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Energy for Our World,
Enhancing Our Future
Southwestern Energy Company
2016 Annual Report
We have featured
the Formula on the
cover as 2016
was indeed a year
of adjusting to
market dynamics.
As a company we have
responded quickly and decisively
to the challenging commodity
price environment. We have
realigned our Company and
recalibrated our strategy with a
steadfast focus on creating
Value+ for our shareholders.
SWN’s formula
reflects our values and
clarifies our priorities.
It was developed by company
leaders years ago as a guiding
light defining how SWN
will conduct its business.
The arrow denoting
value creation was
originally drawn as a
straight line arrow
angling up.
But one leader thoughtfully
insisted it be redrawn as a jagged
arrow, recognizing that business
conditions do not always
let you follow a straight line
to long-term value creation
and, instead, course corrections
may be necessary.
®
The Right People doing the
Right Things, wisely investing
the cash flow from the underlying
Assets will create Value+®
Enhancing our Future
SW N 2016 AN NUA L RE PORT
1
Dear Fellow Shareholders
The bold and decisive actions we took in 2016 have built strong momentum to
tackle market challenges and capture the opportunities ahead, and we are delivering
remarkable results. With the gains we made in 2016, we are creating long-term
sustainable value, as evidenced by our return to value-added growth.
Financial Discipline
Financial discipline is a core principle in the fabric of SWN. Throughout 2016, we took actions that
strengthened the balance sheet and increased our liquidity. Through the combination of extending bank
agreements, successfully issuing equity, launching and concluding tender offers for debt and completing
the sale of long-dated inventory, we reduced net debt by $1.5 billion and our remaining 2017 and 2018 debt
maturities to $316 million. Based on the recent 2017 strip, we anticipate continued improvement to
the balance sheet and expect net debt to EBITDA at year-end 2017 to be below 3.0. We are continuing
to proactively look for opportunities to further de-lever and strengthen the balance sheet.
Strategy Execution
Delivering value to shareholders is at the core of our forward strategy and plan. Our employees are
aggressively executing our strategy with the goal of powering SWN to industry-leading financial and operational
performance. Our continued drive to expand margins is unyielding. In 2016, we reduced costs by more
than $200 million with the majority of these savings structural and sustainable. As an example, we successfully
renegotiated gathering and processing contracts in Southwest Appalachia, which reduced lease operating
costs, and created a solution for our dry gas gathering needs for our northern acreage. Enterprising employees
are testing several promising technical and operating methods to improve well productivity. The initial results
are encouraging and we look forward to sharing more on our progress throughout the year as we have
more definitive information to report.
Two overarching principles of our strategy are that we will invest within cash flow and be disciplined in capital
allocation. This capital discipline differentiates us from many in the industry and will continue to do so
moving forward. It is designed deliberately to result in greater assurance of realizing expected returns while
mitigating some of the risk associated with commodity prices.
Operations Overview
We are leveraging our operational expertise as a competitive advantage. We entered 2017 with strong
momentum propelled by the success from the resumption of drilling and completion activities. We took
advantage of the pause in activity during 2016 to drive greater operational efficiency and technological
advances. Each of our core asset areas is intensely focused on finding innovative ways to reduce costs and
increase value-added production. We are seeing strong results!
We have a robust, well-balanced portfolio of large-scale, high-quality, long-lived assets that continues to
provide steady production through the near, medium and long term, with an abundance of exciting growth
opportunities. This balance gives us flexibility and optionality to ramp up or ramp down accordingly to
operate profitably under various price scenarios.
Our Fayetteville asset has vast reserves and generates a strong stream of cash flow. We have challenged
ourselves to bring down our breakeven costs to compete for capital with the Appalachia locations in alignment
with our disciplined investment approach. We are currently in the early delineation phase of testing the
Moorefield formation and our initial results are encouraging.
Our Northeast Appalachia asset offers the advantageous combination of world-class E&P acreage and strategic
and highly profitable transportation capacity options. Our increased well productivity here is driving long-term
value. Early on, SWN recognized the strategic importance of buying firm transportation to maximize the value of
our world-class Northeast Appalachia E&P assets. We were able to build a takeaway portfolio with access to
many diversified markets which gives us the ability to capture incremental value. This is a distinct competitive
advantage. As a first mover, we were able to strategically purchase capacity at very competitive rates and build
renewal and extension options into our contracts. This has resulted in greater flexibility, lower costs and less
risk, while minimizing our exposure to long-term (“take or pay”) commitments.
Our Southwest Appalachia asset has premier rock quality and offers the opportunity to drill both wet and dry gas
wells, which we will optimize to capture the best commodity prices. The scale and diversity of this asset allows
the Company to shift capital to maximize returns in any commodity price environment. With abundant resource
potential, these assets will generate significant value-adding growth that will drive the Company in the long run.
“We have met the challenge to re-invent ourselves, and we have
taken dramatic steps to strengthen our balance sheet and expand
margins to prosper even in an extended period of lower prices.”
Core Value Focus
Along with our operational achievements, I am also very proud of our 2016 safety and environmental
performance. We took extra time and precautions to ensure our workforce resumed drilling and completion
activity in a safe manner. Our culture is one built on safety as a core value and our results in 2016 demonstrate
that commitment. We improved our metrics and will strive to continue that trend in 2017.
Additionally, we strive to be good environmental stewards and respected members of the community. In 2016, we
achieved our goal of being fresh water neutral, whereby we replace more fresh water than we use in our operation
through treating or conservation projects that include restoring fresh water sources that had become compromised
by others. And we continue to reduce our own methane emission levels and work on programs to reduce emissions
throughout the vertical natural gas chain. These are but two examples of our industry-leading environmental efforts
to identify and implement innovative solutions to minimize environmental and community impacts of our activities.
Looking forward
With commodity prices headlining 2016 financial news, it is easy to lose sight of one of the greatest success
stories of the 21st Century—the incredible transformation of the U.S. energy market. Today, the U.S. is the world’s
largest producer of natural gas, a triumph that was inconceivable just a decade ago. This transformation has
brought us close to the goal of American energy independence. It has sparked a resurgence in U.S. manufacturing,
bringing back jobs and prosperity and improving the lives of Americans. As the third largest U.S. gas producer,
it is a privilege and a responsibility to be an integral part of America’s energy success story.
While a lower price environment is not without its challenges, we have taken dramatic steps to strengthen
our balance sheet and re-invent ourselves to prosper even in an extended period of low prices. At the same time,
we are prepared to move quickly to take advantage of price recovery.
SWN is ideally positioned to tap our abundant, high-quality resources to meet the nation’s demand for reliable,
affordable clean energy. Clean-burning natural gas will continue to be the world’s essential lower-carbon
energy supply well into the future. SWN is proud of our role as an industry leader in safe, responsible resource
development and confident in our ability to deliver top-quartile growth in shareholder value.
Thank you for your support.
Sincerely,
William J. Way, President & Chief Executive Officer
Enhancing our Future
SW N 2016 A NN UA L RE PORT
3
Financial Highlights
Average Realized
Gas Price ($/Mcf)
Net Cash Provided by
Operating Activities
(in Millions)
Capital
Investments (in Millions)(1)
’16
’15
’14
’13
’12
$ 1.64
$ 2.37
$ 3.72
$ 3.65
$ 3.44
Diluted (Loss)
Earnings Per Share
’16 $ (6.32)
’15
’14
’13
’12
$ (12.25)
$ 2.62
$ 2.00
$ (2.03)
’16
’15
’14
’13
’12
$ 498
$ 1,580
$ 2,335
$ 1,909
$ 1,654
’16
’15
’14
’13
’12
$ 648
$ 2,437
$ 7,447
$ 2,235
$ 2,081
Adjusted Diluted (Loss)
Earnings Per Share (2)
Adjusted
EBITDA (in Millions)(2)
’16
’15
’14
’13
’12
$ (0.01)
$ 0.19
$ 2.27
$ 2.00
$ 1.39
’16
’15
’14
’13
’12
$ 686
$ 1,440
$ 2,320
$ 1,998
$ 1,638
Production
(Bcfe)
Reserves
(Bcfe)
Production
Costs ($/Mcfe)(3)
’16
’15
’14
’13
’12
875
976
768
657
565
’16
’15
’14
’13
’12
5,253
6,215
10,747
6,976
4,018
’16
’15
’14
’13
’12
$ 0.97
$ 1.02
$ 1.02
$ 0.96
$ 0.89
Footnotes (1) Includes acquisition costs and post-closing adjustments for the Appalachia
transactions that closed in December 2014 and January 2015 of $609 million in 2015 and
$5,007 million in 2014. (2) For the Company’s reconciliation of adjusted diluted (loss)
earnings per share and adjusted EBITDA to Generally Accepted Accounting Principles, see
“Non-GAAP Reconciliations” on the inside back cover. (3) Production cost per Mcfe includes
lease operating expenses and production taxes. (4) Proved developed fi nding and
development cost are computed by dividing exploration and development capital costs
incurred, excluding capitalized interest and expenses by PDP reserve additions and
proved undeveloped conversions.
2016 Proved
Developed Finding
& Development
Cost
$0.75/Mcfe(4)
Enhancing our Future
SW N 2016 A NN UA L RE PORT
5
Financial
Strength
We are
committed
to rigorously
managing our
balance sheet
and risks.
program designed
to provide
protection of cash
flows and ensure
targeted returns
utilizing a
combination of
commodity and
basis hedges.
As of December
31, 2016, we had
approximately 560
Bcf of our 2017 gas
production hedged
at a floor price
of $3.02, 240 Bcf
of our 2018 gas
production hedged
at a floor price of
$2.97 and 62 Bcf
of our 2019 gas
production hedged
at a floor price
of $2.92.
We budget to invest
only from our net
cash flow, protect
our projected cash
flows through
hedging, and
continue to ensure
strong liquidity while
de-levering the
Company. Our
capital budgets in
2016 and 2017 were
supplemented by
$500 million from
our $1.2 billion
equity offering
in 2016.
In 2016, we
rearranged and
extended our bank
credit facilities,
successfully
tendered for
approximately $700
million of our
near-term senior
notes, and divested
of long-dated
acreage. These
activities reduced
total debt to $4.7
billion and net debt
to $3.2 billion, with
only $316 million
remaining of
outstanding debt
maturities through
2018. Additionally,
we initiated a rolling
3-year hedge
Debt
......................................................
$
7.0
$
6.0
......................................................
$
5.0
......................................................
$
4.0
......................................................
$
3.0
......................................................
$
2.0
......................................................
s
n
o
i
l
l
i
B
n
i
$
$
1.0
......................................................
s
n
o
i
l
l
i
M
n
i
$
Invest within Cash Flow
.......................................................................
.......................................................................
301
Equity
Proceeds
.......................................................................
.......................................................................
$
1,000
$
900
$
800
$
700
$
600
.......................................................................
$
500
$
400
$
300
.......................................................................
.......................................................................
.......................................................................
648
645
Net Cash
Flow(1)
$
200
.......................................................................
$
100
.......................................................................
$
0.0
......................................................
$
0
.......................................................................
2014
2015
2016
Debt
Net Debt
2016 Net
Funds*
2016 Capital
Investments
(1) For the reconciliation of net cash flow to Generally
Accepted Accounting Principles, see “Non-GAAP
Reconciliations” on the inside back cover
*Net Funds is the sum of Net Cash Flow and
the amount of proceeds from the 2016 equity
offering utilized for capital investments
Enhancing our Future
SW N 2016 A NN UA L RE PORT
7
Margin
Expansion
Margin
expansion is
a key focus at
Southwestern,
both through
cost reductions
and revenue
enhancements.
We apply
strong technical,
operational,
commercial and
marketing skills
to improve the
productivity of
our wells, reduce
cost, and pursue
commercial
arrangements that
extract greater
value from each
of our assets.
We believe our
demonstrated
ability to improve
production
declines.
Additionally, we
finalized a new
gathering
agreement in
Southwest
Appalachia that was
estimated to reduce
costs by over $35
million, with future
savings realized
with increased
production levels.
As a company, lease
operating expenses
were reduced by
$0.05 per Mcfe, or
5% in 2016. Margin
enhancement is a
key component of
our strategy and
will remain a
focus as we move
throughout 2017
and beyond.
margins, especially
by levering the
scale of our large
assets, gives us a
competitive
advantage as we
move into the future.
In 2016, great
strides were made
in our efforts to
enhance margins.
For example,
we executed
production
enhancement
initiatives, such as
compression
optimization, that
resulted in over 30
Bcfe of production
from lower base
Taxes other than income
General & administrative
Lease operating expense
E&P Cash Operating Costs
........................................................................................................
$1.23
........................................................................................................
0.10
........................................................................................................
0.21
$1.26
$1.19
0.24
0.11
0.10
0.22
........................................................................................................
0.92
........................................................................................................
0.87
0.91
$
1.50
$
1.25
$
1.00
$
0.75
$
0.50
e
f
c
M
/
$
$
0.25
........................................................................................................
$
0.00
........................................................................................................
2014
2015
2016
Enhancing our Future
SW N 2016 A NN UA L RE PORT
9
The
Hydrocarbon
Value
Chain
We often
expand our
activities
vertically
when we
believe this
will enhance
our margins
or otherwise
provide us
competitive
advantages.
operational
efficiencies
throughout our
assets. These drilling
rigs continue to
deliver extraordinary
results, both
in drilling time
and drilling
accuracy, and are a
key component of
the improved well
productivity
exhibited in each of
our operating areas.
We also own
a sand mine that
provides proppant
in hydraulic
fracturing in the
Fayetteville area.
As a result, we are
able to keep costs
low while testing
For example, the
Company developed
and operates
one of the largest
contiguous
gathering systems
in the United States.
As of December 31,
2016, we gathered
1.5 Bcf per day of
gas volumes and
had approximately
2,045 miles of pipe
from the individual
wellheads to the
transmission lines.
We also operate
drilling rigs, which
we custom built
to maximize
various proppant
amounts used
in completions,
potentially
unlocking significant
additional value
from that asset.
Additionally, we
own two pressure
pumping spreads
that we operated
until early 2016 and
that are available
to be put back into
service should
service costs rise
from their current
levels. Combined,
our vertical
integration activities
help protect and
expand margins,
minimize the risk
of unavailability of
these services from
third parties,
diversify our cash
flows and capture
additional value.
$
1.40
$
1.20
$
1.00
$
0.80
$
0.60
$
0.40
e
f
c
M
/
$
PDP Finding & Development Cost
.........................................................................................................................................
.........................................................................................................................................
.........................................................................................................................................
.........................................................................................................................................
.........................................................................................................................................
$1.33
$1.23
.........................................................................................................................................
$0.88
$0.75
$
0.20
.........................................................................................................................................
$
0.00
.........................................................................................................................................
2013
2014
2015
2016
Enhancing our Future
SW N 2016 A NN UA L RE PORT
11
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.
pursue the off set of
our freshwater use
including innovative
water management
practices and
conservation
projects. During
2016, we
accomplished our
goal of becoming
fresh water neutral
in each of our
operating areas.
That is, for every
gallon of fresh water
we use, we aim to
off set or replenish
that gallon through
water quality
improvement
projects or
treatment
technologies that
return fresh water to
the environment.
The performance
based approach of
Our Nation’s Energy
(ONE) Future was
We work extensively
with governmental,
non-governmental
and industry
stakeholders to
develop responsible
and cost-eff ective
programs. We
demonstrate that a
company can
operate responsibly
and profi tably,
putting us in a
better position not
only to comply with
new regulations,
but also to work
with regulators to
demonstrate
eff ective methods
for dealing with
important concerns.
Through our ECH2O
(Energy Conserving
Water) initiative we
recognized by the
EPA in 2016 and
accepted as part of
the EPA Methane
Challenge. The ONE
Future coalition
is a group of
eight companies,
co-founded by
SWN, dedicated to
reducing methane
emissions across
the natural gas value
chain. ONE Future
seeks to reduce
emissions to an
average annual
leak/loss rate
of no more than 1
percent of gross
U.S. natural gas
production by
2025. (The EPA’s
2012 National
Greenhouse Gas
Inventory estimated
the industry’s leak/
loss rate at 1.3
percent.) In 2015,
SWN reported a
methane leak loss
rate of 0.18% of
production, a rate
well below our ONE
Future target.
Enhancing our Future
SW N 2016 A NN UA L RE PORT
13
Executive Officers
From left to right: R. Craig Owen (8), Senior Vice President and Chief Financial Officer; James W. Vick (5), Senior Vice President-Business Information
Services; John E. “Jack” Bergeron, Jr. (9), Senior Vice President-Operations; John C. Ale (3), Senior Vice President, General Counsel and Secretary;
Randy L. Curry (2), Senior Vice President- Midstream; William J. Way (5), President and Chief Executive Officer; C. Greg Stoute (11), Vice
President- Health, Safety and Environmental, and Regulatory; Jennifer N. McCauley (7), Senior Vice President-Administration; Paul W. Geiger (2),
Senior Vice President- Corporate Development; Mark K. Boling (15), President-V+ Development Solutions
Directors
Catherine A. Kehr (5)
Retired–The Capital
Group Companies
William J. Way (1)
President and
Chief Executive Officer
John D. Gass (4)
Retired–Chevron
Corporation
Greg D. Kerley (6)
Retired–Southwestern
Energy Company
Jon A. Marshall (*)
Retired–
Transocean Ltd.
Kenneth R. Mourton (22)
Managing Partner–Ball
and Mourton, Ltd., PLLC
Terry W. Rathert (2)
Retired–Newfield
Exploration Company
Elliott Pew (4)
Retired–
Common Resources
Alan H. Stevens (6)
Retired–Southwestern
Energy Company
Corporate Officers
William J. Way (5)
President and Chief
Executive Officer
Mark K. Boling (15)
President–V+
Development Solutions
R. Craig Owen (8)
Senior Vice President
and Chief
Financial Officer
John C. Ale (3)
Senior Vice President,
General Counsel
and Secretary
Jennifer N.
McCauley (7)
Senior Vice President–
Administration
James W. Vick (5)
Senior Vice President–
Business Information
Services
Mark L. Colassaco (4)
Vice President–
Business Information
Services
Colin P. O’Beirne (6)
Vice President
and Controller
Jennifer E. Stewart (6)
Senior Vice President–
Tax and Treasury
Operating Subsidiary Officers
Randall L. Barron (14)
Vice President–
Treasury
Jim R. Dewbre (19)
Senior Vice
President–Land
Randy L. Curry (2)
Senior Vice
President–Midstream
Sarah E. Battisti (2)
Vice President–
Government and
Community Relations
John E. “Jack”
Bergeron, Jr. (9)
Senior Vice President–
Operations
Danny W. Ferguson (12)
Vice President–
Government and
Community Relations
Paul W. Geiger (2)
Senior Vice President–
Corporate Development
Roy D. Hartstein (9)
Vice President–
Strategic Solutions
John C. Gargani (23)
Vice President–
Human Resources
Ron E. Hyden (3)
Vice President–
Technology
Douglas H. Van
Slambrouck (17)
Senior Vice President–
Fayetteville
Shale Division
C. Greg Stoute (11)
Vice President–
Health, Safety and
Environmental,
and Regulatory
David A. Dell’Osso (11)
Vice President–
Northeast Appalachia
Division
Derek W. Cutright (8)
Vice President–
Southwest
Appalachia Division
Harry H. “Sonny”
Bryan (16)
Vice President–
Drilling and
Completions
Stephen M. Guidry (9)
Vice President–
Land, Southwest
Appalachia Division
John R. Lee III (7)
Vice President–
Midstream
Field Operations
R. Jason Kurtz (19)
Vice President–
Marketing
and Transportation
For Executive Officers, years with the Company are shown on this page in parentheses.
For Directors, years served on the Board of Directors are shown on this page in parentheses,
and an asterisk (*) indicates less than one year of service.
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 1
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
Southwestern Energy Company
(Exact name of registrant as specified in its charter)
Delaware
(State or other jurisdiction of
incorporation or organization)
10000 Energy Drive,
Spring, Texas
(Address of principal executive offices)
71-0205415
(I.R.S. Employer
Identification No.)
77389
(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
Common Stock, Par Value $0.01
Depositary Shares, each representing a 1/20th ownership interest in a
share of 6.25% Series B Mandatory Convertible Preferred Stock
Name of each exchange on which registered
New York Stock Exchange
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.
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.
Document Incorporated by Reference
SWN 15
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 2
SOUTHWESTERN ENERGY COMPANY
ANNUAL REPORT ON FORM 10-K
For Fiscal Year Ended December 31, 2016
TABLE OF CONTENTS
PART I
Item 1.
Business
Glossary of Certain Industry Terms
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Item 3.
Item 4. Mine Safety Disclosures
Properties
Legal Proceedings
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Stock Performance Graph
Selected Financial Data
Item 6.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
Results of Operations
Liquidity and Capital Resources
Critical Accounting Policies and Estimates
Cautionary Statement about Forward-Looking Statements
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Financial Statements and Supplementary Data
Item 8.
Index to Consolidated Financial Statements
Changes In and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9.
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
PART IV
Item 15. Exhibits, Financial Statement Schedules
Item 16. Summary
EXHIBIT INDEX
Page
18
39
43
53
54
58
58
59
60
61
63
63
65
70
76
81
82
83
83
130
130
130
131
131
132
132
132
132
132
134
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This Annual Report on Form 10-K includes certain statements that may be deemed to be “forward-looking” within the
meaning of Section 27A of the Securities Act of 1933, or the Securities Act, and Section 21E of the Securities Exchange Act
of 1934, or the Exchange Act. We refer you to “Risk Factors” in Item 1A of Part I and to “Management’s Discussion and
Analysis of Financial Condition and Results of Operations – Cautionary Statement about Forward-Looking Statements” in
Item 7 of Part II of this 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.
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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:
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.
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148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 5
•
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.
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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.
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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.
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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)
Undeveloped (Bcf)
Crude Oil (MMBbls):
Developed (MMBbls)
Undeveloped (MMBbls)
Natural Gas Liquids (MMBbls):
Developed (MMBbls)
Undeveloped (MMBbls)
Total Proved Reserves (Bcfe): (2)
Developed (Bcfe)
Undeveloped (Bcfe)
Percent of Total
Percent Proved Developed
Percent Proved Undeveloped
Production (Bcfe)
Capital Investments (in millions) (3)
Total Gross Producing Wells (4)
Total Net Producing Wells (4)
Total Net Acreage
Net Undeveloped Acreage
PV-10:
Pre-Tax (in millions) (9)
PV of Taxes (in millions) (9)
After-Tax (in millions) (9)
Percent of Total
Percent Operated (10)
$
$
$
1,540
34
1,574
–
–
–
–
–
–
1,540
34
1,574
30%
98%
2%
350
204
820
439
$
293
–
293
10.2
–
10.2
53.8
–
53.8
677
–
677
13%
100%
0%
148
288
306
216
$
2,954
43
2,997
–
–
–
–
–
–
2,954
43
2,997
57%
99%
1%
375
86
4,217
2,932
2
–
2
0.3
–
0.3
0.1
–
0.1
5
–
5
0%
100%
0%
$
2
19
16
13
$
4,789
77
4,866
10.5
–
10.5
53.9
–
53.9
5,176
77
5,253
100%
99%
1%
875
597
5,359
3,600
245,805 (5)
146,096 (5)
321,563 (6)
161,607 (6)
918,535 (7)
285,692 (7)
3,023,386 (8)
3,010,908 (8)
4,509,289
3,604,303
$
$
183
–
183
11%
95%
$
$
163
–
163
10%
100%
$
$
1,325
–
1,325
79%
99%
$
$
(6)
–
(6)
0%
100%
1,665
–
1,665
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) 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
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148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 9
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)
December 31, 2013
Extensions, discoveries and other additions (2)
Total revision attributable to performance and
production (3)
Price revisions
Developed
Disposition of reserves in place
Acquisition of reserves in place (4)
December 31, 2014
Extensions, discoveries and other additions
Total revision attributable to performance and
production (3)
Price revisions
Developed
Disposition of reserves in place
Acquisition of reserves in place
December 31, 2015
Extensions, discoveries and other additions
Total revision attributable to performance and
production (3)
Price revisions
Developed
Disposition of reserves in place
Acquisition of reserves in place
December 31, 2016
Appalachia
Northeast
1,075
589
307
11
(384)
–
–
1,598
138
513
(1,447)
(488)
–
–
314
–
204
(303)
(181)
–
–
34
Southwest
–
–
–
–
–
–
1,481
1,481
4
158
(1,413)
(226)
–
–
4
–
–
(4)
–
–
–
–
Fayetteville
Shale
Other (1)
Total
1,655
573
(130)
24
(406)
–
–
1,716
34
62
(1,357)
(330)
–
–
125
25
(1)
(67)
(39)
–
–
43
7
–
(6)
–
–
–
–
1
–
–
–
–
(1)
–
–
–
–
–
–
–
–
–
2,737
1,162
171
35
(790)
–
1,481
4,796
176
733
(4,217)
(1,044)
(1)
–
443
25
203
(374)
(220)
–
–
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.
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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.
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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
Net developed acres
Total net acres
Net Production (Bcf)
Reserves
Reserves (Bcf)
Locations:
Proved developed
Proved developed non-producing
Proved undeveloped
Total locations
Gross Operated Well Count Summary
Spud or acquired
Completed
Wells to sales
Capital Investments (in millions)
Exploratory and development drilling, including workovers
Acquisition and leasehold
Seismic and other
Capitalized interest and expense
Total capital investments
Average completed well cost (in millions)
Average lateral length (feet)
146,096 (1)
99,709
245,805
174,826
95,509
270,335
205,491
60,582
266,073
350
360
254
1,574
2,319
3,192
820
39
2
861
32
33
24
160
3
2
39
204
5.3
6,142
$
$
$
767
23
36
826
524
13
200
737
177 (2)
92
100
106 (3)
104
88
$
$
$
472
172
8
58
710
5.4
5,403
$
$
$
571
28
30
66
695
6.1
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)
(3)
Includes 86 horizontal and 2 vertical acquired wells.
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.
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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:
Acreage
Net undeveloped acres
Net developed acres
Total net acres
Net Production (Bcfe)
Reserves
Reserves (Bcfe)
Locations:
Proved developed
Proved developed non-producing
Proved undeveloped
Total locations
Gross Operated Well Count Summary
Spud or acquired
Completed
Wells to sales
Capital Investments (in millions)
Exploratory and development drilling, including workovers
Acquisition and leasehold
Seismic and other
Capitalized interest and expense
Total capital investments
Average completed well cost (in millions) (4)
Average lateral length (feet) (4)
For the years ended December 31,
2015
2016
2014
161,607 (1)
159,956
321,563
148
677
306 (2)
44 (2)
–
350 (2)
17
17
18
111
18
1
158
288
6.5
5,499
$
$
$
$
$
$
193,582
231,516
425,098
143
188,244
225,132
413,376
3
611
1,028
400
1
1,429
48
38
47
248
409
2
198
857
6.9
6,985
$
$
$
2,297
1,034
124
344
1,502
1,334 (3)
–
–
3
5,007
–
2
5,012
–
–
(1) Our undeveloped acreage position as of December 31, 2016 had an average royalty interest of 14%.
(2)
(3)
(4)
Includes the impact of legacy assets divested in 2016.
Includes 323 horizontal and 1,011 vertical wells acquired in CHK and STO acquisitions.
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.
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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,
2015
2014
2016
Acreage
Net undeveloped acres (2)
Net developed acres (3)
Total net acres
Net Production (Bcf)
Reserves
Reserves (Bcf)
Locations:
Proved developed
Proved developed non-producing
Proved undeveloped
Total locations
Gross Operated Well Count Summary
Spud or acquired
Completed
Wells to sales
Capital Investments (in millions)
Exploratory and development drilling, including workovers
Acquisition and leasehold
Seismic and other
Capitalized interest and expense
Total capital investments
Average completed well cost (in millions)
Average lateral length (feet)
285,692 (1)
632,843
918,535
288,569
669,072
957,641
267,888
620,273
888,161
375
465
494
2,997
4,217
311
13
4,541
4
34
43
63
2
–
21
86
3.2
5,717
$
$
$
3,281
4,268
231
61
4,560
155
262
260
484
4
8
69
565
2.8
5,729
$
$
$
5,069
4,045
187
1,213
5,445
465
458
455
838
7
4
95
944
2.6
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)
(3)
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.
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,
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
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148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 14
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.
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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.
E&P Capital Investments by Type
Exploratory and development drilling, including workovers
Acquisition and leasehold
Seismic expenditures
Drilling rigs, sand facility and other
Capitalized interest and other expenses
Total E&P capital investments
E&P Capital Investments by Area
Northeast Appalachia
Southwest Appalachia
Fayetteville Shale
Other
Capitalized interest and other expenses
Total E&P capital investments
2016
For the years ended December 31,
2015
(in millions)
2014
$
$
$
$
358
23
1
2
239
623
165
130
65
24
239
623
$
$
$
$
1,226
607
6
40
379
2,258
652
659
496
72
379
2,258
$
$
$
$
1,514
5,328
56
116
240
7,254
629
5,010
849
526
240
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 2014. Operating 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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148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 18
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 employees. None 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
William J. Way
Mark K. Boling
R. Craig Owen
Jennifer N. McCauley
John C. Ale
John E. Bergeron, Jr.
Paul W. Geiger III
Randy L. Curry
James W. Vick
C. Greg Stoute
(1) As of February 21, 2017
Age (1)
57
59
47
53
62
59
45
59
55
55
Officer Position
President and Chief Executive Officer
Executive Vice President and President V+ Development Solutions
Senior Vice President and Chief Financial Officer
Senior Vice President – Administration
Senior Vice President, General Counsel and Secretary
Senior Vice President – E&P Operations
Senior Vice President – Corporate Development
Senior Vice President – Midstream
Senior Vice President – Business Information Systems
Vice President – Health, Safety, Environmental and Regulatory
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 SEC’s 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 SEC’s definition in Item
1208(c)(1) of Regulation S-K, a link for which is available at the SEC’s 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 SEC’s definition in Item 1208(c)(2) of Regulation S-K, a link for which is
available at the SEC’s 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 SEC’s definition in Item 1208(c)(2) of Regulation S-K, a link for which is available at the SEC’s 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 SEC’s
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 SEC’s definition in Item 1208(c)(4) of Regulation S-K, a link for which is available at the
SEC’s 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;
• government regulations, such as regulation of natural gas transportation and price controls;
•
inventory levels; and
• market perceptions of future prices, whether due to the foregoing factors or others.
For example, in 2016 and 2015, our production was approximately 90% and 92% natural gas, respectively, and during
this period spot prices ranged from a low of $1.49 per Mcf in March 2016 to a high of $3.80 per Mcf in December 2016.
In our exploration and production business, lower natural gas, oil and NGL prices directly reduce our revenues and thus
our operating income and cash flow. Lower prices also reduce the projected profitability of further drilling and therefore are
likely to reduce our drilling activity, which in turn means we will have fewer wells on production in the future. Lower prices
also reduce the value of our assets, both by a direct reduction in what the production would be worth and by making some
properties uneconomic, resulting in impairments to the recorded value of our reserves and non-cash charges to earnings. For
example, in 2016, we reported non-cash impairment charges on our natural gas and oil properties totaling $2,321 million,
primarily resulting from decreases in trailing 12-month average first-day-of-the-month natural gas prices throughout 2016,
as compared to 2015, and the impairment of certain undeveloped leasehold interests. Further impairments in subsequent
periods could occur if the trailing 12-month commodity prices continue to fall as compared to the average used in prior
periods.
In our Midstream Services segment, lower production by us and others can mean reduced volumes being transported in
the gathering systems we operate and thus lower revenues.
As of December 31, 2016, we had $4.7 billion of debt outstanding, consisting principally of $3.2 billion in senior notes
maturing in various increments from 2017 to 2025 and $1.5 billion in term loans due in 2020. At current commodity price
levels, our net cash flow from operations is substantially higher than our interest obligations under this debt, but significant
drops in realized prices could affect our ability to pay our current obligations or refinance our debt as it becomes due.
Moreover, general industry conditions may make it difficult or costly to refinance increments of this debt as it matures.
While our indentures do not contain significant covenants restricting our operations and other activities, our 2016 credit
agreement contains financial covenants with which we must comply. We refer you to the risk factor “Our current and future
levels of indebtedness may adversely affect our results and limit our growth.” Our inability to pay our current obligations
or refinance our debt as it becomes due could have a material and adverse effect on our company. The drop in prices in the
past three years has reduced our revenues, profits and cash flow, caused us to record significant asset impairments and led
us to reduce both our level of capital investing and our workforce, which has caused us to incur significant expenses relating
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to employee terminations. Further price decreases could have similar consequences. Similarly, a rise in prices to levels
experienced into the middle of 2014 could significantly increase our revenues, profits and cash flow, which could be used to
expand capital investments.
Significant capital investment is required to replace our reserves and conduct our business.
Our activities require substantial capital investment. We intend to fund our capital investing through net cash flows
from operations, plus the uninvested amount of the proceeds from our July 2016 equity offering and West Virginia acreage
sale earmarked for capital investment (approximately $200 million remaining as of December 31, 2016). Our ability to
generate operating cash flow is subject to many of the risks and uncertainties that exist in our industry, some of which we
may not be able to anticipate at this time. Future cash flows from operations are subject to a number of risks and variables,
such as the level of production from existing wells, prices of natural gas, oil and natural gas liquids, our success in developing
and producing new reserves and the other risk factors discussed herein. If we are unable to fund capital investing, we could
experience a further reduction in drilling new wells and acquiring new acreage, a loss of properties and a decline in our cash
flow from operations and natural gas, oil and natural gas liquids production and reserves.
If we are not able to replace reserves, we may not be able to grow or sustain production.
Our future success depends largely upon our ability to find, develop or acquire additional natural gas, oil and NGL
reserves that are economically recoverable. Unless we replace the reserves we produce through successful exploration,
development or acquisition activities, our proved reserves and production will decline over time. Recovery of such reserves
will require significant capital investment and successful drilling operations. Thus, our future natural gas, oil and NGL
reserves and production, and therefore our cash flow and income, are highly dependent on our level of capital investments,
our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable
reserves.
A further downgrade in our credit rating could negatively impact our cost of and ability to access capital and our liquidity.
Actual or anticipated changes or downgrades in our credit ratings, including any announcement that our ratings are under
further review for a downgrade, could impact our ability to access debt markets in the future, affect the market value of our
senior notes and increase our corporate borrowing costs. Such ratings are limited in scope, and do not address all material
risks relating to us, but rather reflect only the view of each rating agency at the time the rating is issued of the likelihood we
will be able to repay our debt. An explanation of the significance of each rating may be obtained from the applicable rating
agency. As of February 21, 2017, we were rated Ba3 by Moody’s, BB- by Standard and Poor’s and BB by Fitch Investor
Services. There can be no assurance that such credit ratings will remain in effect for any given period of time or that such
ratings will not be lowered, suspended or withdrawn entirely by the rating agencies, if, in each rating agency’s judgment,
circumstances so warrant.
Actual downgrades in our credit ratings may also impact our liquidity. Many of our existing commercial contracts
contain, and future commercial contracts may contain, provisions permitting the counterparty to require increased security
upon the occurrence of a downgrade in our credit rating. Providing additional security, such as posting letters of credit, could
reduce our available cash or our liquidity under our revolving credit facility for other purposes. We had $174 million of
letters of credit outstanding at December 31, 2016. The amount of additional security would depend on the severity of the
downgrade from the credit rating agencies, and a downgrade could result in a decrease in our liquidity.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are
challenging in the face of shifting market conditions, and our failure to appropriately allocate capital and resources
among our strategic opportunities may adversely affect our financial condition and reduce our future growth rate.
We necessarily must consider future price and cost environments when deciding how much capital we are likely to have
available from net cash flow and how best to allocate it. Our current philosophy is to generally operate within cash flow
from operations and to invest capital in projects only if they are projected to generate a PVI of 1.3 or greater, allocating
generally to the highest PVI projects. Volatility in prices and potential errors in estimating costs, reserves or timing of
production of the reserves could result in uneconomic projects or economic projects generating less than 1.3 PVI.
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.
Leases on approximately 159,176 net acres of our Fayetteville Shale acreage (including 158,231 net acres held on federal
lands that are currently suspended by the Bureau of Land Management) will expire in the next three years if we do not drill
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successful wells to develop the acreage or otherwise take action to extend the leases. Approximately 91,379 and 62,520 net
acres of our Northeast Appalachia and Southwest Appalachia acreage, respectively, will expire in the next three years if we
do not drill successful wells to develop the acreage or otherwise take action to extend the leases. Our ability to drill wells
depends on a number of factors, including certain factors that are beyond our control, such as the ability to obtain permits on
a timely basis or to compel landowners or lease holders on adjacent properties to cooperate. Further, we may not have
sufficient capital to drill all the wells necessary to hold the acreage without increasing our debt levels, or given price
projections at the time, drilling may not be estimated to achieve a PVI of at least 1.3. To the extent we do not drill the wells,
our rights to acreage can be lost.
Natural gas and oil drilling and producing operations and midstream operation can be hazardous and may expose us to
liabilities.
Exploration and production operations are subject to many risks, including well blowouts, cratering and explosions, pipe
failures, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, severe
weather, natural disasters, groundwater contamination and other environmental hazards and risks. Some of these risks or
hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells,
loss of equipment or otherwise negatively impacting the projected economic performance of our prospects. If any of these
risks occurs, we could sustain substantial losses as a result of:
•
•
•
•
•
•
injury or loss of life;
severe damage to or destruction of property, natural resources or equipment;
pollution or other environmental damage;
clean-up responsibilities;
regulatory investigations and administrative, civil and criminal penalties; and
injunctions resulting in limitation or suspension of operations.
For our non-operated properties, we are dependent on the operator for operational and regulatory compliance.
Our midstream operations are subject to all of the risks and operational hazards inherent in transporting natural gas and
ethane and natural gas compression, including:
•
damages to pipelines, facilities and surrounding properties caused by third parties, severe weather, natural disasters,
including hurricanes, and acts of terrorism;
• maintenance, repairs, mechanical or structural failures;
•
•
•
damages to, loss of availability of and delays in gaining access to interconnecting third-party pipelines;
disruption or failure of information technology systems and network infrastructure due to various causes, including
unauthorized access or attack; and
leaks of natural gas or ethane as a result of the malfunction of equipment or facilities.
A material event such as those described above could expose us to liabilities, monetary penalties or interruptions in our
business operations. Although we may maintain insurance against some, but not all, of the risks described above, our
insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that
may be assessed by a governmental authority. Also, in the future we may not be able to obtain insurance at premium levels
that justify its purchase.
Our current and future levels of indebtedness may adversely affect our results and limit our growth.
At December 31, 2016, we had long-term indebtedness of $4.6 billion, including borrowings of $327 million and $1.2
billion under our term loan credit agreements. The terms of the indentures relating to our outstanding senior notes, our credit
facilities, and the master lease agreements relating to our drilling rigs and other equipment, which we collectively refer to as
our “financing agreements,” impose restrictions on our ability and, in some cases, the ability of our subsidiaries to take a
number of actions that we may otherwise desire to take, which may include, without limitation, one or more of the following:
•
•
incurring additional debt;
redeeming stock or redeeming certain debt;
• making certain investments;
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•
•
creating liens on our assets; and
selling assets.
Under the 2013 revolving credit facility, we must keep our total debt at or below 60% of our total adjusted book capital.
This financial covenant with respect to capitalization percentages excludes the effects of any non-cash impacts from any full
cost ceiling impairments, certain non-cash hedging activities and our pension and other post-retirement liabilities. Therefore,
under the 2013 revolving credit facility, our adjusted capital structure as of December 31, 2016 was 34% debt and 66%
equity. Under our 2016 credit agreement, we must maintain certain covenants, including, among others, the following
financial covenants:
• Minimum liquidity of $300 million, subject to increase up to $500 million upon certain conditions;
• Minimum interest coverage ratio of no less than (i) with respect to any fiscal quarter ended on or before
December 31, 2016, 0.75x, (ii) with respect to any fiscal quarter ending on or after March 31, 2017 and on or
before December 31, 2017, 1.00x, (iii) with respect to any fiscal quarter ending on or after March 31, 2018
and on or before December 31, 2018, 1.25x and (iv) with respect to any fiscal quarter ending on or after March
31, 2019, 1.50x, commencing with the fiscal quarter ending June 30, 2016; and
• With respect to the secured term loan, a minimum collateral coverage ratio of no less than 1.50x of the secured
term loan. Currently this collateral consists of most of our interest in E&P properties in the Fayetteville Shale
area, the equity in our subsidiaries and cash and marketable securities.
Although we do not anticipate any violations of our financial covenants, our ability to comply with these covenants
are dependent upon the success of our exploration and development program and upon factors beyond our control, such as
the market prices for natural gas, oil and NGLs.
Although the indentures governing the notes contain covenants that apply to us, covenants limiting liens and sale and
leaseback covenants contain exceptions and limitations that would allow us, pursuant to the terms of the indenture, to create,
grant or incur certain liens or security interests. Moreover, the indentures do not contain any limitations on the ability of us
or our subsidiaries to incur debt, pay dividends, make investments, or limit the ability of our subsidiaries to make distributions
to us. Such activities may, however, be limited by our other financing agreements in certain circumstances.
Our level of indebtedness and off-balance sheet obligations, and the covenants contained in our financing agreements,
could have important consequences for our operations, including:
•
•
•
•
requiring us to dedicate a substantial portion of our cash flow from operations to required payments, thereby
reducing the availability of cash flow for working capital, capital investing and other general business activities;
limiting our ability to obtain additional financing in the future for working capital, capital investing, acquisitions
and general corporate and other activities;
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
and
detracting from our ability to successfully withstand a downturn in our business or the economy generally.
Our ability to comply with the covenants and other restrictions in our financing agreements may be affected by events
beyond our control, including prevailing economic and financial conditions.
If we fail to comply with the covenants and other restrictions, it could lead to an event of default and the acceleration of
our obligations under the notes or our other financing agreements, and in the case of the lease agreements for drilling rigs,
loss of use of our drilling rigs. In particular, a significant or extended decline in natural gas, oil or NGL prices would have
a material adverse effect on our results of operations, our access to capital and the quantities of natural gas, oil and NGLs
that we can produce economically. For example, the New York Mercantile Exchange, or NYMEX, natural gas prices traded
at a low of $1.71 in February 2016 and a high of $3.23 in December 2016 based on the settlement price of the monthly
contract at expiration. If we are unable to satisfy our obligations with cash on hand, we could attempt to refinance such debt,
sell assets or repay such debt with the proceeds from an equity offering. We cannot assure that we will be able to generate
sufficient cash flow to pay the interest on our debt, to meet our lease obligations, or that future borrowings, equity financings
or proceeds from the sale of assets will be available to pay or refinance such debt or obligations. The terms of our financing
agreements may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering
of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value
and operating performance at the time of such offering or other financing. We cannot assure that any such proposed offering,
refinancing or sale of assets can be successfully completed or, if completed, that the terms will be favorable to us.
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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.
Through December 31, 2016, we had invested approximately $1.3 billion in our gas gathering system built for the
Fayetteville Shale. We may make further substantial investments in the expansion of this system. Our ability to recover the
costs of these investments depends on production from the Fayetteville Shale, and reduced production volumes, whether due
to lower drilling activity due to lower prices or failure to produce significant quantities of gas in relevant timeframes, can
adversely affect our ability to recover these investments.
We also have entered into gathering agreements in other producing areas and multiple long-term firm transportation
agreements relating to natural gas volumes from all our producing areas. As of December 31, 2016, our aggregate demand
charge commitments under these firm transportation agreements and gathering agreements were approximately $8.4 billion.
If our development programs fail to produce sufficient quantities of natural gas and ethane within expected timeframes, we
could be forced to pay demand or other charges for transportation on pipelines and gathering systems that we would not be
using.
We also have made significant investments to meet certain of our field services’ needs, including establishing our own
drilling rig operation, sand mine and pressure pumping capability. Reductions in our operating plans caused by the recent
drop in commodity prices has caused us to take much of this equipment out of service and has reduced the need for sand and
other services. If our level of operations is reduced for a long period, we may not be able to recover these investments.
Further, our presence in these service and supply sectors, including competing with them for qualified personnel and supplies,
may have an adverse effect on our relationships with our existing third-party service and resource providers or our ability to
secure these services and resources from other providers.
Our business depends on access to natural gas, oil and NGL transportation systems and facilities.
The marketability of our natural gas, oil and NGL production depends in large part on the operation, availability,
proximity, capacity and expansion of transportation systems and facilities owned by third parties. For example, we can
provide no assurance that sufficient transportation capacity will exist for expected production from the Appalachian Basin
or that we will be able to obtain sufficient transportation capacity on economic terms. During the past year, several planned
pipelines intended to service production in the U.S. Northeast have had their in-service dates delayed due to regulatory delays
and litigation.
Producers compete by lowering their sales prices, resulting in the locational differences from NYMEX pricing.
Further, a lack of available capacity on transportation systems and facilities or delays in their planned expansions could result
in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of availability of these
systems and facilities for an extended period of time could negatively affect our revenues. In addition, we have entered into
contracts for firm transportation and any failure to renew those contracts on the same or better commercial terms could
increase our costs and our exposure to the risks described above.
Our business depends on the availability of water and the ability to dispose of water. Limitations or restrictions on our
ability to obtain or dispose of water may have an adverse effect on our financial condition, results of operations and cash
flows.
With current technology, water is an essential component of drilling and hydraulic fracturing processes. Limitations or
restrictions on our ability to secure sufficient amounts of water, or to dispose of or recycle water after use, could adversely
impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling sites,
resulting in increased costs. Moreover, the introduction of new environmental initiatives and regulations related to water
acquisition or waste water disposal, including produced water, drilling fluids and other wastes associated with the
exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize hydraulic fracturing or
waste water injection control wells.
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 natural gas and oil activities. New rules and
regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in
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certain locations and increasing the cost of disposal in others. 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 seismic.
Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of water
necessary for hydraulic fracturing of wells or the disposal of water may increase our operating costs or may cause us to delay,
curtail or discontinue our exploration and development plans, which could have a material adverse effect on our business,
financial condition, results of operations and cash flows.
Our producing properties are concentrated in two regions, the Appalachian Basin and the Fayetteville Shale, making us
vulnerable to risks associated with operating in limited geographic areas.
Our producing properties are geographically concentrated in the Fayetteville Shale in Arkansas and the Appalachian
Basin in Pennsylvania and West Virginia. At December 31, 2016, 43% of our total estimated proved reserves were
attributable to properties located in the Appalachian Basin and 57% in the Fayetteville Shale. As a result of this concentration
in two primary regions, we may be disproportionately exposed to the impact of regional supply and demand factors, delays
or interruptions of production from wells in this area caused by governmental regulation, state politics, processing or
transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or
interruption of the processing or transportation of natural gas, oil or natural gas liquids.
Competition in the oil and natural gas industry is intense, making it more difficult for us to market natural gas, oil and
NGLs, to secure trained personnel and appropriate services, to obtain additional properties and to raise capital.
The cost of our operations is highly dependent on third-party services, and as activity in our industry increases,
competition for these services may increase. Similarly, we must have trained, qualified personnel, and as commodity prices
rise, competition for this talent also increases. Our ability to acquire and develop reserves in the future will depend on our
ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for
acquiring properties, marketing natural gas, oil and NGLs and securing trained personnel. Also, there is substantial
competition for capital available for investment in the oil and gas industry. Certain of our competitors may possess and
employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for
personnel, property and services and to attract capital at lower rates. This may become more likely if prices for oil and NGLs
recover faster than prices for natural gas, as natural gas comprises a far greater percentage of our overall production than it
does for most of the companies with whom we compete for talent.
Volatility in the financial markets or in global economic factors could adversely impact our business and financial
condition.
Our business may be negatively impacted by adverse economic conditions or future disruptions in global financial
markets. Included among these potential negative impacts are reduced energy demand and lower commodity prices, increased
difficulty in collecting amounts owed to us by our customers and reduced access to credit markets. Our ability to access the
capital markets may be restricted at a time when we would like, or need, to raise financing. If financing is not available
when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise
take advantage of business opportunities or respond to competitive pressures.
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.
Our natural gas and oil exploration and production operations are subject to complex and stringent federal, state and
local laws and regulations, including those governing environmental protection, the occupational health and safety aspects
of our operations, the discharge of materials into the environment, and the protection of certain plant and animal species.
See “Other — Environmental Regulation” in Item 1 of Part I of this Annual Report for a description of the laws and
regulations that affect us. In order to conduct operations in compliance with these laws and regulations, we must obtain and
maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities.
Environmental regulations may restrict the types, quantities and concentration of materials that can be released into the
environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying
within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our
operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or
interrupt our operations and limit our growth and revenues.
Failure to comply with laws and regulations may trigger a variety of administrative, civil and criminal enforcement
measures, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, or
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the issuance of orders or judgments limiting or enjoining future operations. Strict liability or joint and several liability may
be imposed under certain laws, which could cause us to become liable for the conduct of others or for consequences of our
own actions. Moreover, our costs of compliance with existing laws could be substantial and may increase or unforeseen
liabilities could be imposed if existing laws and regulations are revised or reinterpreted, or if new laws and regulations
become applicable to our operations. If we are not able to recover the increased costs through insurance or increased
revenues, our business, financial condition, results of operations and cash flows could be adversely affected.
Climate change legislation or regulations governing the emissions of “greenhouse gases” could result in increased
operating costs and reduce demand for the natural gas, oil and NGLs we produce.
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 natural gas and oil production sources in the United States on an annual basis, which include certain of
our operations. More recently, in May 2016, the EPA finalized additional regulations to control methane and volatile organic
compound emissions from certain oil and gas equipment and 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.
In December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse
gas emissions. The agreement entered into force 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 natural gas industry, it could
have an adverse effect on our business.
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.
As described in more detail under “Critical Accounting Policies and Estimates – Natural Gas and Oil Properties” in Item
7 of Part II of this Annual Report, our reserve data represents the estimates of our reservoir engineers made under the
supervision of our management, and our reserve estimates are audited each year by Netherland, Sewell & Associates, Inc.,
or NSAI, an independent petroleum engineering firm. Reserve engineering is a subjective process of estimating underground
accumulations of natural gas, oil and NGLs that cannot be measured in an exact manner. The process of estimating quantities
of proved reserves is complex and inherently imprecise, and the reserve data included in this document are only estimates.
The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality
and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are
mandated by the SEC, such as natural gas, oil and NGL prices. Additional assumptions include drilling and operating
expenses, capital investing, taxes and availability of funds. Furthermore, different reserve engineers may make different
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estimates of reserves and cash flows based on the same data.
Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate.
Accordingly, initial reserve estimates often vary from the quantities of natural gas, oil and NGLS that are ultimately
recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present
value of our reserves.
You should not assume that the present value of future net cash flows from our proved reserves is the current market
value of our estimated natural gas, oil and NGL reserves. In accordance with SEC requirements, we base the estimated
discounted future net cash flows from our proved reserves on the 12-month average natural gas, oil and NGL index prices,
calculated as the unweighted arithmetic average for the first day of the month price for each month and costs in effect on the
date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs
may differ materially from those used in the net present value estimate, and future net present value estimates using then
current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when
calculating discounted future net cash flows for reporting requirements in compliance with the applicable accounting
standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks
associated with us or the oil and gas industry in general.
Our commodity price risk management and measurement systems and economic hedging activities might not be effective
and could increase the volatility of our results.
We currently seek to hedge the price of a significant portion of our estimated production, through swaps, collars, floors
and other derivative instruments. The systems we use to quantify commodity price risk associated with our businesses might
not always be followed or might not always be effective. Further, such systems do not in themselves manage risk, particularly
risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of
commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this report might still
adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been
identified. Furthermore, no single hedging arrangement can adequately address all risks present in a given contract. For
example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the
contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist.
Our use of derivatives, through which we attempt to reduce the economic risk of our participation in commodity markets
could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that
qualify as hedges under GAAP to the extent that such hedges are not fully effective in offsetting changes to the value of the
hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as
hedges under GAAP, must be recorded in our income. This creates the risk of volatility in earnings even if no economic
impact to us has occurred during the applicable period.
The impact of changes in market prices for oil, natural gas and NGLs on the average prices paid or received by us may
be reduced based on the level of our hedging activities. These hedging arrangements may limit or enhance our margins if
the market prices for oil, natural gas or NGLs were to change substantially from the price established by the hedges. In
addition, our hedging arrangements expose us to the risk of financial loss if our production volumes are less than expected.
We may be unable to dispose of assets on attractive terms, and may be required to retain liabilities for certain matters.
Various factors could materially affect our ability to dispose of assets or complete announced dispositions, including the
availability of purchasers willing to purchase the assets at prices acceptable to us, particularly in times of reduced and volatile
commodity prices. Sellers typically retain certain liabilities for certain matters. The magnitude of any such retained liability
or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also,
as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support
provided prior to the sale of the divested assets. As a result, after a sale, we may remain secondarily liable for the obligations
guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
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The implementation of derivatives legislation could have an adverse effect on our ability to use derivative instruments to
reduce the effect of commodity price, interest rate and other risks associated with our business.
The Dodd-Frank Act established federal oversight and regulation of the over-the-counter (“OTC”) derivatives market
and entities, including us, which participate in that market. The Dodd-Frank Act requires the CFTC, the SEC, and other
regulatory authorities to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has
finalized most of its regulations under the Dodd-Frank Act, it continues to review and refine its initial rulemakings through
additional interpretations and supplemental rulemakings. As a result, it is not possible at this time to predict the ultimate
effect of the rules and regulations on our business and while most of the regulations have been adopted, any new regulations
or modifications to existing regulations may increase the cost of derivative contracts, limit the availability of derivatives to
protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and
increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank
Act and the regulations thereunder, our results of operations may become more volatile and our cash flows may be less
predictable, which could adversely affect our ability to plan for and fund capital investing.
In December 2016, the CFTC re-proposed new rules that would place federal limits on positions in certain core futures
and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide
hedging transactions and finalized a companion rule on aggregation of positions among entities under common ownership
or control. If finalized, the position limits rule may have an impact on our ability to hedge our exposure to certain enumerated
commodities.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and mandatory
trading on designated contract markets or swap execution facilities. The CFTC may designate additional classes of swaps
as subject to the mandatory clearing requirement in the future, but has not yet proposed rules designating any other classes
of swaps, including physical commodity swaps, for mandatory clearing. The CFTC and prudential banking regulators also
adopted mandatory margin requirements on uncleared swaps between swap dealers and certain other counterparties. The
margin requirements are currently effective with respect to certain market participants and will be phased in over time with
respect to other market participants, based on the level of an entity’s swaps activity. We expect to qualify for and rely upon
an end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge our
commercial risks. We also should qualify for an exception from the uncleared swaps margin requirements. However, the
application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirement to other
market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.
Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and
production may be eliminated as a result of future legislation.
The elimination of certain key U.S. federal income tax deductions currently available to oil and natural gas exploration
and production companies has been proposed in recent years by members of the U.S. Congress and by former President
Obama in his fiscal year 2017 budget proposal. These changes have included, among other proposals:
•
•
•
•
repeal of the percentage depletion allowance for natural gas and oil properties;
elimination of current deductions for intangible drilling and development costs;
elimination of the deduction for certain domestic production activities; and
extension of the amortization period for certain geological and geophysical expenditures.
It is unclear whether these or similar changes will be enacted. The passage of these or any similar changes in U.S.
federal income tax laws to eliminate or postpone certain tax deductions that are currently available with respect to oil and
natural gas exploration and development could have an adverse effect on our financial position, results of operations and
cash flows.
We may experience adverse or unforeseen tax consequences due to further developments affecting our deferred tax assets
that could significantly affect our results.
Deferred tax assets, including net operating loss carryforwards, represent future savings of taxes that would otherwise
be paid in cash. At December 31, 2016, the Company had substantial amounts of net operating loss carryforwards for U.S.
federal and state income tax purposes. These loss carryforwards will eventually expire if not utilized. In addition, limitations
may exist upon use of these carryforwards in the event that a change in control of the Company occurs. A valuation allowance
for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the
benefit from the deferred tax asset will not be realized. At December 31, 2016, the Company recorded a valuation allowance
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against its entire deferred tax asset, including the portion related to the remaining net operating loss carryforwards. This
allowance was recorded primarily as a result of cumulative book losses experienced over the three-year period ending
December 31, 2016. If we experience additional book losses, we may be required to increase our valuation allowance against
our deferred tax assets.
Our existing deferred tax asset valuation allowance may also be reversed if significant events occur or market conditions
change materially, and our current or future earnings are, or are projected to be, significantly higher than we currently
estimate. This reversal may result in a significant one-time favorable impact positively affecting our consolidated results of
operations for the period of reversal and for the full fiscal year results.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
Our business has become increasingly dependent on digital technologies to conduct day-to-day operations including
certain exploration, development and production activities. We depend on digital technology, including information systems
and related infrastructure as well as cloud applications and services, to process and record financial and operating data,
analyze seismic and drilling information, conduct reservoir modeling and reserves estimation, communicate with employees
and business associates, perform compliance reporting and in many other activities related to our business. Our business
associates, including vendors, service providers, purchasers of our production, and financial institutions are also dependent
on digital technology.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional
events, have also increased. Our technologies, systems, networks, and those of our business associates may become the
target of cyber-attacks or information security breaches, which could lead to disruptions in critical systems, unauthorized
release of confidential or protected information, corruption of data or other disruptions of our business operations. In
addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber-attack involving our information systems and related infrastructure, or that of our business associates, could
disrupt our business and negatively impact our operations in a variety of ways, including:
•
•
•
•
•
unauthorized access to seismic data, reserves information, strategic information or other sensitive or proprietary
information could have a negative impact on our ability to compete for natural gas and oil resources;
unauthorized access to personal identifying information of royalty owners, employees and vendors, which could
expose us to allegations that we did not sufficiently protect that information;
data corruption or operational disruption of production infrastructure could result in loss of production, or accidental
discharge;
a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our
major development projects; and
a cyber-attack on a third party gathering, pipeline or rail service provider could delay or prevent us from marketing
our production, resulting in a loss of revenues.
These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential
liability, which could have a material adverse effect on our financial condition, results of operations or cash flows.
To date we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that
we will not suffer such losses in the future. As cyber threats continue to evolve, we may be required to expend significant
additional resources to continue to modify or enhance our protective measures or to investigate and remediate any
information security vulnerabilities.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by
advocacy groups about hydraulic fracturing, seismicity, oil spills and explosions of natural gas transmission lines, may lead
to regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines
and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs,
additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable
discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through
intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be
withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.
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Common stockholders will be diluted if additional shares are issued.
In July 2016, we consummated an underwritten offering of 98.9 million shares of our common stock pursuant to an
effective registration statement filed with the Securities and Exchange Commission, with net proceeds of the offering totaling
approximately $1,247 million after underwriting discounts and offering expenses. The proceeds from the offering were used
to repay $375 million of the $750 million term loan entered into in November 2015 and to settle certain tender offers by
purchasing an aggregate principal amount of approximately $700 million of our outstanding senior notes due in the first
quarter of 2018. The remaining net proceeds of the offering have been and will be used for general corporate purposes,
including the completion of wells already drilled or the funding of other capital projects.
In January 2015, we issued 30.0 million shares of common stock and 34.5 million depositary shares representing the
1/20th interest in our 6.25% Series B Mandatory Preferred Stock, which will convert into a minimum of approximately 64
million or a maximum of 75 million shares of common stock by January 2018, to refinance a portion of the debt we incurred
to purchase acreage in West Virginia and southwest Pennsylvania. Dividends on our 6.25% Series B Mandatory Preferred
Stock are payable quarterly until they convert to common stock in January 2018, which dividends we may pay in cash or
shares of our common stock. During 2016, we issued approximately 6.9 million shares of our common stock to satisfy our
dividend obligations, and we may continue to issue common stock in satisfaction of our dividend obligation in 2017. We
also issue restricted stock, options and performance share units to our employees and directors as part of their compensation.
In addition, we may issue additional shares of common stock, additional notes or other securities or debt convertible into
common stock, to extend maturities or fund capital expenditures. If we issue additional shares of our common stock in the
future, it may have a dilutive effect on our current outstanding stockholders.
Anti-takeover provisions in our organizational documents and under Delaware law may impede or discourage a takeover,
which could cause the market price of our common stock to decline.
We are a Delaware corporation, and the anti-takeover provisions of Delaware law impose various impediments to the
ability of a third party to acquire control of us, even if a change in control would be beneficial to our existing stockholders,
which, under certain circumstances, could reduce the market price of our common stock. In addition, protective provisions
in our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws or the implementation by our
board of directors of a stockholder rights plan that could deter a takeover.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
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ITEM 2. PROPERTIES
The summary of our oil and natural gas reserves as of fiscal year-end 2016 based on average fiscal-year prices, as
required by Item 1202 of Regulation S-K, is included in the table headed “2016 Proved Reserves by Category and Summary
Operating Data” in “Business – Exploration and Production – Our Proved Reserves” in Item 1 of this Annual Report and
incorporated by reference into this Item 2.
The information regarding our proved undeveloped reserves required by Item 1203 of Regulation S-K is included under
the heading “Proved Undeveloped Reserves” in “Business – Exploration and Production – Our Proved Reserves” in Item 1
of this Annual Report.
The information regarding delivery commitments required by Item 1207 of Regulation S-K is included under the heading
“Sales, Delivery Commitments and Customers” in the “Business – Exploration and Production – Our Operations” in Item 1
of this Annual Report and incorporated by reference into this Item 2. For additional information about our natural gas and
oil operations, we refer you to “Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report. For
information concerning capital investments, we refer you to “Management’s Discussion and Analysis of Financial Condition
and Results of Operations — Liquidity and Capital Resources — Capital Investments.” We also refer you to Item 6,
“Selected Financial Data” in Part II of this Annual Report for information concerning natural gas, oil and NGLs produced.
The information regarding natural gas and oil properties, wells, operations and acreage required by Item 1208 of
Regulation S-K is set forth below:
Leasehold acreage as of December 31, 2016
Appalachia:
Northeast (1)
Southwest (2)
Fayetteville Shale (3)
Other:
US – Brown Dense (4)
US – Sand Wash Basin (5)
US – Other (6)
Canada – New Brunswick (7)
Undeveloped
Gross
Net
Developed
Total
Gross
Net
Gross
Net
152,019
362,573
368,305
146,096
161,607
285,692
190,638
172,430
606,241
2,518,519
4,370,725
142,184
119,958
230,247
2,518,519
3,604,303
104,888
264,948
985,459
4,903
11,181
–
–
1,371,379
99,709
159,956
632,843
4,493
7,985
–
–
904,986
256,907
627,521
1,353,764
195,541
183,611
606,241
2,518,519
5,742,104
245,805
321,563
918,535
146,677
127,943
230,247
2,518,519
4,509,289
(1) 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.
(2) 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.
(3) 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).
(4) Assuming successful wells are not drilled to develop the acreage and leases are not extended in the Lower Smackover Brown Dense, 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.
(5) Assuming successful wells are not drilled to develop the acreage and leases are not extended in the Sand Wash Basin, 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.
(6) Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be
68,556 net acres in 2017, 21,982 net acres in 2018 and 103,172 net acres in 2019.
(7) Assuming successful wells are not drilled to develop the acreage and our exploration license agreements are not extended, the full acreage of 2,518,519
will expire in March 2021.
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Producing wells as of December 31, 2016
Appalachia:
Northeast
Southwest
Fayetteville Shale
Other
Natural Gas
Oil
Total
Gross
Net
Gross
Net
Gross
Net
Gross Wells
Operated
506
324
4,705
11
5,546
446
228
3,242
8
3,924
–
–
–
14
14
–
–
–
14
14
506
324
4,705
25
5,560
446
228
3,242
22
3,938
453
303
4,039
25
4,820
The information regarding drilling and other exploratory and development activities required by Item 1205 of Regulation
S-K is set forth below:
Year
2016
Appalachia:
Northeast
Southwest
Fayetteville Shale
Other
Total
2015
Appalachia:
Northeast
Southwest
Fayetteville Shale
Other
Total
2014
Appalachia:
Northeast
Southwest
Fayetteville Shale
Other
Total
Year
2016
Appalachia:
Northeast
Southwest
Fayetteville Shale
Other
Total
2015
Appalachia:
Northeast
Southwest
Fayetteville Shale
Other
Total
2014
Appalachia:
Northeast
Southwest
Fayetteville Shale
Other
Total
Productive Wells
Gross
Net
Exploratory
Dry Wells
Total
Gross
Net
Gross
Net
1.0
–
–
–
1.0
1.0
–
–
2.0
3.0
3.0
–
–
9.0
12.0
1.0
–
–
–
1.0
1.0
–
–
2.0
3.0
2.9
–
–
9.0
11.9
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1.0
–
–
–
1.0
1.0
–
–
2.0
3.0
3.0
–
–
9.0
12.0
1.0
–
–
–
1.0
1.0
–
–
2.0
3.0
2.9
–
–
9.0
11.9
Productive Wells
Gross
Net
Development
Dry Wells
Total
Gross
Net
Gross
Net
23.0
18.0
43.0
–
84.0
99.0
63.0
265.0
–
427.0
104.0
–
468.0
–
572.0
22.9
13.4
35.2
–
71.5
98.5
36.6
209.4
–
344.5
88.2
–
377.9
–
466.1
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
23.0
18.0
43.0
–
84.0
99.0
63.0
265.0
–
427.0
104.0
–
468.0
–
572.0
22.9
13.4
35.2
–
71.5
98.5
36.6
209.4
–
344.5
88.2
–
377.9
–
466.1
SWN 55
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 42
The following table presents the information regarding our present activities required by Item 1206 of Regulation S-K:
Wells in progress as of December 31, 2016
Gross
Net
Drilling:
Appalachia:
Northeast
Southwest
Fayetteville Shale
Other
Total
Completing:
Appalachia:
Northeast
Southwest
Fayetteville Shale
Other
Total
Drilling & Completing:
Appalachia:
Northeast
Southwest
Fayetteville Shale
Other
Total
(1)
Includes 35 gross wells that are waiting on pipeline or production facilities.
57.0
20.0
17.0
–
94.0
16.0
22.0
3.0
–
41.0 (1)
73.0
42.0
20.0
–
135.0
56.4
14.9
16.6
–
87.9
15.9
16.9
2.9
–
35.7
72.3
31.8
19.5
–
123.6
SWN 56
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 43
The information regarding oil and gas production, production prices and production costs required by Item 1204 of
Regulation S-K is set forth below:
Production, Average Sales Price and Average Production Cost
For the years ended December 31,
2015
2014
2016
Natural Gas
Production (Bcf):
Northeast Appalachia
Southwest Appalachia
Fayetteville Shale
Other
Total
Average realized gas price per Mcf, excluding derivatives:
Northeast Appalachia
Southwest Appalachia
Fayetteville Shale
Total
Average realized gas price per Mcf, including derivatives
Oil
Production (MBbls):
Southwest Appalachia
Other
Total
Average realized oil price per Bbl:
Southwest Appalachia
Other
Total
NGL
Production (MBbls):
Southwest Appalachia
Other
Total
Average realized NGL price per Bbl:
Southwest Appalachia
Other
Total
Total Production (Bcfe)
Northeast Appalachia
Southwest Appalachia
Fayetteville Shale
Other
Total
Average Production Cost
Cost per Mcfe, excluding ad valorem and severance taxes:
Northeast Appalachia
Southwest Appalachia
Fayetteville Shale
Total
350
62
375
1
788
1.34
1.71
1.80
1.59
1.64
2,041
151
2,192
$
$
$
360
67
465
7
899
1.62
1.92
2.12
1.91
2.37
2,036
229
2,265
$
$
$
254
2
494
16
766
3.48
3.61
3.86
3.74
3.72
45
190
235
30.59
39.44
31.20
$
$
31.80
46.21
33.25
$
$
41.28
89.04
79.91
12,317
55
12,372
10,640
62
10,702
7.41
17.33
7.46
$
$
6.76
14.51
6.80
$
$
350
148
375
2
875
360
143
465
8
976
0.76
1.05
0.89
0.87
$
$
0.71
1.39
0.91
0.92
$
$
182
49
231
10.44
35.22
15.72
254
3
494
17
768
0.83
1.17
0.92
0.91
$
$
$
$
$
$
$
$
$
During 2016, we were required to file Form 23, “Annual Survey of Domestic Oil and Gas Reserves,” with the U.S.
Department of Energy. The basis for reporting reserves on Form 23 is not comparable to the reserve data included in
“Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report. The primary differences are that Form
23 reports gross reserves, including the royalty owners’ share, and includes reserves for only those properties of which we
are the operator.
SWN 57
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 44
Miles of Pipe
As of December 31, 2016, our Midstream Services segment had 2,045 miles and 16 miles of pipe in its gathering systems
located in Arkansas and Louisiana, respectively.
Title to Properties
We believe that we have satisfactory title to substantially all of our active properties in accordance with standards
generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty and overriding royalty
interests, certain contracts relating to the exploration, development, operation and marketing of production from such
properties, consents to assignment and preferential purchase rights, liens for current taxes, applicable laws and other burdens,
encumbrances and irregularities in title, which we believe do not materially interfere with the use of or affect the value of
such properties. Substantially all our Fayetteville Shale properties are subject to liens securing our 2016 credit facility. Prior
to acquiring undeveloped properties, we endeavor to perform a title investigation that is thorough but less vigorous than that
we endeavor to conduct prior to drilling, which is consistent with standard practice in the oil and natural gas industry.
Generally, before we commence drilling operations on properties that we operate, we conduct a title examination and perform
curative work with respect to significant defects that we identify. We believe that we have performed title examination with
respect to substantially all of our active properties that we operate.
ITEM 3. LEGAL PROCEEDINGS
We are subject to litigation, claims and proceedings that arise in the ordinary course of business, such as for alleged
breaches of contract, miscalculation of royalties and pollution, contamination or nuisance. Management believes that such
litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have
a material adverse impact on our financial position, results of operations or cash flows. Many of these matters are in early
stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties;
therefore, management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the
possibility of a material impact on our financial position, results of operations or cash flows for the period in which the effect
becomes reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably
estimated.
Berry-Helfand (Tovah Energy)
In February 2009, one of our subsidiaries was added as a defendant in a case then styled Tovah Energy, LLC and Toby
Berry-Helfand v. David Michael Grimes, et al., then pending in the 273rd District Court in Shelby County, Texas. The
plaintiff alleged that the subsidiary used information provided by the plaintiff under a confidentiality agreement, which she
claimed, among other things, breached the agreement and constituted a trade secret. Following a trial in December 2010,
the court awarded approximately $11 million in actual damages and approximately $24 million in disgorgement of profits,
along with interest and attorneys’ fees. Both sides appealed, and in July 2013 the Texas Court of Appeals for the Twelfth
District reversed on all claims except misappropriation of trade secrets, reduced the judgment to the actual damages award,
along with interest and attorneys’ fees, and ordered the case remanded for an award of attorneys’ fees to our subsidiary on
one of the claims on which judgment was reversed. Both parties petitioned the Supreme Court of Texas for review. In June
2016, the Supreme Court ruled that insufficient evidence supported the damage award and remanded the case for a new trial.
The parties subsequently reached a settlement, the amount of which is reflected in our financial statements as of, and for the
period ended, December 31, 2016.
We are also subject to laws and regulations relating to the protection of the environment. Environmental and cleanup
related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the
amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not
have a material effect on our financial position or results of operations.
See “Litigation” in Note 8, “Commitments and Contingencies” in the consolidated financial statements for further details
on our current legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Our sand mining operations in support of our E&P business are subject to regulation by the Federal Mine Safety and
Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations
or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act
and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Annual Report.
SWN 58
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 45
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the New York Stock Exchange (the “NYSE”) under the symbol “SWN.” On February
21, 2017, the closing price of our common stock trading under the symbol “SWN” was $8.59 and we had 3,283 stockholders
of record. The following table presents, for each of the periods indicated, the high and low reported sales prices for our
common stock trading under the symbol “SWN” as reported on the NYSE:
Quarter Ended
March 31
June 30
September 30
December 31
2016
High
$
$
$
$
9.90
15.45
15.59
14.40
Low
$
$
$
$
5.30
7.55
11.42
9.14
Range of Market Prices
2015
High
$
$
$
$
28.02
29.61
22.84
13.90
Low
$
$
$
$
21.46
22.40
11.84
5.00
2014
High
$
$
$
$
46.90
49.16
45.52
37.26
Low
$ 37.25
$ 44.01
$ 34.82
$ 26.75
We do not currently pay dividends on our common stock.
Issuer Purchases of Equity Securities
The table below sets forth information with respect to purchases of our common stock made by us or on our behalf
during the quarter ended December 31, 2016:
Period
October 2016
November 2016
December 2016
Total fourth-quarter 2016:
Total Number of Shares
Purchased (1)
Average Price Paid per
Share
Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs
Maximum Dollar Value
of Shares that May Yet
Be Purchased Under the
Plans or Programs
$
–
$
–
265,058 $
265,058 $
–
–
11.71
11.71
n/a
n/a
n/a
n/a
n/a
n/a
n/a
n/a
(1) Reflects shares retired by us to satisfy applicable tax withholding obligations due on employee stock plan share issuances. All changes in common
stock in treasury in 2016 were due to purchases and sales of shares held on behalf of participants in a non-qualified deferred compensation supplemental
retirement savings plan.
Recent Sales of Unregistered Equity Securities
We did not sell any unregistered equity securities during 2016, 2015 or 2014. See Item 12, “Security Ownership of
Certain Beneficial Owners and Management and Related Stockholder Matters,” in Part III of this Annual Report for
information regarding our equity compensation plans as of December 31, 2016.
SWN 59
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 46
STOCK PERFORMANCE GRAPH
The following graph compares, for the last five years, the performance of our common stock to the S&P 500 Index and
our peer group. Our peer group consists of Anadarko Petroleum Corporation, Apache Corporation, Cabot Oil & Gas
Corporation, Chesapeake Energy Corporation, Cimarex Energy Co., Concho Resources Inc., Continental Resources Inc.,
Denbury Resources Inc., Devon Energy Corporation, EOG Resources, Inc., EQT Corporation, Newfield Exploration
Company, Noble Energy, Inc., Pioneer Natural Resources Co., QEP Resources, Inc., Range Resources Corporation,
Sandridge Energy, Inc., SM Energy Company, Ultra Petroleum Corp., Whiting Petroleum Corporation and WPX Energy,
Inc. The chart assumes that the value of the investment in our common stock and each index was $100 at December 31,
2011, and that all dividends were reinvested. The stock performance shown on the graph below is not indicative of future
price performance:
COMPARISON OF CUMULATIVE FIVE YEAR TOTAL RETURN
$250
$200
$150
$100
$50
$0
2011
2012
2013
2014
2015
2016
Southwestern Energy Company
S&P 500 Index
Peer Group
12/31/11
12/31/12
12/31/13
12/31/14
12/31/15
Southwestern Energy Company
S&P 500 Index
Peer Group
$
100 $
100
100
105 $
116
98
123 $
154
130
85 $
175
110
SWN 60
22 $
177
73
12/31/16
34
198
106
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 47
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth a summary of selected historical financial information for each of the years in the five-
year period ended December 31, 2016. This information and the notes thereto are derived from our consolidated financial
statements. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and
“Financial Statements and Supplementary Data.”
Financial Review
Operating revenues:
Exploration and production
Midstream services
Other
Intersegment revenues
$
Operating costs and expenses:
Marketing purchases – midstream services
Operating and general and administrative expenses
Restructuring charges
Depreciation, depletion and amortization
Impairment of natural gas and oil properties
Gain on sale of assets, net
Taxes, other than income taxes
Operating income (loss)
Interest expense, net
Gain (loss) on derivatives
Loss on early extinguishment of debt
Other income (loss), net
Income (loss) before income taxes
Provision (benefit) for income taxes:
Current
Deferred
Net income (loss)
Mandatory convertible preferred stock dividend
Net income (loss) attributable to common stock
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
Common Stock Statistics
Earnings per share:
Net income (loss) attributable to common
stockholders – Basic
Net income (loss) attributable to common
stockholders – Diluted
Book value per average diluted share
Market price at year-end
Number of stockholders of record at year-end
Average diluted shares outstanding
$
$
$
$
$
$
2016
2014
(in millions except shares, per share, stockholder data and percentages)
2013
2015
2012
1,413
2,569
–
(1,546)
2,436
864
839
78
436
2,321
–
93
4,631
(2,195)
88
(339)
(51)
1
$
2,074 $
3,119
–
(2,060)
3,133
$
2,862
4,358
–
(3,182)
4,038
$
2,404
3,347
–
(2,380)
3,371
852
935
–
1,091
6,950
(283)
110
9,655
(6,522)
56
47
–
(30)
980
648
–
942
–
–
95
2,665
1,373
59
139
–
(4)
782
519
–
787
–
–
79
2,167
1,204
42
26
–
2
1,964
2,363
3
(1,600)
2,730
592
420
–
811
1,940
–
68
3,831
(1,101)
35
(15)
–
1
(2,672)
(6,561)
1,449
1,190
(1,150)
(7)
(22)
(29)
(2)
(2,003)
(2,005)
(2,643)
108
(2,751) $
(4,556)
106
(4,662) $
21
504
525
924
–
924
$
(11)
497
486
704
–
704
$
19
(462)
(443)
(707)
–
(707)
498 $
(162) $
1,072 $
1,580 $
(1,638) $
20 $
2,335
$
(7,288) $
$
4,983
1,909
$
(2,216) $
$
277
1,654
(1,907)
291
(6.32) $
(12.25) $
(6.32) $
(12.25) $
2.63
2.62
$
$
2.01
2.00
$
$
(2.03)
(2.03)
$
$
2.11
10.82
3,292
435,337,402
$
$
6.00
7.11
3,415
380,521,039
$
$
13.23
27.29
3,271
352,410,683
$
$
10.32
39.33
3,259
351,101,452
$
$
8.71
33.41
3,122
348,610,503
SWN 61
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 48
Capitalization (in millions)
Total debt
Total equity
Total capitalization
Total assets
Capitalization ratios:
Debt
Equity
Capital Investments (in millions) (1)
Exploration and production
Midstream services
Other
Exploration and Production
Natural gas:
Production, Bcf
Average realized price per Mcf, including
derivatives
Average realized price per Mcf, excluding
derivatives
Oil:
Production, MBbls
Average realized price per barrel
NGL:
Production, MBbls
Average realized price per barrel
Total production, Bcfe
$
$
$
$
$
$
$
$
Lease operating expenses per Mcfe
$
General and administrative expenses per Mcfe (2) $
Taxes, other than income taxes per Mcfe (3)
$
Proved reserves at year-end:
Natural gas, Bcf
Oil, MMBbls
NGLs, MMBbls
Total reserves, Bcfe
Midstream Services
Volumes marketed, Bcfe
Volumes gathered, Bcf
2016
2015
2014
2013
2012
$
$
$
$
$
$
$
$
$
$
$
4,653
917
5,570
7,076
$
$
$
4,705
2,282
6,987
8,086
$
$
$
6,957
4,662
11,619
14,915
$
$
$
$
$
$
$
$
84%
16%
623
21
4
648
788
1.64
1.59
2,192
31.20
12,372
7.46
875
0.87
0.22
0.10
4,866
10.5
53.9
5,253
1,062
601
$
$
$
$
$
$
$
$
67%
33%
2,258
167
12
2,437
899
2.37
1.91
2,265
33.25
10,702
6.80
976
0.92
0.21
0.10
5,917
8.8
40.9
6,215
1,127
799
60%
40%
7,254
144
49
7,447
766
3.72
3.74
235
79.91
231
15.72
768
0.91
0.24
0.11
9,809
37.6
118.7
10,747
904
963
1,940
3,622
5,562
8,037
$
$
$
$
$
$
$
$
$
$
$
35%
65%
2,052
158
25
2,235
656
3.65
3.17
138
103.32
50
43.63
657
0.86
0.24
0.10
6,974
0.4
–
6,976
786
900
1,657
3,036
4,693
6,726
35%
65%
1,861
165
55
2,081
565
3.44
2.34
83
101.54
–
–
565
0.80
0.26
0.10
4,017
0.2
–
4,018
676
846
(1) Capital investments include an increase of $43 million for 2016, a decrease of $33 million for 2015, an increase of $155 million for 2014, and decreases
of $25 million and $37 million for 2013 and 2012, respectively, related to the change in accrued expenditures between years.
(2) Excludes $83 million of restructuring and other one-time charges for 2016.
(3) Excludes $3 million of restructuring charges for 2016.
SWN 62
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 49
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Management’s Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends
that may affect future performance. It should be read in conjunction with the financial statements and notes, and
supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including,
without limitation, statements relating to the Company’s plans, strategies, objectives, expectations and intentions that are
made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words
“anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,”
“guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “target” or similar
words identify forward-looking statements. The Company does not undertake to update, revise or correct any of the forward-
looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-
looking statements should be read in conjunction with the Company’s disclosures under the heading: “Cautionary Statement
about Forward-Looking Statements.”
Background
OVERVIEW
Southwestern Energy Company (including its subsidiaries, collectively, “we”, “our”, “us” or “Southwestern”) is an
independent energy company engaged in natural gas, oil and NGL exploration, development and production, which we refer
to as “E&P.” We are also focused on creating and capturing additional value through our natural gas gathering and marketing
businesses, which we refer to as “Midstream Services.” We conduct most of our businesses through subsidiaries and we
operate principally in two segments: E&P and Midstream Services. Currently we operate only in the United States.
Exploration and Production. Our primary business is the exploration for and production of natural gas, oil and NGLs,
with our current operations principally focused on the development of unconventional natural gas reservoirs located in
Pennsylvania, West Virginia and Arkansas. Our operations in northeast Pennsylvania, which we refer 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, which we refer to as “Southwest Appalachia,” are focused on the
Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, we refer to
our properties located in Pennsylvania and West Virginia as the “Appalachian Basin.” Our operations in Arkansas are
primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale. 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 oilfield products and services, principally serving our E&P
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 fees associated
with the gathering of natural gas. Our marketing activities capture opportunities that arise through the marketing and
transportation of natural gas, oil, and NGLs produced in our E&P operations.
We are focused on providing long-term growth in the net asset value per share of our business. Historically, the vast
majority of our operating income and cash flow has been derived from the production associated with our E&P business.
However, beginning in 2015 and continuing through 2016, depressed commodity prices significantly decreased our E&P
results of operations. The price we expect to receive for our production is a critical factor in the capital investments we make
to develop our properties. The current commodity price environment has resulted in the impairment of a significant portion
of our natural gas and oil properties over recent reporting periods. Commodity prices fluctuate due to a variety of factors we
cannot control or predict. These factors, which include increased supplies of natural gas, oil or NGLs due to greater
exploration and development activities, weather conditions, political and economic events, and competition from other
energy sources, impact supply and demand, which in turn determines the sales prices for our production. In addition to the
factors identified above, the prices we realize for our production are affected by our hedging activities as well as locational
differences in market prices, including basis differentials. Our 2016 results also reflect reduced costs of third-party services
we were able to negotiate during the downturn in the industry. As industry activity increases, demand for these services also
increases, and these service providers are likely to seek higher prices than we were able to obtain in 2016.
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Beginning in the fourth quarter of 2015, we decreased activity in the Appalachian Basin and the Fayetteville Shale as a
result of the lower commodity price environment. During the first half of 2016, we took steps to refocus the Company
through a 40% reduction in our workforce, executive management restructuring and a commitment to strengthen our balance
sheet by addressing potential near-term liquidity challenges, as we waited for commodity prices to recover. With the
successful implementation of our debt reduction strategy, along with improving forward pricing, we began increasing our
activity in the third quarter of 2016, and expect to continue these operations in 2017. During the second half of 2016, we
increased our hedging activity designed to assure certain desired levels of cash flow.
Recent Financial and Operating Results
In 2016, our net loss attributable to common stock was $2,751 million, or ($6.32) per diluted share, a decrease from a
net loss of $4,662 million, or ($12.25) per diluted share, in 2015. Our net income was $924 million, or $2.62 per diluted
share, in 2014. We incurred non-cash impairments of our natural gas and oil properties totaling $2,321 million, or $1,444
million net of taxes, in 2016 and $6,950 million, or $4,287 million net of taxes, in 2015, which resulted primarily from the
significant decline in natural gas prices.
In 2016, our natural gas and liquids production totaled 875 Bcfe, a decrease of 10% from 976 Bcfe in 2015. The 101
Bcfe decrease in our 2016 production resulted from a 96 Bcfe decrease in net production from our Fayetteville Shale and
other properties and a 10 Bcf decrease in net production from our Northeast Appalachia properties, partially offset by a 5
Bcfe increase in net production from our Southwest Appalachia properties. The reductions resulted primarily from the
suspension of drilling activities in the first half of 2016. Our 2015 total natural gas and liquids production of 976 Bcfe
increased 27% from 768 Bcfe in 2014. The 208 Bcfe increase in our 2015 production resulted from a 140 Bcfe increase in
net production from our Southwest Appalachia properties, a 106 Bcf increase in net production from our Northeast
Appalachia properties and was partially offset by a 38 Bcfe decrease in net production from our Fayetteville Shale and other
properties.
Our year-end reserves decreased 15% in 2016 to 5,253 Bcfe from 6,215 Bcfe at the end of 2015 and 10,747 Bcfe at the
end of 2014. The overall decrease in total estimated proved reserves in 2016 was primarily due to production and downward
price revisions associated with decreased commodity prices, partially offset by upward performance revisions in Northeast
and Southwest Appalachia and the Fayetteville Shale. The overall decrease in total estimated proved reserves in 2015 was
primarily due to downward revisions associated with decreased commodity prices, partially offset by upward performance
revisions in Northeast and Southwest Appalachia.
Our E&P segment operating loss was $2,404 million in 2016, a decrease from an operating loss of $7,104 million in
2015. The operating loss in 2016 included non-cash impairments of natural gas and oil properties totaling $2,321 million.
Excluding the non-cash impairments, our E&P segment operating loss decreased to $83 million in 2016 from $154 million
in 2015 as the $732 million decrease in operating costs and expenses and $19 million increase in NGL revenues was only
partially offset by a 31%, or $0.73 per Mcf, decrease in our average realized natural gas price, a 12%, or 111 Bcf, decrease
in natural gas production and a $7 million decrease in oil revenues. Our E&P segment operating loss was $7,104 million in
2015, a decrease from operating income of $1,013 million in 2014. Excluding the non-cash impairments, operating income
in 2015 decreased $1,167 million over 2014 as the revenue impact of our 27%, or 208 Bcfe, increase in production was more
than offset by a 36%, or $1.35, decrease in our average realized natural gas price and a $379 million increase in operating
costs and expenses that resulted from our production growth. In May 2015, we sold our conventional oil and gas assets
located in East Texas and the Arkoma Basin that accounted for $27 million in operating income for the year ended December
31, 2014.
Operating income for our Midstream Services segment was $209 million in 2016, a decrease from $583 million in 2015
and $361 million in 2014. Operating 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, our Midstream Services segment operating
income decreased $97 million primarily due to decreased volumes gathered and decreased marketing margin, partially offset
by a $32 million decrease in operating costs and expenses, exclusive of marketing purchase costs. Volumes gathered
decreased to 601 Bcf in 2016, compared to 799 Bcf in 2015. Excluding the gain on sales, operating income for our Midstream
Services segment decreased in 2015 primarily due to a $71 million decrease in gathering revenues, which resulted from
decreased volumes gathered, partially offset by a $13 million decrease in operating costs and expenses, exclusive of
marketing purchase costs. Volumes gathered decreased to 799 Bcf in 2015, compared to 963 Bcf in 2014. In the second
quarter of 2015, we sold our northeastern Pennsylvania and East Texas gathering assets that accounted for $13 million and
$35 million in operating income for the years ended December 31, 2015 and 2014, respectively. A net gain of $277 million
was recognized and is included in gain on sale of assets, net in the consolidated statement of operations.
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We had total capital investments of $648 million in 2016, compared to $2.4 billion in 2015 and $7.4 billion in 2014. Of
our total capital investments for 2016, $623 million was invested in our E&P segment, which included $152 million related
to capitalized interest and $87 million in capitalized expenses. Of our total capital investments in 2015, $2.3 billion was
invested in our E&P segment, which included $533 million related to acquisitions from WPX Energy, Inc. (“WPX” with
acquisition called the “WPX Property Acquisition”) and Statoil ASA (“Statoil” with the acquisition called “Statoil Property
Acquisition”), compared to $7.3 billion in 2014, which included $5.2 billion primarily related to the December 2014
acquisition of certain oil and natural gas assets in Southwest Appalachia from Chesapeake Energy Corporation (the
“Chesapeake Property Acquisition”). Our Midstream Services capital investments for 2015 included $109 million related to
the WPX Property Acquisition.
Outlook
We expect to continue to exercise capital discipline by aligning our 2017 capital investing program with our expected
cash flow from operations and the remaining funds from our equity offering and sale of West Virginia assets. We will also
look for opportunities to further strengthen our balance sheet, maximize margins in each core area of our business and further
develop our knowledge of our asset base. We believe that 2017 will continue to be a challenging year for our business due
to the commodity price environment and continued uncertainty of natural gas, oil and NGL prices in the United States.
However, we expect that our resource base, financial flexibility and disciplined investment of capital will position us for
success in the current environment and any improvements thereto.
RESULTS OF OPERATIONS
The following discussion of our results of operations for our segments is presented before intersegment eliminations.
We evaluate our segments as if they were stand-alone operations and accordingly discuss their results prior to any
intersegment eliminations. Interest expense and income tax expense are discussed on a consolidated basis.
Exploration and Production
Revenues (in millions)
Impairment of natural gas and oil properties (in millions)
Operating costs and expenses (in millions) (1)
Operating income (loss) (in millions)
Gain on derivatives, settled (in millions) (2)
Gas production (Bcf)
Oil production (MBbls)
NGL production (MBbls)
Total production (Bcfe)
Average realized gas price per Mcf, including derivatives (3)
Average realized gas price per Mcf, excluding derivatives
Average realized oil price per Bbl
Average realized NGL price per Bbl
Average unit costs per Mcfe:
Lease operating expenses
General & administrative expenses (4)
Taxes, other than income taxes (5)
Full cost pool amortization
For the years ended December 31,
2015
2014
2016
$
$
$
$
$
$
$
$
$
$
$
$
$
1,413
2,321
1,496
(2,404)
36
788
2,192
12,372
875
1.64
1.59
31.20
7.46
0.87
0.22
0.10
0.38
$
$
$
$
$
$
$
$
$
$
$
$
$
2,074
6,950
2,228
(7,104)
206
899
2,265
10,702
976
2.37
1.91
33.25
6.80
0.92
0.21
0.10
1.00
$
$
$
$
$
$
$
$
$
$
$
$
$
2,862
–
1,849
1,013
9
766
235
231
768
3.72
3.74
79.91
15.72
0.91
0.24
0.11
1.10
(1)
Includes $86 million of restructuring and other one-time charges for the year ended December 31, 2016.
(2) Represents the gain (loss) on settled commodity derivatives.
(3)
Includes the gain (loss) on settled commodity derivatives.
(4) Excludes $83 million of restructuring and other one-time charges for the year ended December 31, 2016.
(5) Excludes $3 million of restructuring charges for the year ended December 31, 2016.
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Revenues
Revenues for our E&P segment were $1,413 million in 2016, a decrease of 32% compared to 2015. Revenues decreased
by $248 million as a result of decreased realized natural gas pricing, excluding the effects of derivatives, $212 million as a
result of decreased natural gas production, $209 million as a result of decreased derivative settlement proceeds, $7 million
as a result of decreased oil production and realized price and $4 million as a result of decreased other operating revenue.
These decreases were partially offset by an increase of $19 million in NGL sales resulting from increased production and
realized price. Revenues for our E&P segment were $2,074 million in 2015, a decrease of 28% compared to 2014. A
decrease in the price realized from the sale of our natural gas production decreased revenue by $1,647 million in 2015,
partially offset by an increase of $497 million due to higher natural gas production volumes and an increase of $235 million
in hedge settlement proceeds. Additionally, there was a $328 million increase due to increased net NGL and oil production
related to our Southwest Appalachia property acquisition partially offset by a $201 million decrease due to decreased net
NGL and oil pricing. Natural gas, oil and NGL prices are difficult to predict and are subject to wide price fluctuations. We
refer you to Note 4 to the consolidated financial statements included in this Annual Report and to the discussion of
“Commodity Prices” provided below for additional information. In May 2015, we sold our conventional oil and gas assets
located in East Texas and the Arkoma Basin that accounted for $15 million and $70 million of our gas and oil revenues for
the years ended December 31, 2015 and 2014, respectively.
Production
In 2016, our natural gas and liquids production totaled 875 Bcfe, a 10% decrease from 976 Bcfe in 2015, and was
produced entirely by our properties in the United States. The 101 Bcfe decrease was primarily due to a 96 Bcfe decrease in
net production from our Fayetteville Shale and other properties and a 10 Bcf decrease in net production from our Northeast
Appalachia properties, partially offset by a 5 Bcfe increase in net production from our Southwest Appalachia properties. Net
production from our Northeast Appalachia, Southwest Appalachia and Fayetteville Shale properties was 350 Bcf, 148 Bcfe
and 375 Bcf, respectively, for the year ended 2016, compared to 360 Bcf, 143 Bcfe, and 465 Bcf, respectively, for 2015.
The reductions resulted primarily from the suspension of drilling activities in the first half of 2016. Our 2015 total natural
gas and liquids production of 976 Bcfe increased 27% from 768 Bcfe in 2014, and was also produced entirely by our
properties in the United States. The 208 Bcfe increase in our 2015 production resulted from a 140 Bcfe increase in net
production from our Southwest Appalachia properties and a 106 Bcf increase in net production from our Northeast
Appalachia properties, partially offset by a 38 Bcfe decrease in net production in our Fayetteville Shale and other properties.
Net production for 2014 from our Northeast Appalachia, Southwest Appalachia and Fayetteville Shale properties was 254
Bcf, 3 Bcfe and 494 Bcf, respectively.
Natural gas accounted for approximately 90%, 92% and 100% of our total production for the years ended December 31,
2016, 2015 and 2014, respectively. Oil accounted for 2% and 1% of our total production for the years ended December 31,
2016 and 2015, respectively. NGLs accounted for 8% and 7% of our total production for the years ended December 31,
2016 and 2015, respectively.
Our ability to identify, develop and produce reserves is dependent upon a number of factors, many of which are beyond
our control, including the availability of capital, availability of transportation, weather, the timing and extent of changes in
natural gas, oil and NGL prices and competition. There are also many risks inherent in the discovery, development and
production of natural gas, oil and NGLs. We refer you to “Risk Factors” in Item 1A of Part I of this Annual Report for a
discussion of these risks and the impact they could have on our financial condition and results of operations.
Commodity Prices
The average price realized for our natural gas production, after the effects of derivatives, decreased 31% to $1.64 per
Mcf in 2016, compared to a decrease of 36% to $2.37 per Mcf in 2015 from 2014 levels. The decrease in 2016 was the result
of a $0.32 per Mcf decrease in the average natural gas price, excluding derivatives, and lower proceeds from our hedging
program in 2016 as compared to 2015. The decrease in 2015 was the result of a $1.83 per Mcf decrease in the average
natural gas price, excluding derivatives, partially offset by higher proceeds from our hedging program in 2015 as compared
to 2014. In 2016, our derivatives increased the average natural gas price we realized by $0.05 per Mcf, compared to an
increase of $0.46 per Mcf in 2015 and a decrease of $0.02 per Mcf in 2014.
Our E&P segment receives a sales price for our natural gas at a discount to average monthly NYMEX settlement prices
due to heating content of the gas, locational basis differentials, transportation charges and fuel charges. Additionally, we
receive a sales price for our oil and NGLs at a difference to average monthly West Texas Intermediate settlement and Mont
Belvieu NGL composite prices, respectively, due to a number of factors including product quality, composition, and types
of NGLs sold, locational basis differentials, transportation and fuel charges.
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We regularly enter into various hedging and other financial arrangements with respect to a portion of our projected
natural gas production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations,
including fluctuations in locational market differentials. We refer you to Item 7A of this Annual Report, Note 4 to the
consolidated financial statements, and our hedge risk factor for additional discussion about our derivatives and risk
management activities.
In 2016, the average price received, excluding the impact of derivatives, for our natural gas production was $1.59 per
Mcf, approximately $0.87 per Mcf lower than the average monthly NYMEX settlement price, primarily due to locational
basis differentials and transportation costs. We protected approximately 38% of our natural gas production in 2016 from the
impact of widening basis differentials through our sales arrangements and financial derivatives. For the year ended December
31, 2016, we protected the basis differentials on approximately 277 Bcf and 78 Bcf of our 2017 and 2018 expected natural
gas production 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 of the
consolidated financial statements included in this Annual Report for additional details about our derivative instruments.
Our 2016 average realized sales price of $31.20 per barrel for our oil production decreased approximately 6% from the
prior year. The 2015 average realized price of $33.25 per barrel decreased 58% from 2014. We did not use derivatives to
financially protect our 2016, 2015 or 2014 oil production.
Our 2016 average realized sales price of $7.46 per barrel for our NGL production increased approximately 10% from
the prior year. The 2015 average realized price of $6.80 per barrel decreased 57% from 2014. We did not use derivatives to
financially protect our 2016, 2015 or 2014 NGL production.
Operating Income
Our E&P segment operating loss was $2,404 million in 2016, a decrease from an operating loss of $7,104 million in
2015. The E&P segment recorded a $2,321 million impairment of natural gas and oil properties for the year ended December
31, 2016, compared to a $6,950 million impairment for the same period in 2015. Excluding impairments, our E&P segment
reported an operating loss of $83 million for the year ended December 31, 2016, compared to an operating loss of $154
million for the same period in 2015, primarily due to a $732 million decrease in operating costs and expenses, consisting of
a $657 million decrease in depreciation, depletion and amortization, a $138 million decrease in operating expenses and a $12
million decrease in taxes other than income, partially offset by a $69 million increase in general and administrative expenses
and a $6 million decrease in gain on sale of assets, net. General and administrative expenses included $83 million related to
restructuring and other one-time charges. Taxes other than income taxes included $3 million related to restructuring charges.
Additionally, there was a $19 million increase in NGL revenues resulting from increased production and realized price. The
benefits of a net decrease in operating costs and expenses were largely offset by a 31%, or $0.73 per Mcf, decrease in our
realized natural gas price, after the effect of derivatives, a 111 Bcf decrease in natural gas production and decreased oil
revenues due to decreased production and realized price.
Our E&P segment operating loss was $7,104 million in 2015, a decrease from an operating income of $1,013 million in
2014. The E&P segment recorded a $6,950 million impairment of natural gas and oil properties for the year ended December
31, 2015. There was no impairment recorded in 2014. Excluding the impairments, our E&P segment reported an operating
loss of $154 million for the year ended December 31, 2015 compared to an operating income of $1,013 million for the same
period in 2014, primarily due to a 36%, or $1.35, decrease in our realized natural gas price, including derivatives, and a $379
million increase in operating costs and expenses that resulted from our production growth, partially offset by a 27%, or 208
Bcfe, increase in production. In May 2015, we sold our conventional oil and gas assets located in East Texas and the Arkoma
Basin, which accounted for $27 million of our operating income for the year ended December 31, 2014.
Operating Costs and Expenses
Lease operating expenses per Mcfe for the E&P segment were $0.87 in 2016, compared to $0.92 in 2015 and $0.91 in
2014. Lease operating expenses per Mcfe decreased in 2016 compared to 2015 primarily due to successful renegotiations of
our existing gathering and processing rates in our Southwest Appalachia operations and decreased workover activity and
contract services. As industry activity increases, demand for third-party services also increases, and these service providers
are likely to seek higher prices than we were able to obtain in 2016. Lease operating expenses per unit of production increased
in 2015 compared to 2014 primarily due to an increase in gathering and compression charges in our Southwest Appalachia
operations.
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In January 2016, as a result of lower anticipated drilling activity due to a prolonged depressed commodity price
environment, we announced a workforce reduction of approximately 1,100 employees, which was substantially complete by
the end of the first quarter of 2016. Excluding the restructuring charges associated primarily with our workforce reduction
and other one-time charges, general and administrative expenses for the E&P segment increased to $0.22 per Mcfe in 2016
compared to $0.21 per Mcfe in 2015 and $0.24 per Mcfe in 2014. The 2016 increase was a result of decreased production
volumes. In total, excluding the restructuring and other one-time charges, general and administrative expenses for the E&P
segment were $193 million for the year ended December 31, 2016 compared to $207 million in 2015 and $182 million in
2014. Including the restructuring and other one-time charges, general and administrative costs for year ended December 31,
2016 were $276 million for our E&P segment. The decrease in general and administrative costs excluding the restructuring
and other one-time charges was primarily the result of decreased headcount due to the reduction in workforce and decreased
discretionary spending. The increase in general and administrative expenses in 2015 was primarily a result of increased
personnel and technological costs associated with the expansion of our E&P operations, due to the acquisition of our
Southwest Appalachia assets, and accounted for $21 million, or 85%, of the 2015 increase. Our E&P employees decreased
by 930 during 2016 compared to a decrease of 155 in 2015. The decrease in 2016 was the result of the 40% workforce
reduction during the first quarter as a result of lower anticipated drilling activity.
Taxes other than income taxes per Mcfe were $0.10, $0.10 and $0.11 in 2016, 2015 and 2014, respectively, excluding
$3 million related to restructuring charges in 2016. Taxes other than income taxes per Mcfe vary from period to period due
to changes in ad valorem and severance taxes that result from the mix of our production volumes and fluctuations in
commodity prices.
Our full cost pool amortization rate averaged $0.38 per Mcfe for 2016, $1.00 per Mcfe for 2015 and $1.10 per Mcfe for
2014. The decreases in the average amortization rates resulted primarily from our full cost ceiling impairments over the
respective periods. The amortization rate is impacted by the timing and amount of reserve additions and the costs associated
with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result
from full cost ceiling impairments, proceeds from the sale of properties that reduce the full cost pool and the levels of costs
subject to amortization. We cannot predict our future full cost pool amortization rate with accuracy due to the variability of
each of the factors discussed above, as well as other factors, including but not limited to the uncertainty of the amount of
future reserve changes.
Unevaluated costs excluded from amortization were $2.1 billion, $3.7 billion and $4.6 billion at December 31, 2016,
2015 and 2014, respectively. The decrease in unevaluated costs primarily resulted from the evaluation of a portion of our
Southwest Appalachia assets of which 55,000 net acres were sold to Antero Resources Corporation during the third quarter
of 2016, along with the evaluation of a portion of our New Venture assets. See “Supplemental Oil and Gas Disclosures” in
Item 8 of Part II of this Annual Report for additional information regarding our unevaluated costs excluded from
amortization.
The timing and amount of production and reserve additions could have a material impact on our per unit costs.
Midstream Services
Marketing revenues
Gas gathering revenues
Marketing purchases
Operating costs and expenses (1)
Gain on sale of assets, net
Operating income
Volumes marketed (Bcfe)
Volumes gathered (Bcf)
$
$
$
$
$
$
2016
For the years ended December 31,
2015
($ in millions, except volumes)
$
$
$
$
$
$
$
$
$
$
$
$
2,628
491
2,566
247
277
583
1,127
799
2,191
378
2,145
215
–
209
1,062
601
2014
3,797
562
3,738
260
–
361
904
963
(1)
Includes $3 million of restructuring charges for the year ended December 31, 2016.
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Revenues
Revenues from our marketing activities decreased 17% to $2.2 billion for 2016 compared to 2015 due to a 12% decrease
in the average price received for volumes marketed and a 6% decrease in volumes marketed. Revenues from our marketing
activities decreased 31% to $2.6 billion for 2015 compared to 2014 primarily due to a 45% decrease in the average price
received for volumes marketed, partially offset by a 25% increase in volumes marketed. Increases and decreases in marketing
revenues due to changes in commodity prices are largely offset by corresponding changes in marketing purchase expenses.
Of the total natural gas volumes marketed, production from our affiliated E&P operated wells accounted for 93% in 2016,
97% in 2015 and 97% in 2014. Our Midstream Services segment marketed approximately 65% and 60% of our combined
oil and NGL production for the years ended December 31, 2016 and 2015, respectively.
Revenues from our gathering activities decreased 23% to $378 million for 2016 compared to 2015, primarily from a
25% decrease in natural gas volumes gathered in 2016. The decrease in gathering revenues for 2016 was primarily due to
decreased volumes in the Fayetteville Shale and the divestiture of our northeastern Pennsylvania and East Texas gathering
assets in 2015. Revenues from our gathering activities decreased 13% to $491 million for 2015 compared to 2014, primarily
due to a 17% decrease in natural gas volumes gathered in 2015. The decrease in gathering revenues for 2015 was primarily
due to the divestiture of our northeastern Pennsylvania and East Texas gathering assets in 2015. 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.
Operating Income
Operating income from our Midstream Services segment decreased to $209 million in 2016 and increased to $583
million in 2015, compared to the prior year. The decrease in operating income in 2016 is primarily due to a $277 million net
gain on sale of assets in 2015 related to the sale of our northeastern Pennsylvania and East Texas gathering assets. Excluding
the net gain on sale, operating income decreased 32% to $209 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. Decreases of $113 million in gas gathering revenues and $16 million in marketing margin were partially
offset by a $32 million decrease in operating costs and expenses. Excluding the net gain on sale, our Midstream Services
segment operating income decreased 15% to $306 million in 2015 due to a decrease in volumes gathered resulting from
lower production volumes in the Fayetteville Shale and the absence of income from the northeastern Pennsylvania and East
Texas gathering assets that we sold. A decrease of $71 million in gas gathering revenues was partially offset by a $13 million
decrease in operating costs and expenses and a $3 million increase in marketing margin. The divested gathering assets
accounted for $13 million and $35 million of our operating income for the years ended December 31, 2015 and 2014,
respectively.
The margin generated from marketing activities was $46 million for 2016, compared to $62 million for 2015 and $59
million for 2014. Margins are driven primarily by volumes marketed and may fluctuate depending on the prices paid for
commodities and the ultimate disposition of those commodities. We enter into derivative contracts from time to time with
respect to our natural gas marketing activities to provide margin protection. For more information about our derivatives and
risk management activities, we refer you to Item 7A of Part II of this Annual Report and Note 4 to the consolidated financial
statements.
Restructuring Charges
In January 2016, we announced a 40% workforce reduction, which was substantially concluded by the end of March
2016. In April 2016, we also partially restructured executive management. Affected employees were offered a severance
package that included a one-time cash payment depending on length of service and, if applicable, accelerated vesting of
outstanding stock-based equity awards. As a result of the workforce reduction and executive management restructuring, we
recognized restructuring charges of $78 million for the year ended December 31, 2016.
Interest Expense
Interest expense, net of capitalization, was $88 million in 2016, compared to $56 million in 2015 and $59 million in
2014. Gross interest expense increased to $240 million in 2016 from $213 million in 2015, excluding a $47 million charge
for unamortized fees associated with the repayment of our bridge facility in the first quarter of 2015, due to an increase in
our cost of debt. Gross interest expense for 2016 includes $6 million related to unamortized debt issuance costs and debt
discounts associated with the extinguished debt. Capitalized interest decreased to $152 million in 2016, compared to $204
million in 2015 primarily due to the evaluation of a portion of our Southwest Appalachia assets acquired in December 2014.
Gross interest expense increased in 2015 from $114 million in 2014 due to our increased borrowing level related to financing
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the acquisition of our Southwest Appalachia assets and a $47 million charge for unamortized fees associated with the
repayment of our bridge facility in January 2015. Interest capitalized increased to $204 million in 2015 compared to $55
million in 2014 as the result of the increase in our unevaluated property balance associated with the 2014 acquisition of our
Southwest Appalachia assets.
Gain (Loss) on Derivatives
In general, our derivatives are not designated for hedge accounting treatment. Changes in the fair value of derivatives
that are not designated for hedge accounting are recorded in gain (loss) on derivatives. We recorded a $339 million net loss
on our derivatives for the year ended December 31, 2016, consisting of a $373 million loss on unsettled derivatives, partially
offset by a $34 million gain on settled derivatives. We recorded a $47 million net gain on our derivatives for the year ended
December 31, 2015, consisting of a $202 million gain on settled derivatives, partially offset by a $155 million loss on
unsettled derivatives. We refer you to Note 4 to the consolidated financial statements included in the Annual Report for
additional details about our gain (loss) on derivatives. In general and without consideration of volatility or duration, as natural
gas prices increase from December 31, 2016 levels, we will recognize losses in future periods and, likewise, as natural gas
prices decline from December 31, 2016 levels, we will recognize gains in future periods on our derivative contracts not
designated for hedge accounting treatment prior to settlement.
Loss on Early Extinguishment of Debt
During the third quarter of 2016, we used a portion of the proceeds from our July 2016 equity offering to purchase and
retire $700 million of our outstanding senior notes due in the first quarter of 2018 and retire $375 million of our $750 million
term loan entered into in November 2015. For the year ended December 31, 2016, we recognized a loss of $51 million for
the redemption of these senior notes, which included $50 million of premiums paid. Unamortized debt issuance costs and
debt discounts associated with the extinguished debt totaled $6 million and were included in other interest charges for the
year ended December 31, 2016. In September 2016, we used $48 million of the proceeds received from the West Virginia
sale to Antero Resources Corporation to further decrease the balance of the term loan entered into in November 2015.
Income Taxes
Our effective tax rate was approximately 1%, 31%, and 36%, in 2016, 2015 and 2014, respectively. We recorded an
income tax benefit of $29 million and $2,005 million in 2016 and 2015, respectively, and income tax expense of $525 million
in 2014. Our effective tax rate decreased as a result of our recognition of a valuation allowance (beginning in the fourth
quarter of 2015 and persisting throughout 2016) that reduced the deferred tax asset primarily related to our current net
operating loss carryforward. A valuation allowance for deferred tax assets, including net operating losses, is recognized
when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. We refer you
to Note 9 to the consolidated financial statements for additional discussion about our income taxes.
LIQUIDITY AND CAPITAL RESOURCES
We depend primarily on funds generated from our operations, our cash and cash equivalents balance, our $809 million
revolving credit facilities and capital markets as our primary sources of liquidity.
During 2016, we took significant steps in managing our maturities and liquidity. In June 2016, we refinanced
approximately 97% of our principal credit facility, which was due in December 2018, including extending the maturity by
two years until December 2020, granting liens on certain assets and modifying interest rates and covenants. We
simultaneously modified interest rates and covenants under our $750 million unsecured term loan facility and provided for
its extension to December 2020 should its principal balance be reduced by 50% by June 2018. The maturity date will
accelerate to October 2019 if, by that date, we have not amended, redeemed or refinanced at least $765 million of our senior
notes due in January 2020. In July 2016, we completed a public offering of 98,900,000 shares of our common stock, with
net proceeds totaling approximately $1,247 million after underwriting discounts and offering expenses. Of the funds received
from the common stock offering, $375 million was used to pay down a portion of our $750 million unsecured term loan and
$750 million was used to settle certain tender offers by purchasing an aggregate principal amount of approximately $700
million of our outstanding senior notes due in the first quarter of 2018. The repayment of $375 million on the $750 million
unsecured term loan had the effect of extending its maturity date to December 2020, subject to the conditions described
above. In September 2016, we completed the sale of 55,000 net acres in West Virginia for $422 million to Antero Resources
Corporation, subject to customary post-closing adjustments, and used $48 million of the proceeds to further decrease the
balance of this term loan. We earmarked $500 million of the remaining funds from the equity issuance and the sale of the
West Virginia acreage for capital activity, with approximately $300 million having been invested as of December 31, 2016.
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During the first half of 2016, we suspended drilling and completion activity in the Appalachian Basin and Fayetteville
Shale as a result of the commodity price environment. After the successful implementation of our debt reduction strategy
and our equity offering, we began increasing our activity in the third quarter of 2016, which continued throughout the
remainder of the year. Although we have the financial flexibility to draw on the funds available under our cash balance and
revolving credit facility as necessary, we continue to be committed to our capital discipline strategy of investing within our
cash flow from operations, supplemented by the remaining funds from the July 2016 equity issuance and asset sale in West
Virginia. We refer you to Note 7 of the consolidated financial statements included in this Annual Report and the section
below under “Financing Requirements” for additional discussion of our credit facilities.
The credit status of the financial institutions participating in our revolving credit facilities could adversely impact our
ability to borrow funds under the revolving credit facilities. Although we believe all of the lenders under the facilities have
the ability to provide funds, we cannot predict whether each will be able to meet their obligation to us. We refer you to the
section below under “Financing Requirements” for additional discussion of our compliance with the covenants of our term
loans and revolving credit facilities.
Net cash provided by operating activities decreased to $0.5 billion in 2016, down 69% from $1.6 billion in 2015,
primarily due to decreased natural gas prices and production. Net cash provided by operating activities decreased to $1.6
billion in 2015, down 32% from $2.3 billion in 2014 primarily due to decreased natural gas prices. Net cash generated from
operating activities provided 77% of our cash requirements for capital investments in 2016, reflecting our commitment to
our capital discipline strategy of investing within our cash flow from operations, supplemented by the recent equity issuance
and asset sales, during the current commodity price environment. Net cash generated from operating activities provided 66%
of our cash requirements for capital investments, including acquisitions, in 2015 and 31% in 2014.
Our cash flow from operating activities is highly dependent upon the sales prices that we receive for our natural gas and
liquids production. Natural gas, oil and NGL prices are subject to wide fluctuations and are driven by market supply and
demand, which is impacted by many factors. The sales price we receive for our production is also influenced by our
commodity hedging activities. See “Risk Factors” in Item 1A, “Quantitative and Qualitative Disclosures about Market
Risks” in Item 7A and Note 4, “Derivatives and Risk Management” in the consolidated financial statements for further
details. Our commodity hedging activities are subject to the credit risk of our counterparties being financially unable to
complete the transaction. We actively monitor the credit status of our counterparties, performing both quantitative and
qualitative assessments based on their credit ratings and credit default swap rates where applicable, and to date have not had
any credit defaults associated with our transactions. However, any future failures by one or more counterparties could
negatively impact our cash flow from operating activities.
Additionally, our short-term cash flows are dependent on the timely collection of receivables from our customers and
joint interest partners. We actively manage this risk through credit management activities and, through the date of this filing,
have not experienced any significant write-offs for non-collectable amounts. However, any sustained inaccessibility of credit
by our customers and joint interest partners could adversely impact our cash flows.
Due to these above factors, we are unable to forecast with certainty our future level of cash flow from operations.
Accordingly, we expect to adjust our discretionary uses of cash depending upon available cash flow. Further, we may from
time to time seek to retire or rearrange some or all of our outstanding debt or preferred stock through cash purchases and/or
exchanges, open market purchases, privately negotiated transactions, tender offers or otherwise. Such transactions, if any,
will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The
amounts involved may be material.
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Capital Investments
Our capital investments were $648 million, $2.4 billion and $7.4 billion in 2016, 2015 and 2014, respectively. Capital
investments include an increase of $43 million in 2016, a decrease of $33 million in 2015 and an increase of $155 million in
2014 related to the change in accrued expenditures between years. Our E&P segment investments in 2016 were $623 million,
compared to $2.3 billion in 2015, which included $533 million, in total, relating to the WPX and Statoil Property
Acquisitions, and $7.3 billion in 2014, which included $5.2 billion primarily related to the Chesapeake Property Acquisition.
Our E&P segment capitalized internal costs of $112 million for the year ended December 31, 2016 compared to $307 million
and $320 million in 2015 and 2014, respectively. These internal costs were directly related to acquisition, exploration and
development activities and are included as part of the cost of natural gas and oil properties. Our Midstream Services capital
investments for 2015 excludes $109 million related to the WPX Property Acquisition that is recognized in “Acquisitions” in
the table below:
Exploration and production
Acquisitions
Midstream Services
Other
Capital investments for the years ended December 31,
2016
2015
(in millions)
2014
623
–
21
4
648
$
$
1,725
642
58
12
2,437
$
$
2,021
5,233
144
49
7,447
$
$
The remaining funds, after debt reduction, from the equity issuance and West Virginia acreage sale enabled us to
supplement our 2016 capital budget, allowing us the opportunity to complete many of our drilled but uncompleted wells and
resume drilling on our high PVI projects.
Financing Requirements
Our total debt outstanding was $4.7 billion as of December 31, 2016 and December 31, 2015. Our total debt, net of cash
and cash equivalents of $1.4 billion, was $3.2 billion at December 31, 2016, compared to $4.7 billion at December 31, 2015.
Our actions to reduce and extend our total debt outstanding are further discussed below.
At February 21, 2017, we had a long-term issuer credit rating of Ba3 by Moody’s, a long-term debt rating of BB- by
S&P and a long-term issuer default rating of BB by Fitch Ratings. Any downgrades in our public debt ratings by Moody’s
or S&P could increase our cost of funds and decrease our liquidity under our revolving credit facilities.
At December 31, 2016, our capital structure consisted of 84% debt (excluding $1.4 billion in cash and cash equivalents)
and 16% equity, compared to 67% debt (excluding $15 million in cash and cash equivalents) and 33% equity at December
31, 2015. This increase was due principally to a 59% decrease in shareholders equity, resulting primarily from non-cash
ceiling test impairments.
In July 2016, we consummated an underwritten offering of 98,900,000 shares of our common stock pursuant to an
effective registration statement filed with the Securities and Exchange Commission, with net proceeds of the offering totaling
approximately $1,247 million after underwriting discounts and offering expenses. A portion of the proceeds from the
offering were used to repay $375 million of the $750 million term loan entered into in November 2015 and to settle certain
tender offers by purchasing an aggregate principal amount of approximately $700 million of our outstanding senior notes
due in the first quarter of 2018. The remaining net proceeds of the offering will be used for general corporate purposes,
including the completion of wells already drilled or the funding of other capital projects.
In June 2016, we reduced our existing $2.0 billion unsecured revolving credit facility to $66 million and entered into a
new credit agreement for $1,934 million, consisting of a $1,191 million secured term loan and a new unsecured $743 million
revolving credit facility, which matures in December 2020. The maturity date will accelerate to October 2019 if, by that
date, we have not amended, redeemed or refinanced at least $765 million of our senior notes due in January 2020. The
$1,191 million secured term loan is fully drawn, with approximately $285 million of this balance used to pay down the
existing revolving credit facility balance in its entirety. As of December 31, 2016, there were no borrowings under either
revolving credit facility, however, there was $174 million in letters of credit outstanding against the 2016 revolving credit
facility.
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Loans under the 2016 credit agreement are subject to varying rates of interest based on whether the loan is a Eurodollar
loan or an alternate base rate loan. Eurodollar loans bear interest at the Eurodollar rate, which is adjusted London Interbank
Offered Rate (“LIBOR”) plus applicable margins ranging from 1.750% to 2.500%. Alternate base rate loans bear interest at
the alternate base rate plus the applicable margin ranging from 0.750% to 1.500%. The interest rate on the term loan facility
is determined based upon our public debt ratings and was 250 basis points over LIBOR as of December 31, 2016.
Our 2016 credit agreement contains financial covenants that impose certain restrictions on us. Under our revolving
credit and term loan facilities, we must keep a minimum interest coverage of 0.75x in 2016, increasing by 0.25x increments
per year to 1.50x in 2019 and 2020. We are also subject to a minimum liquidity requirement of $300 million, which could
be increased up to $500 million upon certain conditions, as well as an anti-hoarding provision, requiring unrestricted cash in
excess of $100 million to pay down any amounts borrowed under the new revolving credit facility. The financial covenant
with respect to minimum interest coverage consists of EBITDAX divided by consolidated interest expense. EBITDAX, as
defined in our 2016 credit agreement, excludes the effects of interest expense, income taxes, depreciation, depletion and
amortization, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation
expense, non-cash gains or losses on asset sales, unamortized issuance cost, unamortized debt discount and certain
restructuring costs. Collateral for the new secured term loan is principally our E&P properties in the Fayetteville Shale area,
the equity of its subsidiaries and cash and marketable securities on hand. This collateral also may support all or a part of
revolving credit extensions depending on restrictions in our senior notes indentures, and requires a minimum collateral
coverage ratio of 1.50x.
The existing unsecured 2013 revolving credit facility includes a financial covenant under which we may not issue total
debt in excess of 60% of our total adjusted book capital, as defined in that agreement. This financial covenant with respect
to capitalization percentages excludes the effects of any full cost ceiling impairments, certain hedging activities and our
pension and other postretirement liabilities. We are in compliance with this covenant. As of December 31, 2016, the
maximum amount available under this credit facility was $66 million, with no amounts outstanding.
In November 2015, we entered into a $750 million unsecured three-year term loan credit agreement with various lenders
that was used to repay borrowings under the existing revolving credit facility. The interest rate on the term loan facility is
determined based upon our public debt ratings from Moody’s and S&P and was 250 basis points over LIBOR as of December
31, 2016. The term loan facility requires prepayment under certain circumstances from the net cash proceeds of sales of
equity or certain assets and borrowings outside the ordinary course of business. In June 2016, the 2015 term loan agreement
was amended to extend the maturity date, provided at least 50% would be paid down by June 2017. After our July 2016
equity offering, we repaid $375 million of the $750 million term loan, which had the effect of extending its maturity from
November 2018 to December 2020. The maturity date will accelerate to October 2019 if, by that date, we have not amended,
redeemed or refinanced at least $765 million of our 2020 Senior Notes. In September 2016, we repaid an additional $48
million of the term loan with proceeds from the sale of our West Virginia acreage.
As of December 31, 2016, we were in compliance with all of the covenants of the term loans and revolving credit
facilities. Although we do not anticipate any violations of the financial covenants, our ability to comply with these covenants
is dependent upon the success of our exploration and development program and upon factors beyond our control, such as the
market prices for natural gas and liquids.
In January 2015, we completed concurrent underwritten public offerings of 30,000,000 shares of common stock and
34,500,000 depositary shares (both share counts include shares issued as a result of the underwriters exercising their options
to purchase additional shares). Net proceeds from the offerings totaled approximately $2.3 billion, after underwriting
discount and expenses. Each depositary share represents a 1/20th interest in a share of our mandatory convertible preferred
stock, with a liquidation preference of $1,000 per share (equivalent to a $50 liquidation preference per depositary share).
The proceeds from the offerings were used to partially repay borrowings under a $4.5 billion 364-day bridge facility that we
entered into in December 2014 in connection with our acquisition of assets in Southwest Appalachia, with the remaining
balance fully repaid with proceeds from our January 2015 public offering of $2.2 billion in senior notes.
The mandatory convertible preferred stock entitles the holders to a proportional fractional interest in the rights and
preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights. Dividends are
to be paid at a rate of 6.25% per annum on the liquidation preference of $1,000 per share and can be paid in cash, common
stock or a combination of both. Since inception, and as of February 21, 2017, we have made four of the quarterly dividend
payments in cash and four of the dividend payments in common stock. Unless converted earlier at the option of the holders,
on or around January 15, 2018 each share of convertible preferred stock will automatically convert into between 37.0028
and 43.4782 shares of our common stock (correspondingly, each depositary share will convert into between 1.85014 and
2.17391 shares of our common stock), subject to customary anti-dilution adjustments, depending on the volume-weighted
average price of our common stock over a 20 trading-day period immediately prior to that date.
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Our mandatory convertible preferred stock has the non-forfeitable right to participate on an as-converted basis at the
conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security.
As such, it is included in the computation of basic and diluted earnings per share, pursuant to the two-class method. In the
calculation of basic earnings per share attributable to common shareholders, participating securities are allocated earnings
based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common
shareholders, if any, after recognizing distributed earnings.
In January 2015, we completed a public offering of $350 million aggregate principal amount of our 3.30% senior notes
due 2018 (the “2018 Notes”), $850 million aggregate principal amount of our 4.05% senior notes due 2020 (the “2020
Notes”) and $1.0 billion aggregate principal amount of our 4.95% senior notes due 2025 (the “2025 Notes” and together with
the 2018 and 2020 Notes, the “Notes”), with net proceeds from the offering totaling approximately $2.2 billion after
underwriting discounts and offering expenses. The proceeds from the sale of the Notes were used to repay all principal and
interest remaining outstanding under our $4.5 billion 364-day bridge facility, which was first reduced with proceeds from
our concurrent underwritten public offerings of common stock and depositary shares. Proceeds from the sale of the Notes
were also used to repay a portion of amounts outstanding under our existing revolving credit facility. The Notes were sold
to the public at a price of 99.949% of their face value for the 2018 Notes, 99.897% of their face value for the 2020 Notes and
99.782% of their face value for the 2025 Notes. The interest rates on the Notes are determined based on our public bond
ratings from Moody’s and S&P. Downgrades on the Notes from either rating agency increase our interest costs by 25 basis
points per downgrade level on the following semi-annual bond interest payment. Based on the February and June 2016
downgrades from Moody’s and S&P our interest rates on these Notes increased by 175 basis points in July 2016. In July
2016, we used a portion of the proceeds from the July 2016 equity offering to settle certain tender offers by purchasing an
aggregate principal amount of approximately $700 million of our outstanding senior notes due in the first quarter of 2018.
In December 2014, we entered into a $500 million unsecured two-year term loan credit agreement with various lenders.
The term loan facility required prepayments under certain circumstances from the net cash proceeds of sales of equity or
certain assets and borrowings outside the ordinary course of business or for specified uses and was repaid in full in April
2015 principally with proceeds from the divestiture of our northeast Pennsylvania gathering assets and borrowings under our
revolving credit facility.
Our derivative contracts allow us to ensure a certain level of cash flow to fund our operations. Excluding basis swaps,
at February 21, 2017, we had 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 also had commodity derivatives in place on 350 MBbls of our
targeted ethane production for 2017 and 2018.
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet
obligations. As of December 31, 2016, our material off-balance sheet arrangements and transactions include operating lease
arrangements and $174 million in letters of credit outstanding against our 2016 revolving credit facility. There are no other
transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to
materially affect our liquidity or availability of our capital resources. For more information regarding off-balance sheet
arrangements, we refer you to “Contractual Obligations and Contingent Liabilities and Commitments” below for more
information on our operating leases.
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Contractual Obligations and Contingent Liabilities and Commitments
We have various contractual obligations in the normal course of our operations and financing activities. Significant
contractual obligations as of December 31, 2016, were as follows:
Contractual Obligations:
Total
Less than 1
Year
Payments Due by Period
1 to 3 Years
3 to 5 Years
5 to 8 Years
(in millions)
More than 8
Years
Transportation charges (1) $
Debt
Interest on debt (2)
Operating leases (3)
Compression services (4)
Operating agreements
Purchase obligations
Other obligations (5)
$
8,429
4,684
1,195
229
26
3
33
35
14,634
$
$
627
41
229
66
16
3
33
27
1,042
$
$
1,484
275
422
97
10
–
–
8
2,296
$
$
1,275
2,368
289
52
–
–
–
–
3,984
$
$
1,507
1,000
221
7
–
–
–
–
2,735
$
$
3,536
1,000
34
7
–
–
–
–
4,577
(1) As of December 31, 2016, we had commitments for demand and similar charges under firm transport and gathering agreements to guarantee access
capacity on natural gas and liquids pipelines and gathering systems. Of the total $8.4 billion, 40% related to access capacity on future pipeline and
gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts.
(2)
Interest payments on our senior notes were calculated utilizing the fixed rates associated with our fixed rate notes outstanding at December 31, 2016.
Interest payments on the term loan facility were calculated by assuming that the December 31, 2016 outstanding balance of $327 million will be
outstanding through the December 2020 maturity date. Interest payments on the term loan facility were calculated by assuming that the December 31,
2016 outstanding balance of $1,191 million will be outstanding through the December 2020 maturity date. A constant rate of 3.22%, the rate as of
December 31, 2016, was assumed for the December 2020 term loan facilities. All interest rates were based on our credit ratings as of December 31,
2016.
(3) Operating leases include costs for compressors, aircraft, vehicles, office space and equipment under non-cancelable operating leases expiring through
2027.
(4) As of December 31, 2016, our Midstream Services segment had commitments of approximately $24 million and our E&P segment had commitments
of approximately $2 million for compression services associated primarily with our Fayetteville and Southwest Appalachia divisions.
(5) Our other significant contractual obligations include approximately $13 million for various information technology support and data subscription
agreements.
Liabilities relating to uncertain tax positions are excluded from the table above as there is a high degree of uncertainty
regarding the timing of future cash outflows related to such liabilities. Also excluded from the table above are future
contributions to the pension and postretirement benefit plans. For further information regarding our pension and other
postretirement benefit plans, we refer you to Note 11 to the consolidated financial statements and “Critical Accounting
Policies and Estimates” below for additional information.
We refer you to Note 7 to the consolidated financial statements for a discussion of the terms of our debt.
Working Capital
We maintain access to funds that may be needed to meet capital requirements through our revolving credit facility
described in “Financing Requirements” above. We had positive working capital of $808 million as of December 31, 2016
and negative working capital of $314 million at December 31, 2015. The positive working capital as of December 31, 2016
was primarily due to $1.4 billion of cash and cash equivalents resulting from our new term loan, equity offering and proceeds
from the sale of our West Virginia acreage. The negative working capital as of December 31, 2015 was primarily due to a
decrease in derivative assets in 2015.
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CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The discussion and analysis of financial condition and results of operations are based upon our consolidated financial
statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The
preparation of these financial statements requires management to make estimates and judgments that affect the amounts of
assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. We evaluate our estimates
on an on-going basis, based on historical experience and on various other assumptions that are believed to be reasonable
under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We
believe the following describes significant judgments and estimates used in the preparation of our consolidated financial
statements.
Natural Gas and Oil Properties
We utilize the full cost method of accounting for costs related to the exploration, development and acquisition of natural
gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and
other internal costs directly attributable to these activities are capitalized on a country-by-country basis and amortized over
the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling
test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues
attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure) plus the lower of cost or
market value of unproved properties. Any costs in excess of the ceiling are written off as a non-cash expense. The expense
may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the
ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month
from the previous 12 months, including the impact of derivatives qualifying as cash flow hedges, to calculate the ceiling
value of their reserves.
Costs associated with unevaluated properties are excluded from our amortization base until we have evaluated the
properties or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data,
wells currently drilling and related capitalized interest are initially excluded from our amortization base. Leasehold costs
are either transferred to our amortization base with the costs of drilling a well on the lease or are assessed at least annually
for possible impairment or reduction in value. Our decision to withhold costs from amortization and the timing of the transfer
of those costs into the amortization base involves a significant amount of judgment and may be subject to changes over time
based on several factors, including our drilling plans, availability of capital, project economics and drilling results from
adjacent acreage. At December 31, 2016, we had a total of $2,105 million of costs excluded from our amortization base, all
of which related to our properties in the United States. Inclusion of some or all of these costs in our properties in the United
States in the future, without adding any associated reserves, could result in additional ceiling test impairments.
In the first, second, and third quarters of 2016, the net book value of our United States and Canada natural gas and oil
properties exceeded the ceiling by approximately $641 million (net of tax) at March 31, 2016, $297 million (net of tax) at
June 30, 2016 and $506 million (net of tax) at September 30, 2016, resulting in non-cash ceiling test impairments in each of
those quarters. We had no hedge positions that were designated for hedge accounting as of March 31, 2016, June 30, 2016
and September 30, 2016. Using the average quoted price from the first day of each month from the previous 12 months for
Henry Hub natural gas of $2.48 per MMBtu, West Texas Intermediate oil of $39.25 per barrel and NGLs of $6.74 per barrel,
adjusted for market differentials, the net book value of our United States natural gas and oil properties did not exceed the
ceiling amount and did not result in a ceiling test impairment at December 31, 2016. We had no derivative positions that
were designated for hedge accounting as of December 31, 2016. Although no ceiling test impairment was recorded in the
fourth quarter of 2016, future decreases in commodity prices, increases in costs and/or changes in the balance of costs
excluded from amortization and other factors may result in additional impairments to our natural gas and oil properties in
2017.
In the second and third quarters of 2015, the net book value of our United States natural gas and oil properties exceeded
the ceiling by $944 million (net of tax) at June 30, 2015 and $1,746 million (net of tax) at September 30, 2015 and resulted
in non-cash ceiling test impairments. Cash flow hedges of natural gas production in place increased the ceiling amount by
approximately $60 million and $40 million as of June 30, 2015 and September 30, 2015, respectively. Using the average
quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.59 per MMBtu,
West Texas Intermediate oil of $46.79 per barrel and NGLs of $6.82 per barrel, adjusted for market differentials, the net
book value of our United States natural gas and oil properties exceeded the ceiling by $1,586 million (net of tax) at December
31, 2015 and resulted in a non-cash ceiling test impairment. No cash flow hedges were in place as of December 31, 2015.
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At December 31, 2014, the ceiling value of our reserves was calculated based upon the average quoted price from the
first day of each month from the previous 12 months for Henry Hub natural gas of $4.35 per MMBtu, for West Texas
Intermediate oil of $91.48 per barrel and NGLs of $23.79 per barrel, adjusted for market differentials. The net book value
of our natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at
December 31, 2014.
A decline in natural gas, oil and NGL prices used to calculate the discounted future net revenues of our reserves affects
both the present value of cash flows and the quantity of reserves. Our reserve base as of December 31, 2016 was
approximately 93% natural gas compared to 95% as of December 31, 2015. In the past, nearly all of our reserve base was
natural gas; therefore changes in oil and NGL prices used did not have as significant an impact as natural gas prices on cash
flows and reserve quantities. Our standardized measure and reserve quantities as of December 31, 2016, were $1.7 billion
and 5.3 Tcfe, respectively.
Natural gas, oil and NGL reserves cannot be measured exactly. Our estimate of natural gas, oil and NGL reserves
requires extensive judgments of reservoir engineering data and projections of cost that will be incurred in developing and
producing reserves and is generally less precise than other estimates made in connection with financial disclosures. Our
reservoir engineers prepare our reserve estimates under the supervision of our management. Reserve estimates are prepared
for each of our properties annually by the reservoir engineers assigned to the asset management team to which the property
is assigned. The reservoir engineering and financial data included in these estimates are reviewed by senior engineers, who
are not part of the asset management teams, and by our Reservoir Supervisor - Reserves, who is the technical person primarily
responsible for overseeing the preparation of our reserves estimates. Our Reservoir Supervisor – Reserves has more than 30
years of experience in petroleum engineering, including the estimation of oil and natural gas reserves, and holds a Bachelor
of Science in Petroleum Engineering. Prior to joining us in 2009, our Reservoir Supervisor - Reserves served in various
reservoir engineering roles for Citation Oil & Gas Corporation, Mitchell Energy & Development Corporation, White Stone
Energy and H.J. Gruy & Associates and is a member of the Society of Petroleum Engineers and Society of Petroleum
Evaluation Engineers and is a Licensed Professional Engineer in the state of Texas. He reports to our Planning and Reserves
Manager, who has more than 9 years of experience in reservoir engineering including the estimation of natural gas, oil and
NGL reserves in multiple basins in the United States and holds a Bachelor of Science in Chemical Engineering and a Master
of Business Administration. Prior to joining Southwestern in 2011, our Planning and Reserves Manager served in various
engineering roles for BP and is a member of the Society of Petroleum Engineers and IPAA. Our Planning and Reserves
Manager reports to our Senior Vice President – Corporate Development, who has more than 22 years of experience in
petroleum engineering including the estimation of natural gas, oil and NGL reserves in multiple basins in the United States,
and holds a Bachelor of Science in Petroleum Engineering and a Master of Business Administration. Prior to joining
Southwestern in 2014, our Senior Vice President – Corporate Development served in various engineering and leadership
roles for Quantum Resource Management, Anadarko Petroleum Company, Howell Petroleum and Meridian Oil/Burling
Resources and is a member of the Society of Petroleum Engineers and IPSS.
We engage NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and
government agencies, to independently audit our proved reserves estimates as discussed in more detail below. NSAI was
founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers
Registration No. F-002699. Within NSAI, the two technical persons primarily responsible for auditing our proved reserves
estimates (1) have over 35 years and over 14 years of practical experience in petroleum geosciences and petroleum
engineering, respectively; (2) have over 25 years and over 14 years of experience in the estimation and evaluation of reserves,
respectively; (3) each has a college degree; (4) each is a Licensed Professional Geoscientist in the State of Texas or a Licensed
Professional Engineer in the State of Texas; (5) each meets or exceeds the education, training, and experience requirements
set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the
Society of Petroleum Engineers; and (6) each is proficient in judiciously applying industry standard practices to engineering
and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The financial
data included in the reserve estimates is also separately reviewed by our accounting staff. Our proved reserves estimates, as
internally reviewed and audited by NSAI, are submitted for review and approval to our Chief Executive Officer. Finally,
upon his approval, NSAI reports the results of its reserve audit to the Board of Directors, with whom final authority over the
estimates of our proved reserves rests. A copy of NSAI's report has been filed as Exhibit 99.1 to this Annual Report.
Proved developed reserves generally have a higher degree of accuracy in this estimation process, when compared to
proved undeveloped and proved non-producing reserves, as production history and pressure data over time is available for
the majority of our proved developed properties. Proved developed reserves accounted for 99% of our total reserve base as
of December 31, 2016. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature
of such reserve estimates. The uncertainties inherent in the reserve estimates are compounded by applying additional
estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves.
We cannot assure you that our internal controls sufficiently address the numerous uncertainties and risks that are inherent in
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estimating quantities of natural gas, oil and NGL reserves and projecting future rates of production and timing of development
expenditures as many factors are beyond our control. We refer you to “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, “Risk Factors,” of Part I of this Annual Report for
a more detailed discussion of these uncertainties, risks and other factors.
In conducting its audit, the engineers and geologists of NSAI study our major properties in detail and independently
develop reserve estimates. NSAI’s audit consists primarily of substantive testing, which includes a detailed review of major
properties that account for approximately 99% of the present worth of the company’s total proved reserves. NSAI’s audit
process consists of sorting all fields by descending present value order and selecting the fields from highest value to
descending value until the selected fields account for more than 80% of the present worth of our reserves. The fields included
in approximately the top 99% present value as of December 31, 2016, accounted for approximately 98% of our total proved
reserves and approximately 100% of our proved undeveloped reserves. In the conduct of its audit, NSAI did not
independently verify the data we provided to them with respect to ownership interests, natural gas, oil and NGL production,
well test data, historical costs of operation and development, product prices, or any agreements relating to current and future
operations of the properties and sales of production. NSAI has advised us that if, in the course of its audit, something came
to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on
such information or data until it had satisfactorily resolved any questions relating thereto or had independently verified such
information or data. On January 13, 2017, NSAI issued its audit opinion as to the reasonableness of our reserve estimates
for the year-ended December 31, 2016, stating that our estimated proved natural gas, oil and NGL reserves are, in the
aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil
and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Business Combinations
We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts
for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. We make various
assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based
measurement, it is determined based on the assumptions that market participants would use. The most significant
assumptions relate to the estimated fair values of proved and unproved natural gas and oil properties. The fair values of
these properties are measured using valuation techniques that convert future cash flows to a single discounted amount.
Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity
prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is
subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and
sales of oil and natural gas properties within the same regions, and use that data as a proxy for fair market value; for example,
the amount a willing buyer and seller would enter into in exchange for such properties. Any excess of the acquisition price
over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net
assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are
recorded for any differences between the assigned values and the tax basis of assets and liabilities.
In January 2015, we completed the WPX and the Statoil Property Acquisitions of certain natural gas and oil assets.
These acquisitions qualified as business combinations and as such, we estimated the fair value of the assets acquired and
liabilities assumed as of the January 2015 acquisition dates. The fair value is the price that would be received to sell an asset
or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value
measurements also utilize assumptions of market participants. We used discounted cash flow models and made market
assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations
for timing and amount of future development and operating costs, projections of future rates of production, expected recovery
rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined in Note 6 of our consolidated
financial statements. We recorded the assets acquired and liabilities assumed in the WPX Property Acquisition and the
Statoil Property Acquisition at their estimated fair values of approximately $270 million and $357 million, respectively,
which we consider to be representative of the prices paid by typical market participants. These measurements resulted in no
goodwill or bargain purchases being recognized.
The 2014 Chesapeake Property Acquisition qualified as a business combination, and as such, we estimated the fair value
of the assets acquired and liabilities assumed as of the December 22, 2014 acquisition date. We recorded the assets acquired
and liabilities assumed in the Chesapeake Property Acquisition at their estimated fair value of approximately $5.0 billion,
which we consider to be representative of the price paid by a typical market participant. This measurement resulted in no
goodwill or bargain purchase being recognized.
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Derivatives and Risk Management
We use fixed price swap agreements and options to reduce the volatility of earnings and cash flow due to fluctuations
in the prices of certain commodities and interest rates. Our policies prohibit speculation with derivatives and limit agreements
to counterparties with appropriate credit standings to minimize the risk of uncollectability. We actively monitor the credit
status of our counterparties, performing both quantitative and qualitative assessments based on their credit ratings and credit
default swap rates where applicable, and to date have not had any credit defaults associated with our transactions. In 2016,
2015, and 2014 we financially protected 28%, 27% and 60% of our natural gas production, respectively, with derivatives.
The primary market risks related to our derivative contracts are the volatility in market prices and basis differentials for
natural gas. However, the market price risk is generally offset by the gain or loss recognized upon the related natural gas
transaction that is financially protected.
All derivatives are recognized in the balance sheet as either an asset or liability and are measured at fair value other than
transactions for which normal purchase/normal sale is applied. Certain criteria must be satisfied in order for derivative
financial instruments to be designated for hedge accounting. Accounting guidance for qualifying hedges allows an unsettled
derivative’s unrealized gains and losses to be recorded in either earnings or as a component of other comprehensive income
until settled. In the period of settlement, the Company recognizes the gains and losses from these qualifying hedges in gas
sales revenues. The ineffective portion of those fixed price swaps was recognized in earnings. Gains and losses on
derivatives that are not designated for hedge accounting treatment, or that do not meet hedge accounting requirements, are
recorded as a component of gain (loss) on derivatives on the consolidated statements of operations. Accordingly, the gain
(loss) on derivatives component of the statement of operations reflects the gains and losses on both settled and unsettled
derivatives. The Company calculates gains and losses on settled derivatives as the summation of gains and losses on positions
which have settled within the reporting period.
As of December 31, 2016, none of our derivative contracts were designated for hedge accounting treatment. During
2016, the Company settled all of its purchased put options, which were not designated for hedge accounting treatment.
Changes in the fair value of derivatives that were not designated for hedge accounting treatment are recorded in gain (loss)
on derivatives. For those derivatives not designated for hedge accounting treatment, we recorded a loss on derivatives of
$177 million related to fixed price swaps, a loss on derivatives of $81 million related to sold call options, a loss on derivatives
of $80 million related to three-way costless collars and a loss on derivatives of $45 million related to two-way costless
collars. These losses were partially offset by a gain on derivatives of $33 million related to basis swaps and a gain on
derivatives of $11 million related to purchased put options.
Future market price volatility could create significant changes to the hedge positions recorded in our consolidated
financial statements. We refer you to “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of Part II of
this Annual Report for additional information regarding our hedging activities.
Pension and Other Postretirement Benefits
We record our prepaid or accrued benefit cost, as well as our periodic benefit cost, for our pension and other
postretirement benefit plans using measurement assumptions that we consider reasonable at the time of calculation (see Note
11 to the consolidated financial statements for further discussion and disclosures regarding these benefit plans). Two of the
assumptions that affect the amounts recorded are the discount rate, which estimates the rate at which benefits could be
effectively settled, and the expected return on plan assets, which reflects the average rate of earnings expected on the funds
invested. For the December 31, 2016 benefit obligation and periodic benefit cost to be recorded in 2017, the discount rate
assumed is 4.20% and 4.20%, respectively. This compares to a discount rate of 4.60% and 4.25% for the benefit obligation
and periodic benefit cost recorded in 2016, respectively. For the 2017 periodic benefit cost, the expected return assumed is
7.00%, compared to an expected return of 7.00% in 2016.
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Using the assumed rates discussed above, we recorded total benefit cost of $19 million in 2016 related to our pension
and other postretirement benefit plans. Due to the significance of the discount rate and expected long-term rate of return,
the following sensitivity analysis demonstrates the effect that a 50 basis point change in those assumptions would have had
on our 2016 pension expense:
Discount rate
Expected long-term rate of return
Increase (Decrease) of Annual
Pension Expense
50 Basis Point
Increase
50 Basis Point
Decrease
$
$
(in millions)
(1)
(1)
$
$
1
1
As of December 31, 2016, we recognized a liability of $49 million, compared to $50 million at December 31, 2015,
related to our pension and other postretirement benefit plans. During 2016, we also made cash payments totaling $11 million
to fund our pension and other postretirement benefit plans.
Asset Retirement Obligations
We must plug and abandon our wells when they no longer are producing. An asset retirement obligation associated with
the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or when it becomes
determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible
asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is
recorded at its estimated fair value and accretion expense is recognized over time as the discounted liability is accreted to its
expected settlement value. The recognition of asset retirement obligations requires management to make assumptions that
include estimated plugging and abandonment costs, timing of settlements, inflation rates and discount rates, all of which are
subject to change.
Stock-Based Compensation
We account for stock-based compensation transactions using a fair value method and recognize an amount equal to the
fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalize
the cost into natural gas and oil properties or gathering systems included in property and equipment. Costs are capitalized
when they are directly related to the acquisition, exploration and development activities of our natural gas and oil properties
or directly related to the construction of our gathering systems. We use models to determine fair value of stock-based
compensation, which requires significant judgment with respect to forfeitures, volatility and other factors. If any of the
assumptions change significantly, stock-based compensation expense for future grants may differ materially from that
recorded in the current period.
New Accounting Standards
Refer to Note 1 to the consolidated financial statements of this Annual Report for further discussion of our significant
accounting policies and for discussion of accounting standards that have been implemented in this report, along with a
discussion of relevant accounting standards that are pending adoption.
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CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
All statements, other than historical fact or present financial information, may be deemed to be forward-looking
statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange
Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the
future, including, without limitation, statements regarding the financial position, business strategy, production and reserve
growth and other plans and objectives for our future operations, are forward-looking statements. Although we believe the
expectations expressed in such forward-looking statements are not guarantees of future performance. We have no obligation
and make no undertaking to publicly update or revise any forward-looking statements, except as may be required by law.
Forward-looking statements include the items identified in the preceding paragraph, information concerning possible or
assumed future results of operations and other statements in this Annual Report on Form 10-K identified by words such as
“anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,”
“guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “target” or similar
words.
You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks,
uncertainties and other factors that may affect our operations, markets, products, services and prices and cause our actual
results, performance or achievements to be materially different from any future results, performance or achievements
expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to
specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause our actual results
to differ materially from those indicated in any forward-looking statement include, but are not limited to:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
the timing and extent of changes in market conditions and prices for natural gas, oil and NGLs (including regional
basis differentials);
our ability to fund our planned capital investments;
a change in our credit rating;
the extent to which lower commodity prices impact our ability to service or refinance our existing debt;
the impact of volatility in the financial markets or other global economic factors;
difficulties in appropriately allocating capital and resources among our strategic opportunities;
the timing and extent of our success in discovering, developing, producing and estimating reserves;
our ability to maintain leases that may expire if production is not established or profitably maintained;
our ability to realize the expected benefits from recent acquisitions;
our ability to transport our production to the most favorable markets or at all;
availability and costs of personnel and of products and services provided by third parties;
the impact of government regulation, including the ability to obtain and maintain permits, any increase in severance
or similar taxes, and legislation relating to hydraulic fracturing, climate and over-the-counter derivatives;
the impact of the adverse outcome of any material litigation against us;
the effects of weather;
increased competition and regulation;
the financial impact of accounting regulations and critical accounting policies;
the comparative cost of alternative fuels;
credit risk relating to the risk of loss as a result of non-performance by our counterparties; and
any other factors listed in the reports we have filed and may file with the SEC.
Should one or more of the risks or uncertainties described above or elsewhere in this Annual Report occur, or should
underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any
forward-looking statements. We specifically disclaim all responsibility to publicly update any information contained in a
forward-looking statement or any forward-looking statement in its entirety and therefore disclaim any resulting liability for
potentially related damages.
All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market risks relating to our operations result primarily from the volatility in commodity prices, basis differentials and
interest rates, as well as service costs and credit risk concentrations. We use fixed price swap agreements, fixed price options,
basis swaps and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of
natural gas and interest rates. Our Board of Directors has approved risk management policies and procedures to utilize
financial products for the reduction of defined commodity price risk. Utilization of financial products for the reduction of
interest rate risks is also overseen by our Board of Directors. These policies prohibit speculation with derivatives and limit
swap agreements to counterparties with appropriate credit standings.
Credit Risk
Our financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and
derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited
due to the large number of our purchasers and their dispersion across geographic areas. No single purchaser accounted for
greater than 10% of revenues as of December 31, 2016. See “Commodities Risk” below for discussion of credit risk
associated with commodities trading.
Interest Rate Risk
As of December 31, 2016, we had approximately $3.2 billion of outstanding senior notes with a weighted average
interest rate of 5.68%, and $1.5 billion of term loan facility debt with a variable interest rate of 3.22%. We currently have
an interest rate swap in effect to mitigate a portion of our exposure to volatility in interest rates.
Fixed Rate Payments (1)
(in millions)
Weighted Average Interest
Rate
Variable Rate Payments (1)
(in millions)
Weighted Average Interest
Rate
2017
2018
$
41
$
275
$
Expected Maturity Date
2020
$
850
$
2019
–
2021
–
Thereafter
2,000
$
Total
3,166
$
7.21 %
7.13 %
– %
5.80 %
– %
5.40 %
5.68 %
$
–
$
–
$
–
$
1,518 (2)
$
–
$
–
$
1,518
– %
– %
– %
3.22 %
– %
– %
3.22 %
(1) Excludes unamortized debt issuance costs and debt discounts.
(2) The maturity date will accelerate to October 2019 if, by that date, we have not amended, redeemed or refinanced at least $765 million of our 2020
Senior Notes.
Commodities Risk
We use over-the-counter fixed price swap agreements and options to protect sales of our production against the inherent
risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX futures
market. These swaps and options include transactions in which one party will pay a fixed price (or variable price) for a
notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price
swaps) and transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps).
The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for
natural gas. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the
natural gas that is financially protected. Credit risk relates to the risk of loss as a result of non-performance by our
counterparties. The counterparties are primarily major banks and integrated energy companies that management believes
present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each
counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and
qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable.
We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the
information we have currently. However, we cannot be certain that we will not experience such losses in the future. We
refer you to Note 4 of the consolidated financial statements included in this Annual Report for additional details about our
derivative instruments.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Management’s Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Operations for the three years ended December 31, 2016
Consolidated Statements of Comprehensive Income (Loss) for the three years ended December 31, 2016
Consolidated Balance Sheets as of December 31, 2016 and 2015
Consolidated Statements of Cash Flows for the three years ended December 31, 2016
Consolidated Statements of Equity for the three years ended December 31, 2016
Notes to Consolidated Financial Statements
Note 1 – Organization and Summary of Significant Accounting Policies
Note 2 – Reduction in Workforce
Note 3 – Acquisitions and Divestitures
Note 4 – Derivatives and Risk Management
Note 5 – Reclassifications from Accumulated Other Comprehensive Income (Loss)
Note 6 – Fair Value Measurements
Note 7 – Debt
Note 8 – Commitments and Contingencies
Note 9 – Income Taxes
Note 10 – Asset Retirement Obligation
Note 11 – Retirement and Employee Benefit Plans
Note 12 – Stock-Based Compensation
Note 13 – Segment Information
Note 14 – Subsequent Events
Supplemental Quarterly Results
Supplemental Oil and Gas Disclosures
Page
84
85
86
87
88
89
90
91
91
98
98
101
105
105
107
110
112
114
114
119
123
125
125
125
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Management’s Report on Internal Control Over Financial Reporting
It is the responsibility of the management of Southwestern Energy Company to establish and maintain adequate internal
control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management has
assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2016, utilizing the
Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control—Integrated Framework (2013).
Based on this evaluation, management has concluded the Company’s internal control over financial reporting was
effective as of December 31, 2016.
The effectiveness of our internal control over financial reporting as of December 31, 2016 has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Southwestern Energy Company
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material
respects, the financial position of Southwestern Energy Company and its subsidiaries at December 31, 2016 and 2015, and
the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in
conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on
criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations
of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for
maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control
over financial reporting, included in Management’s Report on Internal Control over Financial Reporting. Our responsibility
is to express opinions on these financial statements and on the Company's internal control over financial reporting based on
our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance
about whether the financial statements are free of material misstatement and whether effective internal control over financial
reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and
significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing
the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control
based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions
and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary
to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts
and expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use,
or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become
inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/PRICEWATERHOUSECOOPERS LLP
Houston, TX
February 23, 2017
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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
2016
For the years ended December 31,
2015
(in millions, except share/per share amounts)
2014
Operating Revenues:
Gas sales
Oil sales
NGL sales
Marketing
Gas gathering
Operating Costs and Expenses:
Marketing purchases
Operating expenses
General and administrative expenses
Restructuring charges
Depreciation, depletion and amortization
Impairment of natural gas and oil properties
Gain on sale of assets, net
Taxes, other than income taxes
Operating Income (Loss)
Interest Expense:
Interest on debt
Other interest charges
Interest capitalized
Gain (Loss) on Derivatives
Loss on Early Extinguishment of Debt
Other Income (Loss), Net
Income (Loss) Before Income Taxes
Provision (Benefit) for Income Taxes:
Current
Deferred
Net Income (Loss)
Mandatory convertible preferred stock dividend
Net Income (Loss) Attributable to Common Stock
Earnings (Loss) Per Common Share:
Basic
Diluted
Weighted Average Common Shares Outstanding:
Basic
Diluted
$
$
$
$
$
1,273
69
92
864
138
2,436
864
592
247
78
436
2,321
–
93
4,631
(2,195)
226
14
(152)
88
(339)
(51)
1
(2,672)
(7)
(22)
(29)
(2,643)
108
(2,751)
(6.32)
(6.32)
$
$
$
$
$
1,946
76
73
863
175
3,133
852
689
246
–
1,091
6,950
(283)
110
9,655
(6,522)
200
60
(204)
56
47
–
(30)
(6,561)
(2)
(2,003)
(2,005)
(4,556)
106
(4,662)
(12.25)
(12.25)
$
$
$
$
$
2,827
19
3
996
193
4,038
980
427
221
–
942
–
–
95
2,665
1,373
101
13
(55)
59
139
–
(4)
1,449
21
504
525
924
–
924
2.63
2.62
435,337,402
435,337,402
380,521,039
380,521,039
351,446,747
352,410,683
The accompanying notes are an integral part of these consolidated financial statements.
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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
2016
For the years ended December 31,
2015
(in millions)
2014
$
(2,643)
$
(4,556)
$
924
Net income (loss)
Change in derivatives:
Settlements (1)
Ineffectiveness
Change in fair value of derivative instruments (2)
Total change in derivatives
Change in value of pension and other postretirement liabilities:
Amortization of prior service cost and net loss included in net periodic
pension cost (3)
Net gain (loss) incurred in period (4)
Total change in value of pension and postretirement liabilities
Change in currency translation adjustment
–
–
–
–
13
(7)
6
3
(128)
1
29
(98)
2
(3)
(1)
(11)
Comprehensive income (loss)
$
(2,634)
$
(4,666)
$
(1) Net of ($81) million and $10 million in taxes for the years ended December 31, 2015 and 2014, respectively.
(2) Net of $16 million and $49 million in taxes for the years ended December 31, 2015 and 2014, respectively.
(3) Net of $8 million in taxes for the year ended December 31, 2016.
(4) Net of ($4) million and ($10) million in taxes for the years ended December 31, 2016 and 2014, respectively.
The accompanying notes are an integral part of these consolidated financial statements.
16
–
73
89
–
(15)
(15)
(8)
990
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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
2016
December 31,
2015
(in millions)
$
$
$
Current assets:
Cash and cash equivalents
Accounts receivable, net
Derivative assets
Other current assets
Total current assets
Natural gas and oil properties, using the full cost method, including $2,105 million
as of December 31, 2016 and $3,727 million as of December 31, 2015 excluded
from amortization
Gathering systems
Other
Less: Accumulated depreciation, depletion and amortization
Total property and equipment, net
Other long-term assets
TOTAL ASSETS
LIABILITIES AND EQUITY
Current liabilities:
Short-term debt
Accounts payable
Taxes payable
Interest payable
Dividends payable
Derivative liabilities
Other current liabilities
Total current liabilities
Long-term debt
Pension and other postretirement liabilities
Other long-term liabilities
Total long-term liabilities
Commitments and contingencies (see Note 8)
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued
495,248,369 shares as of December 31, 2016 (does not include 2,751,410 shares
issued on January 17, 2017 on account of a dividend declared on December 12,
2016) and 390,138,549 as of December 31, 2015
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 6.25% Series B
Mandatory Convertible, $1,000 per share liquidation preference, 1,725,000
shares issued and outstanding as of December 31, 2016 and 2015, conversion in
January 2018
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss
Common stock in treasury, 31,269 and 47,149 shares as of December 31, 2016 and
2015, respectively
Total equity
TOTAL LIABILITIES AND EQUITY
$
1,423
363
51
35
1,872
22,653
1,299
537
(19,534)
4,955
249
7,076
41
473
59
74
27
355
35
1,064
4,612
49
434
5,095
5
–
4,677
(3,725)
(39)
(1)
917
7,076
$
$
$
$
15
327
3
48
393
22,478
1,280
606
(16,821)
7,543
150
8,086
1
513
64
75
27
3
24
707
4,704
50
343
5,097
4
–
3,409
(1,082)
(48)
(1)
2,282
8,086
The accompanying notes are an integral part of these consolidated financial statements.
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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash Flows From Operating Activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by
2016
For the twelve months ended
December 31,
2015
(in millions)
2014
$
(2,643)
$
(4,556)
$
924
operating activities:
Depreciation, depletion and amortization
Impairment of natural gas and oil properties
Amortization of debt issuance costs
Deferred income taxes
(Gain) loss on derivatives, net of settlement
Stock-based compensation
Gain on sale of assets, net
Restructuring charges
Loss on early extinguishment of debt
Other
Change in assets and liabilities:
Accounts receivable
Accounts payable
Taxes payable
Interest payable
Other assets and liabilities
Net cash provided by operating activities
Cash Flows From Investing Activities:
Capital investments
Acquisitions
Proceeds from sale of property and equipment
Other
Net cash used in investing activities
Cash Flows From Financing Activities:
Payments on current portion of long-term debt
Payments on long-term debt
Payments on short-term debt
Payments on revolving credit facility
Borrowings under revolving credit facility
Payments on commercial paper
Borrowings under commercial paper
Change in bank drafts outstanding
Proceeds from issuance of long-term debt
Proceeds from issuance of short-term debt
Debt issuance costs
Proceeds from exercise of common stock options
Proceeds from issuance of common stock
Proceeds from issuance of mandatory convertible preferred stock
Preferred stock dividend
Cash paid for tax withholding
Other
Net cash provided by financing activities
436
2,321
14
(22)
373
29
–
30
51
8
(30)
(69)
(5)
–
5
498
(593)
–
430
1
(162)
(1)
(1,175)
–
(3,268)
3,152
(242)
242
(20)
1,191
–
(17)
–
1,247
–
(27)
(9)
(1)
1,072
1,092
6,950
53
(2,003)
155
26
(283)
–
–
34
203
(78)
(28)
9
6
1,580
(1,798)
(579)
729
10
(1,638)
(1)
(500)
(4,500)
(3,024)
2,840
(7,988)
7,988
12
2,950
–
(20)
–
669
1,673
(79)
–
–
20
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
1,408
15
1,423
$
$
(38)
53
15
$
The accompanying notes are an integral part of these consolidated financial statements.
942
–
10
504
(130)
18
–
–
2
(66)
84
24
–
23
2,335
(2,043)
(5,298)
43
10
(7,288)
(1)
–
–
(5,179)
5,196
–
–
11
500
4,500
(56)
12
–
–
–
–
–
4,983
30
23
53
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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Common Stock
Shares
Issued
Amount
Stock
Shares
Issued
Preferred
Retained
Additional Earnings
Accumulated
Other
Paid-In
Capital
Common
(Accumulated Comprehensive Stock in
Income (Loss) Treasury
Deficit)
Total
(in millions, except share amounts)
– $
2,653 $
969 $
(4) $
–
$
3,622
Balance at December 31, 2013 352,938,584 $
Comprehensive income:
Net income
Other comprehensive income
Total comprehensive income
Stock-based compensation
Exercise of stock options
Issuance of restricted stock
Cancellation of restricted stock
Tax withholding – stock
compensation
Issuance of stock awards
–
–
–
–
402,190
1,299,367
(140,703)
(12,133)
1,687
Balance at December 31, 2014 354,488,992 $
Comprehensive loss:
4
–
–
–
–
–
–
–
–
–
4
Net loss
Other comprehensive loss
Total comprehensive loss
Stock-based compensation
Preferred stock dividend
Issuance of common stock
Issuance of preferred stock
Issuance of restricted stock
Cancellation of restricted stock
Treasury stock – non-qualified
plan
Tax withholding – stock
compensation
Issuance of stock awards
Non-controlling interest
–
–
–
–
–
30,000,000
–
5,821,125
(103,162)
–
(73,869)
5,463
–
Balance at December 31, 2015 390,138,549 $
Comprehensive loss:
Net loss
Other comprehensive income
Total comprehensive loss
Stock-based compensation
Preferred stock dividend (1)
Exercise of stock options
Issuance of common stock
Issuance of restricted stock
Cancellation of restricted stock
Tax withholding – stock
compensation
Issuance of stock awards
–
–
–
–
7,166,389
44,880
98,900,000
87,472
(165,483)
(929,252)
5,814
Balance at December 31, 2016 495,248,369 $
–
–
–
–
–
–
–
–
–
–
–
–
– 1,725,000
–
–
–
–
–
–
–
–
–
4
–
–
–
–
–
–
1
–
–
–
–
5
–
–
–
1,725,000 $
–
–
–
–
–
–
–
–
–
–
–
1,725,000 $
–
–
–
–
–
–
–
–
–
–
–
38
12
–
–
–
924
–
–
–
–
–
–
–
–
66
–
–
–
–
–
–
–
– $
–
1,019 $
–
3,577 $
–
62 $
–
–
–
48
–
669
1,673
–
–
–
–
(4,556)
–
–
–
(106)
–
–
–
–
–
–
–
(110)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
(1)
–
924
66
990
38
12
–
–
–
–
4,662
$
(4,556)
(110)
(4,666)
48
(106)
669
1,673
–
–
(1)
–
–
–
3,409 $
–
3
(1,082) $
–
–
(48) $
–
–
(1) $
–
3
2,282
–
–
–
58
(27)
–
1,246
–
–
(9)
(2,643)
–
–
–
–
–
–
–
–
–
–
9
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
(2,643)
9
(2,634)
58
(27)
–
1,247
–
–
(9)
–
4,677 $
–
(3,725) $
–
(39) $
–
(1) $
–
917
(1) Does not include 2,751,410 shares issued on January 17, 2017 and distributed to holders of the Company’s mandatory convertible preferred stock.
The accompanying notes are an integral part of these consolidated financial statements.
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SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations
Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an
independent energy company engaged in natural gas, oil and NGL exploration, development and production (“E&P”). The
Company is also focused on creating and capturing additional value through its natural gas gathering and marketing
businesses (“Midstream Services”). Southwestern conducts most of its businesses through subsidiaries and operates
principally in two segments: E&P and Midstream Services.
Exploration and Production. Southwestern’s primary business is the exploration for and production of natural gas, oil
and NGLs, with current operations principally focused on the development of unconventional natural gas reservoirs located
in Pennsylvania, West Virginia and Arkansas. The Company’s operations in northeast Pennsylvania, herein referred to as
“Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale.
Operations in West Virginia and southwest Pennsylvania, herein referred to as “Southwest Appalachia,” are focused on the
Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, Southwestern
refers to its properties located in Pennsylvania and West Virginia as the “Appalachian Basin.” The Company’s operations
in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale. Southwestern
has activities ongoing in Colorado and Louisiana, along with other areas in which it is currently assessing new development
opportunities. The Company also has drilling rigs located in Pennsylvania, West Virginia and Arkansas and provides oilfield
products and services, principally serving its E&P operations.
Midstream Services. Through the Company’s affiliated midstream subsidiaries, Southwestern engages in natural gas
gathering activities in Arkansas and Louisiana. These activities primarily support the Company’s E&P operations and
generate revenue from fees associated with the gathering of natural gas. Southwestern’s marketing activities capture
opportunities that arise through the marketing and transportation of the natural gas, oil and NGLs produced in its E&P
operations.
Basis of Presentation
The consolidated financial statements included in this Annual Report present the Company’s financial position, results
of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the
United States (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make
estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities,
if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates. The Company evaluates subsequent events through the date the financial statements
are issued. Certain reclassifications have been made to the prior year financial statements to conform to the 2016
presentation. The effects of the reclassifications were not material to the Company’s consolidated financial statements. See
Note 1 – New Accounting Standards Implemented in this Report for additional information regarding the reclassifications.
Principles of Consolidation
The consolidated financial statements include the accounts of Southwestern and its wholly-owned subsidiaries. All
significant intercompany accounts and transactions have been eliminated.
In 2015, the Company purchased an 86% ownership in a limited partnership which owns and operates a gathering system
in Northeast Appalachia as part of the WPX Property Acquisition (as defined and discussed in Note 3). Because the Company
owns a controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P
segment results. The investor’s share of the partnership activity is reported in retained earnings in the consolidated financial
statements. Net income attributable to noncontrolling interest for the years ended December 31, 2016 and 2015 was
insignificant.
Revenue Recognition
Natural gas and liquid sales. Natural gas and liquid sales are recognized when the products are sold to a purchaser at a
fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured.
The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales
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from its properties. Accordingly, natural gas and liquid sales are not recognized for deliveries in excess of the Company’s
net revenue interest, while natural gas and liquid sales are recognized for any under-delivered volumes. Production
imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. The
Company had no significant production imbalances at December 31, 2016 or 2015.
Marketing. The Company generally markets its natural gas and liquids, as well as some products produced by third
parties, to marketers, local distribution companies and end-users, pursuant to a variety of contracts. Marketing revenues are
recognized when delivery has occurred, title has transferred, the price is fixed or determinable and collectability of the
revenue is reasonably assured.
Gas gathering. In certain areas, the Company gathers its natural gas as well as some natural gas produced by third
parties pursuant to a variety of contracts. Gas gathering revenues are recognized when the service is performed, the price is
fixed or determinable and collectability of the revenue is reasonably assured.
Cash and Cash Equivalents
Cash and cash equivalents are defined by the Company as short-term, highly liquid investments that have an original
maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash.
Management considers cash and cash equivalents to have minimal credit and market risk as the Company monitors the credit
status of the financial institutions holding its cash and marketable securities. The following table presents a summary of cash
and cash equivalents as of December 31, 2016 and December 31, 2015:
For the years ended December 31,
2016
2015
Cash
Marketable Securities (1)
Total
(1) Consists of government stable value money market funds.
$
$
(in millions)
254
1,169
1,423
$
$
15
–
15
Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts. The Company presents the
outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying
consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $8 million and $29
million as of December 31, 2016 and 2015, respectively.
Property, Depreciation, Depletion and Amortization
Natural Gas and Oil Properties. The Company utilizes the full cost method of accounting for costs related to the
exploration, development and acquisition of natural gas and oil properties. Under this method, all such costs (productive
and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized
on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method.
These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the
aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at
10% (standardized measure). Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not
be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling.
Companies using the full cost method are required to use the average quoted price from the first day of each month from the
previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of
their reserves. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs
excluded from amortization, future development costs and production costs could result in future ceiling test impairments.
Costs associated with unevaluated properties are excluded from the amortization base until the properties are evaluated
or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data, wells currently
drilling and related capitalized interest are initially excluded from the amortization base. Leasehold costs are either
transferred to the amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible
impairment or reduction in value. The Company’s decision to withhold costs from amortization and the timing of the transfer
of those costs into the amortization base involves a significant amount of judgment and may be subject to changes over time
based on several factors, including drilling plans, availability of capital, project economics and drilling results from adjacent
acreage. At December 31, 2016, the Company had a total of $2,105 million of costs excluded from the amortization base,
all of which related to its properties in the United States. Inclusion of some or all of these costs in the Company’s United
States properties in the future, without adding any associated reserves, could result in additional ceiling test impairments.
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In the first, second, and third quarters of 2016, the Company’s net book value of its United States and Canada natural
gas and oil properties exceeded the ceiling by approximately $641 million (net of tax) at March 31, 2016, $297 million (net
of tax) at June 30, 2016 and $506 million (net of tax) at September 30, 2016, resulting in non-cash ceiling test impairments
in each of those quarters. Using the average quoted price from the first day of each month from the previous 12 months for
Henry Hub natural gas of $2.48 per MMBtu, West Texas Intermediate oil of $39.25 per barrel and NGLs of $6.74 per barrel,
adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not
exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2016. The Company had no
derivative positions that were designated for hedge accounting as of December 31, 2016.
In the second and third quarters of 2015, the net book value of the Company’s United States natural gas and oil properties
exceeded the ceiling by $944 million (net of tax) at June 30, 2015 and $1,746 million (net of tax) at September 30, 2015 and
resulted in non-cash ceiling test impairments. Cash flow hedges of natural gas production in place increased the ceiling
amount by approximately $60 million and $40 million as of June 30, 2015 and September 30, 2015, respectively. Using the
average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.59 per
MMBtu, West Texas Intermediate oil of $46.79 per barrel and NGLs of $6.82 per barrel, adjusted for market differentials,
the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by $1,586 million (net
of tax) at December 31, 2015 and resulted in a non-cash ceiling test impairment. The Company had no derivative positions
that were designated for hedge accounting as of December 31, 2015.
At December 31, 2014, the ceiling value of the Company’s reserves was calculated based upon the average quoted price
from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.35 per MMBtu, for West
Texas Intermediate oil of $91.48 per barrel and NGLs of $23.79 per barrel, adjusted for market differentials. The Company’s
net book value of its natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test
impairment at December 31, 2014.
Gathering Systems. The Company’s investment in gathering systems is primarily in a system serving its Fayetteville
Shale operations in Arkansas. These assets are being depreciated on a straight-line basis over 25 years.
Capitalized Interest. Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded
from amortization and are actively being evaluated.
Asset Retirement Obligations. The Company owns natural gas and oil properties, which require expenditures to plug
and abandon the wells and reclaim the associated pads when the wells are no longer producing. An asset retirement obligation
associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or when it
becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the
tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement
obligation is recorded at its estimated fair value, and accretion expense is recognized over time as the discounted liability is
accreted to its expected settlement value.
Impairment of long-lived assets. The carrying value of non-full cost pool long-lived assets is evaluated for recoverability
whenever events or changes in circumstances indicate that it may not be recoverable.
Intangible assets. The carrying value of intangible assets are evaluated for recoverability whenever events or changes
in circumstances indicate that it may not be recoverable. Intangible assets are amortized over their useful life.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax
assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the
financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities
are measured using the tax rate expected to be in effect for the year in which those temporary differences are expected to
reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate
change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different
years for income tax and financial reporting purposes. A valuation allowance is established to reduce deferred tax assets if
it is more likely than not that the related tax benefits will not be realized.
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The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions
taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more
likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the
position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood
of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect
management’s estimates of the ultimate outcome of various tax uncertainties. The Company recognizes penalties and interest
related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying consolidated
statements of operations. Additional information regarding uncertain tax positions can be found in Note 9 – Income Taxes.
Derivative Financial Instruments
The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for
speculative trading purposes. The Company uses fixed price swap agreements and options to financially protect sales of
natural gas. Gains and losses resulting from the settlement of derivative contracts have been recognized in gas sales if
designated for hedge accounting treatment or gain (loss) on derivatives if not designated for hedge accounting treatment in
the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity
hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges and not settled
are included in other comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash
flows of the hedged item. In contrast, gains and losses from the ineffective portion of derivative contracts designated for
hedge accounting treatment are recognized currently and have an inconsequential impact in the consolidated statement of
operations. Gains and losses from the unsettled portion of derivative contracts not designated for hedge accounting treatment
are recognized in gain (loss) on derivatives in the consolidated statement of operations. See Note 4 – Derivatives and Risk
Management and Note 6 – Fair Value Measurements for a discussion of the Company’s hedging activities.
Earnings Per Share
Basic earnings per common share is computed by dividing net income (loss) attributable to common stock by the
weighted average number of common shares outstanding during the reportable period. The diluted earnings per share
calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have
been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock,
performance units, the assumed conversion of mandatory convertible preferred stock and the shares of common stock
declared as a preferred stock dividend. An antidilutive impact is an increase in earnings per share or a reduction in net loss
per share resulting from the conversion, exercise, or contingent issuance of certain securities.
In July 2016, the Company completed an underwritten public offering of 98,900,000 shares of its common stock, with
an offering price to the public of $13.00 per share. Net proceeds from the common stock offering were approximately $1,247
million, after underwriting discount and offering expenses. The proceeds from the offering were used to repay $375 million
of the $750 million term loan entered into in November 2015 and to settle certain tender offers by purchasing an aggregate
principal amount of approximately $700 million of the Company’s outstanding senior notes due in the first quarter of 2018.
The remaining proceeds of the offering have been or will be used for general corporate purposes.
In January 2015, the Company completed concurrent underwritten public offerings of 30,000,000 shares of its common
stock and 34,500,000 depositary shares (both share counts include shares issued as a result of the underwriters exercising
their options to purchase additional shares). The common stock offering was priced at $23.00 per share. Net proceeds from
the common stock offering were approximately $669 million, after underwriting discount and offering expenses. Net
proceeds from the depositary share offering were approximately $1.7 billion, after underwriting discount and offering
expenses. Each depositary share represents a 1/20th interest in a share of the Company’s mandatory convertible preferred
stock, with a liquidation preference of $1,000 per share (equivalent to a $50 liquidation preference per depositary share).
The proceeds from the offerings were used to partially repay borrowings under the Company’s $4.5 billion 364-day bridge
facility with the remaining balance of the bridge facility fully repaid with proceeds from the Company’s January 2015 public
offering of $2.2 billion in long-term senior notes.
The mandatory convertible preferred stock entitles the holder to a proportional fractional interest in the rights and
preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights. Unless
converted earlier at the option of the holders, on or around January 15, 2018 each share of convertible preferred stock will
automatically convert into between 37.0028 and 43.4782 shares of the Company’s common stock (correspondingly, each
depositary share will convert into between 1.85014 and 2.17391 shares of the Company’s common stock), subject to
customary anti-dilution adjustments, depending on the volume-weighted average price of the Company’s common stock
over a 20 trading day averaging period immediately prior to that date. The total potential shares of common stock resulting
from the conversion will range from 63,829,830 to 74,999,895 shares.
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The mandatory convertible preferred stock has the non-forfeitable right to participate on an as-converted basis at the
conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security.
Accordingly, it is included in the computation of basic and diluted earnings per share, pursuant to the two-class method. In
the calculation of basic earnings per share attributable to common shareholders, participating securities are allocated earnings
based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common
shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in
undistributed net losses because they are not contractually obligated to do so.
On December 12, 2016, the Company declared its quarterly dividend, payable to holders of the mandatory convertible
preferred stock, and announced that it would pay the quarterly dividend in stock, in lieu of cash, to the extent permitted by
the certificate of designations for the Series B preferred stock. The Company issued 2,751,410 shares of common stock on
January 17, 2017 in payment for the dividend. Dividends declared in the first, second and third quarters of 2016 also were
settled in common stock for a total of 7,166,389 shares, while the dividend declared in December 2015 was paid in cash in
January 2016.
The following table presents the computation of earnings per share for the years ended December 31, 2016, 2015 and
2014:
Net income (loss)
Mandatory convertible preferred stock dividend
Net income (loss) attributable to common stock
Number of common shares:
Weighted average outstanding
Issued upon assumed exercise of outstanding stock options
Effect of issuance of non-vested restricted common stock
Effect of issuance of non-vested performance units
Effect of issuance of mandatory convertible preferred stock
Effect of declaration of preferred stock dividends
Weighted average and potential dilutive outstanding
Earnings (loss) per common share:
Basic
Diluted
$
$
$
$
2016
For the years ended December 31,
2015
(in millions, except share/per share amounts)
(2,643)
108
(2,751)
(4,556)
106
(4,662)
$
$
$
$
2014
924
–
924
435,337,402
–
–
–
–
–
435,337,402
380,521,039
–
–
–
–
–
380,521,039
351,446,747
241,603
448,415
273,918
–
–
352,410,683
(6.32)
(6.32)
$
$
(12.25)
(12.25)
$
$
2.63
2.62
The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per
share for the years ended December 31, 2016, 2015 and 2014, as they would have had an antidilutive effect:
Unvested stock options
Unvested share-based payment
Performance units
Mandatory convertible preferred stock
Declared and unpaid preferred stock dividends
Total
Supplemental Disclosures of Cash Flow Information
For the years ended December 31,
2015
3,835,234
1,990,383
140,414
70,890,312
–
76,856,343
2016
3,692,697
959,233
884,644
74,999,895
2,751,410
83,287,879
2014
1,446,004
29,879
–
–
–
1,475,883
The following table provides additional information concerning interest and income taxes paid as well as changes in
noncash investing activities for the years ended December 31, 2016, 2015, and 2014:
Cash paid during the year for interest, net of amounts capitalized
Cash paid (received) during the year for income taxes
Increase (decrease) in noncash property additions
2016
$
75
(15)
55
For the years ended December 31,
2015
(in millions)
$
$
6
(6)
(10)
2014
50
28
174
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Stock-Based Compensation
The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount
equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations
or capitalizes the cost into natural gas and oil properties or gathering systems included in property and equipment. Costs are
capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural
gas and oil properties or directly related to the construction of the Company’s gathering systems.
Treasury Stock
The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key
employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as
permitted by the plan. The Company includes the assets and liabilities of its supplemental retirement savings plan in its
consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred
compensation arrangement are held in the Rabbi Trust, are presented as treasury stock and are carried at cost. As of
December 31, 2016, 31,269 shares were accounted for as treasury stock, compared to 47,149 shares at December 31, 2015.
Foreign Currency Translation
The Company has designated the Canadian dollar as the functional currency for our activities in Canada. The cumulative
translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are
included as a separate component of other comprehensive income within stockholders’ equity.
New Accounting Standards Implemented in this Report
In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Business Combinations (Topic 805)
(“Update 2015-16”), which seeks to reduce the complexity of amounts recognized in a business combination. The
amendments in Update 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified
during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments
in Update 2015-16 require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes
in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated
as if the accounting had been completed at the acquisition date. The amendments in Update 2015-16 require an entity to
present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-
period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional
amounts had been recognized as of the acquisition date. The amendments in Update 2015-16 are effective for fiscal years
beginning after December 15, 2015, including interim periods within those fiscal years. The Company adopted this update
in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position and cash flows.
In May 2015, the FASB issued Accounting Standards Update No. 2015-07, Disclosures for Investments in Certain
Entities That Calculate Net Asset Value per Share (Or Its Equivalent) (“Update 2015-07”), which amends ASC 820, Fair
Value Measurement. The standard removes the requirement to categorize within the fair value hierarchy investments for
which fair value is measured using the net asset value per share practical expedient and removes certain related disclosure
requirements. The amendments in Update 2015-07 are effective for reporting periods beginning after December 15, 2015,
with early adoption permitted. The Company adopted this update in the first quarter of 2016 resulting in no impact on its
consolidated results of operations, financial position and cash flows. As a result of adoption, certain of the Company’s
pension plan assets measured using net asset value as a practical expedient have not been classified in the fair value hierarchy
in Note 11 – Retirement and Employee Benefit Plans.
In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest-Imputation of Interest (Subtopic
835-30) (“Update 2015-03”), in an effort to simplify presentation of debt issuance costs. Update 2015-03 required that debt
issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying
amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance
costs was not affected by the amendments in this Update. Entities were required to apply the amendments in Update 2015-
03 on a retrospective basis, with the balance sheet of each individual period presented adjusted to reflect the period-specific
effects of applying the new guidance. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Interest-
Imputation of Interest (Subtopic 835-30) (“Update 2015-15”), which addressed the presentation or subsequent measurement
of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 2015-
03 for debt issuance costs related to line-of-credit arrangements. For public entities, Update 2015-03 and Update 2015-15
are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting
period. The Company adopted this update in the first quarter of 2016 resulting in an immaterial impact on its consolidated
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financial position. The Company had $24 million in unamortized debt expense that was classified as a long-term asset at
December 31, 2015, which is now presented as a contra-liability as a result of adoption.
In November 2014, the FASB issued Accounting Standards Update No. 2014-16, Derivatives and Hedging –
Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to
Debt or to Equity (Subtopic 815-15) (“Update 2014-16”), which addressed diversity in practice related to the determination
of whether derivative features embedded in hybrid instruments issued in the form of a share should be bifurcated and
accounted for separately. For public entities, Update 2014-16 was effective for annual reporting periods beginning after
December 15, 2015 including interim periods within that reporting period. The Company adopted this update in the first
quarter of 2016 resulting in no impact on its consolidated results of operations, financial position and cash flows.
In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an
Entity’s Ability to Continue as a Going Concern (Subtopic 205-40) (“Update 2014-15”), which requires management to
assess a company’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances.
For public entities, Update 2014-15 was effective for annual reporting periods ending after December 15, 2016. The
Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations,
financial position, cash flows and disclosures.
New Accounting Standards Not Yet Implemented in this Report
In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (Topic 230)
(“Update 2016-15”), which seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments
are presented and classified in the statement of cash flows. For public entities, Update 2016-15 becomes effective for fiscal
years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted.
The Company is currently evaluating the provisions of Update 2016-15 and assessing the impact, if any, it may have on its
consolidated results of operations, financial position or cash flows.
In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Compensation – Stock Compensation
(Topic 718) (“Update 2016-09”), which seeks to simplify accounting for share-based payment transactions including income
tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash
flows. For public entities, Update 2016-09 becomes effective for fiscal years beginning after December 15, 2016, including
interim periods within those fiscal years, with early adoption permitted. The Company expects to adopt this guidance
effective January 1, 2017. The recognition of previously unrecognized windfall tax benefits is expected to result in a
cumulative-effect adjustment of approximately $149 million, which would increase net deferred tax assets and increase the
valuation allowance by the same amount as of the beginning of 2017. The remaining provisions of this amendment are not
expected to have a material effect on the consolidated results of operations, financial position or cash flows.
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“Update 2016-
02”), which seeks to increase transparency and comparability among organizations by, among other things, recognizing lease
assets and lease liabilities on the balance sheet for leases classified as operating leases under previous GAAP and disclosing
key information about leasing arrangements. In 2016, the Company made progress on contract reviews, drafting its
accounting policies and evaluating the new disclosure requirements. The Company will continue assessing the effect that
the updated standard may have on its consolidated financial statements and related disclosures, and anticipates that its
assessment will be complete in 2018. For public entities, Update 2016-02 becomes effective for fiscal years beginning after
December 15, 2018, including interim periods within those fiscal years, with early adoption permitted.
In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers
(Topic 606) (“Update 2014-09”), which seeks to provide clarity for recognizing revenue. The new standard removes
inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers and
increases disclosure requirements. The codification was amended through additional ASUs and, as amended, requires an
entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the
consideration the entity expects to be entitled to in exchange for those goods or services. The standard is required to be
adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective
approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company has not yet selected
a transition method. The Company has a team in place to analyze the impact of Update 2014-09, and the related ASU's,
across all revenue streams to evaluate the impact of the new standard on revenue contracts. This includes reviewing current
accounting policies and practices to identify potential differences that would result from applying the requirements under the
new standard. In 2016, the Company made progress on contract reviews, drafting its accounting policies and evaluating the
new disclosure requirements. The Company expects to complete its evaluations of the impacts of the accounting and
disclosure requirements on its business processes, controls and systems in the second half of 2017. For public entities, the
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new standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within
that reporting period.
(2) REDUCTION IN WORKFORCE
In January 2016, the Company announced a 40% workforce reduction as a result of lower anticipated drilling
activity. This reduction was substantially completed in the first quarter of 2016. In April 2016, the Company also partially
restructured executive management, which was substantially completed in the second quarter of 2016.
The following table presents a summary of the restructuring charges for the year ended December 31, 2016:
Severance (including payroll taxes)
Stock-based compensation
Pension and other postretirement benefits (1)
Other benefits
Outplacement services, other
Total restructuring charges (2)
(in millions)
44
24
5
3
2
78
$
$
(1)
Includes non-cash charges related to the curtailment and settlement of the pension and other postretirement benefit plans. See Note 11 for additional
details regarding the Company’s retirement and employee benefit plans.
(2) Total restructuring charges were $75 million and $3 million for the Company’s E&P and Midstream Services segments, respectively.
The following table presents a summary of liabilities associated with the Company’s restructuring activities for the year
ended December 31, 2016, which are reflected in accounts payable on the unaudited condensed consolidated balance sheet:
Liability at December 31, 2015
Additions
Distributions
Liability at December 31, 2016
(in millions)
–
49
(48)
1
$
$
Severance payments and other separation costs related to restructuring were substantially completed by the end of 2016.
(3) ACQUISITIONS AND DIVESTITURES
In September 2016, the Company sold approximately 55,000 net acres in West Virginia for approximately $422 million,
which reflects customary adjustments at closing and is subject to customary post-closing adjustments. The Company
accounted for the sale of these natural gas and oil properties as adjustments to capitalized costs, with no recognition of gain
or loss as the sales did not involve a significant change in proved reserves or significantly alter the relationship between costs
and proved reserves. In September 2016, $48 million of the net proceeds was used to repay borrowings under the Company’s
term loan entered into in November 2015. The Company intends to use the remaining net proceeds from the sale for general
corporate purposes, including to fund capital projects.
In May 2015, the Company sold conventional oil and gas assets located in East Texas and the Arkoma Basin for
approximately $211 million. The Company also accounted for the sale of these natural gas and oil properties as adjustments
to capitalized costs, with no recognition of gain or loss as the sales did not involve a significant change in proved reserves
or significantly alter the relationship between costs and proved reserves. The proceeds from the transaction were used to
reduce the Company’s debt. Approximately $205 million of the proceeds received were recorded as a reduction of the
capitalized costs of the Company’s natural gas and oil properties in the United States pursuant to the full cost method of
accounting.
In April 2015, the Company sold its gathering assets located in Bradford and Lycoming counties in northeast
Pennsylvania for an adjusted sales price of approximately $489 million. The net book value of these assets was $206 million
and was held in the Midstream Services segment as of the closing date. A gain on sale of $283 million was recognized and
was included in gain on sale of assets, net on the consolidated statement of operations. The assets included approximately
100 miles of natural gas gathering pipelines, with nearly 600 million cubic feet per day of capacity. The proceeds from the
transaction were used to substantially repay borrowings under the Company’s $500 million term loan facility that would
have matured in December 2016.
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In January 2015, the Company completed an acquisition of certain natural gas and oil assets including approximately
46,700 net acres in northeast Pennsylvania from WPX Energy, Inc. for an adjusted purchase price of $270 million (the “WPX
Property Acquisition”). This acreage was producing approximately 50 million net cubic feet of gas per day from 63 operated
horizontal wells as of December 2014. As part of this transaction, the Company assumed firm transportation capacity of 260
million cubic feet of gas per day predominantly on the Millennium pipeline. The firm transport is being amortized over 19
years. As of December 31, 2016 and 2015 the Company has amortized $17 million and $8 million, respectively. This
transaction was funded with the revolving credit facility and was accounted for as a business combination. The following
table summarizes the consideration paid for the WPX Property Acquisition and the fair value of the assets acquired and
liabilities assumed as of the acquisition date:
Consideration:
Cash
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Proved natural gas and oil properties
Unproved natural gas and oil properties
Intangible asset
Gathering system
Other
Total assets acquired
Liabilities assumed:
Asset retirement obligations
Total liabilities assumed
(in millions)
$
270
31
114
109
22
1
277
(7)
(7)
270
$
In January 2015, the Company completed an acquisition of certain natural gas and oil assets from Statoil ASA including
approximately 30,000 net acres in West Virginia and southwest Pennsylvania for $357 million, which was comprised of
approximately 20% of Statoil’s interests in the properties, (the “Statoil Property Acquisition”). All of these assets were also
assets in which the Company had acquired interests under the Chesapeake Property Acquisition as defined below. This
transaction was funded with the revolving credit facility and was accounted for as a business combination. The Company
allocated the purchase price to natural gas and oil properties, based on the respective fair values of the assets acquired.
In December 2014, the Company completed an acquisition of certain gas and oil assets from Chesapeake Energy
Corporation covering approximately 413,000 net acres in West Virginia and southwest Pennsylvania targeting natural gas,
oil and NGLs contained in the Upper Devonian, Marcellus and Utica Shales for approximately $5.0 billion (the “Chesapeake
Property Acquisition”). The transaction was temporarily financed using a $4.5 billion 364-day senior unsecured bridge term
loan credit facility and a $500 million two-year unsecured term loan. The Company repaid all principal and interest
outstanding on the $4.5 billion bridge facility in January 2015 after permanent financing was finalized, and as a result
expensed $47 million of short-term unamortized debt issuance costs related to the bridge facility in January 2015, recognized
in other interest charges on the consolidated statement of operations. The term loan facility was repaid in full in April 2015
with proceeds from the divestiture of the Company’s northeastern Pennsylvania gathering assets and borrowings under the
revolving credit facility.
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The following table summarizes the consideration paid for the Chesapeake Property Acquisition and the fair value of
the assets acquired and liabilities assumed as of the acquisition date, updated for subsequent customary post-closing
adjustments:
Consideration:
Cash
Recognized amounts of identifiable assets acquired and liabilities assumed:
Assets acquired:
Proved natural gas and oil properties
Unproved natural gas and oil properties
Other property and equipment
Inventory
Total assets acquired
Liabilities assumed:
Asset retirement obligations
Other liabilities
Total liabilities assumed
(in millions)
$
4,949
1,418
3,573
33
3
5,027
(42)
(36)
(78)
4,949
$
The Company recorded the assets acquired and liabilities assumed in the Chesapeake Property Acquisition at their
estimated fair value of approximately $5.0 billion, which the Company considered to be representative of the price paid by
a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. In addition,
the Company included $1 million in general and administrative expenses and $5 million in interest expense for fees related
to the Chesapeake Property Acquisition on its consolidated statement of operations for the year ended December 31, 2014.
The Company included $47 million in other current assets and $1 million in other assets for unamortized fees related to the
bridge facility and term loan facility, respectively, for the Chesapeake Property Acquisition on its consolidated balance sheet
as of December 31, 2014.
The results of operations of the Chesapeake Property Acquisition have been included in the Company’s consolidated
financial statements since the December 22, 2014 closing date, including approximately $10 million of total revenue and $2
million of operating income for the year ended December 31, 2014. Summarized below are the consolidated results of
operations for the year ended December 31, 2014 on an unaudited pro forma basis, as if the acquisition and related financing
had occurred on January 1, 2013. The unaudited pro forma financial information was derived from the historical consolidated
statement of operations of the Company and the statement of revenues and direct operating expenses for the Chesapeake
Property Acquisition properties. The unaudited pro forma financial information does not purport to be indicative of results
of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor
is such information indicative of the Company’s expected future results of operations. The unaudited pro forma financial
information excludes the WPX Property and Statoil Property Acquisitions as the impacts are immaterial.
Revenues (in millions)
Net Income attributable to common stock (in millions)
Earnings per share:
Basic
Diluted
For the years ended
December 31,
2014
2013
(unaudited)
$
$
4,439
803
2.11
2.10
$
$
3,713
594
1.56
1.56
The above acquisitions qualified as business combinations, and as a result, the Company estimated the fair value of the assets
acquired and liabilities assumed as of the acquisition date. The fair value is the price that would be received to sell an asset
or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value
measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made
market assumptions as to future commodity prices, projections of estimated quantities of natural gas, oil and NGL reserves,
expectations for timing and amount of future development and operating costs, projections of future rates of production,
expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined in Note 6 –
Fair Value Measurements.
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(4) DERIVATIVES AND RISK MANAGEMENT
The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts
the predictability of its cash flows related to the sale of those commodities. These risks are managed by the Company’s use
of certain derivative financial instruments. As of December 31, 2016, the Company’s derivative financial instruments
consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps, sold call options and interest
rate swaps. During 2016, the Company settled all of its purchased put options. The Company had basis swaps and sold call
options as of December 31, 2015. A description of the Company’s derivative financial instruments is provided below:
Fixed price swaps
The Company receives a fixed price for the contract and pays a floating market price to the
counterparty.
Purchased put options
Two-way costless
collars
Three-way costless
collars
Basis swaps
Sold call options
The Company purchases put options based on an index price from the counterparty by payment
of a cash premium. If the index price is lower than the put’s strike price at the time of
settlement, the Company receives from the counterparty such difference between the index
price and the purchased put strike price. If the market price settles above the put’s strike price,
no payment is due from either party.
Arrangements that contain a fixed floor price (purchased put option) and a fixed ceiling price
(sold call option) based on an index price which, in aggregate, have no net cost. At the contract
settlement date, (1) if the index price is higher than the ceiling price, the Company pays the
counterparty the difference between the index price and ceiling price, (2) if the index price is
between the floor and ceiling prices, no payments are due from either party, and (3) if the index
price is below the floor price, the Company will receive the difference between the floor price
and the index price.
Arrangements that contain a purchased put option, a sold call option and a sold put option based
on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if
the index price is higher than the sold call strike price, the Company pays the counterparty the
difference between the index price and sold call strike price, (2) if the index price is between
the purchased put strike price and the sold call strike price, no payments are due from either
party, (3) if the index price is between the sold put strike price and the purchased put strike
price, the Company will receive the difference between the purchased put strike price and the
index price, and (4) if the index price is below the sold put strike price, the Company will
receive the difference between the purchased put strike price and the sold put strike price.
Arrangements that guarantee a price differential for natural gas from a specified delivery point.
The Company receives a payment from the counterparty if the price differential is greater than
the stated terms of the contract and pays the counterparty if the price differential is less than
the stated terms of the contract.
The Company sells call options in exchange for a premium. If the market price exceeds the
strike price of the call option at the time of settlement, the Company pays the counterparty such
excess on sold call options. If the market price settles below the call’s strike price, no payment
is due from either party.
Interest rate swaps
Interest rate swaps are used to fix or float interest rates on existing or anticipated indebtedness.
The purpose of these instruments is to manage the Company’s existing or anticipated exposure
to unfavorable interest rate changes.
The Company utilizes counterparties for its derivative instruments that it believes are creditworthy at the time the
transactions are entered into, and the Company closely monitors the credit ratings of these counterparties. Additionally, the
Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and
credit default swap rates where applicable. However, the events in the financial markets in recent years demonstrate there
can be no assurance that a counterparty will be able to meet its obligations to the Company.
The following table provides information about the Company’s financial instruments that are sensitive to changes in
commodity prices and that are used to protect the Company’s exposure. None of the financial instruments below are
designated for hedge accounting treatment. The table presents the notional amount in Bcf, the weighted average contract
prices and the fair value by expected maturity dates as of December 31, 2016:
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Weighted Average Price per MMBtu
Volume
(Bcf)
Swaps
Sold Puts
Purchased
Puts
Sold
Calls
Basis
Differential
$
$
$
$
322
103
135
132
692
18
14
208
16
256
62
62
86
63
52
32
233
3.07
–
–
–
3.00
–
–
–
$
$
–
–
2.29
–
–
–
2.37
–
$
$
–
2.94
2.97
–
–
3.00
2.96
–
$
$
–
3.38
3.30
–
–
3.46
3.37
–
$
$
–
–
–
(0.87)
–
–
–
(0.94)
–
–
–
–
–
$
2.50
$
2.92
$
3.35
$
$
$
–
–
–
–
$
–
–
–
–
$
3.25
3.50
3.50
3.75
–
–
–
–
–
Fair value at
December 31,
2016
(in millions)
$
$
$
$
$
$
$
$
(175)
(42)
(59)
19
(257)
(2)
(6)
(20)
(4)
(32)
(2)
(2)
(46)
(18)
(11)
(6)
(81)
Financial protection on
production
2017
Fixed price swaps
Two-way costless collars
Three-way costless collars
Basis swaps
Total
2018
Fixed price swaps
Two-way costless collars
Three-way costless collars
Basis swaps
Total
2019
Three-way costless collars
Total
Sold call options
2017
2018
2019
2020
Total
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The balance sheet classification of the assets and liabilities related to derivative financial instruments (none of which
are designated for hedge accounting treatment) are summarized below as of December 31, 2016 and 2015:
Balance Sheet Classification
Fair Value
Derivative Assets
Derivatives not designated as hedging instruments:
Two-way costless collars
Three-way costless collars
Basis swaps
Fixed price swaps
Two-way costless collars
Three-way costless collars
Basis swaps
Total derivative assets
Derivative assets
Derivative assets
Derivative assets
Other long-term assets
Other long-term assets
Other long-term assets
Other long-term assets
December 31,
2016
December 31,
2015
(in millions)
$
$
8
11
32
1
2
100
1
155
$
$
–
–
3
–
–
–
–
3
Balance Sheet Classification
Fair Value
Derivative Liabilities
Derivatives not designated as hedging instruments:
Fixed price swaps
Two-way costless collars
Three-way costless collars
Basis swaps
Sold call options
Interest rate swaps
Fixed price swaps
Two-way costless collars
Three-way costless collars
Basis swaps
Sold call options
Interest rate swaps
Total derivative liabilities
Derivative liabilities
Derivative liabilities
Derivative liabilities
Derivative liabilities
Derivative liabilities
Derivative liabilities
Other long-term liabilities
Other long-term liabilities
Other long-term liabilities
Other long-term liabilities
Other long-term liabilities
Other long-term liabilities
December 31,
2016
December 31,
2015
(in millions)
$
$
175
49
70
13
46
2
3
9
122
5
35
1
530
$
–
–
–
–
–
3
–
–
–
–
–
2
5
At December 31, 2016, the net fair value of the Company’s financial instruments related to natural gas was a $372
million liability. The net fair value of the Company’s interest rate swaps was a $3 million liability as of December 31, 2016.
Derivative Contracts Not Designated for Hedge Accounting
As of December 31, 2016, the Company had no positions designated for hedge accounting treatment. Gains and losses
on derivatives that are not designated for hedge accounting treatment, or that do not meet hedge accounting requirements,
are recorded as a component of gain (loss) on derivatives on the consolidated statements of operations. Accordingly, the gain
(loss) on derivatives component of the statement of operations reflects the gains and losses on both settled and unsettled
derivatives. The Company calculates gains and losses on settled derivatives as the summation of gains and losses on positions
which have settled within the reporting period. Only the settled gains and losses are included in the Company’s realized
commodity price calculations.
The Company is a party to interest rate swaps that were entered into to mitigate the Company’s exposure to volatility in
interest rates. The interest rate swaps have a notional amount of $170 million and expire in June 2020. The Company did not
designate the interest rate swaps for hedge accounting treatment. Changes in the fair value of the interest rate swaps are
included in gain (loss) on derivatives on the consolidated statements of operations.
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The following tables summarize the before-tax effect of fixed price swaps, purchased put options, two-way costless
collars, three-way costless collars, basis swaps, sold call options and interest rate swaps not designated for hedge accounting
on the consolidated statements of operations for the years ended December 31, 2016 and 2015:
Derivative Instrument
Fixed price swaps
Two-way costless collars
Three-way costless collars
Basis swaps
Sold call options
Interest rate swaps
Total loss on unsettled derivatives
Derivative Instrument
Fixed price swaps
Purchased put options
Two-way costless collars
Three-way costless collars
Basis swaps
Interest rate swaps
Total gain on settled derivatives (2)
Total gain (loss) on derivatives
Consolidated Statement of Operations
Classification of Gain (Loss)
on Derivatives, Unsettled
Gain (Loss) on Derivatives
Gain (Loss) on Derivatives
Gain (Loss) on Derivatives
Gain (Loss) on Derivatives
Gain (Loss) on Derivatives
Gain (Loss) on Derivatives
Consolidated Statement of Operations
Classification of Gain (Loss)
on Derivatives, Settled
Gain (Loss) on Derivatives
Gain (Loss) on Derivatives
Gain (Loss) on Derivatives
Gain (Loss) on Derivatives
Gain (Loss) on Derivatives
Gain (Loss) on Derivatives
Gain (Loss) on Derivatives, Unsettled
Recognized in Earnings
For the years ended
December 31,
2016
2015
(in millions)
$
$
(177)
(48)
(81)
12
(81)
2
(373)
$
$
(164)
–
–
(2)
13
(2)
(155)
Gain (Loss) on Derivatives, Settled (1)
Recognized in Earnings
For the years ended
December 31,
2016
2015
$
$
$
$
(in millions)
–
11
3
1
21
(2)
34
$
(339)
$
208
–
–
–
(2)
(4)
202
47
(1) The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period.
(2) Excluding interest rate swaps, these amounts are included, along with gas sales revenues, in the calculation of the Company’s realized natural gas
price.
Derivative Contracts Designated for Hedge Accounting
All derivatives are recognized in the balance sheet as either an asset or liability and are measured at fair value, other
than transactions for which normal purchase/normal sale is applied. Certain criteria must be satisfied in order for derivative
financial instruments to be designated for hedge accounting. Unrealized gains and losses related to unsettled derivatives that
have been designated for hedge accounting are recorded in either earnings or as a component of other comprehensive income
until settled. In the period of settlement, the Company recognizes the gains and losses from these qualifying hedges in gas
sales revenues. As of December 31, 2016, the Company had no positions designated for hedge accounting treatment. In
2015, the Company had certain fixed price swaps that were designated for hedge accounting. For the year ended December
31, 2015, the Company reported pre-tax gains in other comprehensive income of $45 million related to the effective portion
of the unsettled fixed price swaps. The ineffective portion of those fixed price swaps was recognized in earnings and had an
inconsequential impact to the consolidated statement of operations for the year ended December 31, 2015. For the year ended
December 31, 2015, pre-tax gains of $209 million on settled fixed price swaps were transferred from other comprehensive
income into gas sales revenues in the consolidated statement of operations.
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(5) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
The following tables detail the components of accumulated other comprehensive income (loss), net of related tax effects,
for the year ended December 31, 2016:
Beginning balance, December 31, 2015
Other comprehensive income (loss) before reclassifications
Amounts reclassified from other comprehensive income (loss) (1)
Net current-period other comprehensive income (loss)
Ending balance, December 31, 2016
(1) See separate table below for details about these reclassifications.
For the year ended December 31, 2016
Pension and
Other
Postretirement
$
$
(25) $
(7)
13
6
(19) $
Foreign
Currency
(in millions)
Total
(23) $
3
–
3
(20) $
(48)
(4)
13
9
(39)
Details about Accumulated Other Comprehensive
Income
Affected Line Item in the Consolidated Statement
of Operations
Pension and other postretirement:
Amortization of prior service cost and net loss (1)
General and administrative expenses
Provision (benefit) for income taxes
Net income (loss)
Total reclassifications for the period
Net income (loss)
See Note 11 for additional details regarding the Company’s retirement and employee benefit plans.
(6) FAIR VALUE MEASUREMENTS
Amount Reclassified from
Accumulated Other
Comprehensive Income
For the year ended
December 31, 2016
(in millions)
$
$
$
21
8
13
13
The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2016 and
2015 were as follows:
December 31, 2016
December 31, 2015
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
Cash and cash equivalents
Credit facility
Term loan facility due December 2020 (1)
Term loan facility due December 2020 (1)
Senior notes
Derivative instruments, net
$
$
1,423
–
327
1,191
3,166
(375)
(in millions)
$
1,423
–
327
1,191
3,182
(375)
$
15
116
750
–
3,867
(2)
15
116
750
–
2,672
(2)
(1) The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its
senior notes due in January 2020.
The carrying values of cash and cash equivalents, accounts receivable, other current assets, accounts payable and other
current liabilities on the consolidated balance sheets approximate fair value because of their short-term nature. For debt and
derivative instruments, the following methods and assumptions were used to estimate fair value:
Debt: The fair values of the Company’s senior notes were based on the market value of the Company’s publicly traded
debt as determined based on the yield of the Company’s senior notes.
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The carrying values of the borrowings under the Company’s term loan facilities and unsecured revolving credit facility
approximate fair value because the interest rate is variable and reflective of market rates. The Company considers the fair
value of its debt to be a Level 2 measurement on the fair value hierarchy.
Derivative Instruments: The fair value of all derivative instruments is the amount at which the instrument could be
exchanged currently between willing parties. The amounts are based on quoted market prices, best estimates obtained from
counterparties and an option pricing model, when necessary, for price option contracts.
The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. As presented in the
tables below, this hierarchy consists of three broad levels:
Level 1 valuations – Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have
the highest priority.
Level 2 valuations – Consist of quoted market information for the calculation of fair market value.
Level 3 valuations – Consist of internal estimates and have the lowest priority.
The Company has classified its derivatives into these levels depending upon the data utilized to determine their fair
values. The Company’s fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using
the NYMEX futures index. The Company utilized discounted cash flow models for valuing its interest rate derivatives (Level
2). The net derivative values attributable to the Company’s interest rate derivative contracts as of December 31, 2016 are
based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield
curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s sold call options, purchased put
options, two-way costless collars and three-way costless collars (Level 3) are valued using the Black-Scholes model, an
industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market
parameters, including assumptions of the NYMEX futures index, interest rates, volatility and credit worthiness. The
Company’s basis swaps (Level 3) are estimated using third-party calculations based upon forward commodity price curves.
Inputs to the Black-Scholes model, including the volatility input, which is the significant unobservable input for Level
3 fair value measurements, are obtained from a third-party pricing source, with independent verification of the most
significant inputs on a monthly basis. An increase (decrease) in volatility would result in an increase (decrease) in fair value
measurement, respectively.
Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):
Fixed price swap assets
Two-way costless collars assets
Three-way costless collars assets
Basis swap assets
Fixed price swap liabilities
Two-way costless collars liabilities
Three-way costless collars liabilities
Basis swap liabilities
Sold call option liabilities
Interest rate swap liabilities
Total
$
$
Fair Value Measurements Using:
December 31, 2016
Quoted Prices
in Active
Markets
(Level 1)
Significant Other
Observable Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Assets (Liabilities)
at Fair Value
–
–
–
–
–
–
–
–
–
–
–
$
$
1
–
–
–
(178)
–
–
–
–
(3)
(180)
$
$
December 31, 2015
–
10
111
33
–
(58)
(192)
(18)
(81)
–
(195)
$
$
1
10
111
33
(178)
(58)
(192)
(18)
(81)
(3)
(375)
Quoted Prices
in Active Markets
(Level 1)
Fair Value Measurements Using:
Significant Other
Observable Inputs
(Level 2)
Significant
Unobservable Inputs
(Level 3)
Assets (Liabilities)
at Fair Value
Basis swap assets
Interest rate swap liabilities
Total
$
$
–
–
–
$
$
–
(5)
(5)
$
$
3
–
3
$
$
3
(5)
(2)
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The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at
fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2016 and
2015. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both
market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued
using pricing models incorporating assumptions that, in the Company’s judgment, reflect reasonable assumptions a
marketplace participant would have used as of December 31, 2016 and 2015.
For the years ended
December 31,
2016
2015
$
(in millions)
3
$
(162)
(36)
–
(195)
(198)
$
$
(8)
9
2
–
3
11
Balance at beginning of period
Total gains (losses):
Included in earnings
Settlements
Transfers into/out of Level 3
Balance at end of period
$
Change in gains (losses) included in earnings relating to derivatives still held as of December 31 $
See Note 11 – Retirement and Employee Benefit Plans for a discussion of the fair value measurement of the Company’s
pension plan assets.
(7) DEBT
The components of debt as of December 31, 2016 and 2015 consisted of the following:
December 31, 2016
Debt
Instrument
Unamortized
Issuance Cost
Unamortized
Debt Discount
Total
(in millions)
Short-term debt:
7.35% Senior Notes due October 2017
7.125% Senior Notes due October 2017
7.15% Senior Notes due June 2018
Total short-term debt
Long-term debt:
Variable rate (3.220% at December 31, 2016) term loan
facility, due December 2020 (1)
Variable rate (3.220% at December 31, 2016) term loan
facility, due December 2020 (2)
3.30% Senior Notes due January 2018 (3) (4)
7.50% Senior Notes due February 2018 (3)
7.15% Senior Notes due June 2018
4.05% Senior Notes due January 2020 (4)
4.10% Senior Notes due March 2022
4.95% Senior Notes due January 2025 (4)
Total long-term debt
Total debt
$
$
$
$
$
15
25
1
41 $
327
1,191
38
212
25
850
1,000
1,000
4,643 $
–
–
–
–
$
$
(2)
(10)
–
–
–
(5)
(4)
(7)
(28) $
4,684 $
(28) $
–
–
–
–
$
$
–
–
–
–
–
–
(1)
(2)
(3) $
(3) $
15
25
1
41
325
1,181
38
212
25
845
995
991
4,612
4,653
(1)
In July 2016, $375 million was repaid on the term loan facility, extending the maturity from November 2018 to December 2020, which will accelerate
to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020.
In September 2016, an additional $48 million was repaid.
(2) The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its
senior notes due in January 2020.
(3)
(4)
In July 2016, the Company purchased approximately $312 million of the 3.30% Senior Notes due January 2018 and $388 million of the 7.50% Senior
Notes due February 2018.
In February and June 2016, Moody’s and S&P downgraded certain senior notes, increasing the interest rates by 175 basis points effective July 2016.
As a result of the downgrades, interest rates increased to 5.05% for the 2018 Notes, 5.80% for the 2020 Notes and 6.70% for the 2025 Notes.
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Debt Instrument
December 31, 2015
Unamortized
Issuance Cost
Unamortized
Debt Discount
(in millions)
Total
Short-term debt:
7.15% Senior Notes due June 2018
Total short-term debt
Long-term debt:
$
$
1 $
1 $
Variable rate (1.886% at December 31, 2015) credit facility,
expires December 2018
Variable rate (1.775% at December 31, 2015) term loan
facility, due November 2018
7.35% Senior Notes due October 2017
7.125% Senior Notes due October 2017
3.30% Senior Notes due January 2018
7.50% Senior Notes due February 2018
7.15% Senior Notes due June 2018
4.05% Senior Notes due January 2020
4.10% Senior Notes due March 2022
4.95% Senior Notes due January 2025
Total long-term debt
Total debt
$
$
116
750
15
25
350
600
26
850
1,000
1,000
4,732 $
$
$
–
–
–
(3)
–
–
(2)
(2)
–
(5)
(5)
(7)
(24) $
$
$
–
–
–
–
–
–
–
–
–
(1)
(1)
(2)
(4) $
1
1
116
747
15
25
348
598
26
844
994
991
4,704
4,733 $
(24) $
(4) $
4,705
The following is a summary of scheduled debt maturities by year as of December 31, 2016 (in millions):
2017
2018
2019
2020
2021
Thereafter
2016 Credit Facility
$
$
41
275
–
2,368
–
2,000
4,684
In June 2016, the Company reduced its existing $2.0 billion unsecured revolving credit facility to $66 million and entered
into a new credit agreement for $1,934 million, consisting of a $1,191 million secured term loan and a new $743 million
unsecured revolving credit facility, which matures in December 2020. The maturity date will accelerate to October 2019 if,
by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due January
2020. The $1,191 million secured term loan is fully drawn, with approximately $285 million of this balance used to pay
down the previous revolving credit facility balance in its entirety. As of December 31, 2016, there were no borrowings under
either revolving credit facility; however, $174 million in letters of credit was outstanding against the 2016 revolving credit
facility.
Loans under the 2016 credit agreement are subject to varying rates of interest based on whether the loan is a Eurodollar
loan or an alternate base rate loan. Eurodollar loans bear interest at the Eurodollar rate, which is adjusted LIBOR plus
applicable margins ranging from 1.750% to 2.500%. Alternate base rate loans bear interest at the alternate base rate plus the
applicable margin ranging from 0.750% to 1.500%. The interest rate on the term loan facility is determined based upon the
Company’s public debt ratings and was 250 basis points over LIBOR as of December 31, 2016.
The new term loan and revolving credit facility contain financial covenants that impose certain restrictions on the
Company. Under the new credit agreement, the Company must maintain a minimum interest coverage of 0.75x in 2016,
increasing by 0.25x increments per year to 1.50x in 2019 and 2020. The Company is also subject to a minimum liquidity
requirement of $300 million, which could be increased up to $500 million upon certain conditions, as well as an anti-hoarding
provision, requiring unrestricted cash in excess of $100 million to pay down any amounts borrowed under the new revolving
credit facility. The financial covenant with respect to minimum interest coverage consists of EBITDAX divided by
consolidated interest expense. EBITDAX, as defined in our 2016 credit agreement, excludes the effects of interest expense,
income taxes, depreciation, depletion and amortization, any non-cash impacts from impairments, certain non-cash hedging
activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost,
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unamortized debt discount and certain restructuring costs. Collateral for the new secured term loan is principally the
Company’s E&P properties in the Fayetteville Shale area, the equity of its subsidiaries and cash and marketable securities
on hand, and the new credit agreement requires a minimum collateral coverage ratio of 1.50x for the 2016 secured term
loan. This collateral also may support all or a part of revolving credit extensions depending on restrictions in the Company’s
senior notes indentures.
As of December 31, 2016, the Company was in compliance with all of the covenants of this credit agreement. Although
the Company does not anticipate any violations of the financial covenants, its ability to comply with these covenants is
dependent upon the success of its exploration and development program and upon factors beyond the Company’s control,
such as the market prices for natural gas, oil and NGLs.
2013 Credit Facility
In December 2013, the Company entered into a credit agreement that exchanged its previous revolving credit
facility. Under the revolving credit facility, the Company had a borrowing capacity of $2.0 billion. The revolving credit
facility was unsecured and was not guaranteed by any subsidiaries. In June 2016, this credit facility was substantially
exchanged for a new credit facility comprised of a $1,191 million secured term loan and a new $743 million revolving credit
facility. The borrowing capacity of the original 2013 credit agreement was reduced from $2.0 billion to $66 million, remains
unsecured and the maturity remains December 2018. As of December 31, 2016, there were no borrowings under this facility.
The existing unsecured 2013 revolving credit facility includes a financial covenant under which the Company may not
have total debt in excess of 60% of its total adjusted book capital. This financial covenant with respect to capitalization
percentages excludes the effects of any full cost ceiling impairments, certain hedging activities and the Company’s pension
and other postretirement liabilities. At December 31, 2016, the Company’s adjusted book capital was 34% debt and 66%
equity.
2015 Term Facility
In November 2015, the Company entered into a $750 million unsecured three-year term loan credit agreement with
various lenders that was utilized to repay borrowings under the revolving credit facility. The interest rate on the term loan
facility is determined based upon the Company’s public debt ratings from Moody’s and S&P and was 250 basis points over
LIBOR as of December 31, 2016. The term loan facility requires prepayment under certain circumstances from the net cash
proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business. In June 2016, this term
loan agreement was amended to extend the maturity date upon a repayment threshold. From the net proceeds of the July
2016 equity offering, the Company repaid $375 million of the $750 million unsecured term loan, which had the effect of
extending the term loan maturity from November 2018 to December 2020, which will accelerate to October 2019 if, by that
date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020. As
a result of the repayment, the Company expensed $3 million of unamortized debt issuance costs, recognized in other interest
charges on the consolidated statement of operations for the year ended December 31, 2016. In September 2016, the Company
repaid an additional $48 million from the proceeds received from the closing of the sale of approximately 55,000 net acres
in West Virginia to Antero Resources Corporation, resulting in an additional $0.4 million of interest expense related to
unamortized debt issuance costs.
Commercial Paper
In April 2015, the Company entered into a commercial paper program which allowed it to issue up to $2.0 billion in
commercial paper, provided that outstanding borrowings from its commercial paper program, combined with outstanding
borrowings under our revolving credit facility, not exceed $2.0 billion. The commercial paper issuance had terms of up to
397 days and carried interest at rates agreed upon at the time of each issuance. As of December 31, 2016 and 2015, the
Company had no outstanding issuances under its commercial paper program, respectively, and had no current plans of further
utilizing the commercial paper market.
Senior Notes
In July 2016, the Company used a portion of the proceeds from the July 2016 equity offering to settle certain tender
offers by purchasing an aggregate principal amount of approximately $700 million of the Company’s outstanding senior
notes due in the first quarter of 2018, resulting in a loss of $51 million for the early retirement and redemption of these senior
notes including $50 million of premiums paid. Additionally, the Company expensed $2 million of unamortized debt issuance
costs and debt discounts, recognized in other interest charges.
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In January 2015, the Company completed a public offering of $350 million aggregate principal amount of its 3.30%
senior notes due 2018 (the “2018 Notes”), $850 million aggregate principal amount of its 4.05% senior notes due 2020 (the
“2020 Notes”) and $1.0 billion aggregate principal amount of its 4.95% senior notes due 2025 (the “2025 Notes” together
with the 2018 and 2020 Notes, the “Notes”), with net proceeds from the offering totaling approximately $2.2 billion after
underwriting discounts and offering expenses. The proceeds from this offering were used to repay the remaining principal
and interest outstanding under the Company’s $4.5 billion 364-day bridge term loan facility, which was first reduced with
proceeds from the Company’s concurrent underwritten public offerings of common and preferred stock, and were also used
to repay a portion of amounts outstanding under the Company’s revolving credit facility. As a result of this repayment, the
Company expensed $47 million of short-term unamortized debt issuance costs related to the bridge facility in January 2015,
recognized in other interest charges on the consolidated statement of operations for the year ended December 31, 2016. The
Notes were sold to the public at a price of 99.949% of their face value for the 2018 Notes, 99.897% of their face value for
the 2020 Notes and 99.782% of their face value for the 2025 Notes. The interest rates on the Notes are determined based
upon the public bond ratings from Moody’s and S&P. Downgrades on the Notes from either rating agency increase interest
costs by 25 basis points per downgrade level and upgrades decrease interest costs by 25 basis points per upgrade level, up to
the stated coupon rate, on the following semi-annual bond interest payment. In February and June 2016, Moody’s and S&P
downgraded the Notes, increasing the interest rates by 175 basis points effective July 2016. As a result of these downgrades,
interest rates increased to 5.05% for the 2018 Notes, 5.80% for the 2020 Notes and 6.70% for the 2025 Notes. In the event
of future downgrades, the coupons for this series of notes are capped at 5.30%, 6.05% and 6.95%, respectively. The first
coupon payment to the bondholders at the higher interest rates was paid in January 2017.
Chesapeake Property Acquisition Financing
On December 19, 2014, the Company entered into a $4.5 billion unsecured 364-day bridge term loan credit agreement
with various lenders. The bridge facility required prepayments under certain circumstances from the net cash proceeds of
sales of equity or certain assets and borrowings outside the ordinary course of business or for specified uses. The Company
repaid the $4.5 billion outstanding and terminated the bridge facility in January 2015 with net proceeds of $669 million and
$1.7 billion from common stock and depositary share offerings, respectively, and $2.2 billion from senior note offerings with
the difference utilized to pay down amounts under the revolving credit facility.
(8) COMMITMENTS AND CONTINGENCIES
Operating Commitments and Contingencies
As of December 31, 2016, the Company’s contractual obligations for demand and similar charges under firm
transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering
systems 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. The Company
also had guarantee obligations of up to $862 million of that amount. As of December 31, 2016, future payments under non-
cancelable firm transportation and gathering agreements are as follows:
Infrastructure Currently in Service
Pending Regulatory Approval and/or
Construction (1)
Total Transportation Charges
$
$
Payments Due by Period
Total
Less than 1
Year
1 to 3 Years 3 to 5 Years
(in millions)
5 to 8 years
More than 8
Years
5,067 $
3,362
612 $
15
1,158 $
326
825 $
450
829 $
678
1,643
1,893
8,429 $
627 $
1,484 $
1,275 $
1,507 $
3,536
(1) Based on the estimated in-service dates as of December 31, 2016.
The Company has 13 leases for pressure pumping equipment for its E&P operations under leases that expire between
December 2017 and January 2018. The Company’s current aggregate annual payment under the leases is approximately $8
million. Certain of these leases provide for a residual value guarantee for any deficiency if the equipment is sold for less
than the sale option amount (recognized as a liability of approximately $4 million at December 31, 2016). The Company
has 7 leases for drilling rigs for its E&P operations that expire through 2021 with a current aggregate annual payment of
approximately $13 million. The lease payments for the pressure pumping equipment, as well as other operating expenses
for the Company’s drilling operations, are capitalized to natural gas and oil properties and are partially offset by billings to
third-party working interest owners for their share of fracture stage charges.
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The Company leases compressors, aircraft, vehicles, office space and equipment under non-cancelable operating leases
expiring through 2027. As of December 31, 2016, future minimum payments under these non-cancelable leases accounted
for as operating leases are approximately $66 million in 2017, $52 million in 2018, $45 million in 2019, $35 million in 2020,
$17 million in 2021 and $14 million thereafter.
The Company also has commitments for compression services related to its Midstream Services and E&P segments. As
of December 31, 2016, future minimum payments under these non-cancelable agreements are approximately $16 million in
2017, $7 million in 2018 and $3 million in 2019.
Environmental Risk
The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup
related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the
amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not
have a material effect on the financial position or results of operations of the Company.
Litigation
The Company is subject to various litigation, claims and proceedings that have arisen in the ordinary course of business,
such as for alleged breaches of contract, miscalculation of royalties, and pollution, contamination or nuisance. Management
believes that such litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are
not likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows. Many
of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all
subject to inherent uncertainties; therefore, management’s view may change in the future. If an unfavorable final outcome
were to occur, there exists the possibility of a material impact on the Company’s financial position, results of operations or
cash flows for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a
liability is both probable and the amount can be reasonably estimated.
Berry-Helfand (Tovah Energy)
In February 2009, one of the Company’s subsidiaries was added as a defendant in a case then styled Tovah Energy, LLC
and Toby Berry-Helfand v. David Michael Grimes, et al., then pending in the 273rd District Court in Shelby County, Texas.
The plaintiff alleged that the subsidiary used information provided by the plaintiff under a confidentiality agreement, which
she claimed, among other things, breached the agreement and constituted a trade secret. Following a trial in December 2010,
the court awarded approximately $11 million in actual damages and approximately $24 million in disgorgement of profits,
along with interest and attorneys’ fees. Both sides appealed, and in July 2013 the Texas Court of Appeals for the Twelfth
District reversed on all claims except misappropriation of trade secrets, reduced the judgment to the actual damages award,
along with interest and attorneys’ fees, and ordered the case remanded for an award of attorneys’ fees to the Company’s
subsidiary on one of the claims on which judgment was reversed. Both parties petitioned the Supreme Court of Texas for
review. In June 2016, the Supreme Court ruled that insufficient evidence supported the damage award and remanded the
case for a new trial. The parties subsequently reached a settlement, the amount of which is reflected in the Company’s
financial statements as of, and for the period ended, December 31, 2016.
Arkansas Royalty Litigation
Certain of the Company’s subsidiaries are defendants in three cases, two filed in Arkansas state court in 2010 and 2013
and one in federal court in 2014, on behalf of putative classes of royalty owners on some of the Company’s leases located in
Arkansas. The chief complaint in all three cases is that one of the Company’s subsidiaries underpaid the royalty owners by,
among other things, deducting from royalty payments costs for gathering, transportation, and compression of natural gas in
excess of what is permitted by the relevant leases. In September and October 2014 the judges in the two Arkansas state
actions entered orders certifying classes of royalty owners who are citizens of Arkansas.
In November 2015, the court in the federal case denied the plaintiff’s motion to certify a class of royalty owners not
included in either of the two state cases. In April 2016, the court certified a broader class that includes Arkansas residents
and citizens. Class members were notified of the pending action in late 2016, and the period to “opt out” of the class has
expired. The plaintiff in the federal case presented two alternative damages theories. Under one theory, plaintiffs have
asserted that obligations to affiliates are not “incurred” and therefore the exploration and production subsidiary was not
entitled to deduct any post-production costs; the federal court has granted partial summary judgment for the Company’s
subsidiaries on this theory. Under another theory, plaintiffs assert that the gathering and treating rates the Company deducted
from royalty payments exceeded the affiliates’ actual costs or otherwise were not reasonable. The plaintiffs have not
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disclosed a specific damage calculation for any putative class, but based on the class representative’s disclosure regarding
the calculation of claimed damages, class-wide damages could exceed $100 million. The court has set a trial date in the
second quarter of 2017. The Company has moved for summary judgment on all claims, which remains pending before the
trial judge.
The Company’s subsidiaries appealed the class certification orders in the state cases. In December 2016 the Arkansas
Supreme Court affirmed the certifications. These cases are now before the Arkansas trial judges. The precise configuration
of the classes has not been determined, particularly in light of the overlapping composition of the class in the federal case.
No date for trial has been set.
In addition, in September 2015 three cases were filed in Arkansas state court on behalf of a total of 248 individually
named plaintiffs. Each case asserts complaints that are in substance virtually identical to the above-described case. The
Company and its subsidiaries have removed two of the cases to federal court, and those cases have been assigned to the court
in which the above-described federal case is pending. All three cases have been stayed.
Management believes that, in all of the above cases, the deductions from royalty payments as calculated are permitted
and intends to defend the cases vigorously. The Company’s assessment may change in the future due to the occurrence of
certain events, such as adverse judgments, and such a re-assessment could lead to the determination that the potential liability
is probable and could be material to the Company’s results of operations, financial position or cash flows.
Indemnifications
The Company provides certain indemnifications in relation to dispositions of assets. These indemnifications typically
relate to disputes, litigation or tax matters existing at the date of disposition. No liability has been recognized in connection
with these indemnifications.
(9) INCOME TAXES
The provision (benefit) for income taxes included the following components:
Current:
Federal
State
Deferred:
Federal
State
Foreign
Provision (benefit) for income taxes
2016
2015
(in millions)
2014
$
$
(6)
(1)
(7)
(22)
–
–
(22)
(29)
$
$
$
1
(3)
(2)
(1,697)
(304)
(2)
(2,003)
(2,005)
$
11
10
21
501
2
1
504
525
The provision for income taxes was an effective rate of 1% in 2016, 31% in 2015 and 36% in 2014. The following
reconciles the provision for income taxes included in the consolidated statements of operations with the provision which
would result from application of the statutory federal tax rate to pre-tax financial income:
Expected provision (benefit) at federal statutory rate
Increase (decrease) resulting from:
State income taxes, net of federal income tax effect
Nondeductible expenses
State rate redetermination
Change in uncertain tax positions
Change in valuation allowance
Other
Provision (benefit) for income taxes
2016
2015
(in millions)
2014
$
(935)
$
(2,296)
$
(79)
–
–
(19)
1,002
2
(29)
$
(194)
–
–
(7)
495
(3)
(2,005)
$
$
507
58
3
(48)
–
5
–
525
Our effective tax rate decreased in 2016, as compared with 2015, primarily due to the recognition of a valuation
allowance in the fourth quarter of 2015 that persisted throughout 2016.
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The components of the Company’s deferred tax balances as of December 31, 2016 and 2015 were as follows:
Deferred tax liabilities:
Differences between book and tax basis of property
Other
Deferred tax assets:
Accrued compensation
Alternative minimum tax credit carryforward
Accrued pension costs
Asset retirement obligations
Net operating loss carryforward
Derivative activity
Other
Valuation allowance
Net deferred tax liability
2016
2015
(in millions)
$
$
$
81
1
82
38
100
19
53
1,177
142
29
1,558
(1,476)
–
$
216
2
218
19
125
19
77
445
–
26
711
(493)
–
In 2016, the Company paid less than $1 million in state income taxes and received $15 million in federal income tax
refunds. In 2015, the Company paid less than $1 million in state income taxes and did not pay federal income taxes. The
Company’s net operating loss carryforward as of December 31, 2016 was $3.2 billion and $2.2 billion for federal and state
reporting purposes, respectively, the majority of which will expire between 2029 and 2036. Additionally, the Company has
an income tax net operating loss carryforward related to its Canadian operations of $35 million, with expiration dates of 2030
through 2036. The Company also had an alternative minimum tax credit carryforward of $100 million and a statutory
depletion carryforward of $13 million as of December 31, 2016.
A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than
not that some or all of the benefit from the deferred tax asset will not be realized. To assess the likelihood, the Company
uses estimates and judgment regarding future taxable income, and considers the tax consequences in the jurisdiction where
such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current
financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning
strategies as well as current and forecasted business economics of the oil and gas industry.
Due to the continued write-downs of the carrying value of natural gas and oil properties, the Company maintained its
net deferred tax asset position at December 31, 2016. The Company believes it is more likely than not that these deferred
tax assets will not be realized and recorded a $983 million increase in valuation allowance for the year ended December 31,
2016, reflected as a component of income tax expense. Management assesses available positive and negative evidence to
estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. In management’s
view, the cumulative loss incurred over the three-year period ending December 31, 2016, outweighs any positive factors,
such as the possibility of future growth. The amount of the deferred tax asset considered realizable, however, could be
adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of cumulative losses
is no longer present and additional weight is given to subjective evidence such as future expected growth.
Deferred tax assets relating to tax benefits of employee stock option grants have been reduced to reflect exercises. Some
exercises resulted in tax deductions in excess of previously recorded benefits based on the option value at the time of the
grant (“windfalls”). Although these additional tax benefits or “windfalls” are reflected in net operating loss carryforwards,
the additional tax benefit associated with the windfall is not recognized until the deduction reduces taxes payable.
Accordingly, since the tax benefit does not reduce the Company’s current taxes payable in 2016 due to net operating loss
carryforwards, these “windfall” tax benefits are not reflected in its net operating losses in deferred tax assets for 2016.
Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets for 2016 were $149 million.
A tax position must meet certain thresholds for any of the benefit of the uncertain tax position to be recognized in the
financial statements. As of December 31, 2016, the amount of unrecognized tax benefits related to alternative minimum tax
was $17 million. The uncertain tax position identified would not have a material effect on the effective tax rate. No material
changes to the current uncertain tax position are expected within the next 12 months. As of December 31, 2016, the Company
had accrued a liability of less than $1 million of interest related to this uncertain tax position. The Company recognizes
penalties and interest related to uncertain tax positions in income tax expense.
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A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
2016
2015
Unrecognized tax benefits at beginning of period
Additions based on tax positions related to the current year
Additions to tax positions of prior years
Reductions to tax positions of prior years
Unrecognized tax benefits at end of period
$
$
$
(in millions)
37
–
–
(20)
17
$
44
7
–
(14)
37
The Internal Revenue Service is currently auditing the Company’s federal income tax return for 2014. The income tax
years 2013 to 2016 remain open to examination by the major taxing jurisdictions to which the Company is subject.
(10) ASSET RETIREMENT OBLIGATIONS
The following table summarizes the Company’s 2016 and 2015 activity related to asset retirement obligations:
Asset retirement obligation at January 1
Accretion of discount
Obligations incurred
Obligations settled/removed (1)
Revisions of estimates (2)
Asset retirement obligation at December 31
Current liability
Long-term liability
Asset retirement obligation at December 31
2016
2015
(in millions)
$
$
$
201
10
1
(45)
(26)
141
6
135
141
$
$
$
207
11
17
(30)
(4)
201
10
191
201
(1) Obligations settled/removed include $35 million and $25 million related to asset divestitures in 2016 and 2015, respectively.
(2) Estimates in the costs to retire wells and well pads were revised downward based on internal estimates of future obligation requirements and
updated third-party cost quotes.
(11) RETIREMENT AND EMPLOYEE BENEFIT PLANS
401(k) Defined Contribution Plan
The Company has a 401(k) defined contribution plan covering eligible employees. The Company expensed $4 million,
$3 million and $3 million of contribution expense in 2016, 2015 and 2014, respectively. Additionally, the Company
capitalized $2 million, $4 million and $3 million of contributions in 2016, 2015 and 2014, respectively, directly related to
the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to
the construction of the Company’s gathering systems.
Defined Benefit Pension and Other Postretirement Plans
Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon
average final compensation and years of service. Effective January 1, 1998, the Company amended its pension plan to
become a “cash balance” plan on a prospective basis for its non-bargaining employees. A cash balance plan provides benefits
based upon a fixed percentage of an employee’s annual compensation. The Company’s funding policy is to contribute
amounts which are actuarially determined to provide the plans with sufficient assets to meet future benefit payment
requirements and which are tax deductible.
The postretirement benefit plan provides contributory health care and life insurance benefits. Employees become eligible
for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical
expenses reduced by deductibles and other coverages.
Substantially all employees are covered by the Company’s defined benefit pension and postretirement benefit plans. The
Company accounts for its defined benefit pension and other postretirement plans by recognizing the funded status of each
defined pension benefit plan and other postretirement benefit plan on the Company’s balance sheet. In the event a plan is
overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, the Company recognizes a liability.
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In January 2016, the Company initiated a reduction in workforce that was effectively completed by the end of the first
quarter. As a result of the workforce reduction, the Company recognized a $1 million non-cash curtailment loss related to its
pension plan for both the curtailment-related decrease to the benefit obligation and the recognition of the proportionate share
of unrecognized prior service cost and net loss from other comprehensive income (loss) in the second quarter of 2016. For
the year ended December 31, 2016, the Company recognized a non-cash settlement loss of $11 million related to a total of
$37 million of lump sum payments from the pension plan. Additionally, the Company recognized a non-cash curtailment
gain of $6 million related to its other postretirement benefit plan in the first quarter of 2016.
The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded
status as of December 31, 2016 and 2015:
Change in benefit obligations:
Benefit obligation at January 1
Service cost
Interest cost
Participant contributions
Actuarial loss (gain)
Benefits paid
Plan amendments
Curtailments
Settlements
Benefit obligation at December 31
Change in plan assets:
Fair value of plan assets at January 1
Actual return on plan assets
Employer contributions
Participant contributions
Benefits paid
Settlements
Fair value of plan assets at December 31
Funded status of plans at December 31
Pension Benefits
2016
2015
Other Postretirement
Benefits
2016
2015
138
11
5
–
14
(3)
–
(8)
(40)
117
$
$
Pension Benefits
2016
2015
108
3
10
–
(3)
(37)
81
$
$
(in millions)
134
16
6
–
(7)
(11)
–
–
–
138
$
$
(in millions)
108
(1)
12
–
(11)
–
108
$
$
20
2
1
–
(2)
(1)
–
(7)
–
13
$
$
Other Postretirement
Benefits
2016
2015
–
–
1
–
(1)
–
–
$
$
18
3
1
–
(2)
–
–
–
–
20
–
–
–
–
–
–
–
(36) $
(30) $
(13) $
(20)
$
$
$
$
$
The Company uses a December 31 measurement date for all of its plans and had liabilities recorded for the underfunded
status for each period as presented above.
The change in accumulated other comprehensive income related to the pension plans was a gain of $7 million ($4 million
after tax) for the year ended December 31, 2016 and a loss of $2 million ($2 million after tax) for the year ended December
31, 2015. The change in accumulated other comprehensive income related to the other postretirement benefit plan was a
gain of $3 million ($2 million after tax) for the year ended December 31, 2016 and a gain of $1 million ($1 million after tax)
for the year ended December 31, 2015. Included in accumulated other comprehensive income as of December 31, 2016 and
2015 was a $31 million loss ($19 million net of tax) and a $42 million loss ($25 million net of tax), respectively, related to
the Company’s pension and other postretirement benefit plans. For the year ended December 31, 2016, $6 million was
classified to accumulated other comprehensive income, primarily driven by actuarial loss adjustments. Amortization of prior
period service cost reclassified from accumulated other comprehensive income to general and administrative expenses for
the year was immaterial.
The amount in accumulated other comprehensive income that is expected to be recognized as a component of net
periodic benefit cost during 2017 is a $1 million net loss.
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The pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of
December 31, 2016 and 2015 are as follows:
Projected benefit obligation
Accumulated benefit obligation
Fair value of plan assets
$
2016
2015
(in millions)
117 $
116
81
138
135
108
Pension and other postretirement benefit costs include the following components for 2016, 2015 and 2014:
2016
Pension Benefits
2015
2014
2016
Other Postretirement
Benefits
2015
2014
$
Service cost
Interest cost
Expected return on plan assets
Amortization of transition obligation
Amortization of prior service cost
Amortization of net loss
Net periodic benefit cost
Curtailment loss
Settlement loss
Total benefit cost (benefit)
$
11 $
5
(6)
–
–
2
12
1
11
24 $
16 $
6
(9)
–
–
2
15
–
–
15 $
(in millions)
13 $
5
(7)
–
–
1
12
–
–
12 $
2 $
1
–
–
–
–
3
(6)
–
(3) $
3 $
1
–
–
–
–
4
–
–
4 $
2
1
–
–
–
–
3
–
–
3
Amounts recognized in other comprehensive income for the year ended December 31, 2016 were as follows:
Pension Benefits
Other Postretirement
Benefits
Net actuarial (loss) gain arising during the year
Amortization of prior service cost
Amortization of net loss
Settlements
Tax effect
$
$
$
(in millions)
(13)
–
20
–
(3)
4
$
2
–
–
1
(1)
2
The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2016 and 2015 are
as follows:
Pension Benefits
Other Postretirement
Benefits
2016
2015
2016
2015
Discount rate
Rate of compensation increase
4.20 %
3.50 %
4.60 %
3.50 %
4.20 %
n/a
4.60 %
n/a %
The assumptions used in the measurement of the Company’s net periodic benefit cost for 2016, 2015 and 2014 are as
follows:
Discount rate
Expected return on plan assets
Rate of compensation increase
2016
4.20 %
7.00 %
3.50 %
Pension Benefits
2015
4.25 %
7.00 %
4.50 %
2014
5.00 %
7.00 %
4.50 %
Other Postretirement
Benefits
2015
4.25 %
n/a
n/a
2016
4.20 %
n/a
n/a
2014
5.00 %
n/a
n/a
The expected return on plan assets for the various benefit plans is based upon a review of the historical returns
experienced, combined with the future expected returns based upon the asset allocation strategy employed. The plans seek
to achieve an adequate return to fund the obligations in a manner consistent with the federal standards of the Employee
Retirement Income Security Act and with a prudent level of diversification.
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For measurement purposes, the following trend rates were assumed for 2016 and 2015:
Health care cost trend assumed for next year
Rate to which the cost trend is assumed to decline
Year that the rate reaches the ultimate trend rate
2016
2015
7%
5%
2034
8%
5%
2034
Assumed health care cost trend rates have a significant effect on the amounts for the health care plans. A one percentage
point change in assumed health care cost trend rates would have the following effects:
Effect on the total service and interest cost components
Effect on postretirement benefit obligations
Pension Payments and Asset Management
1% Increase
1% Decrease
$
$
(in millions)
–
2
$
$
–
(2)
In 2016, the Company contributed $10 million to its pension plans and $1 million to its other postretirement benefit
plan. The Company expects to contribute $15 million to its pension and other postretirement benefit plans in 2017.
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
Pension Benefits
Other Postretirement Benefits
2017
2018
2019
2020
2021
Years 2022-2026
$
(in millions)
8
6
6
7
8
46
2017
2018
2019
2020
2021
Years 2022-2026
$
1
1
1
1
1
6
The Company’s overall investment strategy is to provide an adequate pool of assets to support both the long-term growth
of plan assets and to ensure adequate liquidity exists for the near-term payment of benefit obligations to participants, retirees
and beneficiaries. The Benefits Administration Committee of the Company administers the Company’s pension plan assets.
The Benefits Administration Committee believes long-term investment performance is a function of asset-class mix and
restricts the composition of pension plan assets to a combination of cash and cash equivalents, domestic equity markets,
international equity markets or investment grade fixed income assets.
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The table below presents the allocations targeted by the Benefits Administration Committee and the actual weighted-
average asset allocation of the Company’s pension plan as of December 31, 2016, by asset category. The asset allocation
targets are subject to change and the Benefits Administration Committee allows for its actual allocations to deviate from
target as a result of current and anticipated market conditions. Plan assets are periodically balanced whenever the allocation
to any asset class falls outside of the specified range.
Asset category:
Equity securities:
U.S. Equity (1)
Non-U.S. Developed Equity (2)
Emerging Markets Equity (3)
Opportunistic (4)
Fixed income (5)
Cash (6)
Total
Pension Plan Asset
Allocations
Target
Actual
35 %
30 %
5 %
– %
28 %
2 %
100 %
36 %
28 %
6 %
– %
25 %
5 %
100 %
(1)
(2)
(3)
(4)
(5)
(6)
Includes the following equity securities in the table below: U.S. large cap growth equity, U.S. large cap value equity, U.S. large cap core equity, and
U.S. small cap equity.
Includes Non-U.S. equity securities in the table below.
Includes emerging markets equity securities below.
Includes none of the securities in the table below.
Includes fixed income pension plan assets in the table below.
Includes Cash and cash equivalents pension plan assets in the table below.
Utilizing the fair value hierarchy described in Note 6 – Fair Value Measurements, the Company’s fair value measurement
of pension plan assets as of December 31, 2016 is as follows:
Total
$
Measured within fair value hierarchy
Equity securities:
U.S. large cap growth equity (1)
U.S. large cap value equity (2)
U.S. small cap equity (3)
Non-U.S. equity (4)
Emerging markets equity (5)
Fixed income (6)
Cash and cash equivalents
Total measured within fair value hierarchy $
Measured at net asset value (7)
Equity securities:
U.S. large cap core equity (8)
Total measured at net asset value
Total plan assets at fair value
$
$
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant
Observable Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
(in millions)
6 $
6
3
23
4
21
4
67 $
–
–
–
–
–
–
–
–
$
$
–
–
–
–
–
–
–
–
6 $
6
3
23
4
21
4
67 $
14
14
81
(1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
(2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
(3) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
(4) Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.
(5) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.
(6) Institutional funds that seek an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S.
Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term.
(7) Plan assets for which fair value was measured using net asset value as a practical expedient.
(8) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
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Utilizing the fair value hierarchy described in Note 6 – Fair Value Measurements, the Company’s fair value measurement
of pension plan assets at December 31, 2015 is as follows:
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Total
Significant
Observable Inputs
(Level 2)
Significant
Unobservable Inputs
(Level 3)
Measured within fair value hierarchy
Equity securities:
U.S. large cap growth equity (1)
U.S. large cap value equity (2)
U.S. small cap equity (3)
Non-U.S. equity (4)
Emerging markets equity (5)
Cash and cash equivalents
$
Total measured within fair value hierarchy $
Measured at net asset value (6)
Equity securities:
U.S. large cap core equity (7)
Fixed income (8)
Total measured at net asset value
Total plan assets at fair value
$
$
9 $
9
3
31
5
2
59 $
18
31
49
108
(in millions)
9 $
9
3
31
5
2
59 $
–
–
–
–
–
–
–
$
$
–
–
–
–
–
–
–
(1) Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
(2) Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
(3) Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
(4) Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.
(5) An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.
(6) Plan assets for which fair value was measured using net asset value as a practical expedient.
(7) An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
(8) An institutional fund that seeks an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S.
Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term.
The Company’s pension plan assets that are classified as Level 1 are the investments comprised of either cash or
investments in open-ended mutual funds which produce a daily net asset value that is validated with a sufficient level of
observable activity to support classification of the fair value measurement as Level 1. Due to the Company’s implementation
of Accounting Standards Update No. 2015-07, assets measured using net asset value as a practical expedient have not been
classified in the fair value hierarchy. No concentration of risk arising within or across categories of plan assets exists due to
any significant investments in a single entity, industry, country or investment fund.
(12) STOCK-BASED COMPENSATION
The Southwestern Energy Company 2013 Incentive Plan was adopted in February 2013, approved by stockholders in
May 2013 and amended and restated per stockholders’ approval in May 2016 (the “2013 Plan”). The 2013 Plan provides
for the compensation of officers, key employees and eligible non-employee directors of the Company and its subsidiaries.
The 2013 Plan replaced the Southwestern Energy Company 2004 Stock Incentive Plan, the Southwestern Energy Company
2000 Stock Incentive Plan (“2000 Plan”) and the Southwestern Energy Company 2002 Employee Stock Incentive Plan
(“2002 Plan”) but did not affect prior awards under those plans which remained valid and some of which are still outstanding.
The awards under the prior plans have been adjusted for stock splits as permitted under such plans.
The 2013 Plan provides for grants of options, stock appreciation rights, and shares of restricted stock and restricted stock
units to employees, officers and directors that, in the aggregate, do not exceed 33,850,000 shares. The types of incentives
that may be awarded are comprehensive and are intended to enable the Company’s board of directors to structure the most
appropriate incentives and to address changes in income tax laws which may be enacted over the term of the 2013 Plan.
As initially adopted, the 2004 Plan, the 2000 Plan and the 2002 Plan provided for grants of options, stock appreciation
rights, shares of phantom stock and shares of restricted stock that, in the aggregate, did not exceed 16,800,000, 1,250,000
and 300,000 shares, respectively, to employees who are not officers or directors of the Company under provisions of Section
16 of the Securities Exchange Act of 1934, as amended. The Company may utilize treasury shares, if available, or authorized
but unissued shares when a stock option is exercised or when restricted stock is granted.
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The Company measures the cost of employee services received in exchange for an award of equity instruments based
on the grant date fair value of the award. All options are issued at fair market value at the date of grant and expire seven
years from the date of grant for awards under both the 2013 Plan and the 2004 Plan and ten years from the date of grant for
awards under all other plans. Generally, stock options granted to employees and directors vest ratably over three years from
the grant date. The Company issues shares of restricted stock to employees and directors which generally vest over four
years. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period
of the individual grants with the exception of awards granted to participants who have reached retirement age or will reach
retirement age during the vesting period. Restricted stock and stock options granted to participants on or after December 6,
2013 immediately vest upon death, disability or retirement (subject to a minimum of three years of service).
In January 2016, the Company announced a 40% workforce reduction that was substantially concluded by the end of
March 2016. In April 2016, the Company also partially restructured executive management, which was substantially
completed in the second quarter of 2016. Affected employees were offered a severance package that included, if applicable,
amendments to certain outstanding equity awards that modified forfeiture provisions upon separation from the Company.
As a result, certain unvested stock-based equity awards became fully vested at the time of separation. These shares were
revalued and recognized immediately as a component of restructuring charges on the Company’s unaudited consolidated
statement of operations. The unvested portion of equity-based performance units was forfeited upon separation from the
Company.
Stock Options
The Company recorded the following compensation costs related to stock options for the years ended December 31,
2016, 2015 and 2014:
2016
2015
(in millions)
2014
Stock-based compensation cost related to stock options – general and
administrative expense (1)
Stock-based compensation cost related to stock options – capitalized
$
$
6 $
1 $
5 $
3 $
5
4
(1)
Includes less than $1 million and $1 million related to the reduction in workforce and executive management restructuring, respectively, for the year
ended December 31, 2016.
The Company also recorded a deferred tax asset of $2 million, $2 million and $3 million related to stock options in 2016,
2015 and 2014, respectively. Unrecognized compensation cost related to the Company’s unvested stock options totaled $4
million at December 31, 2016. This cost is expected to be recognized over a weighted-average period of 2 years.
The fair value of stock options is estimated on the date of the grant using a Black-Scholes valuation model that uses the
weighted average assumptions noted in the following table. Expected volatility is based on historical volatility of the
Company’s common stock and other factors. The Company uses historical data on the exercise of stock options, post-vesting
forfeitures and other factors to estimate the expected term of the stock-based payments granted. The risk-free interest rate is
based on the U.S. Treasury yield curve in effect at the time of grant.
Assumptions
Risk-free interest rate
Expected dividend yield
Expected volatility
Expected term
2016
2015
2014
1.4%
–
41.0%
5 years
1.7%
–
36.0%
5 years
1.6%
–
32.5%
5 years
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The following tables summarize stock option activity for the years 2016, 2015 and 2014, and provide information for
options outstanding at December 31 of each year:
2016
2015
2014
Number
of Shares
(in thousands)
Weighted
Average
Exercise
Price
Number
of Shares
(in thousands)
Weighted
Average
Exercise
Price
Weighted
Average
Exercise
Price
Number
of Shares
(in thousands)
Options outstanding at January 1
Granted (1)
Exercised
Forfeited or expired
Options outstanding at December 31
5,623 $
155
(45)
(317)
5,416 $
24.57
8.60
7.74
38.01
23.46
3,622 $
2,401
–
(400)
5,623 $
35.41
9.47
–
32.20
24.57
3,313 $
835
(402)
(124)
3,622 $
35.70
32.31
30.60
37.80
35.41
(1) Shares granted in 2016 are considerably lower than historical norms. In 2016, the Company changed the grant date of its annual stock option awards
from December to the following February.
Options Outstanding
Options Exercisable
Options
Weighted
Weighted
Average
Outstanding at Average Remaining
Contractual
December 31, Exercise
Life
(years)
Price
Aggregate
Intrinsic
Value
Options
Weighted
Weighted
Average
Exercisable at Average Remaining
Contractual
December 31, Exercise
Life
(years)
Price
2016
( in millions) (in thousands)
781
1,146
1,402
99
3,428 $
7
5.9
3.9
2.4
3.3
4.4 $
9.77
32.68
37.49
45.57
29.80
5.8
3.7
2.4
3.0
3.6 $
Range of
Exercise Prices
$7.74-$29.69
$30.59-$35.91
$36.22-$39.68
$40.15-$51.47
2016
(in thousands)
2,501
1,384
1,402
129
5,416 $
9.54
32.32
37.49
45.79
23.46
Aggregate
Intrinsic
Value
(in millions)
2
The weighted-average grant date fair value of options granted during the years 2016, 2015 and 2014 was $3.22, $3.16
and $10.16, respectively. The total intrinsic value of options exercised during 2016 and 2014 was less than $1 million and
$4 million, respectively. There were no options exercised in 2015.
Restricted Stock
The Company recorded the following compensation costs related to restricted stock grants for the years ended December
31, 2016, 2015 and 2014:
Stock-based compensation cost related to restricted stock grants – general and
administrative expense (1)
Stock-based compensation cost related to restricted stock grants – capitalized
$
$
2016
2015
(in millions)
14
16
$
$
33
8
$
$
2014
10
12
(1)
Includes $16 million and $1 million related to the reduction in workforce and executive management restructuring, respectively, for the year ended
December 31, 2016.
The Company also recorded a deferred tax asset of $12 million related to restricted stock for the year ended December
31, 2016, compared to a deferred tax asset of $11 million for 2015 and a deferred tax liability of $10 million for 2014. As of
December 31, 2016, there was $37 million of total unrecognized compensation cost related to unvested shares of restricted
stock that is expected to be recognized over a weighted-average period of 2 years.
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The following table summarizes the restricted stock activity for the years 2016, 2015 and 2014, and provides information
for restricted stock outstanding at December 31 of each year:
2016
2015
2014
Number of
Shares
(in thousands)
Weighted
Average
Fair Value
Number of
Shares
(in thousands)
Weighted
Average
Fair Value
Number of
Shares
(in thousands)
Weighted
Average
Fair Value
Unvested shares at January 1
Granted (1)
Vested (2)
Forfeited
Unvested shares at December 31
7,222 $
81
(3,817)
(165)
3,321 $
13.24
8.56
11.34
12.05
11.85
2,376 $
5,822
(873)
(103)
7,222 $
34.00
8.07
33.33
29.14
13.24
1,771 $
1,295
(548)
(142)
2,376 $
37.55
30.89
37.12
37.91
34.00
(1) Shares granted in 2016 are considerably lower than historical norms. In 2016, the Company changed the grant date of its annual restricted stock
awards from December to the following February.
(2)
Includes 2,059,626 shares and 151,575 shares related to reduction in workforce and executive management restructuring, respectively, for the year
ended December 31, 2016.
The fair values of the grants were $1 million for 2016, $47 million for 2015 and $40 million for 2014. The total fair
value of shares vested were $43 million for 2016, $29 million for 2015 and $20 million for 2014.
Equity-Classified Performance Units
The Company recorded compensation costs related to equity-classified performance units for the years ended December
31, 2016, 2015 and 2014. The performance units awarded in 2013 and 2014 included a market condition based on relative
Total Shareholder Return (“TSR”) and a performance condition based on the Company’s Present Value Index (“PVI”),
collectively the “Performance Measures.” The fair value of the TSR market condition is based on a Monte Carlo model and
is amortized to compensation expense on a straight-line basis over the vesting period of the award. The fair value of the PVI
performance condition is based on economic analysis for each investment opportunity based upon the expected present value
added for each dollar to be invested and amortized to compensation expense on a straight line basis over the vesting period
of the award. The performance units awarded in 2016 and 2015 are based exclusively on TSR. The grant date fair value is
calculated using the applicable Performance Measures and the closing price of the Company’s common stock at the grant
date.
Stock-based compensation cost related to performance units – general and
administrative expense (1)
Stock-based compensation cost related to performance units – capitalized
$
$
2016
2015
(in millions)
$
6
$
4
$
$
9
1
2014
3
2
(1)
Includes less than $1 million and $1 million related to reduction in workforce and executive management restructuring, respectively, for the year
ended December 31, 2016.
The Company also recorded a deferred tax asset of $4 million related to equity-based performance units for the year
ended December 31, 2016, compared to deferred tax assets of $4 million and $2 million in 2015 and 2014, respectively. As
of December 31, 2016, there was $9 million of total unrecognized compensation cost related to unvested equity-based
performance units that is expected to be recognized over a weighted-average period of 2 years.
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The following table summarizes performance unit activity to be paid out in Company stock for the years ended December
31, 2016, 2015 and 2014, and provides information for unvested units as of December 31, 2016, 2015 and 2014:
2016
2015
2014
Number of
Units (1)
(in thousands)
Weighted
Average Fair
Value
Number of
Units (1)
(in thousands)
Weighted
Average Fair
Value
Weighted
Average Fair
Value
Number of
Units (1)
(in thousands)
Unvested shares at January 1
Granted
Vested (2)
Forfeited (3)
Unvested shares at December 31
407 $
1,503
(889)
(302)
719 $
36.65
8.60
12.78
11.26
11.46
223 $
443
(259)
–
407 $
40.44
35.22
37.46
–
36.65
$
–
359
(111)
(25)
223 $
–
40.44
40.44
40.44
40.44
(1) These amounts reflect the number of performance units granted in thousands. The actual payout in shares may range from a minimum of zero shares
to a maximum of two shares contingent upon the actual performance against the Performance Measures. The performance units have a three-year
vesting term and the actual disbursement of shares, if any, is not determined until March following the end of the three-year vesting period.
(2)
(3)
Includes 22,918 units and 37,590 units related to the reduction in workforce and executive management restructuring, respectively, for the year ended
December 31, 2016.
Includes 87,595 units and 195,834 units related to the reduction in workforce and executive management restructuring, respectively, for the year ended
December 31, 2016.
Liability-Classified Performance Units
Prior to 2013, certain employees were provided performance units vesting equally over three years that were settled in
cash. The payout of these units was based on certain metrics, such as total shareholder return and reserve replacement
efficiency, compared to a predetermined group of peer companies and Company goals. At the end of each performance
period, the value of the vested performance units, if any, would be paid in cash. In the first quarter of 2016, the Company
completed the final payout under these performance unit agreements.
(13) SEGMENT INFORMATION
The Company’s reportable business segments have been identified based on the differences in products or services
provided. Revenues for the E&P segment are derived from the production and sale of natural gas and liquids. The Midstream
Services segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids
volumes and through gathering fees associated with the transportation of natural gas to market.
Summarized financial information for the Company’s reportable segments is shown in the following table. The
accounting policies of the segments are the same as those described in Note 1 – Organization and Summary of Significant
Accounting Policies. Management evaluates the performance of its segments based on operating income, defined as
operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income
amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, gain
(loss) on derivatives, loss on early extinguishment of debt and other income (loss). The “Other” column includes items not
related to the Company’s reportable segments, including real estate and corporate items.
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2016
Revenues from external customers
Intersegment revenues
Depreciation, depletion and amortization expense
Impairment of natural gas and oil properties
Operating income (loss)
Interest expense (3)
Gain (loss) on derivatives
Loss on early extinguishment of debt
Other income (loss), net
Provision (benefit) for income taxes (3)
Assets
Capital investments (6)
2015
Revenues from external customers
Intersegment revenues
Depreciation, depletion and amortization expense
Impairment of natural gas and oil properties
Operating income (loss)
Interest expense (3)
Gain (loss) on derivatives
Other loss, net
Provision (benefit) for income taxes (3)
Assets
Capital investments (6)
2014
Revenues from external customers
Intersegment revenues
Depreciation, depletion and amortization expense
Operating income (loss)
Interest expense (3)
Gain (loss) on derivatives
Other loss, net
Provision for income taxes (3)
Assets
Capital investments (6)
Exploration
and
Production
Midstream
Services
(in millions)
Other
Total
$
$
$
$
$
$
1,435
(22)
371
2,321
(2,404) (1)
87
(338)
–
5
(29)
4,178 (4)
623
2,095
(21)
1,028
6,950
(7,104)
47
51
(21)
(2,273)
6,588 (4)
2,258
2,850
12
884
1,013
47
142
(3)
402
13,018 (4)
7,254
$
$
$
1,001
1,568
65
–
209 (2)
1
(1)
–
(2)
–
1,331
21
1,038
2,081
62
–
583 (7)
9
–
(9)
268
1,290
167
1,188
3,170
58
361
12
(1)
(1)
123
1,554
144
$
$
$
–
–
–
–
–
–
–
(51)
(2)
–
1,567 (5)
4
–
–
1
–
(1)
–
(4)
–
–
208
12
–
–
–
(1)
–
(2)
–
–
343
49
2,436
1,546
436
2,321
(2,195)
88
(339)
(51)
1
(29)
7,076
648
3,133
2,060
1,091
6,950
(6,522)
56
47
(30)
(2,005)
8,086
2,437
4,038
3,182
942
1,373
59
139
(4)
525
14,915
7,447
(1) Operating loss for the E&P segment includes $86 million related to restructuring and other one-time charges for the year ended December 31, 2016.
(2) Operating income for the Midstream Services segment includes $3 million related to restructuring charges for the year ended December 31, 2016.
(3) Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate
level.
(4) Includes office, technology, drilling rigs and other ancillary equipment not directly related to natural gas and oil property acquisition, exploration and
development activities.
(5) Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At December 31, 2016, other assets includes
approximately $1.4 billion in cash and cash equivalents.
(6) Capital investments include an increase of $43 million for 2016, a decrease of $33 million for 2015 and an increase of $155 million for 2014 related to
the change in accrued expenditures between years.
(7) Operating income (loss) for the Midstream Services segment includes a $277 million gain on sale of assets for the year ended December 31, 2015.
Included in intersegment revenues of the Midstream Services segment are $1.3 billion, $1.8 billion and $2.8 billion for
2016, 2015 and 2014, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash
equivalents, furniture and fixtures and other costs. Corporate general and administrative costs, depreciation expense and
taxes other than income are allocated to the segments.
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(14) SUBSEQUENT EVENTS
None.
SUPPLEMENTAL QUARTERLY RESULTS (UNAUDITED)
The following is a summary of the quarterly results of operations for the years ended December 31, 2016 and 2015:
1st Quarter
2nd Quarter
3rd Quarter
4th Quarter
(in millions, except per share amounts)
2016
Operating revenues
Operating income (loss) (1)
Net loss attributable to common stock
Loss per share - Basic
Loss per share - Diluted
$
579 $
(1,100)
(1,159)
(3.03)
(3.03)
$
522
(492)
(620)
(1.61)
(1.61)
2015
651 $
(725)
(735)
(1.52)
(1.52)
Operating revenues
Operating income (loss) (1)
Net income (loss) attributable to common stock (2)
Earnings (Loss) per share - Basic
Earnings (Loss) per share - Diluted
$
933 $
165
46
0.12
0.12
764
(1,284)
(815)
(2.13)
(2.13)
$
749 $
(2,842)
(1,766)
(4.62)
(4.62)
684
122
(237)
(0.48)
(0.48)
687
(2,561)
(2,134)
(5.58)
(5.58)
(1) The operating losses for the first, second and third quarters of 2016 included non-cash full cost impairments of natural gas and oil properties of $1,034
million, $470 million, and $817 million, respectively. There was no full cost impairment in the fourth quarter of 2016. The operating losses for the
second, third and fourth quarters of 2015 included non-cash full cost impairments of natural gas and oil properties of $1,535 million, $2,839 million
and $2,576 million, respectively.
(2) Net income attributable to common stock was reduced by $7 million in the first quarter of 2015 to recognize the portion of the Company’s net income
that would be distributed to the holders of preferred securities (mandatory convertible preferred stock) at year-end. However, as a result of the
Company’s net loss in the second quarter that persisted for the year ended December 31, 2015, participating securities were ultimately not entitled to
receive a distribution.
SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)
The Company’s operating natural gas and oil properties are located solely in the United States. The Company also has
licenses to properties in Canada, the development of which is subject to an indefinite moratorium. See “Our Operations —
Other — New Brunswick, Canada” in Item 1 of Part 1 of this Annual Report.
Net Capitalized Costs
The following table shows the capitalized costs of natural gas and oil properties and the related accumulated
depreciation, depletion and amortization as of December 31, 2016 and 2015:
Proved properties
Unproved properties
Total capitalized costs
Less: Accumulated depreciation, depletion and amortization
Net capitalized costs
2016
2015
(in millions)
20,548
2,105
22,653
(18,897)
3,756
$
$
18,751
3,727
22,478
(16,248)
6,230
$
$
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Natural gas and oil properties not subject to amortization represent investments in unproved properties and major
development projects in which the Company owns an interest. These unproved property costs include unevaluated costs
associated with leasehold or drilling interests and unevaluated costs associated with wells in progress. The table below sets
forth the composition of net unevaluated costs excluded from amortization as of December 31, 2016:
Property acquisition costs
Exploration and development costs
Capitalized interest
2016
2015
$
$
22
55
70
147
$
$
213
64
55
332
$
$
2014
(in millions)
1,501
24
10
1,535
$
$
Prior
Total
54
16
21
91
$
$
1,790
159
156
2,105
Of the total net unevaluated costs excluded from amortization as of December 31, 2016, approximately $1.6 billion is
related to the Chesapeake and Statoil Property Acquisitions, approximately $100 million is related to the acquisition of
undeveloped properties outside the Appalachian Basin and the Fayetteville Shale, excluding licenses in Canada subject to an
indefinite moratorium, and approximately $94 million is related to the acquisition of the Company’s undeveloped properties
in Northeast Appalachia. Additionally, the Company has approximately $113 million of unevaluated costs related to costs
of wells in progress. The remaining costs excluded from amortization are related to properties which are not individually
significant and on which the evaluation process has not been completed. The timing and amount of property acquisition and
seismic costs included in the amortization computation will depend on the location and timing of drilling wells, results of
drilling and other assessments. The Company is, therefore, unable to estimate when these costs will be included in the
amortization computation.
Costs Incurred in Natural Gas and Oil Exploration and Development
The table below sets forth capitalized costs incurred in natural gas and oil property acquisition, exploration and
development activities:
Proved property acquisition costs
Unproved property acquisition costs
Exploration costs
Development costs
Capitalized costs incurred
Full cost pool amortization per Mcfe
2016
$
$
$
2015
(in millions, except per Mcfe amounts)
–
$
171
17
433
621
0.38
81
692
50
1,417
2,240
1.00
$
$
2014
1,455
3,934
232
1,600
7,221
1.10
Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $152
million, $204 million and $55 million during 2016, 2015 and 2014, respectively, based on the Company’s weighted average
cost of borrowings used to finance expenditures.
In addition to capitalized interest, the Company capitalized internal costs totaling $112 million, $307 million and $320
million during 2016, 2015 and 2014, respectively, which were directly related to the acquisition, exploration and
development of the Company’s natural gas and oil properties. Included in these amounts are internal costs from the
Company’s subsidiaries involved with vertical integration of the Company’s exploration and development activities, which
totaled $19 million, $118 million and $123 million during 2016, 2015 and 2014, respectively. All internal costs are included
in the Company’s cost of natural gas and oil properties.
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Results of Operations from Natural Gas and Oil Producing Activities
The table below sets forth the results of operations from natural gas and oil producing activities:
Sales
Production (lifting) costs
Depreciation, depletion and amortization
Impairment of natural gas and oil properties
Provision (benefit) for income taxes
Results of operations (2)
2016
2015
(in millions)
2014
$
$
$
1,413
(839)
(371)
(2,321)
(2,118)
– (1)
(2,118) $
2,074
(989)
(1,028)
(6,950)
(6,893)
(2,619)
(4,274)
$
$
2,862
(776)
(884)
–
1,202
457
745
(1) Prior to the Company’s recognition of a valuation allowance in 2016, the Company recognized an income tax benefit of $805 million.
(2) Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 4 - Derivatives and Risk Management
The results of operations shown above exclude general and administrative expenses and interest expense and are not
necessarily indicative of the contribution made by the Company’s natural gas and oil operations to its consolidated operating
results. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation,
depletion and amortization, and after giving effect to permanent differences and tax credits.
Natural Gas and Oil Reserve Quantities
The Company engaged the services of Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum
engineering firm, to audit the reserves estimated by the Company’s reservoir engineers. In conducting its audit, the engineers
and geologists of NSAI studied the Company’s major properties in detail and independently developed reserve estimates.
NSAI’s audit consists primarily of substantive testing, which includes a detailed review of the Company’s major properties,
and accounted for approximately 99%, 100% and 97% of the present worth of the Company’s total proved reserves as of
December 31, 2016, 2015 and 2014, respectively. A reserve audit is not the same as a financial audit, and a reserve audit is
less rigorous in nature than a reserve report prepared by an independent petroleum engineering firm containing its own
estimate of reserves. Reserve estimates are inherently imprecise, and the Company’s reserve estimates are generally based
upon extrapolation of historical production trends, historical prices of natural gas and crude oil and analogy to similar
properties and volumetric calculations. Accordingly, the Company’s estimates are expected to change, and such changes
could be material and occur in the near term as future information becomes available. For more information over reserves,
refer to the table titled “Changes in Proved Undeveloped Reserves (Bcfe)” in “Business – Exploration and Production” in
Item 1 of this Annual Report.
The following table summarizes the changes in the Company’s proved natural gas, oil and NGL reserves for 2016, 2015
and 2014, all of which were located in the United States:
Proved reserves, beginning of year
Revisions of previous estimates
Extensions, discoveries and other
additions
Production
Acquisition of reserves in place
Disposition of reserves in place
Proved reserves, end of year
Proved developed reserves:
Beginning of year
End of year
Proved undeveloped reserves:
Beginning of year
End of year
Natural
Gas
(Bcf)
2016
Oil
NGL
(MBbls) (MBbls)
8,753
40,947
1,564 13,794
11,576
2,417
5,917
(446)
198
2015
Natural
Oil
Gas
(MBbls)
(Bcf)
9,809
37,615
(3,458) (28,394)
1,367
546
NGL
(MBbls)
118,699
(75,664)
6,274
Natural
Gas
(Bcf)
6,974
542
1,692
2014
Oil
NGL
(MBbls) (MBbls)
–
66
48
373
(14)
250
(788)
(2,192) (12,372)
–
(15)
4,866
–
(19)
10,523
–
(14)
53,931
(899)
97
(178)
5,917
(2,265) (10,702)
2,340
–
525
(95)
8,753
(766)
1,367
–
(235)
37,246
(5)
37,615
(231)
118,816
–
118,699
40,947
9,809
5,474
4,789
8,753
10,523
40,947
53,931
5,675
5,474
7,445
8,753
38,632
40,947
4,237
5,675
372
7,445
–
38,632
443
77
–
–
–
–
4,134 30,170
–
443
80,067
–
2,737
–
4,134 30,170 80,067
1
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The Company’s estimated proved natural gas, oil and NGL reserves were 5,253 Bcfe at December 31, 2016, compared
to 6,215 Bcfe at December 31, 2015. The decrease in the Company's reserves in 2016 was primarily due to the decrease in
commodity prices. The significant decrease in the Company's reserves in 2015 was primarily due to the decrease in
commodity prices. The significant increase in the Company's reserves in 2014 was primarily due to the acquisition of
approximately 413,000 net acres in Southwest Appalachia, successful development drilling programs in the Fayetteville
Shale and Northeast Appalachia and upward performance revisions in Northeast Appalachia. In 2014, the Company replaced
550% of its production volumes with proved reserve additions and proved reserve additions as a result of acquisitions
primarily associated with acreage in Southwest Appalachia. The following table summarizes the changes in reserves for
2014, 2015 and 2016:
December 31, 2013
Production
Disposition of reserves in place
Acquisition of reserves in place
Net revisions
Price revisions
Performance and production revisions
Total net revisions
Reserve additions
Proved developed
Proved undeveloped
Total reserve additions
December 31, 2014
Production
Disposition of reserves in place
Acquisition of reserves in place
Net revisions
Price revisions
Performance and production revisions
Total net revisions
Reserve additions
Proved developed
Proved undeveloped
Total reserve additions
December 31, 2015
Production
Disposition of reserves in place
Acquisition of reserves in place
Net revisions
Price revisions
Performance and production revisions
Total net revisions
Reserve additions
Proved developed
Proved undeveloped
Total reserve additions
December 31, 2016
Appalachia
Total
Northeast
6,976
(768)
–
2,303
54
489
543
531
1,162
1,693
10,747
(976)
(180)
115
(5,718)
1,635
(4,083)
416
176
592
6,215
(875)
(15)
–
(1,037)
683
(354)
257
25
282
5,253
1,963
(254)
–
1
10
636
646
246
589
835
3,191
(360)
–
80
(2,315)
1,383
(932)
202
138
340
2,319
(350)
–
–
(794)
318
(476)
81
–
81
1,574
Southwest
(in Bcfe)
–
(3)
–
2,300
–
–
–
–
–
–
2,297
(143)
–
35
(1,875)
209
(1,666)
84
4
88
611
(148)
(15)
–
(127)
199
72
157
–
157
677
Fayetteville
Shale
Other (1)
4,795
(494)
–
–
38
(126)
(88)
283
573
856
5,069
(465)
–
–
(1,496)
10
(1,486)
129
34
163
3,281
(375)
–
–
(116)
163
47
19
25
44
2,997
218
(17)
–
2
6
(21)
(15)
2
–
2
190
(8)
(180)
–
(32)
33
1
1
–
1
4
(2)
–
–
–
3
3
–
–
–
5
(1) Other includes properties outside of the Appalachian Basin and Fayetteville Shale along with Ark-La-Tex properties divested in May 2015.
The Company's December 31, 2016 proved reserves included 77 Bcfe of proved undeveloped reserves from 15 locations
that had 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 had a negative present value of $11 million when
discounted at 10%. The Company made a final investment decision and is committed to developing these reserves within
the next five years from the date of initial booking. The Company's December 31, 2015 proved reserves included 217 Bcfe
of proved undeveloped reserves from 75 locations that had a positive present value on an undiscounted basis in compliance
with proved reserve requirements, but that have a negative $34 million present value when discounted at 10%. The
Company's December 31, 2014 proved reserves included 181 Bcfe of proved undeveloped reserves from 60 locations that
had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a
negative $28 million present value when discounted at 10%.
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The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be
upgraded into synthetic gas or oil. The Company 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.
Standardized Measure of Discounted Future Net Cash Flows
The following standardized measures of discounted future net cash flows relating to proved natural gas, oil and NGL
reserves as of December 31, 2016, 2015 and 2014 are calculated after income taxes, discounted using a 10% annual discount
rate and do not purport to present the fair market value the Company’s proved gas, oil and NGL reserves:
Future cash inflows
Future production costs
Future development costs (1)
Future income tax expense (2)
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows
(1)
Includes abandonment costs.
2016
2015
(in millions)
2014
9,064
(5,880)
(485)
–
2,699
(1,034)
1,665
$
$
11,887 $
(7,376)
(792)
–
3,719
(1,302)
2,417 $
41,812
(16,477)
(5,750)
(4,743)
14,842
(7,299)
7,543
$
$
(2) The December 31, 2016 and 2015 standardized measure computation does not have future income taxes because the Company’s tax basis in the
associated oil and gas properties exceeded expected pre-tax cash inflows. Future net cash flows are not permitted to be increased by excess tax basis.
Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of
each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of
year-end proved reserves. Prices used for the standardized measure above were $2.48 per MMBtu for natural gas, $39.25
per barrel for oil and $6.74 per barrel for NGLs in 2016, $2.59 per MMBtu for natural gas, $46.79 per barrel for oil and $6.82
per barrel for NGLs in 2015, and $4.35 per MMBtu for natural gas, $91.48 per barrel for oil and $23.79 per barrel for NGLs
in 2014. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to
determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate to the excess of
pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties after giving effect to
permanent differences and tax credits.
Following is an analysis of changes in the standardized measure during 2016, 2015 and 2014:
Standardized measure, beginning of year
Sales and transfers of natural gas and oil produced, net of production costs
Net changes in prices and production costs
Extensions, discoveries, and other additions, net of future production and
development costs
Acquisition of reserves in place
Sales of reserves in place
Revisions of previous quantity estimates
Accretion of discount
Net change in income taxes
Changes in estimated future development costs
Previously estimated development costs incurred during the year
Changes in production rates (timing) and other
Standardized measure, end of year
$
$
2016
2015
(in millions)
2014
$
2,417
(574)
(415)
45
–
(10)
(140)
242
–
71
114
(85)
1,665
$
7,543
(1,082)
(8,075)
162
28
(244)
(1,385)
946
1,915
2,007
875
(273)
2,417
$
$
3,736
(2,084)
1,192
1,049
1,897
–
622
513
(522)
110
815
215
7,543
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
We have performed an evaluation under the supervision and with the participation of our management, including our
Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined
in Rule 13a-15(e) and 15d-15(e) under the Exchange Act. Our disclosure controls and procedures are the controls and other
procedures that we have designed to ensure that we record, process, accumulate and communicate information to our
management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required
disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no
matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a
level of reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our
management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and
procedures were effective as of December 31, 2016 at a reasonable assurance level.
There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under
the Exchange Act) that occurred during the quarter ended December 31, 2016, that have materially affected, or are reasonably
likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting is included on page 84 of this Annual Report.
PricewaterhouseCoopers LLP’s report on Southwestern Energy’s internal control over financial reporting is included in
its Report of Independent Registered Public Accounting Firm on page 85 of this Annual Report.
ITEM 9B. OTHER INFORMATION
Election of Director
On February 21, 2017, the Board of Directors elected Jon A. Marshall, 65, as a director of the Company effective
February 27, 2017, for a term expiring at the 2017 annual meeting of stockholders. With the election of Mr. Marshall, the
Board of Directors has nine members.
Mr. Marshall served as President and Chief Operating Officer of Transocean Ltd. from 2007 to 2008 and as the Chief
Executive Officer and President of GlobalSantaFe Corporation from 2003 to 2007, when it merged with Transocean. He
also served on the boards of directors of those companies. Currently he is a director of Noble Corporation plc (chairman of
its HSE & Engineering Committee and member of its Audit and Finance Committees) and of Cobalt International Energy,
Inc. (chairman of its Compensation Committee). He is a former chairman of the board of directors of the National Ocean
Industries Association. Mr. Marshall received a bachelor of science degree from the United States Military Academy.
The selection of Mr. Marshall was not pursuant to any arrangement or understanding between him and any other person.
Mr. Marshall has not been appointed to serve on any standing committees of the Board of Directors and is not expected to
be so appointed at this time.
There are no transactions between Mr. Marshall and the Company that are required to be reported under Item 404(a) of
Regulation S-K.
In connection with his election, Mr. Marshall will receive a pro rata portion of the annual cash compensation, the equity
compensation and the additional compensation amounts received by non-employee directors, which are described in the
Company’s definitive proxy statement delivered to its stockholders in connection with the 2016 annual meeting of
stockholders and filed with the Securities and Exchange Commission on April 6, 2016.
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Appointment of Vice President and Controller
On February 21, 2017, effective as of that date, the Board of Directors promoted Colin O’Beirne, 41, to the position of
Vice President and Controller and designated him as our principal accounting officer, to serve until the next annual meeting
of stockholders and/or until his successor shall be duly elected and shall qualify. In his capacity as the Company’s principal
accounting officer, Mr. O’Beirne will report to R. Craig Owen, Senior Vice President and Chief Financial Officer, who had
reassumed the duties of principal accounting officer on an interim basis beginning in July 2017. Mr. O’Beirne joined the
Company in October 2010 as a senior manager over the Company’s internal controls and compliance team and, since 2012,
has served as a director over various groups within the accounting function. Immediately prior to joining the Company, Mr.
O’Beirne was a senior manager at PricewaterhouseCoopers LLP in Houston with over twelve years of accounting and
financial reporting experience in the energy industry. Mr. O’Beirne holds a master of science in accounting from Texas
A&M University. He is a Certified Public Accountant.
The selection of Mr. O’Beirne was not pursuant to any arrangement or understanding between him and any other person.
There is no family relationship between Mr. O’Beirne and any director or executive officer of the Company.
There are no transactions between Mr. O’Beirne and the Company that are required to be reported under Item 404(a) of
Regulation S-K.
Other than as disclosed below, we do not have any agreement with Mr. O’Beirne, either written or oral, that guarantees
salaries, salary increases, bonuses or benefits. Mr. O’Beirne and the Company will enter into an indemnity agreement and
an executive severance agreement to be effective as of the date of his promotion, the forms of which are expected to be
consistent with the forms of indemnity agreement incorporated by reference as Exhibit 10.1 to this annual report on Form
10-K and executive severance agreement incorporated by reference as Exhibit 10.2 to this annual report on Form 10-K (as
amended by Exhibits 10.3 and 10.4 to this annual report on Form 10-K). The executive severance agreement will entitle him
to receive a payment if, within three years after a “Change in Control,” (i) his employment is terminated without “Cause” or
(ii) he voluntarily terminates employment with the Company for “Good Reason.” The severance payment for Mr. O’Beirne
will be equal to the product of 2.0 and the sum of base salary as of his termination date plus the maximum bonus opportunity
available to him. Mr. O’Beirne also is eligible to participate in the Company’s compensation and benefit plans available to
executives.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The definitive proxy statement to holders of the Company’s common stock in connection with the solicitation of proxies
to be used in voting at the Annual Meeting of Stockholders to be held on or about May 23, 2017 (the “Proxy Statement”), is
hereby incorporated by reference for the purpose of providing information about the Company’s directors, and for discussion
of its audit committee and its audit committee financial expert. Refer to the sections “Proposal No. 1: Election of Directors”
and “Share Ownership of Management, Directors and Nominees” in the Proxy Statement for information concerning our
directors. Refer to the section “Corporate Governance – Committees of the Board of Directors” in the 2017 Proxy Statement
for discussion of its audit committee and its audit committee financial expert. Information concerning the Company’s
executive officers is presented in Part I of this Annual Report. The Company refers you to the section “Section 16(a)
Beneficial Ownership Reporting Compliance” in the Proxy Statement for information relating to compliance with Section
16(a) of the Exchange Act.
Code of Business Ethics and Conduct for Directors and Employees
The Company has adopted a code of ethics that applies to its Chief Executive Officer, Chief Financial Officer and
Controller as well as other officers and employees. We have posted a copy of our code of ethics on the “Corporate
Governance” section of our website at www.swn.com, and it is available free of charge in print to any stockholder who
requests it. Requests for copies should be addressed to the Secretary at 10000 Energy Drive, Spring, Texas 77389. Any
amendments to, or waivers from, our code of ethics that apply to our executive officers and directors will be posted on the
“Corporate Governance” section of our website.
ITEM 11. EXECUTIVE COMPENSATION
Information required by Item 11 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting
of Stockholders, to be filed pursuant to Regulation 14A on or before May 23, 2017, and is incorporated herein by reference.*
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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
Information required by Item 12 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting
of Stockholders, to be filed pursuant to Regulation 14A on or before May 23, 2017, and is incorporated herein by reference.*
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required by Item 13 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting
of Stockholders, to be filed pursuant to Regulation 14A on or before May 23, 2017, and is incorporated herein by reference.*
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information required by Item 14 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting
of Stockholders, to be filed pursuant to Regulation 14A on or before May 23, 2017, and is incorporated herein by reference.*
•
Except for information or data specifically incorporated by reference under Items 10 through 14, all other information in our 2017 Proxy Statement is
not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as part of this report.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
(1) The consolidated financial statements of Southwestern Energy Company and its subsidiaries and the report of
independent registered public accounting firm are included in Item 8 of this Annual Report.
(2) The consolidated financial statement schedules have been omitted because they are not required under the related
instructions, or are not applicable.
(3) The exhibits listed on the accompanying Exhibit Index are filed as part of, or incorporated by reference into, this
Annual Report.
ITEM 16. SUMMARY
None.
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly
caused the report to be signed on its behalf by the undersigned, thereunto duly authorized.
SIGNATURES
Dated: February 23, 2017
SOUTHWESTERN ENERGY COMPANY
By: /s/ R. CRAIG OWEN
R. Craig Owen
Senior Vice President
and Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February 23,
2017, on behalf of the Registrant below by the following officers and by a majority of the directors.
/s/ WILLIAM J. WAY
William J. Way
/s/ R. CRAIG OWEN
R. Craig Owen
/s/ COLIN P. O’BEIRNE
Colin P. O’Beirne
/s/ JOHN D. GASS
John D. Gass
/s/ CATHERINE A. KEHR
Catherine A. Kehr
/s/ GREG D. KERLEY
Greg D. Kerley
/s/ KENNETH R. MOURTON
Kenneth R. Mourton
/s/ ELLIOTT PEW
Elliott Pew
/s/ TERRY W. RATHERT
Terry W. Rathert
/s/ ALAN H. STEVENS
Alan H. Stevens
Director, President and Chief Executive Officer
(Principal executive officer)
Senior Vice President and Chief Financial Officer
(Principal financial officer)
Vice President, Controller
(Principal accounting officer)
Director
Director
Director
Director
Director
Director
Director
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Exhibit Number
Description
EXHIBIT INDEX
2.1
3.1
3.2
3.3
3.4
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
4.9
4.10
SWN 134
Purchase Agreement dated as of October 14, 2014 between Southwestern Energy Production
Company and Chesapeake Appalachia, L.L.C. (Incorporated by reference to Exhibit 2.1 to the
Registrant’s Current Report on Form 8-K filed on October 17, 2014)
Amended and Restated Certificate of Incorporation of Southwestern Energy Company.
(Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed
May 24, 2010)
Amended and Restated Bylaws of Southwestern Energy Company, as amended on November
9, 2015. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form
8-K filed November 13, 2015)
Certificate of Designations of 6.25% Series B Mandatory Convertible Preferred Stock
(including form of stock certificate). (Incorporated by reference to Exhibit 3.1 to the
Registrant’s Current Report on Form 8-K filed on January 21, 2015)
Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred
Stock, dated April 9, 2009. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current
Report on Form 8-K filed on April 9, 2009)
Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.4 to the
Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
Indenture, dated as of December 1, 1995 between Southwestern Energy Company and The First
National Bank of Chicago, as trustee. (Incorporated by reference to Exhibit 4 to Amendment
No. 1 to the Registrant’s Registration Statement on Form S-3 (File No. 33-63895) filed on
November 17, 1995)
First Supplemental Indenture between Southwestern Energy Company and J.P. Morgan Trust
Company, N.A. (as successor to the First National Bank of Chicago) dated June 30, 2006.
(Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K/A
filed August 3, 2006)
Second Supplemental Indenture by and among Southwestern Energy Company, SEECO, Inc.,
Southwestern Energy Production Company, Southwestern Energy Services Company and The
Bank of New York Trust Company, N.A., as trustee (as successor to J.P. Morgan Trust
Company, N.A.), dated as of May 2, 2008. (Incorporated by reference to Exhibit 4.1 to the
Registrant’s Current Report on Form 8-K/A filed on May 8, 2008)
Indenture dated June 1, 1998 by and among NOARK Pipeline Finance, L.L.C. and The Bank
of New York. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on
Form 8-K filed May 4, 2006)
First Supplemental Indenture dated May 2, 2006 by and among Southwestern Energy Company,
NOARK Pipeline Finance, L.L.C., and UMB Bank, N.A., as trustee (as successor to the Bank
of New York). (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on
Form 8-K filed May 4, 2006)
Second Supplemental Indenture between Southwestern Energy Company and UMB Bank,
N.A., as trustee, dated June 30, 2006. (Incorporated by reference to Exhibit 4.3 to the
Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
Third Supplemental Indenture by and among Southwestern Energy Company, SEECO, Inc.,
Southwestern Energy Production Company, Southwestern Energy Services Company and
UMB Bank, N.A., as trustee, dated as of May 2, 2008. (Incorporated by reference to Exhibit
4.2 to the Registrant’s Current Report on Form 8-K/A filed on May 8, 2008)
Guaranty dated June 1, 1998 by Southwestern Energy Company in favor of The Bank of New
York, as trustee, under the Indenture dated as of June 1, 1998 between NOARK Pipeline
Finance L.L.C. and such trustee. (Incorporated by reference to Exhibit 4.6 to the Registrant’s
Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31,
2005)
Indenture dated January 16, 2008 among Southwestern Energy Company, the Guarantors
named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by
reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed January 16, 2008)
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 121
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
4.22
4.23
4.24
10.1
Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy
Production Company, Southwestern Energy Services Company and The Bank of New York
Trust Company, N.A., as trustee, dated as of March 5, 2012. (Incorporated by reference to
Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012)
Policy on Confidential Voting of Southwestern Energy Company. (Incorporated by reference
to the Appendix of the Registrant’s Definitive Proxy Statement (Commission File No. 1-08246)
for the 2006 Annual Meeting of Stockholders)
Credit Agreement dated December 16, 2013 among Southwestern Energy Company, JPMorgan
Chase Bank, NA, Bank of America, N.A., Wells Fargo N.A., The Royal Bank of Scotland PLC,
Citibank, N.A. and the other lenders named therein, JPMorgan Chase Bank, NA, as
administrative agent. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current
Report on Form 8-K filed December 17, 2013)
Commitment Letter dated October 14, 2014 between Southwestern Energy Company, Merrill
Lynch, Pierce, Fenner & Smith Incorporated and Bank of America, N.A. (Incorporated by
reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on October 17,
2014)
Bridge Term Loan Credit Agreement, dated December 19, 2014, among Southwestern Energy
Company, Bank of America, N.A., as Administrative Agent, Citibank, N.A., JPMorgan Chase
Bank, N.A., Wells Fargo Bank, National Association and The Royal Bank of Scotland plc, as
Co-Syndication Agents, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Sole Lead
Arranger and Sole Bookrunner, and the lenders from time to time party thereto (Incorporated
by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December
23, 2014)
Term Loan Credit Agreement, dated December 19, 2014, among Southwestern Energy
Company, Bank of America, N.A., as Administrative Agent, and Merrill Lynch, Pierce, Fenner
& Smith Incorporated, as Sole Lead Arranger and Sole Bookrunner, and the lenders from time
to time party thereto (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current
Report on Form 8-K filed on December 23, 2014)
Form of certificate for the 6.25% Series B Mandatory Convertible Preferred Stock.
(Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed
on January 21, 2015)
Deposit Agreement, dated as of January 21, 2015, between Southwestern Energy Company and
Computershare Trust Company, N.A., as depositary, on behalf of all holders from time to time
of the receipts issued thereunder (including form of Depositary Receipt). (Incorporated by
reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on January 21,
2015)
Form of Depositary Receipt for the Depositary Shares. (Incorporated by reference to Exhibit
4.3 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
Indenture, dated as of January 23, 2015 between Southwestern Energy Company and U.S. Bank
National Association, as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s
Current Report on Form 8-K filed on January 23, 2015)
First Supplemental Indenture, dated as of January 23, 2015 between Southwestern Energy
Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit
4.2 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
Form of 3.300% Notes due 2018. (Incorporated by reference to Exhibit 4.3 to the Registrant’s
Current Report on Form 8-K filed on January 23, 2015)
Form of 4.050% Notes due 2020. (Incorporated by reference to Exhibit 4.4 to the Registrant’s
Current Report on Form 8-K filed on January 23, 2015)
Form of 4.95% Notes due 2025. (Incorporated by reference to Exhibit 4.5 to the Registrant’s
Current Report on Form 8-K filed on January 23, 2015)
Form of Second Amended and Restated Indemnity Agreement between Southwestern Energy
Company and each Executive Officer and Director of the Registrant. (Incorporated by reference
to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
SWN 135
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 122
Form of Executive Severance Agreement between Southwestern Energy Company and each of
the Executive Officers of Southwestern Energy Company, effective February 17, 1999.
(Incorporated by reference to Exhibit 10.12 of the Registrant’s Annual Report on Form 10-K
(Commission File No. 1-08246) for the year ended December 31, 1998)
Form of Amendment to Executive Severance Agreement between Southwestern Energy
Company and each of the Executive Officers of Southwestern Energy Company prior to 2011.
(Incorporated by reference to Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K
(Commission File No. 1-08246) for the year ended December 31, 2008)
Form of Executive Severance Agreement between Southwestern Energy Company and
Executive Officers Post 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s
Annual Report on Form 10-K (Commission File No.1-08426) for the year ended December 31,
2012)
Southwestern Energy Company Incentive Compensation Plan. (Incorporated by reference to
Exhibit 10.2(b) to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-
08246) for the year ended December 31, 1998)
Amendment to Southwestern Energy Company Incentive Compensation Plan. (Incorporated by
reference to Exhibit 10.5 to the Registrant’s Annual Report on Form 10-K (Commission File
No. 1-08246) for the year ended December 31, 2008)
Second Amendment to Southwestern Energy Company Incentive Compensation Plan
(Incorporated by reference to Exhibit 10.6 to the Registrant’s Annual Report on Form 10-K
(Commission File No. 1-08246) for the year ended December 31, 2009)
Southwestern Energy Company Supplemental Retirement Plan as amended. (Incorporated by
reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 19,
2008)
Southwestern Energy Company Non-Qualified Retirement Plan as amended. (Incorporated by
reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on February 19,
2008)
Amendment One to the Southwestern Energy Company Non-Qualified Retirement Plan
(Incorporated by reference to Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K
(Commission File No. 1-08246) for the year ended December 31, 2009)
Southwestern Energy Company 2000 Stock Incentive Plan dated February 18, 2000.
(Incorporated by reference to the Appendix of the Registrant’s Definitive Proxy Statement
(Commission File No. 1-08246) for the 2000 Annual Meeting of Stockholders)
Southwestern Energy Company 2002 Employee Stock Incentive Plan, effective October 23,
2002. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form
8-K filed on December 13, 2005)
Southwestern Energy Company 2002 Performance Unit Plan, as amended, effective December
8, 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form
10-K (Commission File No. 1-08246) for the year ended December 31, 2012)
Southwestern Energy Company 2004 Stock Incentive Plan. (Incorporated by reference to
Appendix A to the Registrant’s Proxy Statement dated March 29, 2004)
Southwestern Energy Company 2013 Incentive Plan. (Incorporated by reference to Annex A of
the Registrant’s Proxy Statement filed April 8, 2013)
First Amendment to Southwestern Energy Company 2013 Incentive Plan. (Incorporated by
reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K filed on May 20, 2016)
Southwestern Energy Company 2013 Incentive Plan Form of Performance Unit Award
Agreement. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended March 31, 2016)
Southwestern Energy Company 2013 Incentive Plan Guidelines for Annual Incentive Awards.
(Incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q
for the quarter ended June 30, 2013)
Southwestern Energy Company 2013 Incentive Plan Form of Incentive Stock Option Award
Agreement. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended June 30, 2013)
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
SWN 136
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 123
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
10.29
10.30
10.31
10.32
10.33
10.34
10.35
10.36
Southwestern Energy Company 2013 Incentive Plan Form of Non-Qualified Stock Option
Award Agreement. (Incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly
Report on Form 10-Q for the quarter ended June 30, 2013)
Southwestern Energy Company 2013 Incentive Plan Form of Non-Qualified Stock Option
Award Agreement for Directors. (Incorporated by reference to Exhibit 10.6 to the Registrant’s
Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Award
Agreement. (Incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended June 30, 2013)
Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Award
Agreement for Directors. (Incorporated by reference to Exhibit 10.8 to the Registrant’s
Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Unit Award
Agreement. (Incorporated by reference to Exhibit 10.9 to the Registrant’s Quarterly Report on
Form 10-Q for the quarter ended June 30, 2013)
Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Unit Award
Agreement for Directors. (Incorporated by reference to Exhibit 10.10 to the Registrant’s
Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
Form of Incentive Stock Option Agreement for awards prior to December 8, 2005.
(Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed
on December 20, 2004)
Form of Non-Qualified Stock Option Agreement for non-employee directors for awards prior
to December 8, 2005. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current
Report on Form 8-K filed on December 20, 2004)
Form of Incentive Stock Option for awards granted on or after December 8, 2005. (Incorporated
by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December
13, 2005)
Form of Restricted Stock Agreement for awards granted on or after December 8, 2005.
(Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed
on December 13, 2005)
Form of Non-Qualified Stock Option Agreement for awards granted on or after December 8,
2005 and through December 8, 2011 (Incorporated by reference to Exhibit 10.4 to the
Registrant’s Current Report on Form 8-K filed on December 13, 2005)
Form of Non-Qualified Stock Option Agreement for awards granted on or after December 8,
2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form
10-K (Commission File No. 1-08426) for the year ended December 31, 2012)
Master Lease Agreement by and between Southwestern Energy Company and SunTrust
Leasing Corporation dated December 29, 2006. (Incorporated by reference to Exhibit 10.22 to
the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year
ended December 31, 2006)
Guaranty by and between Southwestern Energy Company and Texas Gas Transmission, LLC,
dated as of October 27, 2008. (Incorporated by reference to Exhibit 10.3 to the Registrant’s
Quarterly Report on Form 10-Q (Commission File No. 1-08246) for the period ended
September 30, 2008)
Guaranty by and between Southwestern Energy Company and Fayetteville Express Pipeline,
LLC dated September 30, 2008 (Incorporated by reference to Exhibit 10.22 to the Registrant’s
Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31,
2008)
Retirement Letter Agreement dated February 24, 2012 between Southwestern Energy Company
and Gene A. Hammons. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current
Report on Form 8-K filed February 27, 2012)
Retirement Agreement dated August 11, 2009 between Southwestern Energy Company and
Harold M. Korell. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report
on Form 8-K filed on August 14, 2009)
SWN 137
148762Financials_r2_2016 Glossy 10K - Final 3.15.2017-1.pdf 124
Settlement Agreement, dated December 22, 2014, between Chesapeake Appalachia, L.L.C. and
SWN Production Company, LLC (Incorporated by reference to Exhibit 10.3 to the Registrant’s
Current Report on Form 8-K filed on December 23, 2014)
Retirement Agreement dated January 11, 2016 between Southwestern Energy Company and
Steven L. Mueller. (Incorporated by reference to Exhibit 10.38 to the Registrant’s Annual
Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2015)
Retirement Agreement dated May 19, 2016 between Southwestern Energy Company and
Jeffrey B. Sherrick. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly
Report on Form 10-Q for the quarter ended June 30, 2016)
Amendment to Awards Agreement dated May 19, 2016 between Southwestern Energy
Company and Jeffrey B. Sherrick. (Incorporated by reference to Exhibit 10.3 to the Registrant’s
Quarterly Report on Form 10-Q for the quarter ended June 30, 2016)
Amended and Restated Term Loan Credit Agreement, dated June 27, 2016 among
Southwestern Energy Company, Bank of America, N.A., as Administrative Agent, and the
lenders from time to time party thereto. (Incorporated by reference to Exhibit A to Exhibit 10.3
to the Registrant’s Current Report on Form 8-K filed on June 27, 2016)
Credit Agreement, dated June 27, 2016 among Southwestern Energy Company, JPMorgan
Chase Bank, N.A., as Administrative Agent, and the lenders from time to time party thereto.
(Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed
on June 27, 2016)
Amendment and Restatement Agreement, dated as of June 27, 2016 among Southwestern
Energy Company, Bank of America, N.A., as Administrative Agent, and the lenders party
thereto, giving effect to the Amended and Restated Term Loan Credit Agreement. (Incorporated
by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on June 27,
2016)
Amendment No. 1 to Credit Agreement, dated as of June 27, 2016 among Southwestern Energy
Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto.
(Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed
on June 27, 2016)
List of Subsidiaries
Consent of PricewaterhouseCoopers LLP
Consent of Netherland, Sewell & Associates, Inc.
Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of CEO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
Certification of CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
Mine Safety Disclosure
Reserve Audit Report of Netherland, Sewell & Associates, Inc., dated January 15, 2016
Interactive Data File Instance Document
Interactive Data File Schema Document
Interactive Data File Calculation Linkbase Document
Interactive Data File Label Linkbase Document
Interactive Data File Presentation Linkbase Document
Interactive Data File Definition Linkbase Document
10.37
10.38
10.39
10.40
10.41
10.42
10.43
10.44
21.1*
23.1*
23.2*
31.1*
31.2*
32.1*
32.2*
95.1*
99.1*
101.INS*
101.SCH*
101.CAL*
101.LAB*
101.PRE*
101.DEF*
____________
*Filed herewith
SWN 138
Forward Looking Statements
Annual Meeting
May 23, 2017 at 9:00 a.m. CDT
Southwestern Energy Company
10000 Energy Drive
Spring, TX 77389-4954
Corporate Headquarters
Southwestern
Energy Company
10000 Energy Drive
Spring, TX 77389-4954
832.796.4700
This annual report contains forward-looking
statements regarding Southwestern Energy
Company’s future plans and performance based
on assumptions the Company believes are
reasonable. A number of factors could cause
actual results to differ materially from these
statements. For further information regarding
these factors, see “Cautionary Statement
About Forward-Looking Statements” in
Management’s Discussion and Analysis of
Financial Condition and Results of Operations
and “Risk Factors” in the Company’s 2016
Form 10-K.
Certifications
In 2016, SWN’s Chief Executive Officer (CEO)
provided to the NYSE the annual CEO
certification regarding SWN’s compliance
with the NYSE’s corporate governance listing
standards. In addition, SWN’s CEO (principal
executive officer) and SWN’s principal financial
officer filed with the United States Securities
and Exchange Commission (SEC) all
certifications required in SWN’s SEC reports
for fiscal year 2016.
Independent
Registered
Public Accountants
Investor Relations
PricewaterhouseCoopers LLP
Houston, TX
Michael E. Hancock, Director
Investor Relations
Website
www.swn.com
Transfer Agent
Computershare
P.O. Box 30170
College Station, TX 77842-3170
800.446.2617
By overnight delivery
211 Quality Circle, Suite 210
College Station, TX 77845
Non-GAAP Reconciliations
Diluted (loss) earnings per share
Add back:
Participating securities–mandatory convertible preferred stock
Impairment of natural gas and oil properties
Restructuring and other one-time charges
Gain on sale of assets, net
Loss on early extinguishment of debt and other
Transaction costs
Loss (Gain) on certain derivatives
Adjustments due to inventory valuation
Adjustments due to discrete tax items
Tax impact on adjustments
Adjusted diluted (loss) earnings per share
Net cash provided by operating activities
Add back:
Changes in operating assets and liabilities
Restructuring charges
Net cash flow
Net income (loss)
Add back:
Depreciation, depletion and amortization
Gain on sale of assets, net
Write-down of inventory
Loss (Gain) on derivatives excluding derivatives, settled
Restructuring and other one-time charges
Loss on debt extinguishment
Net interest expense
Provision (benefit) for income taxes
Adjusted EBITDA
Total debt
Subtract:
Cash and cash equivalents
Net debt
2016
)
$ (6.32
--
5.33
0.20
--
0.13
--
0.86
0.01
2.25
)
(2.47
)
$ (0.01
2016
$ 498
99
48
$ 645
2016
)
$ (2,643
2,757
(3
)
3
373
89
51
88
(29
)
$ 686
2016
$ 4,653
(1,423
)
$ 3,230
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Adjusted Diluted (Loss) Earnings Per Share
2014
$ 2.62
2015
)
$ (12.25
2013
$ 2.00
)
(0.03
18.26
0.01
(0.74
)
--
0.14
0.41
0.08
1.27
)
(6.96
$ 0.19
--
--
--
--
--
0.01
)
(0.37
--
(0.13
)
0.14
$ 2.27
--
--
--
--
--
--
)
(0.06
--
0.04
0.02
$ 2.00
Net Cash Flow (in millions)
2014
$ 2,335
2013
$ 1,909
2015
$ 1,580
)
(112
--
$ 1,468
)
(65
--
$ 2,270
76
--
$ 1,985
Adjusted EBITDA (in millions)
2014
$ 924
2013
$ 704
2015
)
$ (4,556
787
--
--
)
(21
--
--
42
486
$ 1,998
8,041
(283
)
32
155
--
--
56
)
(2,005
$ 1,440
Net Debt (in millions)
2015
$ 4,705
(15
)
$ 4,690
942
--
--
)
(130
--
--
59
525
$ 2,320
2014
$ 6,957
(53
)
$ 6,904
2012
)
$ (2.03
--
5.56
--
--
--
--
0.01
--
--
(2.15
1.39
)
$
2012
$ 1,654
)
(55
--
$ 1,599
2012
$ (707
)
2,751
--
--
2
--
--
35
(443
)
$ 1,638
10000 Energy Drive
Spring, TX 77389-4954
832.796.4700