officer

Mark K. Boling

59

Executive Vice President and President V+ Development Solutions

R. Craig Owen

47

Senior Vice President and Chief Financial Officer

Jennifer N. McCauley

53

Senior Vice President – Administration

John C. Ale

62

Senior Vice President, General Counsel and Secretary

John E. Bergeron, Jr.

59

Senior Vice President – E&P Operations

Paul W. Geiger III

45

Senior Vice President – Corporate Development

Randy L. Curry

59

Senior Vice President – Midstream

James W. Vick

55

Senior Vice President – Business Information Systems

C. Greg Stoute

55

Vice President – Health, Safety, Environmental and Regulatory



(1)

As of February 21, 2017



Mr. Way was appointed Chief Executive Officer in January 2016.  Prior to that, he served as Chief Operating Officer since 2011, having also been appointed President in December 2014.  Prior to joining the Company, he was Senior Vice President, Americas of BG Group plc with responsibility for E&P, Midstream and LNG operations in the United States, Trinidad and Tobago, Chile, Bolivia, Canada and Argentina since 2007.



Mr. Boling was appointed Executive Vice President and President, V+ Development Solutions in December 2012.  Prior to that, he served as Senior Vice President, General Counsel and Secretary since January 2002.



Mr. Owen was appointed Senior Vice President in May 2012 and Chief Financial Officer in October 2012.  Prior to October 2012, he served as Controller since 2008.



Ms. McCauley was appointed Senior Vice President – Administration in April 2016.  Prior to that, she served as Senior Vice President – Human Resources since 2009.



Mr. Ale was appointed Senior Vice President, General Counsel and Secretary in November 2013.  Prior to that, he was Vice President and General Counsel of Occidental Petroleum Corporation since April 2012.  Prior to that, he was a partner with Skadden, Arps, Slate, Meagher & Flom LLP since 2002.



Mr. Bergeron was appointed Senior Vice President – E&P in April 2016.  From April 2014 to March 2016, he served as Senior Vice President, Northeast Appalachia Division.  Since joining the Company in 2007, he served as Senior Vice President, Fayetteville Shale Division; Vice President and General Manager, Fayetteville Shale Division; Vice President, Economic Planning and Acquisitions; and as Vice President, Fayetteville Shale Planning and Technology.



Mr. Geiger was appointed Senior Vice President – Corporate Development in April 2016.  Prior to that, he served as Senior Vice President of the West Virginia division in 2015 and of the Fayetteville Shale division since joining the Company in April 2014.  Prior to joining Southwestern Energy Company, Mr. Geiger served as Senior Vice President of Operations at Quantum Resources Management and QR Energy since October 2012.



Mr. Curry as appointed Senior Vice President – Midstream in 2014.  Beginning in January 2003,  he served as President of Chevron Natural Gas. Prior to that, Mr. Curry held various management positions with Chevron’s Global Gas and Midstream organizations.



Mr. Vick was appointed Senior Vice President – Business Information Services in November 2011.  Prior to that he was a Principal with Deloitte Consulting’s Information Management practice.



Mr. Stoute was appointed Vice President of Health, Safety, Environmental and Regulatory in January 2016.  Since joining the Company in 2005 as a senior staff reservoir engineer, he has worked in various leadership positions within SWN and was most recently General Manager for the New Ventures team.



The Company’s officers are elected each year at the first meeting of the Board of Directors following the annual meeting of stockholders, the next of which is expected to occur on May 23, 2017, and hold office until their successors are duly elected and qualified. There are no family relationships between any of the Company’s directors or executive officers.

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GLOSSARY OF CERTAIN INDUSTRY TERMS



The definitions set forth below apply to the indicated terms as used in this Annual Report. All natural gas reserves reported in this Annual Report 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.



Available reserves”  Estimates of the amounts of natural gas, oil and NGLs 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 SECs website.



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 or natural gas liquids 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.



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.



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.



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.



Development costs”   Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing natural gas, oil and NGLs. 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.



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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.



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.



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



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.



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.



Exploitation”   The development of a reservoir to extract its natural 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.



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 SEC’s definition in Rule 4-10(a) (15) of Regulation S-X, a link for which is available at the SEC’s website.



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 SECs definition in Item 1208(c)(1) of Regulation S-K, a link for which is available at the SECs website.



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.



Hydraulic fracturing  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.



Infill drilling”  Drilling wells in between established producing wells to increase recovery of natural gas, oil and NGLs 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.



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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.



Mont Belvieu”  A pricing point for North American NGLs.



Net acres”    The sum, for any area, of the products for each tract of the acres in that tract multiplied by the working interest in that tract.  For additional information, see the SECs definition in Item 1208(c)(2) of Regulation S-K, a link for which is available at the SECs website.



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



Net well  The sum, for all wells being discussed, of the working interests in those wells.    For additional information, see the SECs definition in Item 1208(c)(2) of Regulation S-K, a link for which is available at the SECs website.



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.



Pressure pumping spread”  All of the equipment needed to carry out a hydraulic fracturing job.



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 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.



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 SECs definition in Item 1208(c)(3) of Regulation S-K, a link for which is available at the SEC’s website.



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 natural gas, oil and NGLs that are also developed natural gas, oil and NGL reserves.



Proved oil and gas reserves”   Proved natural gas, oil and NGL reserves are those quantities of natural gas, oil and NGLs, 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,

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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.



Proved reserves”  See “proved natural gas, oil and NGL reserves.”



Proved undeveloped reserves”  Proved natural gas, oil and NGL reserves that are also undeveloped natural gas, oil and NGL reserves.



PV-10”  When used with respect to natural gas, oil and NGL 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.



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



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.



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 SECs definition in Item 1208(c)(4) of Regulation S-K, a link for which is available at the SECs website.



Undeveloped natural gas, oil and NGL reserves”  Undeveloped natural gas, oil and NGL 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.



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



Wells to sales”  Wells that have been placed on sales for the first time.



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.



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

 

ITEM 1A. RISK FACTORS



You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K.  Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.



Natural gas, oil and natural gas liquids prices greatly affect our business, including our revenues, profits, liquidity, growth, ability to repay our debt and the value of our assets.



Our revenues, profitability, liquidity, growth, ability to repay our debt and the value of our assets greatly depend on prices for natural gas, oil and natural gas liquids.  The markets for these commodities have been volatile, and we expect that volatility to continue.  The prices of natural gas, oil and natural gas liquids fluctuate in response to changes in supply and demand (global, regional and local), transportation costs, market uncertainty and other factors that are beyond our control.  Short- and long-term prices are subject to a myriad of factors such as:

•    overall demand, including the relative cost of competing sources of energy or fuel;

•    overall supply, including costs of production;

•    the availability, proximity and capacity of pipelines, other transportation facilities and gathering, processing and storage facilities;

•    regional basis differentials;

•    national and worldwide economic and political conditions;

•    weather conditions and seasonal trends;

•