10-K 1 swn20171231x10k.htm SWN 2017 FORM 10-K 20171231 10K



 

 

 

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, 2017

Commission file number 001-08246



SWN Logo

 

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



 



 

 

 

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, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging Growth Company 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 

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 $3,061,637,340 based on the New York Stock Exchange – Composite Transactions closing price on June 30, 2017 of $6.08. For purposes of this calculation, the registrant has assumed that its directors and executive officers are affiliates.

As of February 27, 2018, the number of outstanding shares of the registrant’s Common Stock, par value $0.01, was 587,063,366

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 22, 2018 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, 2017



TABLE OF CONTENTS



 

Page

PART I

 

 

Item 1.

Business 

3



Glossary of Certain Industry Terms

23

Item 1A.

Risk Factors

28

Item 1B.

Unresolved Staff Comments

39

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

57



Critical Accounting Policies and Estimates

62



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

112

Item 9A.

Controls and Procedures

112

Item 9B.

Other Information

112



 

 

PART III

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

112

Item 11.

Executive Compensation

113

Item 12.

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

113

Item 13.

Certain Relationships and Related Transactions, and Director Independence

113

Item 14.

Principal Accounting Fees and Services

113



 

 

PART IV

 

 

Item 15.

Exhibits, Financial Statement Schedules

113

Item 16.

Summary

113



 

 

EXHIBIT INDEX

 

115







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”, “our”, “us”, “the Company” or “Southwestern”) is an independent energy company engaged in exploration, 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 exclusively in the United States.  Our common stock is listed and traded on the NYSE under the ticker symbol “SWN.”



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 and Damascus, 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:

SWN Formula

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 skills, which we believe will grow long-term value for our shareholders.  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 financial risks.  We budget to invest only from our net cash flow (supplemented in 2017 by a 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. 

·

Exercising Capital Discipline.  We prepare an economic analysis for our drilling programs and other investments based upon the expected net present value added for each dollar to be invested, which we refer to as Present Value Index, or PVI.  We target creating an average of at least a 1.3 PVI in our projects using a 10% discount rate.  Our actual PVI results are utilized to help determine the allocation of our future capital investments and are reflected in our management compensation.  This disciplined investment approach governs our investment decisions at all times, including the current lower-price commodity market.

·

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.

3

 


 

·

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, we developed and operate the largest gathering system in the Fayetteville Shale area and currently are investing in a water transportation project in West Virginia.  We operate drilling rigs and own a sand mine capable of providing 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.

·

Innovative Environmental Solutions and Policy Formation.    We are 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.



In early 2016, we faced significant challenges due to a rapid and dramatic fall in natural gas prices, which reduced our revenues and margins.  We implemented the first phase of strategic initiatives, which were designed to stabilize the Company financially.  We suspended drilling and completion activities, reduced our workforce and revised and extended the maturity of our debt while assuring liquidity to pursue our activities.

When the first phase of these activities was complete, we resumed development activities and entered the next phase, focusing on improving the performance of our large asset portfolio, applying the principles described above.  During 2017, we executed on this part of our business strategy by:

·

Demonstrating financial discipline by investing within our announced plan of cash flow plus the remaining portion of the proceeds from our 2016 equity offering earmarked for this purpose;

·

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

·

Enhancing margins through renegotiation of transportation and processing contracts and expansion of firm pipeline capacity portfolio to maximize realized prices;

·

Improving debt maturity schedule through successful $1.15 billion debt issuance, leaving only $92 million in bonds maturing prior to 2022 and no significant other debt maturities expected before December 2020;

·

Delivering operational excellence with improved well productivity and economics from enhanced completion techniques, initiation of water infrastructure projects, optimization of surface equipment and managing reservoir drawdown; and

·

Significantly expanding our proved reserve quantities across our portfolio through our successful drilling program and improved operational performance as well as improved commodity prices.



In February 2018, we announced the next phase of strategic steps, designed to reposition our portfolio, sharpen our focus on our highest return assets, strengthen our balance sheet and enhance financial performance.  These initiatives include:

·

Actively pursuing strategic alternatives for the Fayetteville Shale E&P and related Midstream gathering assets;

·

Identifying and implementing structural, process and organizational changes to further reduce costs; and

·

Utilizing funds realized from the foregoing to reduce debt, supplement Appalachian Basin development capital, potentially return capital to shareholders, and for general corporate purposes.



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.



4

 


 

 

Exploration and Production



Overview



Our primary business is the exploration for and production of natural gas, oil and NGLs, with our current operations solely within the United States and focused on development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia and Arkansas.  Our operations in northeast Pennsylvania (herein referred to as “Northeast Appalachia”) are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale, our operations in West Virginia and southwest Pennsylvania (herein referred to as “Southwest Appalachia”) are also focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas, oil and NGL reservoirs, 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.  We also have drilling rigs located in Pennsylvania, West Virginia and Arkansas and provide certain oilfield products and services, principally serving our production operations.



·

Our E&P segment recorded operating income of $549 million in 2017, compared to an operating loss of $2.4 billion in 2016.  The operating loss in 2016 was primarily the result of $2.3 billion of non-cash impairments of natural gas and oil properties due to decreased commodity prices.  Excluding the 2016 impairments, our E&P segment operating income increased $632 million in 2017 from 2016 primarily due to a $673 million increase in revenues, partially offset by a $41 million increase in operating expenses due primarily to increased gathering and transportation fees resulting from a shift in our production growth to the Appalachian Basin.



·

Cash flow from operations from our E&P segment was $985 million in 2017, compared to $297 million in 2016.  Our cash flow from operations increased in 2017 as the effects of higher realized prices and increased production volumes more than offset increased operating expenses.



Oilfield Services Vertical Integration



We provide certain 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, water management and movement, and the mining of sand used as proppant for certain of our well completions.



As of December 31, 2017, we had a total of seven re-entry rigs and two leased pressure pumping spreads with a total capacity of approximately 72,000 horsepower.  These services provide us greater flexibility to align our operational activities with commodity prices.  In 2017, we provided drilling services for all of our 134 drilled wells and were able to reduce our drilling costs on average by approximately 11%, as compared to recent years.  In late 2017, we reinitiated our hydraulic fracturing services and are currently utilizing one pressure pumping spread in Southwest Appalachia.  The majority of our wells in 2017 were completed utilizing third-party hydraulic fracturing services who were offering lower costs.



Our Proved Reserves





 

 

 

 

 

 

 

 

 

 

 

 

 



 

For the years ended December 31,



2017

 

2016

 

2015

Proved reserves (Bcfe)

 

14,775 

 

 

5,253 

 

 

6,215 

Prices used

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

$

2.98 

 

$

2.48 

 

$

2.59 

Oil (per Bbl)

$

47.79 

 

$

39.25 

 

$

46.79 

NGL (per Bbl)

$

14.41 

 

$

6.74 

 

$

6.82 



 

 

 

 

 

 

 

 

PV-10:

 

 

 

 

 

 

 

 

Pre-Tax (in millions)

$

5,784 

 

$

1,665 

 

$

2,417 

PV of Taxes (in millions)

 

(222)

 

 

 –  

 

 

–  

After-Tax (in millions)

$

5,562 

 

$

1,665 

 

$

2,417 



 

 

 

 

 

 

 

 

Percent of estimated proved reserves that are:

 

 

 

 

 

 

 

 

Natural gas

 

75% 

 

 

93% 

 

 

95% 

Proved developed

 

54% 

 

 

99% 

 

 

93% 



 

 

 

 

 

 

 

 

Percent of operating revenues generated by natural gas sales

 

85% 

 

 

89% 

 

 

93% 

5

 


 



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.



·

Our reserves increased in 2017, compared to 2016, primarily through extensions, discoveries and other additions in the Appalachian Basin along with increases in both price and performance revisions across our portfolio.



·

The decrease in our reserves in 2016 compared to 2015 was primarily due to downward price revisions, associated with decreased commodity prices, and our production in 2016, partially offset by upward performance revisions in the Appalachian Basin and the Fayetteville Shale. 



·

The increase in our after-tax PV-10 value in 2017 compared to 2016  was primarily due to higher reserve levels, including a significantly larger percentage of oil and NGL reserves.



·

The decrease in our after-tax PV-10 value in 2016 compared to 2015 was primarily due to lower reserve levels.



·

We operate approximately 99% of our reserves, based on the pre-tax PV-10 value of our proved developed producing reserves, and our reserve life index was approximately 16.5 years at year-end 2017.



The difference in after-tax PV-10 and pre-tax PV-10 (a non-GAAP measure which is reconciled in the 2017 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 and 2015 after-tax PV-10 computations did not have future income taxes because our tax basis in the associated natural gas and oil 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.



6

 


 

 

The following table provides an overall and categorical summary of our natural gas, oil and NGL reserves, as of fiscal year-end 2017 based on average fiscal year prices, and our well count, net acreage and PV-10 as of December 31, 2017, and sets forth 2017 annual information related to production and capital investments for each of our operating areas:







 

 

 

 

 

 

 

 

 

 

 

 

 

 

2017 PROVED RESERVES BY CATEGORY AND SUMMARY OPERATING DATA



 

 

 

 

 

 

 

 

 

 

 

 

 

 



Appalachia

 

Fayetteville

 

 

 

 

 



Northeast

 

Southwest

 

Shale

 

Other (1)

 

Total

Estimated Proved Reserves:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas (Bcf):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed (Bcf)

 

3,007 

 

 

833 

 

 

3,135 

 

 

 

 

6,979 

Undeveloped (Bcf)

 

1,119 

 

 

2,484 

 

 

544 

 

 

–  

 

 

4,147 



 

4,126 

 

 

3,317 

 

 

3,679 

 

 

 

 

11,126 

Crude Oil (MMBbls):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed (MMBbls)

 

–  

 

 

14.2 

 

 

–  

 

 

0.3 

 

 

14.5 

Undeveloped (MMBbls)

 

–  

 

 

51.1 

 

 

–  

 

 

–  

 

 

51.1 



 

–  

 

 

65.3 

 

 

–  

 

 

0.3 

 

 

65.6 

Natural Gas Liquids (MMBbls):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed (MMBbls)

 

–  

 

 

141.9 

 

 

–  

 

 

0.3 

 

 

142.2 

Undeveloped (MMBbls)

 

–  

 

 

400.2 

 

 

–  

 

 

–  

 

 

400.2 



 

–  

 

 

542.1 

 

 

–  

 

 

0.3 

 

 

542.4 

Total Proved Reserves (Bcfe) (2):

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Developed (Bcfe)

 

3,007 

 

 

1,770 

 

 

3,135 

 

 

 

 

7,920 

Undeveloped (Bcfe)

 

1,119 

 

 

5,192 

 

 

544 

 

 

–  

 

 

6,855 



 

4,126 

 

 

6,962 

 

 

3,679 

 

 

 

 

14,775 

Percent of Total

 

28% 

 

 

47% 

 

 

25% 

 

 

0% 

 

 

100% 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Percent Proved Developed

 

73% 

 

 

25% 

 

 

85% 

 

 

100% 

 

 

54% 

Percent Proved Undeveloped

 

27% 

 

 

75% 

 

 

15% 

 

 

0% 

 

 

46% 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production (Bcfe)

 

395 

 

 

183 

 

 

316 

 

 

 

 

897 

Capital Investments (in millions) (3)

$

489 

 

$

547 

 

$

114 

 

$

41 

 

$

1,191 

Total Gross Producing Wells (4)

 

983 

 

 

364 

 

 

4,191 

 

 

20 

 

 

5,558 

Total Net Producing Wells (4)

 

516 

 

 

255 

 

 

2,921 

 

 

17 

 

 

3,709 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Net Acreage

 

191,226 

 

 

290,291 

 

 

917,842 

 

 

386,304 

(5)

 

1,785,663 

Net Undeveloped Acreage

 

87,927 

 

 

219,709 

 

 

424,858 

 

 

369,236 

(5)

 

1,101,730 



 

 

 

 

 

 

 

 

 

 

 

 

 

 

PV-10:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pre-Tax (in millions) (6)

$

2,085 

 

$

1,718 

 

$

1,978 

 

$

 

$

5,784 

PV of Taxes (in millions) (6)

 

80 

 

 

66 

 

 

76 

 

 

–  

 

 

222 

After-Tax (in millions) (6)

$

2,005 

 

$

1,652 

 

$

1,902 

 

$

 

$

5,562 

Percent of Total

 

36% 

 

 

30% 

 

 

34% 

 

 

0% 

 

 

100% 

Percent Operated (7)

 

99% 

 

 

100% 

 

 

99% 

 

 

100% 

 

 

99% 



(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 $57 million related to our E&P service companies, of which $37 million related to water infrastructure.

(4)

Represents producing wells, including 400 wells in which we only have an overriding royalty interest in Northeast Appalachia,  used in the December 31, 2017 reserves calculation.

(5)

Excludes exploration licenses for 2,518,519 net acres in New Brunswick, Canada, which have been subject to a moratorium since 2015.

(6)

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.

(7)

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



7

 


 

 

Lease Expirations



The following table summarizes the leasehold expiring over the next three years, assuming successful wells are not drilled to develop the acreage and leases are not extended:





 

 

 

 

 

 



 

For the years ended December 31,

Net acreage expiring:

 

2018

 

2019

 

2020

Northeast Appalachia

 

15,731 

 

10,852 

 

4,953 

Southwest Appalachia (1)

 

12,552 

 

14,247 

 

12,456 

Fayetteville Shale (2)

 

262 

 

859 

 

743 

Other:

 

 

 

 

 

 

US – Other Exploration

 

62,583 

 

104,798 

 

16,212 

US – Brown Dense

 

83,023 

 

5,850 

 

3,196 

US – Sand Wash Basin

 

4,998 

 

4,435 

 

1,000 

Canada – New Brunswick (3)

 

 –  

 

 –  

 

 –  



(1)

Of this acreage, 2,666 net acres in 2018, 5,907 net acres in 2019 and 1,850 net acres in 2020 can be extended for an average of 5.9 years.

(2)

Excludes 158,231 net acres held on federal lands which are currently suspended by the Bureau of Land Management.

(3)

Exploration licenses for 2,518,519 net acres were extended through 2021 but have been subject to a moratorium since 2015.  



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 2015, 2016 and 2017:







 

 

 

 

 

 

 

 

 

 

CHANGES IN PROVED UNDEVELOPED RESERVES



 

 

 

 

 

 

 

 

 

 



 

Appalachia

 

Fayetteville

 

 

 

 

(Bcfe)

 

Northeast

 

Southwest

 

Shale

 

Other (1)

 

Total

December 31, 2014

 

1,598 

 

1,481 

 

1,716 

 

 

4,796 

Extensions, discoveries and other additions

 

138 

 

 

34 

 

– 

 

176 

Performance and production revisions (2)

 

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 

Performance and production revisions (2)

 

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 

Extensions, discoveries and other additions (3)

 

1,100 

 

5,186 

 

543 

 

– 

 

6,829 

Performance and production revisions (2)

 

–  

 

 

(14)

 

– 

 

(8)

Price revisions

 

 

–  

 

 

– 

 

Developed

 

(17)

 

 –  

 

(29)

 

– 

 

(46)

Disposition of reserves in place

 

– 

 

 –

 

– 

 

 –   

 

 –   

Acquisition of reserves in place

 

– 

 

 –

 

– 

 

– 

 

– 

December 31, 2017

 

1,119 

 

5,192 

 

544 

 

 –   

 

6,855 



(1)

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

(2)

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

(3)

The 2017 PUD additions are primarily associated with the increase in commodity prices.

8

 


 



·

As of December 31, 2017, we had 6,855 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 2017, we invested $23 million in connection with converting 46 Bcfe, or 60%, of our proved undeveloped reserves as of December 31, 2016 into proved developed reserves and added 6,829 Bcfe of proved undeveloped reserve additions, primarily in the Appalachian Basin.    The significant increase in our proved undeveloped reserve additions in 2017 was the result of adding new undeveloped locations throughout the year through our successful drilling program, improved operational performance and increased commodity pricing across our portfolio.



·

As of December 31, 2016, we had 77 Bcfe of proved undeveloped reserves.  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.



Our December 31, 2017 proved reserves included 1,375 Bcfe of proved undeveloped reserves from 330 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 $124 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 6,855 Bcfe as of December 31, 2017 will require us to invest an additional $4.2 billion 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 current 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



In recent years, the Appalachian Basin has provided the majority of our reserve additions.  In 2017, our proved undeveloped reserves in the Appalachian Basin increased by approximately 6.3 Tcfe, as compared to 2016, primarily due to improved commodity pricing.  Our proved developed reserves in the Appalachian Basin increased by approximately 1.2 Tcfe in 2017, as compared to 2016, primarily due to our successful drilling program.  Over the past three years, Northeast Appalachia has contributed 790 Bcf, 81 Bcf and 202 Bcf in 2017, 2016 and 2015, respectively, of our reserve additions as a result of successful development activity.  Additionally, we added 419 Bcfe, 157 Bcfe and 84 Bcfe of reserves in 2017, 2016 and 2015, respectively, as a result of our drilling program in Southwest Appalachia.  We expect our drilling programs in the Appalachian Basin 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



Northeast Appalachia represented 44% of our total 2017 net production and 28% of our total reserves as of December 31, 2017.  In 2017, our reserves in Northeast Appalachia increased by 2,552 Bcf, which included net additions of 1,890 Bcf, net upward price revisions of 903 Bcf and net upward performance revisions of 154 Bcf, partially offset by production of 395 Bcf.  As of December 31, 2017, we had approximately 191,226 net acres in Northeast Appalachia and had spud or acquired 645 operated wells, 538 of which were on productionBelow is a summary of Northeast Appalachia’s operating results for the latest three years:    









 

 

 

 

 

 

 

 

 



For the years ended December 31,

 



2017

 

2016

 

2015

 

Acreage

 

 

 

 

 

 

 

 

 

Net undeveloped acres

 

87,927 

(1)

 

146,096 

 

 

174,826 

 

Net developed acres

 

103,299 

 

 

99,709 

 

 

95,509 

 

Total net acres

 

191,226 

 

 

245,805 

 

 

270,335 

 



 

 

 

 

 

 

 

 

 

Net Production (Bcf)

 

395 

 

 

350 

 

 

360 

 



 

 

 

 

 

 

 

 

 

Reserves

 

 

 

 

 

 

 

 

 

Reserves (Bcf)

 

4,126 

 

 

1,574 

 

 

2,319 

 

Locations:

 

 

 

 

 

 

 

 

 

Proved developed

 

983 

 

 

820 

 

 

767 

 

Proved developed non-producing

 

25 

 

 

39 

 

 

23 

 

Proved undeveloped

 

100 

 

 

 

 

36 

 

Total locations

 

1,108 

 

 

861 

 

 

826 

 



 

 

 

 

 

 

 

 

 

Gross Operated Well Count Summary

 

 

 

 

 

 

 

 

 

Spud or acquired

 

58 

 

 

32 

 

 

177 

(2)

Completed

 

77 

 

 

33 

 

 

92 

 

Wells to sales

 

83 

 

 

24 

 

 

100 

 



 

 

 

 

 

 

 

 

 

Capital Investments (in millions)

 

 

 

 

 

 

 

 

 

Exploratory and development drilling, including workovers

$

420 

 

$

160 

 

$

472 

 

Acquisition and leasehold

 

14 

 

 

 

 

172 

 

Seismic and other

 

13 

 

 

 

 

 

Capitalized interest and expense

 

42 

 

 

39 

 

 

58 

 

Total capital investments

$

489 

 

$

204 

 

$

710 

 



 

 

 

 

 

 

 

 

 

Average completed well cost (in millions)

$

5.9 

 

$

5.3 

 

$

5.4 

 

Average lateral length (feet)

 

6,185 

 

 

6,142 

 

 

5,403 

 



(1)    Our undeveloped acreage position as of December 31, 2017 had an average royalty interest of 15%. The decrease in our net undeveloped acres in 2017 as compared to 2016 is due to leasehold expirations in areas we did not plan on developing.

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



·

Our proved undeveloped reserve locations increased significantly in 2017, as compared to 2016, primarily through our successful drilling program in less developed areas and improved realized commodity pricing.



·

Our average completed well cost increased in 2017, as compared to 2016, primarily due to tighter hydraulic fracturing spacing and increased activity in delineation areas.



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” 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



Southwest Appalachia represented 20% of our total 2017 net production and 47% of our total reserves as of December 31, 2017.  In 2017, our reserves in Southwest Appalachia increased by 6,285 Bcfe, which included net additions of 5,605 Bcfe, net upward price revisions of 738 Bcfe and 125 Bcfe of net upward performance revisions, partially offset by production of 183 Bcfe.  As of December 31, 2017, we had approximately 290,291 net acres in Southwest Appalachia and had a total of 360 wells on production that we operated.  Below is a summary of Southwest Appalachia’s operating results for the latest three years:







 

 

 

 

 

 

 

 

 

 



For the years ended December 31,



2017

 

2016

 

2015

Acreage

 

 

 

 

 

 

 

 

Net undeveloped acres (1)

 

219,709 

(2)

 

252,470 

 

 

193,582 

Net developed acres (1)

 

70,582 

 

 

69,093 

 

 

231,516 

Total net acres

 

290,291 

 

 

321,563 

 

 

425,098 



 

 

 

 

 

 

 

 

Net Production (Bcfe)

 

183 

 

 

148 

 

 

143 



 

 

 

 

 

 

 

 

Reserves

 

 

 

 

 

 

 

 

Reserves (Bcfe)

 

6,962 

 

 

677 

 

 

611 

Locations:

 

 

 

 

 

 

 

 

Proved developed

 

364 

 

 

306 

(3)

 

1,028 

Proved developed non-producing

 

37 

 

 

44 

(3)

 

400 

Proved undeveloped

 

559 

 

 

–  

 

 

Total locations

 

960 

 

 

350 

(3)

 

1,429 



 

 

 

 

 

 

 

 

Gross Operated Well Count Summary

 

 

 

 

 

 

 

 

Spud or acquired

 

55 

 

 

17 

 

 

48 

Completed

 

50 

 

 

17 

 

 

38 

Wells to sales

 

57 

 

 

18 

 

 

47 



 

 

 

 

 

 

 

 

Capital Investments (in millions)

 

 

 

 

 

 

 

 

Exploratory and development drilling, including workovers

$

353 

 

$

111 

 

$

248 

Acquisition and leasehold

 

59 

 

 

18 

 

 

409 

Seismic and other

 

 

 

 

 

Capitalized interest and expense

 

131 

 

 

158 

 

 

198 

Total capital investments

$

547 

 

$

288 

 

$

857 



 

 

 

 

 

 

 

 

Average completed well cost (in millions)  (4)

$

7.4 

(5)

$

5.4 

(5)

$

6.9 

Average lateral length (feet)  (4)

 

7,451 

(5)

 

5,275 

(5)

 

6,985 



(1)

A divestiture of shallow legacy assets, in which we retained the Marcellus and Utica geologic intervals, resulted in a reclassification of acreage from developed to undeveloped in 2016.

(2)

Our undeveloped acreage position as of December 31, 2017 had an average royalty interest of 14%.

(3)

Includes the impact of legacy assets divested in 2016.

(4)

Includes wells only drilled by SWN.

(5)

Excludes one Utica delineation well in 2017 and one in 2016, respectively.



·

Our proved undeveloped reserve locations increased significantly in 2017, as compared to 2016, primarily through our successful drilling program in less developed areas and improved realized commodity pricing.



·

Our average completed well cost increased in 2017, as compared to 2016, primarily due to longer lateral lengths, tighter hydraulic fracturing spacing and increased proppant volumes.



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” 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



The Fayetteville Shale represented 35% of our total 2017 net production and 25% of our total reserves as of December 31, 2017.  In 2017, our reserves in the Fayetteville Shale increased by 682 Bcf, which included net reserve additions of 591 Bcf, 358 Bcf of net upward revisions due to well performance and net upward price revisions of 49 Bcf, partially offset by production of 316 Bcf.  As of December 31, 2017, we held leases for approximately 917,842 net acres in the Fayetteville Shale and had 4,698 wells on production, 4,033 which were operated by us and 665 were outside-operated wells.  Below is a summary of the Fayetteville Shale’s operating results for the latest three years:

   





 

 

 

 

 

 

 

 

 

 



For the years ended December 31,



2017

 

2016

 

2015

Acreage

 

 

 

 

 

 

 

 

Net undeveloped acres (1) (2)

 

424,858 

(3)   

 

426,717 

 

 

459,312 

Net developed acres (1)

 

492,984 

 

 

491,818 

 

 

498,329 

Total net acres

 

917,842 

 

 

918,535 

 

 

957,641 



 

 

 

 

 

 

 

 

Net Production (Bcf)

 

316 

 

 

375 

 

 

465 



 

 

 

 

 

 

 

 

Reserves

 

 

 

 

 

 

 

 

Reserves (Bcf)

 

3,679 

 

 

2,997 

 

 

3,281 

Locations:

 

 

 

 

 

 

 

 

Proved developed

 

4,191 

 

 

4,217 

 

 

4,268 

Proved developed non-producing

 

304 

 

 

311 

 

 

231 

Proved undeveloped

 

234 

 

 

13 

 

 

61 

Total locations

 

4,729 

 

 

4,541 

 

 

4,560 



 

 

 

 

 

 

 

 

Gross Operated Well Count Summary

 

 

 

 

 

 

 

 

Spud or acquired

 

 

 

 

 

155 

Completed

 

23 

 

 

34 

 

 

262 

Wells to sales

 

25 

 

 

43 

 

 

260 



 

 

 

 

 

 

 

 

Capital Investments (in millions)

 

 

 

 

 

 

 

 

Exploratory and development drilling, including workovers

$

82 

 

$

63 

 

$

484 

Acquisition and leasehold

 

 

 

 

 

Seismic and other

 

 

 

–  

 

 

Capitalized interest and expense

 

22 

 

 

21 

 

 

69 

Total capital investments

$

114 

 

$

86 

 

$

565 



 

 

 

 

 

 

 

 

Average completed well cost (in millions)

$

4.2 

 

$

3.2 

 

$

2.8 

Average lateral length (feet)

 

6,609 

 

 

5,717 

 

 

5,729 



(1)

A divestiture of shallow legacy Arkoma assets in 2015, in which we retained the geologic interval from the top of the upper Fayetteville Formation down to the base of the Chattanooga Formation, resulted in a reclassification of acreage from developed to undeveloped.

(2)

Includes 226,312, 227,656 and 202,156 net undeveloped acres in the Arkoma Basin as of December 31, 2017, 2016 and 2015, respectively.

(3)

Our undeveloped acreage position as of December 31, 2017 had an average royalty interest of 13%.



·

Our proved undeveloped reserve locations increased significantly in 2017, as compared to 2016, primarily due to improved realized commodity pricing.



·

Our average completed well cost increased in 2017, as compared to 2016, primarily due to longer lateral lengths and increased activity in the deeper Moorefield zone.



12

 


 

 

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, which were subsequently 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 discontinued approval of operational permits in the forest, including permits to drill, pending resolution of the litigation.  Although the case was dismissed in May 2017, the BLM is not issuing drilling permits.  If and when permit issuance resumes, the leases will expire unless, within nine months, we commence drilling or resume rental payments.  At year-end 2017, after excluding our acreage in the conventional Arkoma Basin and the federal acreage we hold in the Ozark Highlands Unit, approximately 99% of our 533,299 total net leasehold acres remaining in the Fayetteville Shale was held by production.  For more information about our acreage and well count, we refer you to “Properties” in Item 2 of Part I of this Annual Report.  We also 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.



In February 2018, we announced an initiative to actively pursue strategic alternatives for the Fayetteville Shale E&P and related Midstream gathering assets.



Other



Excluding 2,518,519 acres in New Brunswick, Canada, which have been subject to a moratorium since 2015, we held 369,236 net undeveloped acres for the potential development of new resources as of December 31, 2017.  This compares to 492,389 net undeveloped acres held at year-end 2016 and 1,142,856 net undeveloped acres held at year-end 2015, excluding the New Brunswick acreage.



We limited our activities in areas beyond our assets in the Appalachian Basin and the Fayetteville Shale during 2017, 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. 



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, we sold approximately 55,000 net acres in West Virginia for approximately $401 million.  As of December 2015, these assets included approximately 11 Bcfe of proved reserves.



In May 2015, we 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, we sold our 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





 

 

 

 

 

 

 

 



For the years ended December 31,

(in millions)

2017

 

2016

 

2015

E&P Capital Investments by Type

 

 

 

 

 

 

 

 

Exploratory and development drilling, including workovers

$

878 

 

$

358 

 

$

1,226 

Acquisition and leasehold

 

86 

 

 

23 

 

 

607 

Seismic expenditures

 

 

 

 

 

Drilling rigs, sand facility, water infrastructure and other

 

65 

 

 

 

 

40 

Capitalized interest and other expenses

 

212 

 

 

239 

 

 

379 

Total E&P capital investments

$

1,248 

 

$

623 

 

$

2,258 



 

 

 

 

 

 

 

 

E&P Capital Investments by Area

 

 

 

 

 

 

 

 

Northeast Appalachia

$

489 

 

$

204 

 

$

710 

Southwest Appalachia

 

547 

 

 

288 

 

 

857 

Fayetteville Shale

 

114 

 

 

86 

 

 

565 

Other

 

98 

 

 

45 

 

 

126 

Total E&P capital investments

$

1,248 

 

$

623 

 

$

2,258 



·

The significant increase in 2017 E&P capital investing, as compared to 2016, resulted from the resumption of activity following our decision to suspend drilling activity in the first half of 2016 due to an unfavorable commodity price environment.  We began increasing activity in the second half of 2016 as forward pricing improved.



·

The significant decrease in 2016 E&P capital investing, as compared to 2015, was the result of suspending drilling activity in the first half of 2016 due to an unfavorable commodity price environment.



·

In 2017,  we drilled 134 wells (120 of which were spud in 2017), completed 151 wells, placed 166 wells to sales and had 92 wells in progress at year-end. 



·

Of the 92 wells in progress at year-end, 52 and 40 were located in Northeast Appalachia and Southwest Appalachia, respectively, and 19 of these wells were waiting on pipeline or production facilities.



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 2018.



Sales, Delivery Commitments and Customers



Sales.  The following tables present historical information about our production volumes for natural gas, oil and NGLs and our average realized natural gas, oil and NGL sales prices:







 

 

 

 

 



For the years ended December 31,



2017

 

2016

 

2015

Average net daily production (MMcfe/day)

2,456 

 

2,391 

 

2,675 

Production:

 

 

 

 

 

Natural gas (Bcf)

797 

 

788 

 

899 

Oil (MBbls)

2,327 

 

2,192 

 

2,265 

NGLs (MBbls)

14,245 

 

12,372 

 

10,702 

Total production (Bcfe)

897 

 

875 

 

976 



·

The increase in production in 2017 resulted primarily from a 45 Bcf increase in net production from our Northeast Appalachia properties and a 35 Bcfe increase in net production from our Southwest Appalachia properties, partially offset by a decrease of 59 Bcf from our Fayetteville Shale properties.

 

·

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.

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For the years ended December 31,

Average realized price per unit:

2017

 

2016

 

2015

Natural gas sales, excluding derivatives (per Mcf)

$

2.23 

 

$

1.59 

 

$

1.91 

Effect of settled gain (loss) on derivatives (per Mcf)

 

(0.04)

 

 

0.05 

 

 

0.46 

Natural gas sales, including derivatives  (per Mcf)

$

2.19 

 

$

1.64 

 

$

2.37 



 

 

 

 

 

 

 

 

Oil sales (per Bbl)

$

43.12 

 

$

31.20 

 

$

33.25 



 

 

 

 

 

 

 

 

NGL sales, excluding derivatives (per Bbl)

$

14.46 

 

$

7.46 

 

$

6.80 

Effect of settled gain (loss) on derivatives (per Bbl)

 

0.02 

 

 

– 

 

 

– 

NGL sales, including derivatives (per Bbl)

$

14.48 

 

$

7.46 

 

$

6.80 



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 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 agreements to counterparties with appropriate credit standings.



As of December 31, 2017, we had the following commodity price derivatives in place on our targeted future production:





 

 

 

 

 



 

 

 

 

 



For the years ended December 31,

Financial protection on production as of December 31, 2017:

2018

 

2019

 

2020

Natural gas (Bcf)

489 

 

201 

 

 –  

Ethane (MBbls)

183 

 

 –  

 

–  

Propane (MBbls)

183 

 

–  

 

–  



As of February 27, 2018, we had the following commodity price derivatives in place on our targeted future production:





 

 

 

 

 



 

 

 

 

 



For the years ended December 31,

Financial protection on production as of February 27, 2018:

2018

 

2019

 

2020

Natural gas (Bcf)

566 

 

216 

 

–  

Ethane (MBbls)

183 

 

–  

 

–  

Propane (MBbls)

1,353 

 

–  

 

–  



We intend to financially protect pricing on a large portion of expected future production volumes designed to assure certain desired levels 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, 2017.





During 2017, the average price we received for our natural gas production, excluding the impact of derivatives, was approximately $0.88 per Mcf lower than average New York Mercantile Exchange, or NYMEX, prices.  Differences between NYMEX and price realized are due primarily to locational differences and transportation cost.  



As of December 31, 2017, we have partially mitigated the volatility of basis differentials by protecting basis on approximately 182 Bcf and 70 Bcf of our 2018 and 2019 expected natural gas production, respectively, through physical sales arrangements at a basis differential to NYMEX natural gas price of approximately ($0.25) per MMBtu and ($0.31) per MMBtu for 2018 and 2019, respectively.



We have also financially protected basis on approximately 44 Bcf and less than 1 Bcf of our 2018 and 2019 expected natural gas production, respectively, at a basis differential to NYMEX natural gas price of approximately ($0.48) per MMBtu and ($0.59) per MMBtu for 2018 and 2019, respectively, as of December 31, 2017.



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, 2017, we had natural gas delivery commitments of 408 Bcf in 2018 and 100 Bcf in 2019 under existing agreements. These amounts are well below our expected 2018 natural gas production from Northeast Appalachia, Southwest Appalachia and the Fayetteville Shale and expected 2019 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

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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 E&P production is marketed primarily by our Midstream segment.  Our customers include major energy companies, utilities and industrial purchasers of natural gas.  For the year ended December 31, 2017, two subsidiaries of Royal Dutch Shell Plc in aggregate accounted for approximately 10.3% of total natural gas, oil and NGL salesDuring the years ended December 31, 2016 and 2015, no single third-party purchaser accounted for 10% or more of our consolidated revenues.  We believe that the loss of any one customer would not have an adverse effect on our ability to sell our natural gas, oil and NGL production.



Competition



All phases of the natural gas and oil industry are highly competitive.  We compete in the acquisition and disposition 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.  Likewise, there are substitutes for the commodities we produce, such as other fuels for power generation, heating and transportation, and those markets in effect compete with us.



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.



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,