GULFPORT EN ERGY
DISCIPLINE
DEVELOPMENT
DEDICATION
2017 A NN UA L REPORT
Gulfport Energy is a team of data-driven, innovative thought
leaders, applying science and technology to safely and
efficiently develop and expand our valuable resources,
drawing upon the spirit of our employees and investing
in the communities where we live and operate. We are
committed to generating value for all our stockholders
through the production of an economic, clean-burning fuel
and the responsible stewardship of our resources, capital
and the environment.
5.4
TCFE
YEAR- END 2017
TOTAL NET PR OVED
RESERVES
APRIL 10, 2018
DEAR FELLOW
Stockholders
2017 was a pivotal year for Gulfport. Our Utica asset provided con-
sistent results and repeatable growth throughout the year, while we
also began the journey of increasing recoveries and further delineating
the underappreciated, multi-zone opportunities across our recently
acquired SCOOP position. We experienced a year of strong production
growth, increasing our total net production 51% over 2016 and exiting
the year at 1.3 billion cubic feet of gas equivalent per day, positioning
Gulfport at a more significant size and scale as we enter 2018.
Our focus on efficiencies throughout the year continued to improve our overall cost
structure. We also realized pricing uplift from our liquids portfolio during 2017, largely
driven by our liquids-rich SCOOP assets. Primarily as a result of these factors, we
expanded our cash margins by approximately 16% over 2016, increasing our overall
corporate returns for the year. Our reserve report for year-end 2017 speaks to the depth
and quality of our asset base and we witnessed significant growth in our proved reserves
and PV-10 value during the year. Key highlights of our 2017 operating and financial
results include:
Total net production of 397.5 Bcfe, or 1.1 Bcfepd, a 51% increase year-over-year.
Total per unit operating cost of $1.01 per Mcfe, a decrease of 8% year-over-year.
Total proved reserves grew to 5.4 Tcfe, an increase of 132% year-over-year.
SEC PV-10 value of $2.9 billion, an increase of 314% year-over-year.
Gulfport had many accomplishments in 2017 on the operational front and as we enter
2018, we are intently focused on capital discipline and maximizing returns. Our develop-
ment activities leading up to this point will enable us to navigate the current commodity
environment, aligning our business model to deliver a healthy rate of growth within cash
flow for 2018 and beyond.
G U L F P O R T E N E R G Y | 0 3
CAPITAL
Discipline
In the Utica, 2017 was an active year for Gulfport. Our program
focused on putting initiatives in place to further improve our best-
in-class operations, ultimately surpassing our previous records set
in the field.
On the drilling front, during 2017 we drilled 94 gross wells utilizing just under six oper-
ated rigs. These wells had an average drilled lateral length of approximately 8,150 feet,
and when normalized to an 8,000-foot lateral, as assumed in our public type curves, we
averaged a spud to rig release of 19 days, down 16% over our full-year 2016 results. We
exceeded all of our previous drilling records during the year, setting a new standard of
excellence in the field and providing a new set of expectations and goals for the team
to focus on going forward. Overall, we had a solid year and the efficiencies we realized
in 2017 will allow us to plan to do more at the drill bit in 2018 with fewer overall rigs
running in the play.
Turning to completions, in the Utica, we turned-to-sales 68 gross wells with an average
stimulated lateral length of 7,700 feet during 2017. We ran on average two completion
crews during the year and completed over 2,500 stages, which contributed to strong pro-
duction growth in the Utica during 2017, an increase of approximately 30% over 2016.
We continue to benefit from our vertical integration of key segments on the completions
side of the business, which provide access to goods and services critical to our operations,
quality equipment and experienced crews at a fair price.
With regard to leasehold, during 2017 we were successful in our trading efforts and
added leasehold organically within the units scheduled in our near-term development
plan, which allows us to focus our spend on the highest return potential for our capital.
This activity led to a significant increase in our working interests on wells spud during
2017, as we now effectively hold 100% working interest in all operated wells we intend
to turn-to-sales during 2018.
During 2018, we are dedicated to maximizing capital efficiency and our activity in the
Utica will be centered around the dry gas window of the play, with a focus on increasing
lateral lengths and realizing economies of scale on our per-foot metrics.
G U L F P O R T E N E R G Y | 0 4
1.1
BCFEPD
2017 DA ILY TOTAL NET
PRODUCTION
UTICA SHALE
The Utica Shale is located in the Appalachian Basin of the United States and Canada. Com-
posed of organic-rich calcareous black shale that was deposited about 440 million to 460
million years ago during the late Ordovician period, the Utica Shale overlies the Trenton
O HI O
Limestone and is located a few thousand feet below the Marcellus Shale.
Gulfport has approximately 213,000 net acres under lease in the Utica Shale and reported
strong year-end production of approximately 1,041.9 MMcfepd during the fourth quarter
of 2017, an increase of 36% over the fourth quarter of 2016. Gulfport’s production growth
during 2017, driven by the solid results from the dry gas phase window of the play, led to a
70% increase in proved reserves over 2016, totaling approximately 3.9 net Tcfe at year-end
2017. During 2018, Gulfport plans to run approximately 2.5 rigs on its Utica acreage, largely
focused within the dry gas phase window of the play.
3.9
TCFE
1,041.9
MMCFEPD
NET PROVED RESERVES
AT YE 2017
AVG. NET PRODUCTION
DURING 4Q17
~82%
OF PRODU CTION
GULFPORT'S TOTAL NET
PRODUCTION AS OF 4Q17
O KL AHOMA
OKLAHOMA
The SCOOP (South Central Oklahoma Oil Province) play of Oklahoma is located in the
southeast portion of the prolific Anadarko Basin. The SCOOP play mainly targets the
Devonian to Mississippian aged Woodford Shale. The Woodford Shale is a silica and
highly organic-rich black shale that was deposited about 320 million to 370 million years
ago. Across the Gulfport position, the Woodford Shale ranges in thickness from 200 to
over 400 feet and directly overlies the Hunton Limestone and underlies the Sycamore
Formation, both of which are also locally productive reservoirs. The Springer formation
holds organic-rich shale intervals that have thus far been predominantly oil productive
and are located approximately 1,000 feet above the Woodford. Its strata contains several
laterally extensive siliceous black shales that possess highly connected organic pores.
The Sycamore formation is age equivalent to the Meramec and Osage being developed in
the STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher Counties) play and is
located between the organic-rich Woodford and Caney Shales. The Sycamore formation is
approximately 250 feet thick across our acreage position, presenting a significant future
development target across Gulfport’s position.
Gulfport holds approximately 92,900 net reservoir surface acres with multiple producing
zones, including approximately 50,400 Woodford acres and approximately 42,500 Springer
acres across Grady, Stephens and Garvin Counties, Oklahoma. In addition, Gulfport holds
in excess of 40,000 net reservoir acres prospective in the Sycamore formation. At year-end,
Gulfport reported average net production of 206.6 MMcfepd during the fourth quarter of
2017 and proved net reserves of 1.5 Tcfe at year-end 2017. During 2018, Gulfport plans to
run approximately three rigs in the SCOOP, focused in the liquids-rich, wet gas window of
the play, and participate in non-operated activity.
1.5
TCFE
206.6
MMCFEPD
NET PROVED RESERVES
AT YE 2017
AVG. NET PRODUCTION
AS OF 4Q17
~16%
OF PRODU CTION
GULFPORT'S TOTAL NET
PRODUCTION AS OF 4Q17
In the SCOOP, once we completed the acquisition in February 2017,
we implemented our best practices and learnings from our Utica
88%
4%
8%
operations and witnessed significant improvement in our SCOOP
operations as the year progressed. The integration of the assets
went well and our team remains focused on identifying areas where
we can continue to improve operationally.
During 2017, approximately four operated rigs were utilized in the play and 19 gross
wells were spud on our acreage. These wells had an average lateral length of 7,200 feet,
and when normalized to a 7,500-foot lateral, as assumed in our public type curves, the
wells averaged a spud to rig release of approximately 72 days during 2017. The team was
intensely focused on identifying areas for improvement, including seismic reprocessing,
horizontal targeting, bit selection, casing placement and rotary steerable utilization. These
efforts have improved our geo-steering in target percentages above 90% and leading-edge
results leave us confident in our ability to reduce drilling days in 2018.
On the completion front, during 2017 we turned-to-sales 13 gross wells with a collective
average stimulated lateral length of 6,800 feet. In the SCOOP, when we commenced
operations we immediately applied our base completion design from the Utica and we
have yielded superior results from the wells turned-to-sales during 2017 when compared
to offsets completed with the conservative early generation techniques originally utilized
in the play. We continue to see strong results out of the play today. While the initial
production rates have been exciting, we are even more encouraged by the longer-term
production history we are receiving from our well set.
Turning to exploration, during 2017 we elected to include both a Springer and Sycamore
test in our development program to potentially delineate additional resource across the
2017 TOTAL
PRODUCTION
GAS
N GL
OIL
2%
8%
90%
2017 TOTAL
NET PROVED
RESERVES
GAS
N GL
OIL
acreage. Gulfport’s first Springer well is located in the oily area of the play, targeting the
~5%
thick, porous, oil-rich section of the upper member of the Springer and further delineating
~65%
the zone on a portion of the acreage position. In the Sycamore, the well is located in the
heart of the play, on the western side of the wet gas window of the Woodford and we are
very encouraged by the early production history. The Sycamore is an emerging zone in the
SCOOP and presents tremendous upside that is not included in our current inventory, po-
tentially unlocking significant prospective resource and meaningful developable locations.
~30%
CAPITAL
ALLOCATION BY
ASSET AREA
FOR 2018
Our 2018 program is centered around optimizing recoveries and identifying efficiencies
in the field. Similar to our Utica program, we are increasing our average lateral lengths on
both wells spud and turned-to-sales, benefiting recoveries and delivering more for every
dollar invested.
UT ICA
SCOO P
OTHER
G U L F P O R T E N E R G Y | 0 7
OPERATIONAL
Development
Our top-tier, core assets in two of North America’s lowest-cost nat-
ural gas basins and strong 2017 results have placed us in a position
of strength as we look to carry out our 2018 development plan. In
the current environment, we are dedicated to strict capital discipline
and are in a position to be able to generate free cash flow for our
stockholders while also providing strong production growth.
We firmly believe that at current commodity prices, managing the business to align total
capital expenditures within cash flow is the prudent business decision and we currently
forecast our 2018 capital program will be funded entirely with cash flow while growing
production approximately 15% to 19% year-over-year. Furthermore, our robust hedge
portfolio underpins our 2018 capital program with approximately 80% of our expected
2018 natural gas production priced at over $3.05 per MMBtu, providing a high degree of
certainty surrounding the cash flow profile of our 2018 program.
In addition to our planned operational activity for 2018, we previously announced that
Gulfport’s Board of Directors approved a $100 million stock repurchase program. The
repurchase program underscores the confidence that we have in our business model, our
financial performance and our top-tier asset base, and further demonstrates our commitment
to recognizing value for our stockholders. At current commodity prices, we see tremendous
value in reinvesting in our own stock versus generating additional production growth at the
drill bit. In addition, should we receive proceeds earlier or greater than anticipated from
the sale of certain equity investments, we would certainly consider expanding the size of
the repurchase program beyond where it sits today.
In closing, we are committed to disciplined capital allocation and recognizing value for
our stockholders. I would like to thank the leadership team and all of our employees for
their continued dedication to the organization. We all remain steadfastly committed to
executing on our 2018 program and creating greater value for our stockholders. We thank
you for your investment in Gulfport.
Respectfully,
MICHAEL G. MOORE
Chief Executive Officer and President
G U L F P O R T E N E R G Y | 0 8
$100
MILLION
STOCK REPURCHASE
PROGRAM
50
THOUSAND +
LIVE S IMPACTED
THROUGH GU LFPORT
ENERGY FU ND
COMMUNITY
Dedication
Gulfport Energy is committed to investing in the economic and social
well-being of the communities in which we operate. Our greatest asset
is not what we produce from the ground each day, but the spirit of
our employees and the people in the communities surrounding us.
In Ohio, Gulfport has partnered with the Foundation for Appalachian Ohio and established
the Gulfport Energy Fund. Through the Gulfport Energy Fund, we are able to fund projects
at schools and non-profit organizations with our bi-annual grant cycles. To date, Gulfport
has funded over 100 grants totaling more than $300,000 throughout Belmont, Guernsey,
Harrison, Monroe, Jefferson and Noble Counties. We have supported projects focusing on
education, health and human services and environmental stewardship, lending assistance
to more than 50,000 people in the Appalachian region. Gulfport has committed to invest
nearly $1 million to benefit various efforts in the local communities through the Gulfport
Energy Fund between 2014 and 2020.
In Oklahoma, we have been evaluating and establishing philanthropic opportunities and
relationships. By partnering with local Oklahoma City public schools and a variety of local
non-profit organizations, we have extended our corporate giving efforts throughout the
state of Oklahoma. At Gulfport, we believe that by investing our time and resources in our
local communities, we are able to contribute to a brighter tomorrow.
In 2017, Gulfport partnered with Energy FC, an Oklahoma-based professional soccer team,
to become a presenting sponsor of the Sidekicks program. The Sidekicks program pairs
an Energy FC player with a child or young adult with developmental disabilities for the
season. Through this pairing, the Energy FC player and his Sidekick spend time together at
Gulfport-sponsored events for the athletes, Sidekicks and their families. Promoting inclusion,
mentorship, learning and more, the Sidekicks program is an effort we knew we wanted to
be a part of. These pairings create life-long memories for those involved and Gulfport is
proud to be the sponsor of this life-changing program.
While Gulfport’s assets are geographically diverse, the mission and purpose of our efforts
remains constant. Safety and people come first, and Gulfport is committed to being a
responsible corporate citizen you can count on.
G U L F P O R T E N E R G Y | 1 1
FINANCIAL HIGHLIGHTS
2017
2016
2015
PRODUCTION
Oil and Gas Volumes
Natural gas (MMCF)
Oil (MBBLS)
Natural gas liquids (MGALS)
MMCFE
MCFEPD
INCOME STATEMENT
Revenues (in thousands)
Gas sales
Oil and condensate sales
Natural gas liquid sales
Net gain (loss) on gas, oil and NGL derivatives
Total
Costs and Expenses (per MCFE)
Lease operating expenses
Production taxes
Midstream gathering and processing
General and administrative
Interest
Depreciation, depletion and amortization
350,061
2,579
224,038
397,543
1,089,159
845,999
124,568
136,057
213,679
1,320,303
0.20
0.05
0.63
0.13
0.27
0.92
$
$
$
$
$
$
$
$
$
$
$
Financial Highlights (in thousands, except per share data)
Net income (loss)
Basic net income (loss) per share
Diluted net income (loss) per share
$
$
$
435,152
2.42
2.41
227,594
2,126
161,562
263,430
719,753
420,128
81,173
59,115
(174,506)
385,910
0.26
0.05
0.63
0.16
0.24
0.93
156,151
2,899
185,792
200,089
548,188
324,733
122,615
58,129
203,513
708,990
0.35
0.07
0.69
0.21
0.26
1.69
$
$
$
$
$
$
$
$
$
$
$
(979,709)
$ (1,224,884)
(7.97)
(7.97)
$
$
(12.27)
(12.27)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Basic weighted average shares outstanding
Diluted weighted average shares outstanding
179,834
180,253
122,953
122,953
99,792
99,792
EBITDA
Total assets
Total debt, including current maturity
Stockholders’ equity
RESERVES
Proved Reserves
Natural gas (BCF)
Oil (MMBBLS)
Natural gas liquids (MMBBLS)
Gas equivalent (BCFE)
$
911,399
$
43,434
$
349,268
$ 5,807,752
$ 2,038,943
$
3,101,614
$
$
$
4,223,145
1,593,875
2,183,892
$
$
$
3,334,734
946,263
2,038,837
4,825
19
76
5,395
2,167
6
20
2,321
1,560
6
18
1,705
G U L F P O R T E N E R G Y | 1 2
FORM 10-K
2017 AN NUAL REPORT
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
È ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2017
OR
‘ TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission File Number 000-19514
Gulfport Energy Corporation
(Exact Name of Registrant As Specified in Its Charter)
Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
3001 Quail Springs Parkway
Oklahoma City, Oklahoma
(Address of Principal Executive Offices)
73-1521290
(IRS Employer
Identification Number)
73134
(Zip Code)
(405) 252-4600
(Registrant Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share
The Nasdaq Stock Market LLC
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 È 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 È
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 È 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 (Section 232.405 of this chapter)
during the preceding 12 months (or such shorter period that the registrant was required to submit and post such
files). Yes È No ‘
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 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. È
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller
reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller
reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
È
Large Accelerated filer
‘
Non-accelerated filer
Emerging growth company ‘
‘
Accelerated filer
Smaller reporting company ‘
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period
complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ‘
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes ‘ No È
The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of
June 30, 2017, based on the closing price of the common stock on the NASDAQ Global Select Market on June 30, 2017, the last
business day of the registrant’s most recently completed second fiscal quarter ($14.75 per share), was $2,697,110,085.
As of February 12, 2018, 183,105,910 shares of the registrant’s common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Gulfport Energy Corporation’s Proxy Statement for the 2017 Annual Meeting of Stockholders are incorporated by
reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.
GULFPORT ENERGY CORPORATION
TABLE OF CONTENTS
FORWARD-LOOKING STATEMENTS
PART I
ITEM 1.
BUSINESS
ITEM 1A. RISK FACTORS
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 2.
PROPERTIES
ITEM 3.
LEGAL PROCEEDINGS
ITEM 4. MINE SAFETY DISCLOSURES
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
ITEM 6.
SELECTED FINANCIAL DATA
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
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 AND FINANCIAL STATEMENT SCHEDULES
ITEM 16.
FORM 10-K SUMMARY
Signatures
Index to Consolidated Financial Statements
Page
1
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F-1
i
FORWARD-LOOKING STATEMENTS
Our disclosure and analysis in this Form 10-K may include forward-looking statements within the meaning
of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities
Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation Reform Act of
1995, that are subject to risks and uncertainties. These statements involve known and unknown risks,
uncertainties and other factors that may 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 some cases, you can identify forward-looking statements by terms such as “may,” “will,”
“should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,”
“predicts,” “potential” and similar expressions intended to identify forward-looking statements. All statements,
other than statements of historical facts, included in this Form 10-K that address activities, events or
developments that we expect or anticipate will or may occur in the future, including such things as estimated
future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including
the amount and nature thereof), business strategy and measures to implement strategy, competitive strength,
goals, expansion and growth of our business and operations, plans, references to future success, reference to
intentions as to future matters and other such matters are forward-looking statements.
These forward-looking statements are largely based on our expectations and beliefs concerning future
events, which reflect estimates and assumptions made by our management. These estimates and assumptions
reflect our best judgment based on currently known market conditions and other factors relating to our operations
and business environment, all of which are difficult to predict and many of which are beyond our control.
Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and
involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions
about future events may prove to be inaccurate. Management cautions all readers that the forward-looking
statements contained in this Form 10-K are not guarantees of future performance, and we cannot assure any
reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual
results may differ materially from those anticipated or implied in the forward-looking statements due to the
factors listed in Item 1A. “Risk Factors” and Item 7. “Management’s Discussion and Analysis of Financial
Condition and Results of Operations” sections and elsewhere in this Form 10-K. All forward-looking statements
speak only as of the date of this Form 10-K. We do not intend to publicly update or revise any forward-looking
statements as a result of new information, future events or otherwise, except as required by law. These cautionary
statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
1
ITEM 1. BUSINESS
General
PART I
We are an independent oil and natural gas exploration and production company focused on the exploration,
exploitation, acquisition and production of natural gas, crude oil and natural gas liquids, or NGLs, in the
United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those
prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling.
Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as
development and exploratory drilling opportunities on high potential conventional and unconventional oil and
natural gas prospects. Our principal properties are located in the Utica Shale primarily in Eastern Ohio and the
SCOOP Woodford and SCOOP Springer plays in Oklahoma. In addition, among other interests, we hold an
acreage position along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields,
an acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly
and an approximate 25.1% equity interest in Mammoth Energy Services, Inc., or Mammoth Energy, an oil field
services company listed on the Nasdaq Global Select Market (TUSK). We seek to achieve reserve growth and
increase our cash flow through our annual drilling programs.
As of February 9, 2018, we held leasehold interests in approximately 237,000 gross (213,000 net) acres in
the Utica Shale primarily in Eastern Ohio. We spud our first well, the Wagner 1-28H, on our Utica Shale acreage
in February 2012 and, as of December 31, 2017, had spud 362 gross wells, 287 of which were completed and
were producing. In 2017, we spud 94 gross (88.7 net) wells, of which 32 were completed as producing wells and,
as of December 31, 2017, 58 were in various stages of completion and four were still being drilled. We
commenced sales from 68 gross (61.1 net) wells in the Utica Shale during 2017. During 2018 (through
February 9, 2018), we spud eight gross (6.4 net) wells. As of February 9, 2018, five of these wells were waiting
on completion and the other three were still drilling. In addition, other operators drilled 26 gross (8.4 net) wells
and commenced sales from 45 gross (9.3 net) wells on our Utica Shale acreage in 2017.
We currently intend to drill 36 to 40 gross (26 to 29 net) horizontal wells, and commence sales from 33 to
37 gross (33 to 37 net) horizontal wells on our Utica Shale acreage in 2018. We currently anticipate seven to
eight net horizontal wells will be drilled, and sales commenced from nine to ten net horizontal wells, by other
operators on our Utica Shale acreage. We currently expect to spend $425.0 million to $455.0 million on our
operated and non-operated activities during 2018.
Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2017
was approximately 95,854 net million cubic feet of natural gas equivalent, or MMcfe, or 1,041.9 MMcfe per day,
of which 93% was from natural gas and 7% was from oil and NGLs.
As of February 9, 2018, we held leasehold interests in approximately 50,400 net surface acres in the
SCOOP. In 2017, we spud 19 gross (15.7 net) wells, of which seven were completed as producing wells and, as
of December 31, 2017, four were being drilled and eight were in various stages of completion. We commenced
sales from 13 gross (11.0 net) wells in the SCOOP during 2017. During 2018 (through February 9, 2018), we
spud four gross (3.4 net) wells. As of February 9, 2018, one of these wells was waiting on completion and the
other three were still drilling. In addition, other operators drilled 31 gross (0.9 net) wells and commenced sales
from 23 gross (0.8 net) wells on our SCOOP acreage during the period from February 17, 2017 to December 31,
2017.
We currently intend to drill 15 to 16 gross (10 to 11 net) horizontal wells, and commence sales from 20 to
22 gross (16 to 18 net) horizontal wells on our SCOOP acreage in 2018. We currently anticipate four to five net
horizontal wells will be drilled, and sales commenced from two to three net horizontal wells, by other operators
on our SCOOP acreage. We currently expect to spend $185.0 million to $210.0 million on our operated and non-
operated activities during 2018.
2
Aggregate net production from our SCOOP acreage during the three months ended December 31, 2017 was
approximately 19,008 MMcfe, or an average of 206.6 MMcfe per day, of which 67% was from natural gas and
33% was from oil and NGLs.
In 2017, at our WCBB field, we recompleted 60 gross and net wells and spud ten new wells. In the fourth
quarter of 2017, production at WCBB was approximately 1,089 MMcfe, or an average of 11.8 MMcfe per day, of
which 99% was from oil and 1% was from natural gas.
In 2017, at our East Hackberry field, we recompleted 20 gross and net wells and spud four new wells. In the
fourth quarter of 2017, net production at East Hackberry was approximately 174 MMcfe, or an average of
1.9 MMcfe per day, of which 98% was from oil and 2% was from natural gas.
In 2017, at our West Hackberry field, we recompleted one gross and net well and spud one new well. In the
fourth quarter of 2017, net production at West Hackberry was approximately 17 MMcfe, or an average of
188.2 thousand cubic feet of natural gas equivalent, or Mcfe, per day, of which 100% was from oil.
We currently estimate our 2018 activities in our Southern Louisiana fields to be approximately
$20.0 million in aggregate to perform recompletion activities.
As of December 31, 2017, we held leasehold interests in approximately 3,383 net acres in the Niobrara
Formation in Northwestern Colorado. During the year ended December 31, 2017, there were no wells spud on
our Niobrara Formation acreage. In the fourth quarter of 2017, net production from our Niobrara Formation
acreage was approximately 26 MMcfe, or an average of 279.8 Mcfe per day, 100% of which was from oil.
During 2018, we currently do not anticipate drilling any wells in the Niobrara Formation.
As of December 31, 2017, we held leasehold interests in approximately 778 net acres in the Bakken
Formation of Western North Dakota and Eastern Montana, interests in 18 wells and overriding royalty interests
in certain existing and future wells. In the fourth quarter of 2017, our net production from this acreage was
approximately 57 MMcfe, or an average of 622.4 Mcfe per day, of which 81% was from oil, 14% was from
natural gas and 5% was from natural gas liquids.
We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of
December 31, 2017, Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and
Cold Lake oil sands regions of Alberta, Canada. For additional information regarding Grizzly, see “-Our Equity
Investments–Grizzly Oil Sands” below.
We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. Tatex II, a privately held entity,
holds an 8.5% interest in APICO, LLC, or APICO, an international oil and gas exploration company. APICO has
a reserve base located in Southeast Asia through its ownership of concessions covering approximately
180,000 acres which includes the Phu Horm Field. For additional information regarding Tatex II and our other
activities in Southeast Asia, see “-Our Equity Investments–Thailand” below.
In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in
entities that can provide services that are required to support our operations. For additional information regarding
these entities, see “-Our Equity Investments–Other Investments” below.
As of December 31, 2017, we had 5.4 Tcfe of proved reserves with a present value of estimated future net
revenues, discounted at 10%, or PV-10, of approximately $2.9 billion and associated standardized measure of
discounted future net cash flows of approximately $2.6 billion, excluding reserves attributable to our interests in
Grizzly, Tatex II and Tatex III. See Item 2. “Properties-Proved Oil and Natural Gas Reserves” for our definition
of PV-10 (a non-GAAP financial measure) and a reconciliation of our standardized measure of discounted future
net cash flows (the most directly comparable GAAP measure) to PV-10.
3
Principal Oil and Natural Gas Properties
The following table presents certain information as of December 31, 2017 reflecting our net interest in our
principal producing oil and natural gas properties in the Utica Shale primarily in Eastern Ohio, the SCOOP in
Oklahoma, along the Louisiana Gulf Coast, in the Niobrara Formation in Northwestern Colorado and in the
Bakken Formation in Western North Dakota and Eastern Montana.
Field
Utica Shale (3)
SCOOP (4)
West Cote Blanche Bay Field (5)
E. Hackberry Field (6)
W. Hackberry Field
Niobrara Formation
Bakken Formation
Overrides/Royalty Non-operated
NRI/WI (1)
Productive
Wells
Non-Productive
Wells
Developed
Acreage (2)
Gas
Oil
NGLs
Total
Percentages Gross Net Gross
Net
Gross
Net
MMcf MBbls MBbls MMcfe
Proved Reserves
42.75/52.07
30.83/38.52
80.108/100
82.33/100
87.5/100
34.52/48.61
1.51/1.83
Various
507 264.05
410 145.85
86
86
17
17
2
2
3
18
662
5
37
162
130
12
1.46 —
0.3 —
0.8 —
4.23
25.72
162
130
12
—
—
—
66,133
38,182
5,668
2,910
726
1,460
386
—
55,733 3,766,063
2,597 24,154 3,926,574
38,182 1,058,143 14,048 51,610 1,452,094
10,655
5,668
2,594
2,910
892
726
1,218
730
800
77
24
—
1,675 —
397 —
149 —
182 —
107
605
211
—
127
150
11
2
2 —
Total
1,705 517.46
346
333.95 115,465 104,026 4,825,310 19,157 75,766 5,394,851
(1) Net Revenue Interest (NRI)/Working Interest (WI) for producing wells.
(2) Developed acres are acres spaced or assigned to productive wells. Approximately 37% of our acreage is developed acreage and has been
(3)
(4)
held by production.
Includes NRI/WI from wells that have been drilled or in which we have elected to participate. Includes 220 gross (32.47 net) wells
drilled by other operators on our acreage.
Includes NRI/WI from wells that have been drilled or in which we have elected to participate. Includes 240 gross (8.4 net) wells drilled
by other operators on our acreage.
(5) We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet.
Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI).
(6) NRI shown is for producing wells.
Utica Shale (primarily in Eastern Ohio)
Location and Land
As of December 31, 2017, we held leasehold interests in approximately 237,000 gross (213,000 net) acres in
the Utica Shale.
Area History
The Ohio Department of Natural Resources reported that in the Utica Shale in Ohio, as of December 31,
2017, there were 1,798 producing horizontal wells, 236 horizontal wells that had been drilled but were not yet
completed or connected to a pipeline, 206 horizontal wells that were being drilled and an additional 500
horizontal wells that had been permitted.
Geology
The Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a
rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million
years ago during the Late Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet
below the Marcellus Shale.
Recently, the application of horizontal drilling, combined with multi-staged hydraulic fracturing to create
permeable flow paths from shale units into wellbores, has resulted in increased drilling activity and production in
the Devonian-age Marcellus Shale and the Ordovician-age Utica Shale in the Appalachian Basin states of
Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has potential for
application in other shale units which extend across much of the Appalachian Basin region.
4
The Utica Shale is estimated to be thicker and more geographically extensive than the Marcellus Shale. The
source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio,
Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath parts of
Lake Ontario, Lake Erie and Ontario, Canada. Throughout this area, the Utica Shale ranges in thickness from less
than 100 feet to over 500 feet. There is a general thinning from east to west.
The Utica Shale is also significantly deeper than the Marcellus Shale. In some parts of Pennsylvania, the
Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale.
However, the depth of the Utica Shale decreases to the west into Ohio and to the northwest under the Great Lakes
and into Canada to less than 2,000 feet below sea level.
The Utica Shale is estimated to have higher carbonate and lower clay mineral content than the Marcellus
Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments.
Operators in the Utica play continue to refine completions techniques to optimize productivity.
Facilities
There are standard land oil and natural gas processing facilities in the Utica Shale. Our facilities located at
well site pads include storage tank batteries, oil/gas/water separation equipment, vapor recovery units, line
heaters, compression emission control devices and applicable metering.
Recent and Future Activities
We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of
December 31, 2017, had spud 362 gross wells, 287 of which were completed and were producing. In 2017, we
spud 94 gross (88.7 net) wells, of which 32 were completed as producing wells and, as of December 31, 2017, 58
were in various stages of completion and four were still being drilled. We commenced sales from 68 gross (61.1
net) wells in the Utica Shale during 2017. During 2018 (through February 9, 2018), we spud eight gross (6.4 net)
wells. As of February 9, 2018, five of these wells were waiting on completion and the other three were still
drilling. In addition, other operators drilled 26 gross (8.4 net) wells and commenced sales from 45 gross (9.3 net)
wells on our Utica Shale acreage in 2017.
We currently intend to drill 36 to 40 gross (26 to 29 net) horizontal wells, and commence sales from 33 to
37 gross (33 to 37 net) horizontal wells, on our Utica Shale acreage in 2018. We currently anticipate seven to
eight net horizontal wells will be drilled, and sales commenced from nine to ten net horizontal wells, by other
operators on our Utica Shale acreage during 2018. We currently anticipate our 2018 capital expenditures to be
$425.0 million to $455.0 million related to our operated and non-operated Utica Shale activities. As of
February 9, 2018, we had three operated horizontal rigs drilling in the play and expect to release one rig in March
of 2018 as our contract expires. We plan to run, on average, approximately 2.5 operated horizontal rigs in the
Utica Shale in 2018.
Production Status
Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2017
was approximately 95,854 MMcfe, or 1,041.9 MMcfe per day, of which 93% was from natural gas and 7% was
from oil and NGLs.
SCOOP (Oklahoma)
Location and Land
As of December 31, 2017, we held leasehold interests in approximately 50,400 gross (50,400 net) surface
acres in the SCOOP and approximately 92,900 net reservoir acres, which includes 50,400 net Woodford acres
and 42,500 net Springer acres.
5
Area History
The SCOOP, or South Central Oklahoma Oil Province, is a loosely defined province that encompasses
many of the top hydrocarbon producing counties in Oklahoma. The area extends mainly across Grady, Caddo,
McClain, Garvin, Stevens, Carter and Love Counties. The region was historically developed by vertical wells
drilled through multiple stacked reservoirs ranging from the Cambrian to Permian Periods in age. The play
represents the transition to mainly horizontal development targeting predominantly oil and condensate-rich
hydrocarbons. The most prolific of these reservoirs include the, Springer (Goddard) Shale, Caney Shale,
Woodford Shale and Sycamore Formation.
Geology
The SCOOP play of Oklahoma is located in the southeast portion of the prolific Anadarko Basin. The
SCOOP play mainly targets the Devonian to Mississippian aged Woodford Shale. The Woodford Shale is a silica
and highly organic rich black shale that was deposited about 320 million to 370 million years ago. Across our
position, the Woodford Shale ranges in thickness from 200 to over 400 feet and directly overlies the Hunton
Limestone and underlies the Sycamore formation, both of which are also locally productive reservoirs. The
Sycamore formation is age equivalent to the Meramec and Osage being developed in the STACK, or Sooner
Trend Anadarko Basin Canadian and Kingfisher Counties, play and is located between the organic-rich
Woodford and Caney Shales. The Sycamore formation is approximately 250 feet thick across our acreage
position, presenting a significant future development target.
Facilities
There are standard land oil and natural gas processing facilities in the SCOOP. Our facilities located at well
site pads include storage tank batteries, oil/gas/water separation equipment, vapor recovery units, line heaters,
compression emission control devices and applicable metering.
Recent and Future Activities
On February 17, 2017, we, through our wholly-owned subsidiary Gulfport MidCon, LLC, or Gulfport
MidCon (formerly known as SCOOP Acquisition Company, LLC), completed our acquisition, which we refer to
as our SCOOP acquisition, of certain assets from Vitruvian II Woodford, LLC, an unrelated third-party seller, for
a total purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain
adjustments, and approximately 23.9 million shares of the Company’s common stock (of which approximately
5.2 million shares were placed in an indemnity escrow). Our SCOOP acquisition included approximately
46,000 net surface acres with multiple producing zones, including the Woodford and Springer formations in the
SCOOP resource play, in Grady, Stephens and Garvin Counties, Oklahoma.
Upon our acquisition of these assets, we focused on the high-grading of equipment for our rig fleet to drive
efficiencies and lower drill days in the play. Frac design on the wells to date includes an enhanced completion
when compared to historical practices for the area. Our 2017 drilling program concentrated on SCOOP
Woodford wells, however, during 2017, we also spud and turned-to-sales our first Springer and Sycamore wells.
In 2017, we spud 19 gross (15.7 net) wells, of which seven were completed as producing wells and, as of
December 31, 2017, eight were in various stages of completion and four were still being drilled. We commenced
sales from 13 gross (11.0 net) wells in the SCOOP during 2017. During 2018 (through February 9, 2018), we
spud four gross (3.4 net) wells. As of February 9, 2018, one of these wells was waiting on completion and the
other three were still drilling. In addition, other operators drilled 31 gross (0.9 net) wells and commenced sales
from 23 gross (0.8 net) wells on our SCOOP acreage in 2017.
We currently intend to drill 15 to 16 gross (10 to 11 net) horizontal wells, and commence sales from 20 to
22 gross (16 to 18 net) horizontal wells, on our SCOOP acreage in 2018. We currently anticipate four to five net
6
horizontal wells will be drilled, and sales commenced from two to three net horizontal wells, by other operators
on our SCOOP acreage during 2018. We currently anticipate our 2018 capital expenditures to be $185.0 million
to $210.0 million related to our operated and non-operated SCOOP activities. As of February 9, 2018, we had
four operated horizontal rigs drilling in the play and expect to release two rigs in mid-summer 2018 as our
contracts expire. We intend to run, on average, three operated horizontal rigs in the SCOOP during 2018.
Production Status
Aggregate net production from our SCOOP acreage during the three months ended December 31, 2017 was
approximately 19,008 net MMcfe, or 206.6 MMcfe per day, of which 67% was from natural gas and 33% was
from oil and natural gas liquids.
West Cote Blanche Bay Field
Location and Land
The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water
depths averaging eight to ten feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and
are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own
a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is
operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres.
Area History and Production
Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and
gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the
remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over
300 wells were drilled in the field. Of the 1,093 wells drilled as of December 31, 2017, 980 were completed as
producing wells. From the date of our acquisition of WCBB in 1997 through December 31, 2017, we drilled
273 new wells, 240 of which were productive, for an 88% success rate. As of December 31, 2017, estimated field
cumulative gross production was 200 MMBO and 237.8 Bcf of gas. Of the 1,093 wells drilled in WCBB as of
December 31, 2017, 86 were producing, 162 were shut-in, and six were being used as salt water disposal wells.
The other 839 wells have been plugged and abandoned.
Geology
WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a
piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative
movements affected deposition and created a complex system of fault traps. The compensating fault sets
generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage
movement caused extension over the dome and a large graben system (a downthrown area bounded by normal
faults) was formed.
There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly
200 major and minor discrete intervals have been tested. Within the 1,093 wells that had been drilled in the field
as of December 31, 2017, over 4,000 potential zones have been penetrated. These sands are highly porous and
permeable reservoirs primarily with a strong water drive.
WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD,
locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to
penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault
seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will
7
be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault
is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of
interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in
lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated
with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an
effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells
that produced from a sub-optimal position within a particular zone.
Facilities
We own and operate a production facility at WCBB that includes four production tank batteries, seven
natural gas compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system.
Recent Activity
In 2017, at our WCBB field, we recompleted 60 gross and net wells and spud eight new wells. As of
February 9, 2018, we had recompleted seven gross and net wells during 2018 in our WCBB field.
Production Status
In the fourth quarter of 2017, our net production at WCBB was approximately 1,089 MMcfe, or an average
of 11.8 MMcfe per day, of which 99% was from oil and 1% was from natural gas.
East Hackberry Field
Location and Land
The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake
Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 82.33%
average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. As of
December 31, 2017, we held beneficial interests in approximately 4,116 acres, including the Erwin Heirs Block,
which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters
of Lake Calcasieu.
Area History and Production
The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a
gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly
indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated
cumulative oil and condensate production through 2017 was over 4,758 MBO and 332 Bcf of casinghead gas
production. A total of 272 wells have been drilled on our portion of the field. As of December 31, 2017, 17 wells
had daily production, 130 were shut-in and three had been converted to salt water disposal wells. The remaining
122 wells had been plugged and abandoned.
Geology
The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,”
divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the
eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a
series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks.
These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations
found between 5,100 and 12,200 feet.
8
Facilities
We have a field office that serves both the East and West Hackberry fields. In addition, we own and operate
three production facilities at East Hackberry that include two land based tank batteries, a production barge, two
natural gas compressors, dehydration units and salt water disposal systems.
Recent Activity
During 2017 at East Hackberry, we recompleted 20 gross and net wells and spud four new wells. As of
February 9, 2018, we had recompleted two gross and net wells during 2018 in our East Hackberry field.
Production Status
In the fourth quarter of 2017, our net production at East Hackberry was approximately 174 MMcfe, or an
average of 1.9 MMcfe per day, of which 98% was from oil and 2% was from natural gas.
West Hackberry Field
Location and Land
The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish,
Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a
100% working interest (approximately 87.50% NRI) in 1,032 acres within the West Hackberry field. Our leases
at West Hackberry are located within two miles of one of the United States Department of Energy’s Strategic
Petroleum Reserves.
Area History
The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil
Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate
production through 2017 was 493 MBO and 140 Bcf of natural gas. As of December 31, 2017, 42 wells had been
drilled on our portion of West Hackberry. As of December 31, 2017, two of such wells were producing, 12 were
shut-in and one was being used as a salt water disposal well. The remaining 27 wells have been plugged and
abandoned.
Geology
Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There
are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the Oligocene-
age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous,
water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE.
Recent Activity
During 2017 at West Hackberry, we recompleted one gross and net well and spud one new well. As of
February 9, 2018, we had recompleted one gross and net well during 2018 in our West Hackberry field.
Production Status
In the fourth quarter of 2017, our net production at West Hackberry was approximately 17 MMcfe, or an
average of 188.2 Mcfe per day, of which 100% was from oil.
9
Facilities
We own and operate a production facility at West Hackberry that includes a land based tank battery and salt
water disposal system.
During 2018, we intend to run one recompletion rig in our Southern Louisiana fields.
Niobrara Formation (Northwestern Colorado)
Location and Land
Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern
Colorado and, as of December 31, 2017, we held leases for approximately 3,383 net acres. In 2017, no wells
were spud on our Niobrara Formation acreage.
Area History
The Niobrara Formation is a shale oil rock formation located in Colorado, Northwest Kansas, Southwest
Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is
drilled both vertically and horizontally. The Upper Cretaceous Niobrara Formation has emerged as another
potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most
resource plays, the Niobrara Formation has a history of producing through conventional technology with some of
the earliest production dating back to the early 1900s. Natural fracturing has played a key role in producing the
Niobrara Formation historically due to the low porosity and low permeability of the formation. Because of this,
conventional production has been very localized and limited in area extent. We believe the Niobrara Formation
can be produced on a more widespread basis using today’s horizontal multi-stage fracture stimulation technology
where the Niobrara Formation is thermally mature.
Geology
The Niobrara Formation oil play in Northwestern Colorado is located between the Piceance Basin to the
south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous
shales and marlstones. It is the fractured marlstone intervals locally known as the Buck Peak, Tow Creek and
Wolf Mountain benches that account for the majority of the area’s production. These fractured carbonate
reservoirs are associated with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil
accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil
prone and thermally mature with respect to oil generation. The producing intervals are geologically equivalent to
the Niobrara Formation reservoirs of the DJ and Powder River Basins, which are currently emerging as a major
crude resource play.
Production Status
In the fourth quarter of 2017, net production from our Niobrara Formation acreage was approximately
26 MMcfe, or an average of 279.8 Mcfe per day, 100% of which was from oil.
Facilities
There are typical land oil and natural gas processing facilities in the Niobrara Formation. Our facilities
located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units.
Recent Activity
There were no new wells drilled on our Niobrara Formation acreage in 2017. We do not anticipate drilling
any wells in the Niobrara Formation during 2018.
10
Bakken Formation
Location and Land
The Bakken Formation is located in the Williston Basin areas of Western North Dakota and Eastern
Montana. As of December 31, 2017, we held approximately 778 net acres, interests in 18 wells and overriding
royalty interests in certain existing and future wells.
Production Status
In the fourth quarter of 2017, our net production from this acreage was approximately 57 MMcfe, or an
average of 622.4 Mcfe per day, of which 81% was from oil, 14% was from natural gas and 5% was from natural
gas liquids.
Facilities
There are typical land, oil and natural gas processing facilities in the Williston Basin. The facilities located
at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units.
Recent Activities
There were no new wells drilled on our Bakken Formation acreage in 2017. We do not anticipate drilling
any wells in the Bakken Formation during 2018.
Additional Properties
In addition to our core properties discussed above, we also own working interests and overriding royalty
interest in various fields in Louisiana, Texas and Oklahoma as described in the following table as of
December 31, 2017:
Field
State
Parish/County
Acreage Working
Interest
Overriding Royalty
Interests
Producing
Wells
Non-Producing
Wells
Deer Island
Napoleonville
Crest
Eagle City South
Fay South
Squaw Cheek
Watonga Chickasha Trend
Green River Basin
Ochiltree
Louisiana Terrebonne
Louisiana Assumption
Texas
Oklahoma Dewey
Oklahoma Blaine
Oklahoma Blaine
Oklahoma Canadian
Colorado Moffat
3.125%
—
2%
1.04%
0.301%
0.13%
0.052%
0.0686%
—
2.5%
—
—
—
—
—
—
1
3
1
1
1
1
1
1
—
—
—
—
—
—
—
—
Our Equity Investments
Grizzly Oil Sands. We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in
Grizzly. As of December 31, 2017, Grizzly had approximately 830,000 net acres under lease in the Athabasca,
Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly has high-graded three oil sands projects
to various stages of development. Grizzly commenced commercial production from its Algar Lake Phase 1
steam-assisted gravity drainage, or SAGD, oil sand project during the second quarter of 2014 and has regulatory
approval for up to 11,300 barrels per day of bitumen production. Algar Lake production peaked at 2,200 barrels
per day during the ramp-up phase of the SAGD facility, however, in April 2015, Grizzly made the decision to
suspend operations at its Algar Lake facility due to the commodity price drop and its effect on project economics.
Grizzly continues to monitor market conditions as it assesses startup plans for the facility. Grizzly also owns the
May River property comprising approximately 47,000 acres. An initial 12,000 barrel per day development
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application covering the eastern portion of the May River lease has been deemed complete from the Alberta
Energy Regulator and is awaiting final approval, which is expected in early 2018. A 2-D seismic program
covering approximately 83 kilometers has been completed to more fully define the resource over the remaining
lease beyond the development application area. In 2017, Grizzly advanced plans for cold heavy oil sands
production, or CHOPS, at its Cadotte property in Peace River. However, plans for development are dependent on
stabilized commodity prices. Grizzly continues to advance rail marketing strategies to ensure consistent and
flexible access to premium markets for its future production. Grizzly is also advancing a project to utilize its
Windell truck to rail terminal located near Conklin, Alberta, for movement of liquefied petroleum gas, or LPG,
into the oil sands area for use in Thermal applications by SAGD producers.
Thailand. We own a 23.5% ownership interest in Tatex II. Tatex II, a privately held entity, holds an 8.5%
interest in APICO, an international oil and gas exploration company. APICO has a reserve base located in
Southeast Asia through its ownership of concessions covering approximately 180,000 acres which includes the
Phu Horm Field. Our investment is accounted for on the equity method. Tatex II accounts for its investment in
APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in
northeast Thailand. Phu Horm’s initial gross production was approximately 60 MMcf per day. For 2017, net gas
production was approximately 78 MMcf per day and condensate production was 250 barrels per day. PTT
Exploration and Production Public Company Limited operates the field with a 55% interest. Other interest
owners include APICO (35% interest) and ExxonMobil (10% interest). Our gross working interest (through
Tatex II as a member of APICO) in the Phu Horm field is 0.7%. Since our ownership in the Phu Horm field is
indirect and Tatex II’s investment in APICO is accounted for by the cost method, these reserves are not included
in our year-end reserve information.
Other Investments. In an effort to facilitate the development of our Utica Shale and other domestic acreage,
we have invested in entities that can provide services that are required to support our operations. In 2012, we
participated in the formation of Stingray Pressure Pumping LLC, or Stingray Pressure, and Stingray Logistics
LLC, or Stingray Logistics, with an initial ownership interest in each entity of 50%. These entities provide well
completion and other well services. In 2011 and 2012, we acquired an aggregate 40% equity interest in Bison
Drilling and Field Services LLC, or Bison, which owns and operates drilling rigs and related equipment. Also in
2011, we acquired a 25% interest in Muskie Proppant LLC, or Muskie, which is engaged in the processing and
sale of hydraulic fracturing grade sand. In the fourth quarter of 2014, we contributed our investments in Stingray
Pressure, Stingray Logistics, Bison and Muskie to Mammoth Energy Partners LP, or Mammoth, in exchange for
a 30.5% limited partner interest in this newly formed limited partnership. On October 19, 2016, Mammoth
Energy Services, Inc., or Mammoth Energy, which is the parent company of Mammoth, completed its initial
public offering, or the IPO, of 7,750,000 shares of its common stock at a public offering price of $15.00 per
share, of which 7,500,000 shares were sold by Mammoth Energy and 250,000 shares were sold by certain selling
stockholders, including 76,250 shares sold by us for which we received net proceeds of $1.1 million. Prior to the
completion of the IPO, we were issued 9,150,000 shares of Mammoth Energy common stock in return for the
contribution of our 30.5% interest in Mammoth Energy Partners LLC (as the successor to Mammoth).
Immediately following the completion of the IPO, we owned an approximate 24.2% interest in Mammoth
Energy. We used the net proceeds for the sale of our Mammoth Energy shares in the IPO for general corporate
purposes.
In 2013, we participated in the formation of Stingray Energy Services LLC, or Stingray Energy, with an
initial ownership interest of 50%. Stingray Energy provides rental tools for land-based oil and natural gas
drilling, completion and workover activities as well as the transfer of fresh water to wellsites. In 2012, we
participated in the formation of Stingray Cementing LLC, or Stingray Cementing, with an initial ownership of
50%. Stingray Cementing provides well completion and other well services. In 2014, we acquired a 25% equity
interest in Sturgeon Acquisitions LLC, or Sturgeon. Sturgeon owns an entity that operates sand mines that
produce hydraulic fracturing grade sand. On June 5, 2017, we acquired approximately 2.0 million shares of
Mammoth Energy common stock in connection with our contribution of all of our membership interests in
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Sturgeon, Stingray Energy and Stingray Cementing, bringing our equity interest in Mammoth Energy to
approximately 25.1%.
In February 2016, we, through our wholly owned subsidiary Gulfport Midstream Holdings, LLC, or
Midstream Holdings, entered into an agreement with Rice Midstream Holdings LLC, or Rice, a subsidiary of
Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio,
which we refer to as the dedicated areas, through a new entity, Strike Force Midstream LLC, or Strike Force. In
2017, Rice was acquired by EQT Corporation, or EQT. We own a 25% interest in Strike Force. EQT now acts as
operator and owns the remaining 75% interest in Strike Force. Construction of the gathering assets, which is
ongoing, provides gathering services for wells operated by Gulfport and other operators and connectivity of
existing dry gas gathering systems. First flow for Strike Force commenced on February 1, 2016.
See Note 4 to our consolidated financial statements included elsewhere in this report for additional
information regarding these other investments.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies that have
greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry
on midstream and refining operations and market petroleum and other products on a regional, national or
worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to
withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the
availability of alternative energy sources and the application of government regulation. In addition, oil and
natural gas compete with other forms of energy available to customers, primarily based on price. These alternate
forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or
other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to
convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.
Marketing and Customers
The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors
beyond the control of our management, including but not limited to the demand for oil and natural gas and the
level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of
skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production
and federal regulation of gas sold in interstate commerce. Both our Utica Shale and SCOOP natural gas
production is sold to various counterparties through established NAESBs at the plant tailgates and various central
delivery points owned and operated by third party midstream companies. Our natural gas production is sold
under monthly, seasonal and long-term contracts and, as needed, through daily transactions. When sold in basin,
pricing is typically based on Platts Gas Daily - Texas Eastern M2 Zone for our Utica Shale acreage and Platts
Gas Daily - Panhandle Tx-Ok and NGPL Midcontinent for our SCOOP acreage. To maintain flow assurance and
price stability, and as discussed under “- Transportation and Takeaway Capacity,” we have entered into
agreements in both the Utica and SCOOP basins to transport a portion of our natural gas production to various
delivery points. These agreements allow us to price the molecules at those various downstream markets less
transportation charges. The majority of our Utica oil is sold to purchasers at the tailgate of a condensate stabilizer
located near Cadiz, Ohio, owned and operated by MPLX Energy Logistics, or MPLX. Our SCOOP oil is sold at
the lease to various purchasers at respective area postings. In Southern Louisiana, our oil is sold to parties taking
custody at the lease or at the outlet from a Gulfport oil storage barge. Our NGLs in the Utica Shale are primarily
fractionated at MPLX’s Hopedale facility. The majority of the product is marketed by the operator with Gulfport
receiving the benefit from the MPLX’s aggregation and established logistic network. Our SCOOP NGLs are
primarily sent to Mont Belvieu on our commitment to DCP Souther Hills and purchased at the fractionation
facility. For the year ended December 31, 2017, sales to BP Energy Company, or BP, accounted for
approximately 40% of our total oil, natural gas and NGL revenues, before the effects of hedging.
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As of December 31, 2017, we had an average of approximately 560,800 MMBtu per day of firm sales
contracted with third parties for 2018. We had an average of approximately 659,000 MMBtu per day, 526,000
MMBtu per day, 372,000 MMBtu per day, 272,000 MMBtu per day and 240,000 MMBtu per day contracted
with third parties for 2019, 2020, 2021, 2022 and thereafter, respectively.
Transportation and Takeaway Capacity
In Ohio and Oklahoma, as of December 31, 2017, we had entered into firm transportation contracts to
deliver approximately 1,095,000 MMBtu to 1,245,000 MMBtu per day for 2018. For 2019 and 2020, we had
entered into firm transportation contracts to deliver approximately 1,205,000 MMBtu to 1,405,000 MMBtu
per day. We continuously monitor the need to secure additional firm transportation contracts for incremental
volumes from our Utica Shale and SCOOP acreage but expect additional long term contracts to be limited in
2018. Our primary long-haul firm transportation commitments include the following:
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520,000 MMBtu per day of firm capacity on Dominion East Ohio, which began in 2014 and allows us
to reach additional connectivity to Gulf Coast and Midwest natural gas markets;
250,000 MMBtu per day of firm capacity on Dominion Transmission, which began in 2015 and allows
us to reach additional connectivity to Midwest natural gas markets;
194,000 MMBtu per day of firm capacity on ANR Pipeline Company facilities, which began in 2014
and allows us to reach the Michigan, Chicago and Wisconsin natural gas markets;
200,000 MMBtu per day of firm capacity on Tennessee Gas Pipeline facilities, which began in 2015
and allows us to reach Gulf Coast delivery points;
275,000 MMBtu per day of firm capacity on Rockies Express Pipeline facilities, which began in 2015
and allows us to reach additional connectivity to Gulf Coast and Midwest markets;
50,000 MMBtu per day of firm capacity on Rockies Express Pipeline facilities, which went into partial
service in December 2016 and full service in January 2017, allowing additional connectivity to Gulf
Coast and Midwest markets;
20,000 MMBtu per day of firm capacity on Natural Gas Pipeline facilities which began in 2015 and
allows us to reach Midwest markets;
50,000 MMBtu per day of firm capacity on Texas Gas Transmission facilities which began in 2016
allowing additional access to Gulf Coast delivery points;
54,000 MMBtu per day of firm capacity on Texas Gas Transmission facilities which began in 2017
allowing additional access to Gulf Coast delivery points;
100,000 MMBtu per day of firm capacity on Texas Eastern Transmission facilities which began in
2017 allowing additional access to Midwest delivery points;
150,000 MMBtu per day of firm capacity on Energy Transfer’s Rover Pipeline facilities, 50,000 of
which began in 2017 allowing additional access to Midwest delivery points, and 100,000 expected to
begin in 2018 allowing additional access to Canadian, Midwest and Gulf Coast delivery points; and
100,000 MMBtu per day of firm capacity on Columbia Gulf Transmission facilities which began in late
2017 allowing additional access to Gulf Coast delivery points; and
50,000 MMBtu per day of firm capacity on Enable Oklahoma Intrastate which was acquired in early
2017 through our SCOOP acquisition allowing additional connectivity to East Texas and Gulf Coast
markets; and
30,000 MMBtu per day of firm capacity on Enable Gas Transmission facilities which was acquired in
early 2017 through our SCOOP acquisition allowing additional access to East Texas delivery points;
and
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20,000 MMBtu per day of firm capacity on Midcontinent Express Pipeline facilities which began mid
2017 allowing additional access to Gulf Coast delivery points; and
50,000 MMBtu per day of firm capacity on Gulf Crossing Pipeline facilities which began mid 2017
allowing additional access to Gulf Coast delivery points; and
200,000 MMBtu per day of firm capacity on Cheniere Midship Pipeline facilities which will begin in
2019 allowing additional access to East Texas delivery points.
Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any
deficiencies in deliveries. We continue to actively identify and evaluate additional takeaway capacity to facilitate
production growth in our Utica Basin and Oklahoma positions.
Regulation
Regulation of Oil and Natural Gas Production
Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other
legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and
natural gas industry is under constant review for amendment or expansion. Some of these requirements carry
substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our
cost of doing business and, consequently, affects our profitability.
We own interests in producing oil and natural gas properties located in the Utica Shale primarily in Eastern
Ohio, the SCOOP Woodford and SCOOP Springer plays in Oklahoma, along the Louisiana Gulf Coast and in the
Niobrara Formation in Northwestern Colorado and the Bakken Formation in Western North Dakota and Eastern
Montana. The states in which our fields are located regulate the production and sale of oil and natural gas,
including requirements for obtaining drilling permits, the method of developing fields and the spacing and
operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil
and natural gas resources could affect the rate of production and may include maximum daily production
allowables for wells on a market demand or conservation basis.
Environmental Regulation
Our oil and natural gas exploration, development and production operations are subject to stringent laws and
regulations governing the discharge of materials into the environment or otherwise relating to protection of the
environment or occupational health and safety. Numerous governmental agencies, such as the
U.S. Environmental Protection Agency, or the EPA, issue regulations that often require difficult and costly
compliance measures that carry substantial administrative, civil and criminal penalties and may result in
injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentrations of various substances that can be
released into the environment in connection with drilling and production activities, limit or prohibit construction
or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive
areas, and other protected areas, require action to prevent or remediate pollution from current or former
operations, such as plugging abandoned wells or closing earthen pits, result in the suspension or revocation of
necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose
substantial liabilities for pollution resulting from our operations or related to our owned or operated facilities.
Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint
and several. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or
other waste products into the environment. Changes in environmental laws and regulations occur frequently, and
any changes that result in more stringent and costly pollution control or waste handling, storage, transport,
disposal or cleanup requirements could materially adversely affect our operations and financial position, as well
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as the oil and natural gas industry in general. Our management believes that we are in substantial compliance
with applicable environmental laws and regulations and we have not experienced any material adverse effect
from compliance with these environmental requirements. This trend, however, may not continue in the future.
Waste Handling. The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable
state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and
production activities by imposing requirements regarding the generation, transportation, treatment, storage,
disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states
administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent
requirements. Although most wastes associated with the exploration, development and production of crude oil
and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid
wastes” that are subject to the less stringent non-hazardous waste requirements. Moreover, the EPA or state or
local governments may adopt more stringent requirements for the handling of non-hazardous wastes or
categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed
from time to time in Congress to re-categorize certain oil and natural gas exploration, development and
production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review
its regulation of oil and gas waste. It has until March 2019 to determine whether any revisions are necessary. Any
such changes in the laws and regulations could have a material adverse effect on our capital expenditures and
operating expenses.
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling
requirements. We believe that we are in substantial compliance with applicable requirements related to waste
handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the
extent that our operations require them under such laws and regulations. Although we do not believe the current
costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory
reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and
dispose of such wastes.
Remediation of Hazardous Substances. The Comprehensive Environmental Response, Compensation and
Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally
impose liability, without regard to fault or legality of the original conduct, on classes of persons who are
considered to be responsible for the release of a “hazardous substance” into the environment. These persons
include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the
time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at
the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to
strict liability that, in some circumstances, may be joint and several, for the costs of removing or remediating
previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property
contamination (including groundwater contamination), for damages to natural resources and for the costs of
certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file
claims for personal injury and property damage allegedly caused by the hazardous substances released into the
environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA
and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible
under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such
“hazardous substances” have been released.
Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean
Water Act,” the Safe Drinking Water Act, the Oil Pollution Act, or OPA, and analogous state laws and
regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge
of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States,
as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with
the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure plan
requirements under federal law require appropriate containment berms and similar structures to help prevent the
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contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean
Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into
regulated waters, including jurisdictional wetlands, unless authorized by a permit issued by the U.S. Army Corps
of Engineers, or the Corps. On June 29, 2015, the EPA and the Corps jointly promulgated final rules redefining
the scope of waters protected under the Clean Water Act. To the extent the rule expands the range of properties
subject to the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining
permits for dredge and fill activities in wetland areas. Following its promulgation, numerous states and industry
groups challenged the rule and, on October 9, 2015, a federal court stayed the rule’s implementation nationwide,
pending further action in court. In response to this decision, the EPA and the Corps have resumed nationwide use
of the agencies’ prior regulations defining the term “waters of the United States.” Further, on February 28, 2017,
President Trump signed an executive order directing the relevant executive agencies to review the rules and to
initiate rulemaking to rescind or revise them, as appropriate under the stated policies of protecting navigable
waters from pollution while promoting economic growth, reducing uncertainty and showing due regard for
Congress and the states. On July 27, 2017, the EPA and the Corps published a proposed rule to rescind the 2015
rules and, on November 22, 2017, the agencies published a proposed rule to maintain the status quo pending the
agencies review of the 2015 rules.
The EPA has also adopted regulations requiring certain oil and natural gas exploration and production
facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition,
on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore
unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants, which regulations
are discussed in more detail below under the caption “-Regulation of Hydraulic Fracturing.” Costs may be
associated with the treatment of wastewater or developing and implementing storm water pollution prevention
plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states
also maintain groundwater protection programs that require permits for discharges or operations that may impact
groundwater conditions.
The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating
to the prevention of and response to petroleum releases into waters of the United States, including the
requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must
develop and maintain facility response contingency plans and maintain certain significant levels of financial
assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities
to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and
certain other damages arising from a release, including, but not limited to, the costs of responding to a release of
oil to surface waters.
Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and
criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the
requirements of each of these laws.
Air Emissions. The federal Clean Air Act, as amended, and comparable state laws and regulations, regulate
emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The
EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at
specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities
may be required to obtain additional permits and incur capital costs in order to remain in compliance. For
example, on August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish
new emission controls for oil and natural gas production and processing operations, which regulations are
discussed in more detail below under the caption “-Regulation of Hydraulic Fracturing.” Also, on May 12, 2016,
the EPA issued a final rule regarding the criteria for aggregating multiple small surface sites into a single source
for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on
an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and
requirements. These laws and regulations may increase the costs of compliance for some facilities we own or
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operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-
compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and
regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and
that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing
permits has the potential to delay the development of oil and natural gas projects.
Climate Change. In December 2009, the EPA issued an Endangerment Finding that determined that
emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public
health and the environment because, according to the EPA, emissions of such gases contribute to warming of the
earth’s atmosphere and other climatic changes. In May 2010, the EPA adopted regulations establishing new GHG
emissions thresholds that determine when stationary sources must obtain permits under the Prevention of
Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air
Regulatory Group v. EPA, the Supreme Court held that stationary sources could not become subject to PSD or
Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require
installation of best available control technology for GHG emissions at sources otherwise subject to the PSD and
Title V programs. On August 26, 2016, the EPA proposed changes needed to bring EPA’s air permitting
regulations in line with the Supreme Court’s decision on GHG permitting. The proposed rule was published in
the Federal Register on October 3, 2016 and the public comment period closed on December 2, 2016.
The EPA also adopted a GHG reporting rule in September 2009 authorizing the collection of GHG data
from large emission sources across a range of industry sectors. In November 2010, the EPA expanded the GHG
reporting rule to include onshore and offshore oil and natural gas production and onshore processing,
transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for
emissions occurring in 2011. In October 2015, the EPA amended the GHG reporting rule to add the reporting of
GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic
fracturing, and blowdowns of natural gas transmission pipelines.
In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of
greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of
greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or
regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at
this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas
emissions.
In December 2015, the United States participated in the 21st Conference of the Parties, or COP-21, of the
United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls
for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and
enhance sinks and reservoirs of GHGs. The Agreement went into effect on November 4, 2016. The Agreement
establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, on
June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and
begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the
United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of
its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such
notice. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement,
whether a new agreement can be negotiated, or what terms would be included in such an agreement.
Furthermore, in response to the announcement, many state and local leaders have stated their intent to intensify
efforts to uphold the commitments set forth in the international accord.
Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact the
demand for, price of and value of our products and reserves. As our operations also emit greenhouse gases
directly, current and future laws or regulations limiting such emissions could increase our own costs. Currently,
while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not
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adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not
possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions
would impact our business.
There have also been efforts in recent years to influence the investment community, including investment
advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities
and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such
environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere
with our business activities, operations and ability to access capital. Furthermore, claims have been made against
certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public
nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to
enforce environmental laws and regulations against us and could allege personal injury, property damages or
other liabilities. While we are not a party to any such litigation, we could be named in actions making similar
allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an
adverse impact on our financial condition.
Moreover, there has been public discussion that climate change may be associated with extreme weather
conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea
levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some
studies indicate that climate change could cause some areas to experience temperatures substantially hotter or
colder than their historical averages. Extreme weather conditions can interfere with our production and increase
our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are
unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting
our operations.
Endangered Species Act
Environmental laws such as the Endangered Species Act, or the ESA and analogous state statutes, may
impact exploration, development and production activities on public or private lands. The ESA provides broad
protection for species of fish, wildlife and plants that are listed as threatened or endangered in the U.S., and
restricts activities that may adversely affect listed species or their habitat. Similar protections are offered to
migratory birds under the Migratory Bird Treaty Act. Federal agencies are required to insure that any action
authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or
modify their critical habitat. While some of our facilities may be located in areas that are designated as habitat
for endangered or threatened species, we believe that we are in substantial compliance with the ESA. The U.S.
Fish and Wildlife Service may identify, however, previously unidentified endangered or threatened species or
may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened
or endangered species, which could cause us to incur additional costs or become subject to operating restrictions
or bans in the affected areas.
Occupational Safety and Health Act
We are also subject to the requirements of the Occupational Safety and Health Act, or OSHA, and
comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s
hazard communication standard requires that information be maintained about hazardous materials used or
produced in our operations and that this information be provided to employees, state and local government
authorities and citizens. We believe that our operations are in substantial compliance with the OSHA
requirements.
Regulation of Hydraulic Fracturing
Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons,
particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand
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and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. We use
hydraulic fracturing extensively in the development of our Utica Shale and SCOOP acreage. The federal Safe
Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground
Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC
program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. However,
legislation has been proposed in recent sessions of Congress to amend the SDWA to repeal the exemption for
hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory
control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the
fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects
of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel
fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells.
In addition, the EPA previously announced plans to develop a Notice of Proposed Rulemaking by June
2018, which would describe a proposed mechanism - regulatory, voluntary, or a combination of both - to collect
data on hydraulic fracturing chemical substances and mixtures. Also, on June 28, 2016, EPA published a final
rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to
publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment
facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and gas extraction
wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such
wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial
characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
On August 16, 2012, the EPA published final regulations under the federal Clean Air Act that establish new
air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the
EPA’s rule package includes NSP standards to address emissions of sulfur dioxide and volatile organic
compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently
associated with oil and natural gas production and processing activities. The final rule seeks to achieve a
95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on
all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific
new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other
production equipment. The EPA received numerous requests for reconsideration of these rules from both industry
and the environmental community, and court challenges to the rules were also filed. In response, the EPA has
issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In
particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and VOC
emissions for certain new, modified and reconstructed equipment, processes and activities across the oil and
natural gas sector. However, in a March 28, 2017 executive order, President Trump directed the EPA to review
the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the
stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time
avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA
published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive
emission requirements. These standards, as well as any future laws and their implementing regulations, may
require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of
new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of
specific equipment or technologies to control emissions.
In addition, on March 26, 2015, the Bureau of Land Management, or BLM, published a final rule governing
hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in
hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and
submission to the BLM of detailed information about the proposed operation, including wellbore geology, the
location of faults and fractures, and the depths of all usable water. On June 21, 2016, the United States District
Court for Wyoming set aside the rule, holding that the BLM lacked Congressional authority to promulgate the
rule. The BLM has appealed the decision to the Tenth Circuit Court of Appeals. Also, on November 15, 2016, the
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BLM finalized a rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal
and Indian lands. The rule requires operators to use currently available technologies and equipment to reduce
flaring, periodically inspect their operations for leaks, and replace outdated equipment that vents large quantities
of gas into the air. The rule also clarifies when operators owe the government royalties for flared gas. State and
industry groups have challenged this rule in federal court, asserting that the BLM lacks authority to prescribe air
quality regulations. On March 28, 2017, President Trump signed an executive order directing the BLM to review
the above rules and, if appropriate, to initiate a rulemaking to rescind or revise them. Accordingly, on
December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule. Also, on
December 8, 2017, the BLM published a final rule to suspend or delay certain requirements of the 2016 methane
rule until January 17, 2019. Further legal challenges are expected. At this time, it is uncertain when, or if, the
rules will be implemented, and what impact they would have on our operations.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on
environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study
examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under
some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also,
on February 6, 2015, the EPA released a report with findings and recommendations related to public concern
about induced seismic activity from disposal wells. The report recommends strategies for managing and
minimizing the potential for significant injection-induced seismic events. Other governmental agencies,
including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability
Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed
studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult
or costly for us to perform fracturing and increase our costs of compliance and doing business.
Some states and local jurisdictions in which we operate or hold oil and natural gas interests have adopted or
are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances,
impose more stringent operating standards and/or require the disclosure of the composition of hydraulic
fracturing fluids. If new or more stringent state or local legal restrictions relating to the hydraulic fracturing
process are adopted in areas where we operate, we could incur potentially significant added costs to comply with
such requirements, experience delays or curtailment in the pursuit of exploration, development or production
activities, and perhaps even be precluded from drilling wells.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of
fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for
impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement
actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or
regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or
costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for
third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that
specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic
fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to
additional permitting and financial assurance requirements, more stringent construction specifications, increased
monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to
attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur
substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a
material adverse effect on our financial condition and results of operations. At this time, it is not possible to
estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic
fracturing.
Other Regulation of the Oil and Natural Gas Industry
The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities.
Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion,
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frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are
authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its
individual members, some of which carry substantial penalties for failure to comply. Although the regulatory
burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our
profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they
affect other companies in the industry with similar types, quantities and locations of production.
The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The
interstate transportation of oil and natural gas is subject to federal regulation, including regulation of the terms,
conditions and rates for interstate transportation, natural gas storage and various other matters, primarily by the
Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for
access to oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas
transmission in some circumstances may also affect the intrastate transportation of oil and natural gas.
Although oil and natural gas prices are currently unregulated, Congress historically has been active in the
area of oil and natural gas regulation. We cannot predict whether new legislation to regulate oil and natural gas
might be proposed, what proposals, if any, might actually be enacted by Congress or the various state
legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and natural
gas liquids are not currently regulated and are made at market prices.
Drilling and Production. Our operations are subject to various types of regulation at the federal, state and
local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports
concerning operations. The states and some counties and municipalities in which we operate also regulate one or
more of the following:
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the location of wells;
the method of drilling and casing wells;
the timing of construction or drilling activities, including seasonal wildlife closures;
the rates of production or “allowables”;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to, and consultation with, surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling
of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration
while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization
may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state
conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the
venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and
regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of
wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance
tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States
do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they
will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural
gas that may be produced from our wells, negatively affect the economics of production from these wells or to
limit the number of locations we can drill.
Federal, state and local regulations provide detailed requirements for the plugging and abandonment of
wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where
we operate. Although the U.S. Army Corps of Engineers does not require bonds or other financial assurances,
some state agencies and municipalities do have such requirements.
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Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected
the price of the natural gas we produce and the manner in which we market our production. FERC has
jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas
companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various
federal laws have been enacted which have resulted in the complete removal of all price and non-price controls
for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. Under
the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of
natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
FERC also regulates interstate natural gas transportation rates and service conditions and establishes the
terms under which we may use interstate natural gas pipeline capacity, which affects the marketing of natural gas
that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas
pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that
significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline
companies are required to provide nondiscriminatory transportation services to producers, marketers and other
shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s
initiatives have led to the development of a competitive, open access market for natural gas purchases and sales
that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines.
However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee
that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely
into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas
related activities.
Under FERC’s current regulatory regime, transmission services are provided on an open-access, non-
discriminatory basis at cost-based rates or at negotiated rates. Gathering service, which occurs upstream of
jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the
NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the
NGA. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional transmission
facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting
gas to point-of-sale locations.
Oil Sales and Transportation. Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil
in common carrier pipelines is also subject to rate regulation. FERC regulates interstate oil pipeline
transportation rates under the Interstate Commerce Act and intrastate oil pipeline transportation rates are subject
to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of
regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as
effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the
regulation of oil transportation rates will not affect our operations in any materially different way than such
regulation will affect the operations of our competitors.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory
basis. Under this standard, common carriers must offer service to all similarly situated shippers requesting
service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is
governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that
access to oil pipeline transportation services generally will be available to us to the same extent as to our
competitors.
State Regulation. The states in which we operate regulate the drilling for, and the production and gathering
of, oil and natural gas, including through requirements relating to the method of developing new fields, the
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spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may also
regulate rates of production and may establish maximum daily production allowables from oil and natural gas
wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or
engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the
future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced
from our wells and to limit the number of wells or locations we can drill.
In July 2015, the Ohio Department of Natural Resources, or the ODNR, enacted a comprehensive set of
rules to regulate the construction of horizontal well pads. Under these new rules, operators must submit detailed
horizontal well pad design packages prepared by a professional engineer for review and certification by the
ODNR Division of Oil and Gas Resources Management prior to the commencement of any oil and natural gas
activity. These rules resulted in increased construction costs for operators. Furthermore, pursuant to new rules
approved in August 2016, operators must immediately notify ODNR regarding certain oil and natural gas
releases.
The petroleum industry is also subject to compliance with various other federal, state and local regulations
and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not
believe that compliance with these laws will have a material adverse effect on us.
Operational Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions,
blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to
environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should
occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage
or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory
investigation and penalties and suspension of operations.
In accordance with what we believe to be industry practice, we maintain insurance against some, but not all,
of the operating risks to which our business is exposed. We insure some, but not all, of our properties for
operational and hurricane related events. We currently have insurance policies that include coverage for general
liability, physical damage to our oil and natural gas properties, operational control of certain wells, oil pollution,
third party liability, workers compensation, cyber and employers’ liability and other coverage. Our insurance
coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to
exclusions and limitations, and there is no assurance that such coverage will fully or adequately protect us against
liability from all potential consequences, damages and losses. Any of these events could cause a significant
disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our
financial position, results of operations and cash flows.
Currently, we have general liability insurance coverage with an annual aggregate limit of up to
$25.0 million which includes sudden and accidental pollution for the effects of onshore and offshore pollution on
third parties arising from our operations as well as $10.0 million of gradual pollution insurance coverage. For our
offshore WCBB properties, we also have a $40.0 million property physical damage policy which insures against
most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that
this policy is limited to $12.5 million for damages arising as a result of a named windstorm. All of our insurance
coverage includes deductibles of up to $250,000 per occurrence ($1.25 million in the case of a named windstorm)
that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations.
We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our
industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of
insurance may become unavailable in the future or unavailable on terms that we believe are economically
acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we
consider reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to
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secure additional insurance or bonding that might be required by new governmental regulations. This may cause
us to restrict our operations, which might severely impact our financial position. The occurrence of a significant
event, not fully insured against, could have a material adverse effect on our financial condition and results of
operations.
We carry control of well insurance for all of our Utica Shale and SCOOP wells and several Southern
Louisiana wells. We also require all of our third party vendors to sign master service agreements in which they
agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and
subcontractors hired by the service provider.
We have prepared and have in place spill prevention control and countermeasure plans for each of our
principal facilities in response to federal and state requirements. The plans are reviewed annually and updated as
necessary. As required by applicable regulations, our facilities are built with secondary containment systems to
capture potential releases. We also own additional spill kits with oil booms and absorbent pads that are readily
available, if needed. In addition, we have emergency response companies on retainer. These companies
specialize in the clean up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to
us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus
additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and
clean up services during 2017 and 2016 were approximately $0.2 million and $0.1 million. While these
companies have been able to meet our service needs when required from time to time in the past, it is possible
that the ability of one or more of them to provide services to us in the future, if and when needed, could be
hindered or delayed in the event of a widespread disaster. However, in light of the areas in which we operate and
the nature of our production, we believe other companies would be available to us in the event our primary
remediation companies are unable to perform. To supplement our planning and operation activities in Ohio,
Oklahoma and Louisiana, we also actively manage an incident response planning program and coordinate with
applicable state agency personnel on spills and releases through the Ohio, Oklahoma and Louisiana Incident
Notification Hotlines. We also participate in the Ohio, Oklahoma and Louisiana Emergency Planning and
Community Right to Know Act (EPCRA) programs, which includes reporting of various materials used or stored
on-site as well as notification to state and local emergency response centers, such as local fire departments, for
emergency planning purposes.
Headquarters and Other Facilities
We own approximately 120,000 square feet of office space in Oklahoma City, Oklahoma that serves as our
corporate headquarters. We also own an approximately 28,500 square foot office building in Oklahoma City,
Oklahoma where some of our employees office.
We own an approximately 12,300 square feet building located in St. Clairsville, Ohio that serves as our
headquarters for our Ohio operations. We also own an approximately 12,500 square foot building in Lafayette,
Louisiana. This building contains approximately 6,200 square feet of finished office area and 6,300 square feet of
clear span warehouse area. We lease approximately 3,700 square feet in a building in Lafayette that we use as our
Louisiana headquarters. We also lease an office in Lindsay, Oklahoma that serves as our Oklahoma production
field office. Each of these properties is suitable and adequate for its use.
Employees
At December 31, 2017, we had 331 employees.
Availability of Company Reports
Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all
amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made
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available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as
reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information
contained on our website, or on other websites that may be linked to our website, is not incorporated by reference
into this annual report on Form 10-K and should not be considered part of this report or any other filing that we
make with the SEC.
ITEM 1A. RISK FACTORS
Risks Related to our Business and Industry
Market conditions for oil and natural gas, and volatility in prices for oil and natural gas, have in the past
adversely affected, and may continue in the future to adversely affect, our revenue, cash flows, profitability,
growth, production and the present value of our estimated reserves.
Our revenues, cash flows, profitability, future rate of growth, production and the carrying value of our oil
and natural gas properties depend significantly upon the prevailing prices for natural gas and, to a lesser extent,
oil. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to
changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control,
including:
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worldwide and domestic supplies of oil and natural gas;
the level of prices, and expectations about future prices, of oil and natural gas;
the cost of exploring for, developing, producing and delivering oil and natural gas;
the expected rates of declining current production;
the level of consumer demand;
the price and availability of alternative fuels;
technical advances affecting energy consumption;
risks associated with operating drilling rigs;
the availability of pipeline capacity and other transportation facilities;
the price and level of foreign imports;
domestic and foreign governmental regulations and taxes;
the ability of the members of the Organization of Petroleum Exporting Countries to agree to and
maintain oil price and production controls;
speculative trading in crude oil and natural gas derivative contracts;
political or economic instability or armed conflict in oil and natural gas producing regions, including
the Middle East, Africa, South America and Russia;
the overall domestic and global economic environment; and
weather conditions, including hurricanes, and other natural disasters that can affect oil and natural gas
operations over a wide area.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and
natural gas price movements with any certainty. During 2016, West Texas intermediate light sweet crude oil,
which we refer to as West Texas Intermediate or WTI, prices ranged from $26.19 to $54.01 per barrel and the
Henry Hub spot market price of natural gas ranged from $1.49 to $3.80 per MMBtu. During 2017, WTI prices
ranged from $42.48 to $60.46 per barrel and the Henry Hub spot market price of natural gas ranged from $2.44 to
$3.71 per MMBtu. If the prices of oil and natural gas decline, our operations, financial condition and level of
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expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In
addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce
economically. This may result in our having to make substantial downward adjustments to our estimated proved
reserves. If this occurs or if our production estimates change or our exploration or development activities are
curtailed, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying
value of our oil and natural gas properties. Reductions in our reserves could also negatively impact the borrowing
base under our revolving credit facility, which could limit our liquidity and ability to conduct additional
exploration and development activities.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are
challenging, 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.
Our future growth prospects are dependent upon our ability to identify optimal strategies for our business. In
developing our 2018 business plan, we considered allocating capital and other resources to various aspects of our
businesses, including well development, reserve acquisitions, midstream infrastructure and other activities. We
also considered our likely sources of capital. Notwithstanding the determinations made in the development of our
2018 plan, business opportunities not previously identified periodically come to our attention, including possible
acquisitions and dispositions. If we fail to identify optimal business strategies, including the appropriate rate of
reserve development, or fail to optimize our capital investment and capital raising opportunities and the use of
our other resources in furtherance of our business strategies, our financial condition and growth rate may be
adversely affected. Moreover, economic or other circumstances may change from those contemplated by our
2018 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our
objectives.
We periodically engage in acquisitions, dispositions and other strategic transactions, including equity
investments and joint ventures such as our recent midstream agreement with Rice. These transactions involve
various inherent risks, such as changes in prevailing market conditions, our ability to obtain the necessary
regulatory approvals, the timing of and conditions that may be imposed on us by regulators and our ability to
achieve benefits anticipated to result from the transactions. Further, our equity investments and joint venture
arrangements may restrict our operational and corporate flexibility and subject us to risks and uncertainties, such
as committing us to fund operating and/or capital expenditures, the timing and amount of which we may not be
able to control. Further, the counterparties to these transactions may not satisfy their obligations to the joint
venture. Our inability to complete a transaction or to achieve our strategic or financial goals in any transaction
could have significant adverse effects on our earnings, cash flows and financial position.
Concerns over general economic, business or industry conditions may have a material adverse effect on our
results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and
cost of credit and the European, Asian and the United States financial markets have contributed to economic
volatility and diminished expectations for the global economy. In addition, continued hostilities in the Middle
East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect
the global economy. These factors, combined with volatility in commodity prices, business and consumer
confidence and unemployment rates, have in the past precipitated, and may in the future precipitate, an economic
slowdown. Concerns about global economic growth could have a significant adverse impact on global financial
markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide
demand for petroleum products could diminish, which could impact the price at which we can sell our
production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately
adversely impact our results of operations, liquidity and financial condition.
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Our development, acquisition and exploration operations require substantial capital and we may be unable to
obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a
decline in our oil and natural gas reserves.
Our future success depends upon our ability to find, develop or acquire additional oil and natural gas
reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted,
except to the extent that we conduct successful exploration or development activities or acquire properties
containing proved reserves, or both. To increase reserves and production, we undertake development, exploration
and other replacement activities or use third parties to accomplish these activities. We have made and expect to
make in the future substantial capital expenditures in our business and operations for the development,
production, exploration and acquisition of oil and natural gas reserves. For example, we currently estimate our
exploration and production capital expenditures for 2018 to be in the range of $630.0 million to $685.0 million
and an additional $140.0 million to $150.0 million for leasehold expenditures, primarily lease extensions in the
Utica Shale, and for cash capital contributions to our midstream joint venture with EQT in Eastern Ohio.
Historically, we have financed capital expenditures primarily with cash flow from operations, the issuance
of equity and debt securities and borrowings under our bank and other credit facilities. Our cash flow from
operations and access to capital are subject to a number of variables, including:
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our proved reserves;
the volume of oil and natural gas we are able to produce from existing wells;
the prices at which oil and natural gas are sold;
our ability to acquire, locate and produce economically new reserves; and
our ability to borrow under our credit facility.
We cannot assure you that our operations and other capital resources will provide cash in sufficient amounts
to maintain planned or future levels of capital expenditures. Further, our actual capital expenditures in 2018
could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are
greater than the amount of capital we have available, we could be required to seek additional sources of capital,
which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production
payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you
that we will be able to obtain debt or equity financing on terms favorable to us, or at all.
If we are unable to fund our capital requirements, we may be required to curtail our operations relating to
the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a
decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan,
complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of
which could have a material adverse effect on our production, revenues and results of operations. In addition, a
delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential
efficiencies.
Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses
could reduce our earnings and slow our growth.
There is intense competition for acquisition opportunities in our industry. The successful acquisition of
producing properties requires an assessment of several factors, including:
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recoverable reserves;
future oil and natural gas prices and their applicable differentials;
operating costs; and
potential environmental and other liabilities.
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The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive
acquisition opportunities. In connection with these assessments, we perform a review of the subject properties
that we believe to be generally consistent with industry practices. Our review will not reveal all existing or
potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their
deficiencies and capabilities. Inspections may not always be performed on every well, and environmental
problems, such as groundwater contamination, are not necessarily observable even when an inspection is
undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective
contractual protection against all or part of the problems. Even if we do identify attractive acquisition
opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions.
Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity
financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in
which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in
coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new
geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements.
Compliance with regulatory requirements may impose substantial additional obligations on us and our
management, cause us to expend additional time and resources in compliance activities and increase our
exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of
any completed acquisition will depend on our ability to integrate effectively the acquired business into our
existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may
require a disproportionate amount of our managerial and financial resources. In addition, possible future
acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.
No assurance can be given that we will be able to identify additional suitable acquisition opportunities,
negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire
identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets
into our existing operations successfully or to minimize any unforeseen operational difficulties could have a
material adverse effect on our financial condition and results of operations. The inability to effectively manage
the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which,
in turn, could negatively impact our earnings and growth. Our financial position and results of operations may
fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in
particular periods.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential,
identify liabilities associated with the properties that we acquire or obtain protection from sellers against such
liabilities.
Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics,
including recoverable reserves, development and operating costs and potential environmental and other
liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we
perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential
problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily
observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not
be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the
property. We may be required to assume the risk of the physical condition of the properties in addition to the risk
that the properties may not perform in accordance with our expectations.
We may incur losses as a result of title defects in the properties in which we invest.
It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining
lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease
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brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office
before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can
render a lease worthless and can adversely affect our results of operations and financial condition.
Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the
person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no
obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be
done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to
cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely
impact our ability in the future to increase production and reserves. Additionally, undeveloped acreage has
greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of
leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
Recent decisions by the Ohio Supreme Court interpreting the Ohio Dormant Mineral Act relating to
preservation of mineral rights by surface owners could require certain curative efforts to vest title in a portion
of our leasehold acreage, increase our leasehold expenses, subject us to payment of additional royalties and/or
result in the loss of some of our leasehold acreage in Ohio.
On September 15, 2016, the Ohio Supreme Court issued a series of decisions relating to the Ohio Dormant
Mineral Act, which we refer to as the ODMA. In the lead case, Corban v. Chesapeake Exploration L.L.C., the
court concluded that the 1989 version of the ODMA did not transfer ownership of dormant mineral rights
automatically, by operation of law. Instead, prior to 2006, surface owners were required to bring a quiet title
action in order to establish abandonment of mineral rights. After June 30, 2006, (the effective date of the 2006
version of the ODMA), surface owners are required to follow the statutory notice and recording procedures
enacted in 2006. We have assessed the impact of these recent Ohio Supreme Court decisions on our operations in
Ohio where the majority of our acreage and our producing properties are located and have taken steps to mitigate
any potential risks identified as a result of our assessment. However, the Ohio Supreme Court decisions could
require certain curative efforts to vest title in a portion of our leasehold acreage, increase our leasehold expense,
subject us to payment of additional royalties and/or result in the loss of some of our leasehold acreage in Ohio,
any of which could have an adverse effect on our results of operations and financial condition.
If we are unable to complete capital projects in a timely manner, our business, financial condition, results of
operations and cash flows could be materially and adversely affected.
Delays related to capital spending programs involving engineering, procurement and construction of
facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to
achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades
to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we
produce. Such delays may arise as a result of unpredictable factors, many of which are beyond our control,
including:
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denial of or delay in receiving requisite regulatory approvals and/or permits;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of components or construction materials;
adverse weather conditions, natural disasters or other events (such as equipment malfunctions,
explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
market-related increases in a project’s debt or equity financing costs; and
nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.
Any one or more of these factors could have a significant impact on our ongoing capital projects.
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Our Canadian oil sands projects are complex undertakings and may not be completed at our estimated cost or
at all.
We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of
December 31, 2017, Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and
Cold Lake oil sands regions of Alberta, Canada. Grizzly has high-graded three oil sands projects to various stages
of development. Grizzly commenced commercial production from its Algar Lake Phase 1 SAGD oil sand project
during the second quarter of 2014 and has regulatory approval for up to 11,300 barrels per day of bitumen
production. Algar Lake production peaked at 2,200 barrels per day during the ramp-up phase of the SAGD
facility, however, in April 2015, Grizzly made the decision to suspend operations at its Algar Lake facility due to
the commodity price drop and its effect on project economics. Grizzly continues to monitor market conditions as
it assesses startup plans for the facility. We reviewed our investment in Grizzly as of September 30, 2015 and
December 31, 2015, and again at March 31, 2016, for impairment, resulting in an aggregate other than temporary
impairment write down of $101.6 million for the year ended December 31, 2015 and $23.1 million for the year
ended December 31, 2016. As of and during the period ended December 31, 2017, commodity prices had
increased as compared to the quarter ended March 31, 2016, and there were no impairment indicators that
required further evaluation for impairment. If commodity prices decline, further impairment of our investment in
Grizzly may result in the future. The Algar Lake and other pending and proposed projects are complex, subject to
extensive governmental regulation and will require significant additional financing. There can be no assurance
that the necessary governmental approvals will be granted or that such financing could be obtained on
commercially reasonable terms or at all, or that if one or more of these projects are completed that they will be
successful or that we realize a return on our investment.
The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or
personnel may restrict our operations.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw
materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and
delivery times of rigs, equipment and supplies increase and demand for and wage rates of qualified drilling rig
crews also rise with increases in demand. In accordance with customary industry practice, we rely on
independent third party service providers to provide most of the services necessary to drill new wells. If we are
unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of
operations could suffer, and we may not be able to drill all of our acreage before our leases expire. Shortages of
drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking
services, tubulars, fracking and completion services and production equipment could delay or restrict our
exploration and development operations, which in turn could impair our financial condition and results of
operations.
Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially
dependent on the availability of water. Restrictions on the ability to obtain water may impact our operations.
Water is an essential component of oil and natural gas production during the drilling, and in particular,
hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water
used in our exploration and production operations, could adversely impact our operations.
We rely on a few key employees whose absence or loss could disrupt our operations resulting in a loss of
revenues.
Many key responsibilities within our business have been assigned to a small number of employees. The loss
of their services, particularly the loss of Michael G. Moore, our Chief Executive Officer and President, or our
other senior management and technical personnel, could disrupt our operations and have a material adverse effect
on our financial condition and results of operations. Our executives are not restricted from competing with us if
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they cease to be employed by us, except under certain limited circumstances prohibiting competition while
making use of our trade secrets. We are party to an employment agreement with certain of our executive officers.
As a practical matter, however, employment agreements may not assure the retention of our employees. Further,
we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured
against any losses resulting from the death of our key employees.
Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production.
There are numerous uncertainties associated with estimating quantities of proved reserves and in projecting
future rates of production and timing of expenditures. The reserve information herein represents estimates
prepared by (i) Netherland, Sewell & Associates, Inc., or NSAI, with respect to our Utica Shale acreage and our
WCBB and Hackberry fields at December 31, 2017, 2016 and 2015, our SCOOP acreage at December 31, 2017
and our Niobrara field at December 31, 2015 and (ii) our personnel with respect to our overriding royalty and
non-operated interests at December 31, 2017, 2016 and 2015 and our Niobrara field at December 31, 2017 and
2016. Petroleum engineering is not an exact science. Information relating to our proved oil and natural gas
reserves is based upon engineering estimates. Estimates of economically recoverable oil and natural gas reserves
and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as
historical production from the area compared with production from other producing areas, future site restoration
and abandonment costs, the assumed effects of regulations by governmental agencies and assumptions
concerning future oil and natural gas prices, future operating costs, severance and excise taxes, capital
expenditures and workover and remedial costs, all of which may in fact vary considerably from actual results.
For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any
particular group of properties, classifications of such reserves based on risk of recovery and estimates of the
future net cash flows expected therefrom prepared by different engineers or by the same engineers at different
times may vary substantially. Actual production, revenues and expenditures with respect to our reserves will
likely vary from estimates, and such variances may be material.
Estimates of reserves as of year-end 2017, 2016 and 2015 were prepared using an average price equal to the
unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each
month within the 12-month period ended December 31, 2017, 2016 and 2015, respectively, in accordance with
the revised guidelines of the SEC applicable to reserves estimates for such years. Reserve estimates do not
include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped
acreage. The reserve estimates represent our net revenue interest in our properties.
The present value of future net revenues from our proved reserves is not necessarily the same as the current
market value of our estimated oil and natural gas reserves. We base the estimated discounted future net revenue
from our proved reserves for 2017, 2016 and 2015 on an average price equal to the unweighted arithmetic
average of prices received on a field-by-field basis on the first day of each month within the 12-month period
ended December 31, 2017, 2016 and 2015, respectively, in accordance with the revised guidelines of the SEC
applicable to reserves estimates for such years.
Actual future net revenues from our oil and natural gas properties will also be affected by factors such as:
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actual prices we receive for oil and natural gas;
the amount and timing of actual production;
supply of and demand for oil and natural gas; and
changes in governmental regulations or taxation.
The timing of both our production and our incurrence of costs in connection with the development and
production of oil and natural gas properties will affect the timing of actual future net revenues from proved
reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating
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discounted future net cash flows 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 natural gas industry in general.
SEC rules could limit our ability to book additional proved undeveloped reserves in the future.
SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if
they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has
limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our
drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not
drill those wells within the required five-year timeframe, because they have become uneconomic or otherwise.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital
expenditures than we currently anticipate.
Approximately 64.9% of our total estimated proved reserves at December 31, 2017, were proved
undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped
reserves requires significant capital expenditures and successful drilling operations. The reserve data included in
the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are
required to develop such reserves. We cannot be certain that the estimated costs of the development of these
reserves are accurate, that development will occur as scheduled or that the results of such development will be as
estimated. Delays in the development of our reserves, further decreases in commodity prices or increases in costs
to drill and develop such reserves will reduce the future net revenues of our estimated proved undeveloped
reserves and may result in some projects becoming uneconomical. In addition, delays in the development of
reserves could force us to reclassify certain of our proved reserves as unproved reserves.
There are numerous uncertainties in estimating quantities of bitumen reserves and resources in connection
with our equity investment in Grizzly and the indicated level of reserves or recovery of bitumen may not be
realized.
There are numerous uncertainties in estimating quantities of bitumen reserves and resources, and the
indicated level of reserves or recovery of bitumen may not be realized. In general, estimates of economically
recoverable bitumen reserves and the future net cash flow from such reserves are based upon a number of factors
and assumptions made as of the date on which the reserve and resource estimates were determined, such as
geological and engineering estimates which have uncertainties, the assumed effects of regulation by
governmental agencies and estimates of future commodity prices and operating costs, all of which may vary
considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves
are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically
recoverable bitumen, the classification of such reserves based on risk of recovery and estimates of future net
revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may
vary substantially.
Estimates with respect to reserves and resources that may be developed and produced in the future are often
based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual
production history. Estimates based on these methods generally are less reliable than those based on actual
production history. Subsequent evaluation of the same reserves based upon production history may result in
variations in the estimated reserves. Reserve and resource estimates may require revision based on actual
production experience. Reserve and resources estimates are determined with reference to assumed oil prices and
operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of certain grades of
bitumen. The actual gravity or quality of bitumen to be produced from Grizzly’s lands cannot be determined at
this time.
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The marketability of our production is dependent upon compressors, gathering lines, transportation barges
and other facilities, certain of which we do not control. When these facilities are unavailable, our operations
can be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and
capacity of natural gas lines and transportation barges owned by third parties. In general, we do not control these
transportation facilities and our access to them may be limited or denied. A significant disruption in the
availability of these transportation facilities or our compression and other production facilities could adversely
impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant
interruption in our operations. With respect to our Utica Shale acreage where we are focusing a portion of our
exploration and development activity, historically there has been no or only limited infrastructure in this area and
the commencement of production from our initial and subsequent wells on our Utica Shale acreage has been
delayed due to challenges in obtaining rights-of-way and acquiring necessary state and federal permitting and the
completion of facilities by our midstream service provider.
If production from our Utica Shale or SCOOP acreage decreases due to decreased developmental activities,
production related difficulties or otherwise, we may fail to meet our firm commitment delivery obligations
under our firm transportation contracts, which will result in fees and may have a material adverse effect on
our operations.
As of December 31, 2017, we had entered into firm transportation contracts to deliver approximately
1,095,000 MMBtu to 1,245,000 MMBtu per day for 2018 and approximately 1,205,000 MMBtu to 1,405,000
MMBtu per day for 2019 through 2020. See Item 1. “Business-Transportation and Takeaway Capacity.” Under
these firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any
deficiencies in deliveries. If production from our Utica Shale or SCOOP acreage decreases due to decreased
developmental activities, taking into consideration the current low commodity price environment, production
related difficulties or otherwise, we may be unable to meet our obligations under the existing firm transportation
contracts, resulting in fees, which may be significant and may have a material adverse effect on our operations.
Substantially all of our producing properties are located in Eastern Ohio, Oklahoma and Louisiana, making
us vulnerable to risks associated with operating in these regions.
Our largest fields by production are located in Eastern Ohio, Oklahoma and approximately five miles off the
coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. As a result, we may be
disproportionately exposed to the impact of delays or interruptions of production in these geographic regions
caused by weather conditions such as snow, ice, fog, rain, hurricanes or other natural disasters or lack of field
infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage.
We may not be able to obtain and maintain adequate insurance at rates we consider reasonable and it is possible
that certain types of coverage may not be available.
Our identified drilling locations, which are part of our anticipated future drilling plans, are susceptible to
uncertainties that could materially alter the occurrence or timing of their drilling.
We have identified over 1,000 drilling locations on our Ohio, Oklahoma and Louisiana properties assuming
full development of all of our acreage. These drilling locations represent a significant part of our growth strategy.
Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of
capital, oil and natural gas prices, inclement weather, costs, drilling results and regulatory changes. Because of
these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be
drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As
such, our actual drilling activities may materially differ from those presently identified, which could adversely
affect our business.
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Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result
in a total loss of investment and adversely affect our business, financial condition or results of operations.
Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled
by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil
and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are
productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting
drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know
conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The
costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our
control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and
producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other
factors, including:
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unusual or unexpected geological formations;
loss of drilling fluid circulation;
title problems;
facility or equipment malfunctions;
unexpected operational events;
shortages or delivery delays of equipment and services;
compliance with environmental and other governmental requirements; and
adverse weather conditions.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or
destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells
and other regulatory penalties.
Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing
profits.
Our operations are subject to all of the hazards and operating risks associated with drilling for and
production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering,
uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured
formations, casing collapses and environmental hazards such as oil spills, gas leaks, ruptures or discharges of
toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any
mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical
additives. We may face liability for environmental damage caused by previous owners of properties purchased by
us, which liabilities may or may not be covered by insurance. The occurrence of any of these events could result
in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural
resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory
investigations and penalties, suspension of operations and repairs required to resume operations.
In accordance with what we believe to be customary industry practice, we historically have maintained
insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses
or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at
premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess
of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability
insurance could have a material adverse effect on our ability to conduct normal business operations and on our
financial condition, results of operations or cash flow. We may not be able to secure additional insurance or
35
bonding that might be required by new governmental regulations. This may cause us to restrict our operations,
which might severely impact our financial position. A loss not fully covered by insurance could have a material
adverse effect on our financial position, results of operations and cash flows.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health
and safety requirements applicable to our business activities.
We may incur significant delays, costs and liabilities as a result of federal, state and local environmental,
health and safety requirements applicable to our exploration, development and production activities. These laws
and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations
governing our air emissions, water discharges, waste disposal or other environmental impacts associated with
drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling,
fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands
lying within wilderness, wetlands, frontier, seismically active areas and other protected areas; (iv) require
remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or
closing earthen pits; and/or (v) impose substantial liabilities and restrictions on our activities as a result of spills,
pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate
of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to
become increasingly stringent over time. Failure to comply with these laws and regulations may result in the
assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and
liens, the suspension or revocation of necessary permits, licenses and authorizations (which could cause us to
cease operations), the requirement that additional pollution controls be installed and, in some instances, issuance
of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental
laws that impose strict as well as joint and several liability, we may be required to remediate contaminated
properties currently or formerly operated by us or facilities of third parties that received waste generated by our
operations regardless of whether such contamination resulted from the conduct of others or from consequences of
our own actions that were in compliance with all applicable laws at the time those actions were taken. In
addition, claims for damages to persons or property, including natural resources, may result from the
environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted
spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under
applicable laws.
Moreover, public interest in the protection of the environment has tended to increase over time. To the
extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and
costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition
or results of operations could be materially adversely affected.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our
targeted returns.
We acquire significant amounts of unproved property in order to further our development efforts and expect
to continue to undertake acquisitions in the future. Development and exploratory drilling and production
activities are subject to many risks, including the risk that no commercially productive reservoirs will be
discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our
growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be
economically viable or that we will not abandon our investments. Additionally, we cannot assure you that
unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new
wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our
investment in such unproved property or wells.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells
that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other
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costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely
affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result
of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel,
environmental issues and for other reasons. In addition, wells that are profitable may not meet our internal return
targets, which are dependent upon the current and expected future market prices for oil and natural gas, expected
costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. Drilling
results in our newer oil and liquids-rich shale plays may be more uncertain than in shale plays that are more
developed and have longer established production histories, and we can provide no assurance that drilling and
completion techniques that have proven to be successful in other shale formations to maximize recoveries will be
ultimately successful when used in newly developed shale formations.
Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal
drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are
subject to risks associated with drilling and completion techniques and drilling results may not meet our
expectations for reserves or production.
Our operations involve utilizing the latest drilling and completion techniques as developed by us and our
service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the
desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation,
running our casing the entire length of the well bore and being able to run tools and other equipment consistently
through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to,
being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well
bore during completion operations and successfully cleaning out the well bore after completion of the final
fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may
adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations.
Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling,
may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut
in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any
such wells begin producing. The results of our drilling in new or emerging formations are more uncertain initially
than drilling results in areas that are more developed and have a longer history of established production. Newer
or emerging formations and areas often have limited or no production history and consequently we are less able
to predict future drilling results in these areas.
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more
wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results
are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease
expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our
investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these
developments we could incur material write-downs of our oil and natural gas properties and the value of our
undeveloped acreage could decline in the future.
We have been an early entrant into the SCOOP play in Oklahoma. As a result, our drilling results in this area
may vary, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
We have been an early entrant into the SCOOP play in Oklahoma. On February 17, 2017, we completed our
SCOOP acquisition, which included approximately 46,000 net surface acres with multiple producing zones,
including the Woodford and Springer formations in the SCOOP resource play, in Grady, Stephens and Garvin
Counties, Oklahoma. The area was historically developed by vertical wells drilled through multiple stacked
reservoirs; however, the current play represents the transition to mainly horizontal development. As a developing
play, our drilling results in this area are more uncertain than drilling results in areas that are more developed and
have been producing for a longer period of time. Since limited production history from horizontal wells in the
SCOOP exists and since we have limited experience drilling in this play, it is difficult to predict our future
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drilling results. Our cost of drilling, completing and operating wells in this area may be higher than initially
expected, and the value of our undeveloped acreage in the SCOOP may decline if drilling results are
unsuccessful. We cannot assure you that unproved property acquired, or undeveloped acreage leased, by us in the
SCOOP or other emerging plays will be profitably developed, that wells drilled by us in prospects that we pursue
will be productive or that we will recover all or any portion of our investment in such unproved property or wells.
A key part of our strategy involves using some of the latest available horizontal drilling and completion
techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing some of the latest drilling and completion techniques as developed by us
and our service providers. Risks that we face while drilling include, but are not limited to, the following:
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effectively controlling the level of pressure flowing from particular wells;
landing our wellbore in the desired drilling zone;
staying in the desired drilling zone while drilling horizontally through the formation;
running our casing the entire length of the wellbore; and
being able to run tools and other equipment consistently through the horizontal wellbore.
Risks that we face while completing our wells include, but are not limited to, the following:
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the ability to fracture stimulate the planned number of stages;
the ability to run tools the entire length of the wellbore during completion operations; and
the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage
The results of our drilling in new or emerging formations (including the SCOOP) are more uncertain
initially than drilling results in areas that are more developed and have a longer history of established production.
Newer or emerging formations and areas have limited or no production history and, consequently, we are more
limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return
on our investment for a particular project may not be as attractive as we anticipated and we could incur material
write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
We are not the operator of all of our oil and natural gas properties and therefore are not in a position to
control the timing of development efforts, the associated costs or the rate of production of the reserves on such
properties.
We are not the operator of all of the properties in which we have an interest, and have limited ability to
exercise influence over the operations of such non-operated properties or their associated costs. Dependence on
the operator and other working interest owners for these projects, and limited ability to influence operations and
associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities.
The success and timing of development and exploration activities on properties operated by others will depend
upon a number of factors that will be largely outside of our control, including:
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the timing and amount of capital expenditures;
the availability of suitable drilling equipment, production and transportation infrastructure and
qualified operating personnel;
the operator’s expertise and financial resources;
approval of other participants in drilling wells;
selection of technology; and
the rate of production of the reserves.
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In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we
are not willing or able to fund our capital expenditures relating to such projects when required by the majority
owner or operator, our interests in these projects may be reduced or forfeited.
A significant portion of our net leasehold acreage is undeveloped, and that acreage may not ultimately be
developed or become commercially productive, which could cause us to lose rights under our leases as well as
have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our
future cash flow and income.
A significant portion of our net leasehold acreage is undeveloped, or acreage on which wells have not been
drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas
regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases
require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we
could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our
future cash flow and income are highly dependent on successfully developing our undeveloped leasehold
acreage.
Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly
competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial
lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Unless production is established within the spacing units covering the undeveloped acres on which some of
the locations are identified, the leases for such acreage will expire. Approximately 22% of our total Utica Shale
undeveloped acreage will be subject to expiration in 2018, with 8% of such acreage expiring in 2019, 9% in 2020
and 17% thereafter, although our Utica Shale leases generally grant us the right to extend these leases for an
additional five-year period. As of December 31, 2017, leases representing 6%, 67% and 5% respectively, of our
total SCOOP undeveloped acreage are schedule to expire in 2018, 2019 and 2020. As of December 31, 2017,
leases representing 11% and 53%, respectively, of our total Niobrara Formation undeveloped acreage are
scheduled to expire in 2018 and 2019. The cost to renew expiring leases may increase significantly, and we may
not be able to renew such leases on commercially reasonable terms or at all. If we are unable to fund renewals of
expiring leases, we could lose portions of our acreage and our actual drilling activities may differ materially from
our current expectations, which could adversely affect our business.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to
oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand
for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may
have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our operations are subject to various governmental laws and regulations which require compliance that can
be burdensome and expensive and could expose us to significant liabilities.
Our oil and natural gas operations are subject to various federal, state and local governmental regulations
that may be changed from time to time in response to economic and political conditions. Matters subject to
regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the
spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have
imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells
below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling,
storage, transportation, remediation, emission and disposal of oil and natural gas, by-products thereof and other
substances and materials produced or used in connection with oil and natural gas operations are subject to
regulation under federal, state and local laws and regulations, including those relating to protection of human
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health and the environment. Failure to comply with these laws and regulations may result in the assessment of
sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional
pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and
regulations impose increasingly strict requirements for water and air pollution control and solid waste
management, which trend may continue. Significant expenditures may be required to comply with governmental
laws and regulations applicable to us. See Item 1. “Business-Regulation-Environmental Matters and Regulation”
and Item 1. “Business-Regulation-Other Regulation of the Oil and Natural Gas Industry” for a description of
certain laws and regulations that affect us.
Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in
increased costs and additional operating restrictions or delays.
Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons,
particularly natural gas, from tight formations, including shales. We use hydraulic fracturing extensively in
connection with the development and production of certain of our oil and natural gas properties. The process
involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding
rock and stimulate production. There has been increasing public controversy regarding hydraulic fracturing with
regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for
impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement
actions have been initiated across the country implicating hydraulic fracturing practices. The hydraulic fracturing
process is typically regulated by state oil and natural gas commissions. However, legislation has been proposed
in recent sessions of Congress to amend the SDWA to repeal the exemption for hydraulic fracturing from the
definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing,
and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore,
several federal agencies have asserted regulatory authority over certain aspects of the process.
In addition, several states and local jurisdictions in which we operate or hold oil and natural gas interests
have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain
circumstances, impose more stringent operating standards and/or require the disclosure of the composition of
hydraulic fracturing fluids. For a more detailed discussion of federal, state and local laws and initiatives
concerning hydraulic fracturing, see Item 1. “Business-Regulation-Regulation of Hydraulic Fracturing” above.
If new laws or regulations are adopted that significantly restrict hydraulic fracturing, such laws could make
it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as
make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on
allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition,
if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could
become subject to additional permitting and financial assurance requirements, more stringent construction
specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment
requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes
could reduce the volumes of oil and natural gas that we can recover economically and cause us to incur
substantial compliance costs. Reduced production and/or compliance or the consequences of any failure to
comply by us could have a material adverse effect on our financial condition and results of operations.
Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and
production activities, as well as our ability to dispose of produced water gathered from such activities, which
could have a material adverse effect on our business.
State and federal regulatory agencies have recently focused on a possible connection between hydraulic
fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the
increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible
linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in
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some states, including in Oklahoma, alleging that disposal well operations have caused damage to neighboring
properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns,
regulators in some states are seeking to impose additional requirements, including requirements regarding the
permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the
use of such wells.
We dispose of large volumes of produced water gathered from our drilling and production operations in our
Louisiana fields by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing
such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal
requirements are subject to change, which could result in the imposition of more stringent operating constraints
or new monitoring and reporting requirements, owing to, among other things, concerns of the public or
governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any
new laws or regulations that restrict our ability to use hydraulic fracturing or dispose of produced water gathered
from our drilling and production activities by own disposal wells, could have a material adverse effect on our
business, financial condition and results of operations. We do not currently inject produced water in our Utica or
SCOOP operations.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability
to conduct drilling activities in some of the areas where we operate.
Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent
restrictions on drilling activities designed to protect various wildlife species or their habitat. Seasonal restrictions
may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield
equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is
allowed. These constraints and the resulting shortages or high costs could delay our operations and materially
increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered
species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.
The designation of previously unprotected species in areas where we operate as threatened or endangered could
cause us to incur increased costs arising from species protection measures or could result in limitations on our
exploration and production activities that could have an adverse impact on our ability to develop and produce our
reserves.
The adoption of derivatives legislation by the U.S. Congress 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 adoption of derivatives legislation by the U.S. Congress 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 U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR
4173), or Dodd-Frank Act, which, among other provisions, establishes federal oversight and regulation of the
over-the-counter derivatives market and entities that participate in that market. The legislation was signed into
law by the President on July 21, 2010. In its rulemaking under the legislation, the Commodities Futures Trading
Commission, or CFTC, has issued a final rule on position limits for certain futures and option contracts in the
major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide
hedging transactions). The CFTC’s final rule was set aside by the U.S. District Court for the District of Columbia
on September 28, 2012 and remanded to the CFTC to resolve ambiguity as to whether statutory requirements for
such limits to be determined necessary and appropriate were satisfied. As a result, the rule has not yet taken
effect, although the CFTC has indicated that it intends to appeal the court’s decision and that it believes the
Dodd-Frank Act requires it to impose position limits. The impact of such regulations upon our business is not yet
clear. Certain of our hedging and trading activities and those of our counterparties may be subject to the position
limits, which may reduce our ability to enter into hedging transactions.
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In addition, the Dodd-Frank Act does not explicitly exempt end users (such as us) from the requirement to
use cleared exchanges, rather than hedging over-the-counter, and the requirements to post margin in connection
with hedging activities. While it is not possible at this time to predict when the CFTC will finalize certain other
related rules and regulations, the Dodd-Frank Act and related regulations may require us to comply with margin
requirements and with certain clearing and trade-execution requirements in connection with our derivative
activities, although whether these requirements will apply to our business is uncertain at this time. If the
regulations ultimately adopted require that we post margin for our hedging activities or require our counterparties
to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose other
requirements that are more burdensome than current regulations, our hedging would become more expensive and
we may decide to alter our hedging strategy.
The financial reform legislation may also require us to comply with margin requirements and with certain
clearing and trade-execution requirements in connection with our existing or future derivative activities, although
the application of those provisions to us is uncertain at this time. The financial reform legislation may also
require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate
entities, which may not be as creditworthy as the current counterparties. The new legislation and any new
regulations could significantly increase the cost of derivative contracts (including through requirements to post
collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts,
reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or
restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy
counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation and
regulations, 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 expenditures. Finally, the legislation was
intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to
speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could
therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices.
Any of these consequences could have a material adverse effect on our consolidated financial position, results of
operations or cash flows.
Regulation of greenhouse emissions could result in increased operating costs and reduced demand for the oil
and natural gas we produce.
In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse
gases, or GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules for oil
and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce
emissions. Almost one-half of the states have already taken measures to reduce emissions of GHGs primarily
through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. While we
are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not
adversely impacted by existing federal, state and local climate change initiatives. For a description of GHG
existing and proposed rules and regulations, see Item 1. “Business-Regulation-Environmental Regulation-
Climate Change.”
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to
address GHG emissions would impact our business, any such future laws and regulations imposing reporting
obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs
to reduce emissions of GHGs associated with our operations. In addition, substantial limitations on GHG
emissions could adversely affect demand for the oil and natural gas we produce.
In addition, there have also been efforts in recent years to influence the investment community, including
investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil
fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel
reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution
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could interfere with our business activities, operations and ability to access capital. Furthermore, claims have
been made against certain energy companies alleging that GHG emissions from oil and natural gas operations
constitute a public nuisance under federal and/or state common law. As a result, private individuals or public
entities may seek to enforce environmental laws and regulations against us and could allege personal injury,
property damages or other liabilities. While our business is not a party to any such litigation, we could be named
in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our
operations and could have an adverse impact on our financial condition. Moreover, there has been public
discussion that climate change may be associated with extreme weather conditions such as more intense
hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible
consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that
climate change could cause some areas to experience temperatures substantially hotter or colder than their
historical averages. Extreme weather conditions can interfere with our production and increase our costs and
damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to
determine the extent to which climate change may lead to increased storm or weather hazards affecting our
operations.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory
agencies or a change in policy by those agencies may result in increased regulation of our assets, which may
cause our revenues to decline and operating expenses to increase.
Section 1(b) of the Natural Gas Act of 1938, or the NGA, exempts natural gas gathering facilities from
regulation by FERC. We believe that the natural gas pipelines in our gathering systems meet the traditional tests
FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from
FERC’s jurisdiction under the NGA. However, the distinction between FERC-regulated transmission services
and federally unregulated gathering services is a fact-based determination. The classification of facilities as
unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering
facilities are subject to change based on future determinations by FERC, the courts or Congress, which could
cause our revenues to decline and operating expenses to increase and may materially adversely affect our
business, financial condition or results of operations. Additional rules and legislation pertaining to those and
other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations
in the future could subject us to civil penalty liability, which could have a material adverse effect on our
business, financial condition or results of operations.
We face extensive competition in our industry.
The oil and natural gas industry is intensely competitive, and we compete with other companies that have
greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry
on midstream and refining operations and market petroleum and other products on a regional, national or
worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to
withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the
availability of alternative energy sources and the application of government regulation.
The loss of one or more of the purchasers of our production could adversely affect our business, results of
operations, financial condition and cash flows.
The largest purchaser of our oil and natural gas during the year ended December 31, 2017 accounted for
approximately 40% of our total oil, natural gas and NGL revenues. If this purchaser, or one or more other
significant purchasers, are unable to satisfy its contractual obligations, we may be unable to sell such production
to other customers on terms we consider acceptable. Further, the inability of one or more of our customers to pay
amounts owed to us could adversely affect our business, financial condition, results of operations and cash flows.
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Our method of accounting for oil and natural gas properties may result in impairment of asset value.
We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs,
including nonproductive costs and certain general and administrative costs associated with acquisition,
exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to
the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural
gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the
estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-
production method, converting natural gas to barrels at the ratio of six Mcf of natural gas to one barrel of oil.
Companies that use the full cost method of accounting for oil and gas properties are required to perform a
ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties.
Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center
ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per
annum, from proved reserves, based on the 12-month unweighted arithmetic average of the first-day-of-the-
month prices for 2017, 2016 and 2015 adjusted for any contract provisions or financial derivatives, if any, that
hedge oil and natural gas revenue, excluding the estimated abandonment costs for properties with asset
retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and
(c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax
effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book
value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash
writedown is required. A ceiling test impairment can give us a significant loss for a particular period. Once
incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices
increase. As a result of the decline in commodity prices, we recognized a ceiling test impairment of
$715.5 million for the year ended December 31, 2016. If prices of oil, natural gas and natural gas liquids continue
to decrease, we may be required to further write down the value of our oil and natural gas properties. Future non-
cash asset impairments could negatively affect our results of operations.
Recently enacted U.S. tax legislation as well as future U.S. and state tax legislations may adversely affect our
business, results of operations, financial condition and cash flow.
On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform
bill commonly referred to as the Tax Cuts and Jobs Act, or the Tax Act, that significantly reforms the Internal
Revenue Code of 1986, as amended, or the Code. Among other changes, the Tax Act (i) permanently reduces the
U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction
for certain domestic production activities, (iv) imposes new limitations on the utilization of net operating losses,
and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery
rules and to the deductibility of interest expense. The Tax Act is complex and far-reaching, and we cannot predict
with certainty the resulting impact its enactment will have on us. The ultimate impact of the Tax Act may differ
from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory
guidance that may be issued, and any such changes in our interpretations and assumptions could have an adverse
effect on our business, results of operations, financial condition and cash flow.
In addition, from time to time, legislation has been proposed that, if enacted into law, would make
significant changes to U.S. federal and state income tax laws affecting the oil and gas industry. For example,
legislations have been introduced in the past to (i) eliminate the immediate deduction for intangible drilling and
development costs, (ii) repeal of the percentage depletion allowance for oil and natural gas properties; and
(iii) extend the amortization period for certain geological and geophysical expenditures. While these specific
changes are not included in the Tax Act, no accurate prediction can be made as to whether any such legislative
changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date
of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar
changes that would impose additional tax on our activities or reduce or eliminate deductions currently available
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with respect to natural gas and oil exploration, development or similar activities, could adversely affect our
business, results of operations, financial condition and cash flows.
Additional state taxes on natural gas extraction may be imposed as a result of future legislation.
In February 2013, the Governor of the State of Ohio proposed a plan in the Ohio House to enact new
severance taxes on the oil and gas industry. The proposal was part of the state budget bill. Due to pressure from
the State Senate, the proposal was removed from the bill. The bill then passed without the severance tax on
June 7, 2013, with an effective date of July 1, 2013. Later in 2013, the Ohio House introduced a stand-alone bill
to address the severance tax. HB 375 was introduced on December 4, 2013 and after many hearings and
amendments, contained a 2.5% severance tax on horizontal drillers with a percentage of the proceeds earmarked
for affected communities in Southeastern Ohio. This bill passed the Ohio House on May 14, 2014. The Ohio
State Senate held a hearing on the bill, but there was no further movement before the recess of that General
Assembly.
In February 2015, the Governor of Ohio proposed another plan to the new General Assembly to enact new
severance taxes on the oil and gas industry. This proposal was part of a state budget proposal to finance a
reduction in personal income taxes and other initiatives. The proposal would have imposed a 6.5% tax on oil and
gas sold at the wellhead. This severance tax increase was removed from the Bill that was ultimately passed by the
Ohio House.
A new General Assembly took office in January 2017, and the Governor of Ohio proposed a new severance
tax initiative. The proposal would impose a fixed rate of 6.5% for crude oil and natural gas when sold at the
wellhead and a lower rate of 4.5% at later stages of distribution for natural gas and natural gas liquids. The
proposal was again met with opposition and was not included in the final budget that was passed and signed by
the Governor on June 30, 2017 and effective for the period of July 1, 2017 through June 30, 2019.
These proposed changes in the U.S. and applicable state tax law, if adopted, or other similar changes that tax
our production or reduce or eliminate deductions currently available with respect to natural gas and oil
exploration and development, could adversely affect our business, financial condition, results of operations and
cash flows.
Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence
of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only
tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not
enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use
of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling
strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not
be successful or economical.
We are exposed to fluctuations in the price of natural gas and oil. Although we have hedged a portion of our
estimated 2018 production, we may still be adversely affected by continuing and prolonged declines in the
price of natural gas and oil.
We use derivative instruments to reduce price volatility associated with certain of our oil and natural gas
sales, but these hedges may be inadequate to protect us from continuing and prolonged declines in the price of oil
and natural gas. For information regarding these derivative instruments, see Item 7A. “Quantitative and
Qualitative Disclosures about Market Risk.” Such arrangements may expose us to risk of financial loss in certain
circumstances, including instances where production is less than expected or oil and natural gas prices increase.
Further, to the extent that the price of oil and natural gas remains at current levels or declines further, we will not
be able to hedge future production at the same level as our current hedges, and our results of operations and
financial condition would be negatively impacted.
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Our hedging transactions expose us to counterparty credit risk.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a
derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s
liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be
able to realize the benefit of the derivative contract.
A terrorist attack or armed conflict could harm our business.
Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other
countries may adversely affect the United States and global economies and could prevent us from meeting our
financial and other obligations. If any of these events occur, the resulting political instability and societal
disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand
for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct
targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our
customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of
these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Loss of our information and computer systems could adversely affect our business.
We are dependent on our information systems and computer based programs, including our well operations
information, seismic data, electronic data processing and accounting data. If any of such programs or systems
were to fail or create erroneous information in our hardware or software network infrastructure, whether due to
cyber attack or otherwise, possible consequences include our loss of communication links, inability to find,
produce, process and sell oil and natural gas and inability to automatically process commercial transactions or
engage in similar automated or computerized business activities. Any such consequence could have a material
adverse effect on our business.
We are subject to cyber security risks. A cyber incident could occur and result in information theft, data
corruption, operational disruption and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct
certain exploration, development, production, and processing activities. For example, we depend on digital
technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems,
conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the
same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S.
government has issued public warnings that indicate that energy assets might be specific targets of cyber security
threats. Our technologies, systems, networks, and those of its vendors, suppliers and other business partners, may
become the target of cyberattacks or information security breaches that could result in the unauthorized release,
gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of its
business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an
extended period. Our systems and insurance coverage for protecting against cyber security risks may not be
sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue
to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber
incidents.
Risks Relating to Our Indebtedness
Our substantial level of indebtedness could adversely affect our business, financial condition, results of
operations and prospects.
As of December 31, 2017, we had total indebtedness (net of unamortized debt issuance costs) of
approximately $2.0 billion, primarily attributable to our senior notes. We had borrowing base availability of
$759.0 million under our secured revolving credit facility after giving effect to an aggregate of $241.0 million of
letters of credit and no outstanding borrowings.
46
Our outstanding indebtedness could have important consequences to you, including the following:
•
•
•
•
•
•
•
•
our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect
to our indebtedness, and any failure to comply with the obligations under any of our debt instruments,
including restrictive covenants, could result in a default under our secured revolving credit facility or
the senior note indentures;
the restrictions imposed on the operation of our business by the terms of our debt agreements may
hinder our ability to take advantage of strategic opportunities to grow our business;
our ability to obtain additional financing for working capital, capital expenditures, debt service
requirements, restructuring, acquisitions or general corporate purposes may be impaired, which could
be exacerbated by further volatility in the credit markets;
we must use a substantial portion of our cash flow from operations to pay interest on our senior notes
and our other indebtedness, which will reduce the funds available to us for operations and other
purposes;
our level of indebtedness could place us at a competitive disadvantage compared to our competitors
that may have proportionately less debt;
our flexibility in planning for, or reacting to, changes in our business and the industry in which we
operate may be limited;
our high level of indebtedness makes us more vulnerable to economic downturns and adverse
developments in our business; and
we may be vulnerable to interest rate increases, as our borrowings under our secured revolving credit
facility are at variable interest rates.
Any of the foregoing could have a material adverse effect on our business, financial condition, results of
operations and prospects.
In addition, if we are unable to generate sufficient cash flow and are otherwise unable to obtain funds
necessary to meet required payments of principal, premium, if any, or interest on our indebtedness, or if we
otherwise fail to comply with the various covenants, including financial and operating covenants, in the
instruments governing our indebtedness, we could be in default under the terms of the agreements governing
such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the
funds borrowed thereunder to be due and payable, together with accrued and unpaid interest. More specifically,
the lenders under our secured revolving credit facility could elect to terminate their commitments, cease making
further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or
litigation.
Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow
from our business to pay our substantial indebtedness.
Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our
indebtedness, including our senior notes, depends on our future performance, which is subject to economic,
financial, competitive and other factors beyond our control. Our business may not generate cash flow from
operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable
to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying
capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be
onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if
necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have
substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our
debt service and other obligations. Our revolving credit facility and the indentures governing our senior notes
47
restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to
raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate
to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the
capital markets and our financial condition at the time. We may not be able to engage in any of these activities or
engage in these activities on desirable terms, which could result in a default on our debt obligations and have an
adverse effect on our financial condition.
Restrictive covenants in our secured revolving credit facility, the indentures governing our senior notes and in
future debt instruments may restrict our ability to pursue our business strategies.
Our secured revolving credit facility and the indentures governing our senior notes limit, and the terms of
any future indebtedness may limit, our ability, among other things, to:
•
•
•
•
•
•
•
•
•
•
•
incur or guarantee additional indebtedness;
make certain investments;
declare or pay dividends or make distributions on our capital stock;
prepay subordinated indebtedness;
sell assets including capital stock of restricted subsidiaries;
agree to payment restrictions affecting our restricted subsidiaries;
consolidate, merge, sell or otherwise dispose of all or substantially all of our assets;
enter into transactions with our affiliates;
incur liens;
engage in business other than the oil and gas business; and
designate certain of our subsidiaries as unrestricted subsidiaries.
We may be prevented from taking advantage of business opportunities that arise because of the limitations
imposed on us by the restrictive covenants contained in our revolving credit facility and the indentures governing
our senior notes. In addition, our revolving credit facility requires us to maintain certain financial ratios and tests.
The requirement that we comply with these provisions may materially adversely affect our ability to react to
changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future
financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
A breach of any of these restrictive covenants could result in default under our revolving credit facility. If
default occurs, the lenders under our revolving credit facility may elect to declare all borrowings outstanding,
together with accrued interest and other fees, to be immediately due and payable, which would result in an event
of default under the indentures governing our senior notes. The lenders will also have the right in these
circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay
outstanding borrowings when due, the lenders under our revolving credit facility will also have the right to
proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under our revolving
credit facility and our senior notes were to be accelerated, we cannot assure you that our assets would be
sufficient to repay in full that indebtedness.
Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic
borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and
we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result
of a borrowing base redetermination.
Availability under our revolving credit facility is currently subject to a borrowing base of $1.2 billion, with
an elected commitment of $1.0 billion. The borrowing base is subject to scheduled semiannual and other elective
48
collateral borrowing base redeterminations based on our oil and natural gas reserves and other factors. As of
December 31, 2017, we had no borrowings under our revolving credit facility. However, we intend to borrow
under our revolving credit facility in the future. Any significant reduction in our borrowing base as a result of
such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund
our operations and, as a result, may have a material adverse effect on our financial position, results of operation
and cash flow. Further, if the outstanding borrowings under our revolving credit facility were to exceed the
borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not
have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to
negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such
sale could have a material adverse effect on our business and financial results.
We may still be able to incur substantial additional indebtedness in the future, which could further exacerbate
the risks that we and our subsidiaries face.
We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of
our revolving credit facility and the indentures governing our senior notes restrict, but in each case do not
completely prohibit, us from doing so. As of December 31, 2017, our borrowing base under our revolving credit
facility was set at $1.2 billion, with an elected commitment of $1.0 billion, and we had no borrowings
outstanding under this facility. In addition, the indentures governing our senior notes allow us to issue additional
notes under certain circumstances which will also be guaranteed by the guarantors. The indentures governing our
senior notes also allow us to incur certain other additional secured debt and allow us to have subsidiaries that do
not guarantee the senior notes and which may incur additional debt, which would be structurally senior to our
senior notes. In addition, the indentures governing our senior notes do not prevent us from incurring other
liabilities that do not constitute indebtedness. If we or a guarantor incur any additional indebtedness that ranks
equally with our senior notes (or with the guarantees thereof), including additional unsecured indebtedness or
trade payables, the holders of that indebtedness will be entitled to share ratably with holders of our senior notes
in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other
winding-up of us or a guarantor. If new debt or other liabilities are added to our current debt levels, the related
risks that we and our subsidiaries now face could intensify.
Our borrowings under our revolving credit facility expose us to interest rate risk.
Our earnings are exposed to interest rate risk associated with borrowings under our revolving credit facility.
Our revolving credit facility is structured under floating rate terms, as advances under this facility may be in the
form of either base rate loans or eurodollar loans. As such, our interest expense is sensitive to fluctuations in the
prime rates in the U.S. or, if the eurodollar rates are elected, the eurodollar rates. At December 31, 2017, we had
no variable interest rate borrowings outstanding; therefore, an increase in interest rates would not have impacted
our interest expense. However, any increase in our interest rate at the time we do have variable interest rate
borrowings outstanding under our revolving credit facility will increase our costs, which may have a material
adverse effect on our results of operations and financial condition. As of December 31, 2017, we did not hedge
our interest rate risk.
If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our
access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financings and trade credit and the terms of any financings or trade credit are, in part,
dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide
assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not
be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that
may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term
production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing
levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase
our borrowing costs.
49
Risks Related to Our Common Stock
If our quarterly revenues and operating results fluctuate significantly, the price of our common stock may be
volatile.
Our revenues and operating results may in the future vary significantly from quarter to quarter. If our
quarterly results fluctuate, it may cause our stock price to be volatile. We believe that a number of factors could
cause these fluctuations, including:
•
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•
•
•
•
changes in oil and natural gas prices;
changes in production levels;
changes in governmental regulations and taxes;
geopolitical developments;
the level of foreign imports of oil and natural gas; and
conditions in the oil and natural gas industry and the overall economic environment.
Because of the factors listed above, among others, we believe that our quarterly revenues, expenses and
operating results may vary significantly in the future and that period-to-period comparisons of our operating
results are not necessarily meaningful. You should not rely on the results of one quarter as an indication of our
future performance. It is also possible that in some future quarters, our operating results will fall below our
expectations or the expectations of market analysts and investors. If we do not meet these expectations, the price
of our common stock may decline significantly.
We do not currently pay dividends on our common stock and do not anticipate doing so in the future.
We have paid no cash dividends on our common stock, and we may not pay cash dividends on our common
stock in the future. We intend to retain any earnings to fund our operations. Therefore, we do not anticipate
paying any cash dividends on our common stock in the foreseeable future. In addition, the terms of our credit
agreement prohibit the payment of any dividends to the holders of our common stock.
There is no guarantee that we will repurchase shares of our common stock under our recently announced
stock repurchase program at a level anticipated by our stockholders, which could reduce returns to our
stockholders. Decisions to repurchase our common stock will be at the discretion of our board of directors
based upon a review of relevant considerations.
In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0 million
of our outstanding common stock during 2018. The repurchase program does not require us to acquire any
specific number of shares and, as of February 22, 2018, we have not repurchased any shares of our common
stock under our stock repurchase program or otherwise. Our board of director’s determination to repurchase
shares of our common stock will depend upon market conditions, applicable legal requirements, contractual
obligations and other factors that the board of directors deems relevant. Based on an evaluation of these factors,
our board of directors may determine not to repurchase shares or to repurchase shares at reduced levels from
those anticipated by our stockholders, any or all of which could reduce returns to our stockholders.
A change of control could limit our use of net operating losses.
As of December 31, 2017, we had a net operating loss, or NOL, carry forward of approximately
$574.4 million for federal income tax purposes. If we were to experience an “ownership change,” as determined
under Section 382 of the Code, our ability to offset taxable income arising after the ownership change with NOLs
generated prior to the ownership change would be limited, possibly substantially. In general, an ownership
change would establish an annual limitation on the amount of our pre-change NOLs we could utilize to offset our
50
taxable income in any future taxable year to an amount generally equal to the value of our stock immediately
prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change will
occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more
“5% shareholders” (as defined in the Internal Revenue Code) at any time during a rolling three-year period.
Future sales of our common stock may depress our stock price.
We have registered a substantial number of shares of our common stock under a registration statement filed
with the SEC. Sales of these shares of our common stock in the public market or the perception that these sales
may occur, could cause the market price of our common stock to decline. In addition, sales by certain of our
stockholders of their shares could impair our ability to raise capital through the sale of common or preferred
stock. As of February 12, 2018, there were 183,105,910 shares of our common stock issued and outstanding,
excluding 976,027 shares of unvested restricted stock awarded under our Amended and Restated 2005 Stock
Incentive Plan.
We could issue preferred stock which could be entitled to dividend, liquidation and other special rights and
preferences not shared by holders of our common stock or which could have anti-takeover effects.
We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of
preferred stock may be issued from time to time in one or more series as our board of directors, by resolution or
resolutions, may from time to time determine each such series to be distinctively designated. The voting powers,
preferences and relative, participating, optional and other special rights, and the qualifications, limitations or
restrictions, if any, of each such series of preferred stock may differ from those of any and all other series of
preferred stock at any time outstanding, and, subject to certain limitations of our certificate of incorporation and
the Delaware General Corporation Law, or DGCL, our board of directors may fix or alter, by resolution or
resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other
special rights, and qualifications, limitations and restrictions thereof, of each such series preferred stock. The
issuance of any such preferred stock could materially adversely affect the rights of holders of our common stock
and, therefore, could reduce the value of our common stock.
In addition, specific rights granted to future holders of preferred stock could be used to restrict our ability to
merge with, or sell our assets to, a third party. The ability of our board of directors to issue preferred stock could
discourage, delay or prevent a takeover of us, thereby preserving control of the company by the current stockholders.
The existence of some provisions in our organizational documents could delay or prevent a change in
control of our company, even if that change would be beneficial to our stockholders. Our certificate of
incorporation and bylaws contain provisions that may make acquiring control of our company difficult.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
PROPERTIES
Additional information regarding our properties is included in Item 1. “Business” above and in Note 3 of the
notes to our consolidated financial statements included in this report, which information is incorporated herein by
reference.
Proved Oil and Natural Gas Reserves
Evaluation and Review of Reserves.
Reserve estimates at December 31, 2017 were prepared by NSAI with respect to our assets in the Utica
Shale in Eastern Ohio (73% of our proved reserves at December 31, 2017), the SCOOP Woodford and SCOOP
51
Springer plays in Oklahoma which we acquired on February 17, 2017 (27% of our proved reserves at
December 31, 2017) and our WCBB and Hackberry fields (less than 1% of our proved reserves at December 31,
2017). Reserve estimates at December 31, 2016 were prepared by NSAI with respect to our assets in the Utica
Shale in Eastern Ohio and our WCBB and Hackberry fields. Reserve estimates at December 31, 2015 were
prepared by NSAI with respect to our assets in the Utica Shale in Eastern Ohio and our WCBB, Hackberry and
Niobrara fields. Our personnel prepared reserve estimates with respect to our Niobrara field as well as our
overriding royalty and non-operated interests (less than 1% of our proved reserves) at December 31, 2017 and
2016. At December 31, 2015, our personnel prepared reserve estimates with respect to our overriding royalty and
non-operated interests (less than 1% of our proved reserves).
NSAI is an independent petroleum engineering firm. A copy of the summary reserve reports is included as
Exhibit 99.1 to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved
reserve estimates meet the requirements with regards to qualifications, independence, objectivity and
confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not
own an interest in any of our properties and are not employed by us on a contingent basis.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with
NSAI, our independent reserve engineers, to ensure the integrity, accuracy and timeliness of the data used to
calculate our proved reserves relating to our assets in the Utica Shale, SCOOP, WCBB and Hackberry fields. Our
internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and
methods used in the proved reserve estimation process. We provide historical information to NSAI for our
properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and
development costs and other considerations, including availability and costs of infrastructure and status of
permits. Our proved reserves attributable to our other minority interests are prepared internally by our internal
staff of petroleum engineers and geoscience professionals. Our Vice President of Reservoir Engineering is
primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer
with over 35 years of reservoir and operations experience. In addition, our geophysical staff has over 100 years
combined industry experience and our reservoir staff has approximately 50 years combined experience. Our
technical staff uses historical information for our properties such as ownership interest, oil and gas production,
well test data, commodity prices and operating and development costs.
Our proved reserve estimates are prepared in accordance with our internal control procedures. These
procedures, which are intended to ensure reliability of reserve estimations, include the following:
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•
•
•
•
•
•
review and verification of historical production data, which data is based on actual production as
reported by us;
verification of property ownership by our land department;
preparation of reserve estimates by our experienced reservoir engineers or under their direct
supervision;
direct reporting responsibilities by our reservoir engineering department to our Chief Executive
Officer;
review by our reservoir engineering department of all of our reported proved reserves at the close of
each quarter, including the review of all significant reserve changes and all new proved undeveloped
reserves additions;
provision of quarterly updates to our board of directors regarding operational data, including
production, drilling and completion activity levels and any significant changes in our reserves;
annual review by our board of directors of our year-end reserve report and year-over-year changes in
our proved reserves, as well as any changes to our previously adopted development plans;
52
•
•
•
annual review and approval by our senior management and our board of directors of a multi-year
development plan;
annual review by our senior management of adjustments to our previously adopted development plan
and considerations involved in making such adjustments; and
annual review by our board of directors of changes in our previously approved development plan made
by senior management and technical staff during the year, including the substitution, removal or
deferral of PUD locations.
The following table sets forth our estimated proved reserves at December 31, 2017, 2016 and 2015:
Year Ended December 31,
2017
Natural
Gas
(MMcf)
1,616,930
3,208,380
Natural
Gas
Liquids
(MBbls)
36,247
39,519
Oil
(MBbls)
10,245
8,912
2016
Natural
Gas
(MMcf)
Oil
(MBbls)
4,882
664
744,797
1,422,271
Natural
Gas
Liquids
(MBbls)
14,299
5,828
Oil
(MBbls)
6,120
338
2015
Natural
Gas
(MMcf)
652,961
907,184
Natural
Gas
Liquids
(MBbls)
12,910
4,826
Proved developed
Proved undeveloped
Total (1)
19,157
4,825,310
75,766
5,546
2,167,068
20,127
6,458
1,560,145
17,736
Year Ended December 31,
2017
2016
2015
Total net proved oil and natural gas reserves (MMcfe) (1)
5,394,851
2,321,108
1,705,312
PV-10 value (in millions) (2)
Standardized measure (in millions) (3)
$
$
2,883.0
2,643.6
$
$
696.0
688.0
$
$
765.8
764.3
(1) Estimates of reserves as of year-end 2017, 2016 and 2015 were prepared using an average price equal to the
unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of
each month within the 12-month period ended December 31, 2017, 2016 and 2015, respectively, in
accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2017, 2016
and 2015. Reserve estimates do not include any value for probable or possible reserves that may exist, nor
do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest
in our properties. Although we believe these estimates are reasonable, actual future production, cash flows,
taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas
reserves may vary substantially from these estimates.
(2) Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax
of our estimated proven reserves. The estimated future net revenues set forth above were determined by
using reserve quantities of proved reserves and the periods in which they are expected to be developed and
produced based on certain prevailing economic conditions. The estimated future production in our reserve
reports for the years ended December 31, 2017, 2016 and 2015 is priced based on the 12-month unweighted
arithmetic average of the first-day-of-the month price for the period January through December of the
applicable year, using $51.34 per barrel and $2.98 per MMBtu for 2017, $42.75 per barrel and $2.48 per
MMBtu for 2016 and $50.28 per barrel and $2.59 per MMBtu for 2015, and in each case adjusted by lease
for transportation fees and regional price differentials.
PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the
presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because
it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies.
PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered
as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of
PV-10 to the most directly comparable GAAP measure-standardized measure of discounted future net cash
flows.
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The following table reconciles the standardized measure of future net cash flows to the PV-10 value:
Standardized measure of discounted future net cash flows
Add: Present value of future income tax discounted at 10%
$2,643,564
239,468
(In thousands)
$688,040
7,927
$764,331
1,432
PV-10 value
$2,883,032
$695,967
$765,763
December 31,
2017
2016
2015
(3) The standardized measure represents the present value of estimated future cash inflows from proved oil and
natural gas reserves, less future development, abandonment, production, and income tax expenses,
discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions
as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure
includes the effect of future income taxes.
The above table does not include proved reserves net to our interest in Tatex II, Tatex III or Grizzly. For
further discussion of our interest in Tatex II, Tatex III and Grizzly, see Item 1. “Business–Our Equity
Investments.”
As noted above, our December 31, 2017 proved reserves were calculated using prices based on the 12-
month unweighted arithmetic average of the first-day-of-the month price for the period January through
December 2017 of $51.34 per barrel and $2.98 per MMBtu. Holding production and development costs constant,
if our 2017 reserves were calculated using the December 31, 2017 price of $60.42 per barrel and $2.95 per
MMBtu, our discounted future net cash flows before income taxes would have been approximately $3.0 billion,
or $0.1 billion more than our actual PV-10 value of $2.9 billion at December 31, 2017.
The table below provides the 2017 SEC pricing of benchmark prices as well as the unweighted average of
the months ended December 31, 2017 and January 31, 2018:
Henry Hub Natural Gas (per MMBtu)
WTI Crude Oil (per Bbl)
SEC Pricing 2017
2-month Average 2018
$ 2.98
$51.34
$ 2.91
$60.81
The foregoing reserves are all located within the continental United States. Reserve engineering is a
subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be
measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In
addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly,
reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of
economically recoverable oil and natural gas and of future net revenues are based on a number of variables and
assumptions, all of which may vary from actual results, including geologic interpretation, prices and future
production rates and costs. See Item 1A. “Risk Factors” contained elsewhere in this Form 10-K. We have not
filed any estimates of total, proved net oil or gas reserves with any federal authority or agency other than the SEC
since the beginning of our last fiscal year.
54
Changes in Proved Reserves during 2017.
The following table summarizes the changes in our estimated proved reserves during 2017 (in Bcfe):
Proved Reserves, December 31, 2016
Purchases of oil and natural gas reserves in place
Extensions and discoveries
Revisions of prior reserve estimates
Current production
Proved Reserves, December 31, 2017
2,321
1,511
1,629
332
(398)
5,395
Purchases of oil and natural gas reserves in place. These are additions to proved reserves resulting from the
purchases of minerals in place during a period. During 2017, we purchased 1.5 Tcfe of proved oil and natural gas
reserves through our SCOOP acquisition.
Extensions and discoveries. These are additions to our proved reserves that result from (i) extension of the
proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery
and (ii) discovery of new fields with proved reserves or of new reservoirs of proved reserves in existing fields.
Extensions and discoveries of 1.6 Tcfe of proved reserves were attributable to the continued development of our
Utica Shale acreage.
Revisions of prior reserve estimates. Revisions represent changes in previous reserve estimates, either
upward or downward, resulting from new information normally obtained from development drilling and
production history or resulting from a change in economic factors, such as commodity prices, operating costs or
development costs.
Commodity prices increased significantly in 2017. The 12-month average price for natural gas increased
from $2.48 per MMBtu for 2016 to $2.98 per MMBtu for 2017, the 12-month average price for NGLs increased
from $9.91 per barrel for 2016 to $18.40 per barrel for 2017, and the 12-month average price for crude oil
increased from $42.75 per barrel for 2016 to $51.34 per barrel for 2017. We experienced positive revisions of
201.3 Bcfe in estimated proved reserves in 2017 due to an increase in well performance, 214.1 Bcfe due to an
increase in pricing and 95.9 Bcfe due to changes in our ownership interests. These positive revisions were
partially offset by downward revisions of 133.0 Bcfe in estimated proved reserves due to a decline in well
performance specific to one area in our Utica field and a decline of 45.7 Bcfe in estimated proved reserves in
2017 primarily due to the exclusion of ten PUD locations in our Utica field, five of which we operate and five of
which are operated by others operators, that were excluded due to changes in drilling schedules. An additional
downward revision of 0.6 Bcfe was due to two PUD locations in our Southern Louisiana fields that had not been
drilled within five years of initial booking.
Additional information regarding estimates of proved reserves, proved developed reserves and proved
undeveloped reserves at December 31, 2017, 2016 and 2015 and changes in proved reserves during the last three
years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or
Supplemental Information, in Note 18 to our consolidated financial statements included in this report.
Proved Undeveloped Reserves (PUDs)
As of December 31, 2017, our proved undeveloped reserves totaled 8,912 MBbls of oil, 3,208,380 MMcf of
natural gas and 39,519 MBbls of NGLs, for a total of 3,498,965 MMcfe. Approximately 73% and 27% of our
PUDs at year-end 2017 were located in our Utica field and our SCOOP field, respectively. PUDs will be
converted from undeveloped to developed as the applicable wells commence production or there are no material
incremental completion capital expenditures associated with such proved developed reserves.
55
We record PUD reserves only after a development plan has been approved by our senior management and
board of directors to complete the associated development drilling within five years from the time of initial
booking. The PUD locations identified in our development plan are determined based on an analysis of the
information that we have available at that time. After a development plan has been adopted, we may periodically
make adjustments to the approved development plan due to events and circumstances that have occurred
subsequent to the time the plan was approved. These circumstances may include delays in the availability of
infrastructure, well permitting delays, changes in commodity price outlook and costs, and new data from recently
completed wells. During 2017, we did not deviate from our development plan with respect to our PUD locations
booked in our reserve report for the year ended December 31, 2016 and scheduled to be drilled during 2017,
other than to drill 14 additional PUD locations than initially scheduled to be drilled during 2017.
The following table summarizes the changes in our estimated proved undeveloped reserves during 2017 (in
Bcfe):
Proved Undeveloped Reserves, December 31, 2016
Purchases of oil and natural gas reserves in place
Extensions and discoveries
Conversion to proved developed reserves
Revisions of prior reserve estimates
Proved Undeveloped Reserves, December 31, 2017
1,461
947
1,467
(486)
110
3,499
Purchases of oil and natural gas reserves in place. During 2017, we purchased 946.7 Bcfe of proved
undeveloped oil and natural gas reserves through our SCOOP acquisition.
Extensions and discoveries. Our additions of 1.5 Tcfe were primarily attributable to 2017 extensions in our
Utica field.
Conversion to proved developed reserves. We converted approximately 486.2 Bcfe attributable to 76 PUDs
into proved developed reserves and four PUDs into proved developed not producing.
Revision of prior reserve estimates. We experienced positive revisions of 193.9 Bcfe from 92 PUD
locations, of which 95.3 Bcfe was due to an increase in well performance of offset producers, 39.0 Bcfe was a
result of an increase in 2017 prices as compared to 2016 prices and 59.6 Bcfe was due to changes in our
ownership interest. In addition, we also experienced downward revisions of 37.6 Bcfe due to downward
performance revisions on 37 PUD locations. We also experienced downward revisions of 45.7 Bcfe due to
changes in our drilling schedule, including the loss of five locations we operate and five locations operated by
other operators. We also experienced downward revisions of 0.6 Bcfe due to the removal of two PUD locations
in our Southern Louisiana fields that had not been drilled within five years of initial booking.
We drilled approximately 35% of our December 31, 2016 PUD locations during the year ended
December 31, 2017.
Costs incurred relating to the development of PUDs were approximately $386.2 million in 2017. Estimated
future development costs relating to the development of PUDs are projected to be approximately $551.0 million
in 2018, $458.8 million in 2019, $514.5 million in 2020, $842.9 million in 2021 and $400.9 million in 2022.
All PUD drilling locations included in our 2017 reserve report are scheduled to be drilled within five years
of initial booking.
As of December 31, 2017, 3% of our total proved reserves were classified as proved developed non-
producing.
56
As noted above, our December 31, 2017 proved reserves were calculated using prices based on the
12-month unweighted arithmetic average of the first-day-of-the month price for the period January through
December 2017 of $51.34 per barrel and $2.98 per MMBtu. Holding production and development costs constant,
if SEC pricing were $40.00 per barrel and $2.00 per MMBtu, this would have resulted in a loss of 2.9 Tcfe of our
PUD volumes at December 31, 2017. Holding production and development costs constant, if SEC pricing were
$30.00 per barrel and $1.75 per MMBtu, this would have resulted in a loss of 3.4 Tcfe of our PUD volumes at
December 31, 2017.
Production, Prices and Production Costs
The following table presents our production volumes, average prices received and average production costs
during the periods indicated:
Natural gas sales
Natural gas production volumes (MMcf)
Total natural gas sales
Natural gas sales without the impact of derivatives ($/Mcf)
Impact from settled derivatives ($/Mcf)
2017
2016
2015
($ In thousands)
350,061
$ 845,999
2.42
$
0.07
$
227,594
$420,128
1.85
$
0.60
$
156,151
$324,733
2.08
$
0.71
$
Average natural gas sales price, including settled derivatives ($/Mcf)
$
2.49
$
2.45
$
2.79
Oil and condensate sales
Oil and condensate production volumes (MBbls)
Total oil and condensate sales
Oil and condensate sales without the impact of derivatives ($/Bbl)
Impact from settled derivatives ($/Bbl)
Average oil and condensate sales price, including settled derivatives
($/Bbl)
Natural gas liquids sales
Natural gas liquids production volumes (MGal)
Total natural gas liquids sales
Natural gas liquids sales without the impact of derivatives ($/Gal)
Impact from settled derivatives ($/Gal)
Average natural gas liquids sales price, including settled derivatives
($/Gal)
Natural gas, oil and condensate and natural gas liquids sales
Natural gas equivalents (MMcfe)
Total natural gas, oil and condensate and natural gas liquids sales
Natural gas, oil and condensate and natural gas liquids sales without the
impact of derivatives ($/Mcfe)
Impact from settled derivatives ($/Mcfe)
Average natural gas, oil and condensate and natural gas liquids sales
price, including settled derivatives ($/Mcfe)
Production Costs:
Average production costs (per Mcfe)
Average production taxes and midstream costs (per Mcfe)
Total production and midstream costs and production taxes (per Mcfe)
2,579
$ 124,568
48.29
$
1.59
$
2,126
$ 81,173
38.18
$
5.11
$
2,899
$122,615
42.29
$
3.12
$
$
49.88
$
43.29
$
45.41
185,792
161,562
224,038
$ 58,129
$ 59,115
$ 136,057
0.31
0.37
0.61
$
$
$
—
(0.01) $
(0.03) $
$
$
0.58
$
0.36
$
0.31
397,543
$1,106,624
263,430
$560,416
200,089
$505,477
$
$
$
$
$
$
2.78
0.07
2.85
0.20
0.68
0.88
$
$
$
$
$
$
2.13
0.56
2.69
0.26
0.68
0.94
$
$
$
$
$
$
2.53
0.60
3.13
0.35
0.77
1.12
57
The following table provides a summary of our production, average sales prices and average production
costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2017:
Utica Shale
Net Production
Oil (MBbls)
Natural gas (MMcf)
NGL (Mgal)
Total (MMcfe)
Average Sales Price Without the Impact of Derivatives:
Oil (per Bbl)
Natural gas (per Mcf)
NGL (per Gal)
Average Production Cost (per Mcfe)
SCOOP
Net Production
Oil (MBbls)
Natural gas (MMcf)
NGL (Mgal)
Total (MMcfe)
Average Sales Price Without the Impact of Derivatives:
Oil (per Bbl)
Natural gas (per Mcf)
NGL (per Gal)
Average Production Cost (per Mcfe)
Year Ended December 31,
2017
2016
2015
473
309,450
139,634
332,238
870
227,447
161,494
255,740
1,608
155,926
185,753
192,108
$
$
$
$
44.26
2.38
0.60
0.15
$
$
$
$
34.59
1.85
0.37
0.18
$
$
$
$
37.85
2.08
0.31
0.25
Year Ended
December 31,
2017 (1)
1,083
40,501
84,283
59,038
$ 48.70
2.68
$
0.62
$
0.19
$
(1) We acquired our SCOOP assets in our SCOOP acquisition completed on February 17, 2017.
Productive Wells and Acreage
The following table presents our total gross and net productive and non-productive wells, expressed
separately for oil and gas, and the total gross and net developed and undeveloped acres as of December 31, 2017.
NRI/WI (1)
Productive
Oil Wells
Productive
Gas Wells
Non-
Productive
Oil Wells
Non-
Productive
Gas Wells
Developed
Acreage (2)
Undeveloped
Acreage
Field
Percentages Gross Net Gross Net Gross
Net
Gross Net Gross
Net
Gross
Net
42.75/52.07
30.83/38.52
36.15
74
365 109.96
433
45
227.91
35.88
3
25
2.66
14.76
2
12
1.57
10.96
66,133
38,182
55,733 170,826 157,943
12,226
12,226
38,182
80.108/100
82.33/100
E. Hackberry Field (6)
W. Hackberry Field
87.5/100
Niobrara Formation (7) 34.52/48.61
Bakken Formation (8)
1.51/1.83
Overrides/Royalty
Non-operated
Various
86
17
2
3
18
86 —
17 —
2 —
1.46 —
0.3 —
— 146
— 130
—
12
— —
— —
146
16
130 —
12 —
— —
— —
662
0.8 —
— —
— —
16
—
—
—
—
—
5,668
2,910
726
1,460
386
5,668
2,910
726
730
77
—
1,206
306
5,473
3,505
—
1,206
306
2,653
701
—
—
—
—
Total
1,227 253.67
478
263.79
316
305.42
30
28.53 115,465 104,026 193,542 175,035
(1) Net Revenue Interest (NRI)/Working Interest (WI).
58
Utica Shale (3)
SCOOP (4)
West Cote Blanche
Bay Field (5)
(2) Developed acres are acres spaced or assigned to productive wells. Approximately 37% of our acreage is developed acreage and has been
perpetuated by production.
(3) With respect to our total undeveloped Utica Shale acreage as of December 31, 2017, leases representing 22%, 8%, 9% and 17% are
currently scheduled to expire in 2018, 2019, 2020 and thereafter, respectively. Our Utica Shale leases generally grant us the right to
extend these leases for an additional five-year period. NRI/WI is from wells that have been drilled or in which we have elected to
participate. Includes 191 gross (29.15 net) gas wells and 29 gross (3.32 net) oil wells drilled by other operators on our acreage.
(4) With respect to our total undeveloped SCOOP acreage as of December 31, 2017, leases representing 6%, 67% and 5% are currently
scheduled to expire in 2018, 2019 and 2020, respectively. NRI/WI is from wells that have been drilled or in which we have elected to
participate. Includes one gross (.05 net) gas well and 239 gross (8.4 net) oil wells drilled by other operators on our acreage.
(5) We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet.
Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI).
(6) NRI shown is for producing wells.
(7) The leases relating to our Niobrara Formation acreage will expire at the end of their respective primary terms unless the applicable leases
are renewed or extended, we have commenced the necessary operations required by the terms of the applicable leases or we have
obtained actual production from acreage subject to the applicable leases, in which event they will remain in effect until the cessation of
production. Leases representing 11% and 53% of our total Niobrara undeveloped acreage are currently scheduled to expire in 2018 and
2019, respectively.
(8) NRI/WI is from wells that have been drilled or in which we have elected to participate.
Completed and Present Drilling and Recompletion Activities
The following table sets forth information with respect to operated wells completed during the periods
indicated. The information should not be considered indicative of future performance, nor should it be assumed
that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves
found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons,
whether or not they produce a reasonable rate of return.
2017
2016
2015
Gross
Net
Gross
Net
Gross Net
Recompletions:
Productive
Dry
Total
Development:
Productive
Dry
Total
Exploratory:
Productive
Dry
Total
81
—
81
124
2
126
—
—
—
81
77
77
72
72
— — — — —
81
77
77
72
72
115.4
2
117.4
49
1
50
42.5
49
1 — —
38
43.5
49
38
— — — — —
— — — — —
— — — — —
Title to Oil and Natural Gas Properties
It is customary in the oil and natural gas industry to make only a cursory review of title to undeveloped oil
and natural gas leases at the time they are acquired and to obtain more extensive title examinations when
acquiring producing properties. In future acquisitions, we will conduct title examinations on material portions of
such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas
properties may be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of
which, in management’s opinion, will in the aggregate materially restrict our operations.
ITEM 3. LEGAL PROCEEDINGS
In two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the
38th Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of
59
Louisiana and the District Attorney for the 15th Judicial District of the State of Louisiana in the 15th Judicial
District Court for the Parish of Vermilion on July 29, 2016, we were named as a defendant, among 26 oil and gas
companies, in the Cameron Parish complaint and among more than 40 oil and gas companies in the Vermilion
Parish complaint, or the Complaints. The Complaints were filed under the State and Local Coastal Resources
Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted thereunder,
which we referred to collectively as the CZM Laws, and allege that certain of the defendants’ oil and gas
exploration, production and transportation operations associated with the development of the East Hackberry and
West Hackberry oil and gas fields, in the case of the Cameron Parish complaint, and the Tigre Lagoon oil and gas
field, in the case of the Vermilion Parish complaint, were conducted in violation of the CZM Laws. The
Complaints allege that such activities caused substantial damage to land and waterbodies located in the coastal
zone of the relevant Parish, including due to defendants’ design, construction and use of waste pits and the
alleged failure to properly close the waste pits and to clear, re-vegetate, detoxify and return the property affected
to its original condition, as well as the defendants’ alleged discharge of waste into the coastal zone. The
Complaints also allege that the defendants’ oil and gas activities have resulted in the dredging of numerous
canals, which had a direct and significant impact on the state coastal waters within the relevant Parish and that
the defendants, among other things, failed to design, construct and maintain these canals using the best practical
techniques to prevent bank slumping, erosion and saltwater intrusion and to minimize the potential for inland
movement of storm-generated surges, which activities allegedly have resulted in the erosion of marshes and the
degradation of terrestrial and aquatic life therein. The Complaints also allege that the defendants failed to
re-vegetate, refill, clean, detoxify and otherwise restore these canals to their original condition. In these two
petitions, the plaintiffs seek damages and other appropriate relief under the CZM Laws, including the payment of
costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal zone of the relevant
Parish to its original condition, actual restoration of such coastal zone to its original condition, and the payment
of reasonable attorney fees and legal expenses and pre-judgment and post judgment interest.
We were served with the Cameron complaint in early May 2016 and with the Vermilion Complaint in early
September 2016. The Louisiana Attorney General and the Louisiana Department of Natural Resources intervened
in both the Cameron Parish suit and the Vermilion Parish suit. Shortly after the Complaints were filed, certain
defendants removed the cases to the lawsuit to the United States District Court for the Western District of
Louisiana. In both cases, the plaintiffs have filed a motion to remand and the plaintiffs agreed to an extension of
time for all defendants to file responsive pleadings until the District Courts ruled on the motions to remand. In
the Vermilion Parish case, the District Court entered an order on September 26, 2017 remanding the lawsuit to
the 15th Judicial District Court, State of Louisiana, Parish of Vermilion. In the Cameron Parish lawsuit, the
federal magistrate, on January 18, 2018, issued a report and recommendation that the Cameron Parish lawsuit be
remanded to the 38th Judicial District Court, State of Louisiana, Parish of Cameron. It is anticipated that one or
more of the defendants will object to the magistrate’s report and recommendation, in which case the report and
recommendation will be reviewed by the District Court after additional briefing by the parties. Due the
procedural posture of lawsuits, the fact that responsive pleadings have not been filed and the fact that the parties
have not begun discovery, we have not had the opportunity to evaluate the applicability of the allegations made
in plaintiffs’ complaints to our operations and management cannot determine the amount of loss, if any, that may
result.
In addition, due to the nature of our business, we are, from time to time, involved in routine litigation or
subject to disputes or claims related to our business activities, including workers’ compensation claims and
employment related disputes. In the opinion of our management, none of the pending litigation, disputes or
claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows
or results of operations.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
60
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Price Range of Common Stock
Our common stock is quoted on the Nasdaq Global Select Market under the symbol “GPOR.” The following
table sets forth the high and low sale prices of our common stock for the periods presented:
2016
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2017
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Price Range of
Common Stock
High
Low
$31.05
34.67
32.50
30.47
$22.35
17.82
15.09
15.08
$21.00
26.00
25.34
21.30
$15.66
12.47
10.90
11.73
Unregistered Sales of Equity Securities and Use of Proceeds
None.
Repurchases of Equity Securities
In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0 million
of our outstanding common stock during 2018. Purchases under the repurchase program may be made from time
to time in open market or privately negotiated transactions, and will be subject to market conditions, applicable
legal requirements, contractual obligations and other factors. The repurchase program does not require us to
acquire any specific number of shares. We intend to purchase shares under the repurchase program
opportunistically while maintaining sufficient liquidity to fund our 2018 capital development program. This
repurchase program is authorized to extend through December 31, 2018 and may be suspended from time to
time, modified, extended or discontinued by our board of directors at any time. We have not made any purchases
of our common stock as of February 22, 2018.
Holders of Record
At the close of business on February 14, 2018, there were 349 stockholders of record holding 183,105,910
shares of our outstanding common stock. There were approximately 22,941 beneficial owners of our common
stock as of February 14, 2018.
Dividend Policy
We have never paid dividends on our common stock. We currently intend to retain all earnings to fund our
operations. Therefore, we do not intend to pay any cash dividends on the common stock in the foreseeable future.
In addition, the terms of our credit facility restrict the payment of any dividends to the holders of our common
stock.
61
ITEM 6.
SELECTED FINANCIAL DATA
You should read the following selected consolidated financial data in conjunction with Item 7.
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated
financial statements and the related notes appearing elsewhere in this report. The selected consolidated
statements of operations data for the fiscal years ended December 31, 2017, December 31, 2016 and
December 31, 2015 and the selected consolidated balance sheet data at December 31, 2017 and December 31,
2016 are derived from our audited consolidated financial statements appearing elsewhere in this report. The
selected consolidated statements of operations data for the fiscal years ended December 31, 2014 and
December 31, 2013 and the selected consolidated balance sheet data at December 31, 2015, December 31, 2014
and December 31, 2013 are derived from our audited consolidated financial statements that are not included in
this report. The historical data presented below is not indicative of future results. We did not pay any cash
dividends on our common stock during any of the periods set forth in the following table.
Selected Consolidated Statements of Operations
Data:
Revenues
Costs and expenses:
Lease operating expenses
Production taxes
Midstream gathering and processing
Depreciation, depletion and amortization
Impairment of oil and natural gas properties
General and administrative
Accretion expense
Acquisition expense
(Gain) loss on sale of assets
Income (Loss) from Operations
Other (Income) Expense:
Interest expense
Interest income
Litigation settlement
Insurance proceeds
Loss on debt extinguishment
Gain on contribution of investments
Loss (income) from equity method investments
Other (income) expense
Fiscal Year Ended December 31,
2017
2016
2015
2014
2013
(In thousands, except share data)
$1,320,303 $ 385,910 $
708,990 $ 670,762 $ 262,225
80,246
21,126
248,995
364,629
—
52,938
1,611
2,392
—
68,877
13,276
165,972
245,974
715,495
43,409
1,057
—
—
69,475
14,740
138,590
337,694
1,440,418
41,967
820
—
—
52,191
24,006
64,467
265,431
—
38,290
761
—
(11)
26,703
26,933
11,030
118,880
—
22,519
717
—
508
771,937 1,254,060
2,043,704
445,135
207,290
548,366
(868,150) (1,334,714) 225,627
54,935
108,198
(1,009)
—
—
—
—
5,257
(1,041)
63,530
(1,230)
—
(5,718)
23,776
—
33,985
129
51,221
(643)
—
(10,015)
—
— (84,470)
23,986
(195)
25,500
—
—
17,490
(297)
—
—
—
—
106,093 (139,434) (213,058)
(528)
(504)
(485)
Income (Loss) from Continuing Operations before
Income Taxes
Income Tax Expense (Benefit)
436,961
1,809
(982,622) (1,480,885) 400,744
(256,001) 153,341
(2,913)
251,328
98,136
Income (Loss) from Continuing Operations
435,152
(979,709) (1,224,884) 247,403
153,192
111,405
114,472
146,171 (175,117) (196,393)
Net Income (Loss) Available to Common
Stockholders
Net Income (Loss) Per Common Share - Basic:
Net Income (Loss) Per Common Share - Diluted:
$ 435,152 $ (979,709)$(1,224,884)$ 247,403 $ 153,192
2.42 $
(7.97)$
(12.27)$
2.90 $
2.41 $
(7.97)$
(12.27)$
2.88 $
1.98
1.97
$
$
62
Selected Consolidated Balance Sheet
Data:
Total assets
Total debt, including current maturity
Total liabilities
Stockholders’ equity
2017
2016
2015
2014
2013
At December 31,
(In thousands)
$5,807,752
$2,038,943
$2,706,138
$3,101,614
$4,223,145
$1,593,875
$2,039,253
$2,183,892
$3,334,734
$ 946,263
$1,295,897
$2,038,837
$3,619,473
$ 703,564
$1,323,177
$2,296,296
$2,685,039
$ 291,090
$ 634,801
$2,050,238
63
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the consolidated financial
statements and related notes included elsewhere in this Annual Report on Form 10-K. This discussion contains
forward-looking statements reflecting our current expectations, estimates and assumptions concerning events
and financial trends that may affect our future operating results or financial position. Actual results and the
timing of events may differ materially from those contained in these forward-looking statements due to a number
of factors, including those discussed in Item 1A. “Risk Factors” and the section entitled “Cautionary Note
Regarding Forward-Looking Statements” appearing elsewhere in this Annual Report on Form 10-K.
Overview
We are an independent oil and natural gas exploration and production company focused on the exploration,
exploitation, acquisition and production of natural gas, natural gas liquids and crude oil in the United States. Our
principal properties are located in the Utica Shale primarily in Eastern Ohio and the SCOOP Woodford and
SCOOP Springer plans in Oklahoma. In addition, among other interests, we hold an acreage position along the
Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields, an acreage position in the
Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, and an approximate
25.1% equity interest in Mammoth Energy Services, Inc., or Mammoth Energy, an oil field services company
listed on the Nasdaq Global Select Market (TUSK).
Prices for oil and natural gas have historically been volatile and subject to significant fluctuation in response
to changes in supply and demand, market uncertainty and a variety of other factors beyond our control. During
the last three years, particularly in light of the continued downturn in commodity prices, we focused on
operational efficiencies in an effort to reduce our overall well costs and deliver better results in a more
economical manner, all while growing our production base each year. In 2017, an increase in commodity prices
allowed us to increase our capital budget as compared to 2016 and position us well to navigate the current
commodity price environment. In response to current declining forward natural gas prices, we are focused on
delivering growth within cash flow by exercising strict capital discipline and currently expect to reduce our
planned capital expenditures by approximately 23% as compared to 2017.
2017 and 2018 Year to Date Highlights
•
Production increased 51% to approximately 397,543 MMcfe for the year ended December 31, 2017
from approximately 263,430 MMcfe for the year ended December 31, 2016.
• On February 17, 2017, we, through our wholly-owned subsidiary Gulfport MidCon LLC, or Gulfport
MidCon (formerly known as SCOOP Acquisition Company, LLC), completed our acquisition, which
we refer to as our SCOOP acquisition, of certain assets from Vitruvian II Woodford, LLC, an unrelated
third-party seller, for a total purchase price of approximately $1.85 billion, consisting of $1.35 billion
in cash, subject to certain adjustments, and approximately 23.9 million shares of our common stock (of
which approximately 5.2 million shares were placed in an indemnity escrow). Our SCOOP acquisition
included approximately 46,000 net surface acres with multiple producing zones, including the
Woodford and Springer formations in the South Central Oklahoma Oil Province, or SCOOP, resource
play, in Grady, Stephens and Garvin Counties, Oklahoma.
• On June 5, 2017, we acquired approximately 2.0 million shares of Mammoth Energy common stock in
connection with our contribution of all of our membership interests in Sturgeon Acquisitions LLC,
Stingray Energy Services LLC and Stingray Cementing LLC, which we refer to as Sturgeon, Stingray
Energy and Stingray Cementing, respectively, bringing our equity interest in Mammoth Energy to
approximately 25.1%.
• During 2017, we spud 126 gross (117.4 net) wells, turned to sales 81 gross (72.1 net) operated wells,
participated in an additional 57 gross (9.4 net) wells that were drilled by other operators on our Utica
64
Shale and SCOOP acreage and recompleted 81 gross and net wells in our Southern Louisiana fields. Of
our 126 new wells spud during 2017, 50 were completed as producing wells, two were non-productive
and, at year end, 66 were in various stages of completion and eight were drilling.
• Oil and natural gas revenues, before the impact of derivatives, increased 97% to $1.1 billion for the
year ended December 31, 2017 from $560.4 million for the year ended December 31, 2016.
• During the year ended December 31, 2017, we reduced our unit lease operating expense by 23% to
$0.20 per Mcfe from $0.26 per Mcfe during the year ended December 31, 2016.
• During the year ended December 31, 2017, we reduced our unit general and administrative expense by
19% to $0.13 per Mcfe from $0.16 per Mcfe during the year ended December 31, 2016.
• On October 11, 2017, we issued $450.0 million in aggregate principal amount of our 6.375% Senior
Notes due 2026, or the 2026 Notes, to qualified institutional buyers pursuant to Rule 144A under the
Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities
Act. Interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal
amount thereof from October 11, 2017, payable semi-annually on January 15 and July 15 of each year,
commencing on January 15, 2018. The 2026 Notes will mature on January 15, 2026. A portion of the
net proceeds from the issuance of the 2026 Notes was used to repay all of our outstanding borrowings
under our secured revolving credit facility on October 11, 2017 and the balance was used to fund the
remaining outspend related to our 2017 capital development plans.
•
In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0
million of our outstanding common stock during 2018, which we believe underscores the confidence
we have in our business model, financial performance and asset base.
• During 2018 (through February 9, 2018), we spud 12 gross (9.8 net) wells. As of February 9, 2018, six
wells were waiting on completion and six were still being drilled.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon consolidated
financial statements, which have been prepared in accordance with accounting principles generally accepted in
the United States of America, or GAAP. The preparation of these consolidated financial statements requires us to
make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We
have identified certain of these policies as being of particular importance to the portrayal of our financial position
and results of operations and which require the application of significant judgment by our management. We
analyze our estimates including those related to oil and natural gas properties, revenue recognition, income taxes
and commitments and contingencies, and base our estimates on historical experience and various other
assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these
estimates under different assumptions or conditions. We believe the following critical accounting policies affect
our more significant judgments and estimates used in the preparation of our consolidated financial statements:
Oil and Natural Gas Properties. We use the full cost method of accounting for oil and natural gas
operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs
directly associated with acquisition, exploration and development of oil and natural gas properties, are
capitalized. Companies that use the full cost method of accounting for oil and gas properties are required to
perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas
properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the
cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted
at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-
month price for the prior twelve months, adjusted for any contract provisions or financial derivatives, if any, that
hedge our oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset
retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and
65
(c) the lower of cost or market value of unproved properties included in the cost being amortized, including
related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the
net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is
required. Such capitalized costs, including the estimated future development costs and site remediation costs of
proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to
barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon the disposal of oil and
natural gas properties, unless such dispositions significantly alter the relationship between capitalized costs and
proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost
of undeveloped leaseholds and totaled $2.9 billion at December 31, 2017 and $1.6 billion at December 31, 2016.
These costs are reviewed quarterly by management for impairment, with the impairment provision included in
the cost of oil and natural gas properties subject to amortization. Factors considered by management in its
impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas
leases not held by production and available funds for exploration and development.
Ceiling Test. Companies that use the full cost method of accounting for oil and gas properties are required to
perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas
properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the
cost center ceiling (as defined in the preceding paragraph). If the net book value, including related deferred taxes,
exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test impairment can give us a
significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and
gas prices may result in an impairment of oil and gas properties. As a result of the decline in commodity prices,
we recognized a ceiling test impairment of $715.5 million for the year ended December 31, 2016. No ceiling test
impairment was recognized by us for the year ended December 31, 2017. If prices of oil, natural gas and natural
gas liquids decline in the future, we may be required to further write down the value of our oil and natural gas
properties, which could negatively affect our results of operations.
Asset Retirement Obligations. We have obligations to remove equipment and restore land at the end of oil
and gas production operations. Our removal and restoration obligations are primarily associated with plugging
and abandoning wells and associated production facilities.
We account for abandonment and restoration liabilities under FASB ASC 410 which requires us to record a
liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in
the period in which the obligation meets the definition of a liability, which is generally when the asset is placed
into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived
asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the
capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability
or the sale of the well, the liability is reversed. These liability amounts may change because of changes in asset
lives, estimated costs of abandonment or legal or statutory remediation requirements.
The fair value of the liability associated with these retirement obligations is determined using significant
assumptions, including current estimates of the plugging and abandonment or retirement, annual inflation of
these costs, the productive life of the asset and our risk adjusted cost to settle such obligations discounted using
our credit adjusted risk free interest rate. Changes in any of these assumptions can result in significant revisions
to the estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an
offsetting change to the carrying amount of the related long-lived asset, resulting in prospective changes to
depreciation, depletion and amortization expense and accretion of discount. Because of the subjectivity of
assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire
these assets may vary significantly from previous estimates.
Oil and Gas Reserve Quantities. Our estimate of proved reserves is based on the quantities of oil and natural
gas that engineering and geological analysis demonstrate, with reasonable certainty, to be recoverable from
established reservoirs in the future under current operating and economic parameters. Netherland, Sewell &
66
Associates, Inc. and to a lesser extent our personnel have prepared reserve reports of our reserve estimates at
December 31, 2017 on a well-by-well basis for our properties.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment
calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve
estimates. Our reserve estimates and the projected cash flows derived from these reserve estimates have been
prepared in accordance with the guidelines of the Securities and Exchange Commission, or SEC. The accuracy of
our reserve estimates is a function of many factors including the following:
•
•
•
•
the quality and quantity of available data;
the interpretation of that data;
the accuracy of various mandated economic assumptions; and
the judgments of the individuals preparing the estimates.
Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly
from actual results. Therefore, reserve estimates may materially vary from the ultimate quantities of oil and
natural gas eventually recovered.
Income Taxes. We use the asset and liability method of accounting for income taxes, under which deferred
tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the
financial statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and
tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to
the future period when those temporary differences are expected to be recovered or settled. The effect of a
change in tax rates on deferred tax assets and liabilities is recognized in income during the period the rate change
is enacted. Deferred tax assets are recognized in the year in which realization becomes determinable.
Periodically, management performs a forecast of its taxable income to determine whether it is more likely than
not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for
our deferred tax assets is established, if in management’s opinion, it is more likely than not that some portion will
not be realized. At December 31, 2017, a valuation allowance of $298.8 million had been established for the net
deferred tax asset, with the exception of certain NOLs that we expect to realize on a more likely than not basis.
On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act. Further
information on the tax impacts of the Tax Cut and Jobs Act is included in Note 10 of our consolidated financial
statements.
Revenue Recognition. We derive almost all of our revenue from the sale of crude oil and natural gas
produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the
purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the
end of each month, we estimate the amount of production delivered to purchasers that month and the price we
will receive. Variances between our estimated revenue and actual payment received for all prior months are
recorded at the end of the quarter after payment is received. Historically, our actual payments have not
significantly deviated from our accruals.
Investments - Equity Method. Investments in entities greater than 20% and less than 50% and/or investments
in which we have significant influence are accounted for under the equity method. Under the equity method, our
share of investees’ earnings or loss is recognized in the statement of operations.
We review our investments to determine if a loss in value which is other than a temporary decline has
occurred. If such loss has occurred, we recognize an impairment provision. For the years ended December 31,
2016 and 2015, we recognized an impairment loss related to our investment in Grizzly of approximately $23.1
million and $101.6 million, respectively.
67
Commitments and Contingencies. Liabilities for loss contingencies arising from claims, assessments,
litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can
be reasonably estimated. We are involved in certain litigation for which the outcome is uncertain. Changes in the
certainty and the ability to reasonably estimate a loss amount, if any, may result in the recognition and
subsequent payment of legal liabilities.
Derivative Instruments. We seek to reduce our exposure to unfavorable changes in oil, natural gas and
natural gas liquids prices, which are subject to significant and often volatile fluctuation, by entering into over-
the-counter fixed price swaps, basis swaps and various types of option contracts. We follow the provisions of
FASB ASC 815, “Derivatives and Hedging,” as amended. It requires that all derivative instruments be
recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all
derivative instruments using industry-standard models that considered various assumptions including current
market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk,
as well as other relevant economic measures.
The accounting for changes in the fair value of a derivative depends on the intended use of the derivative
and the resulting designation. While we have historically designated derivative instruments as accounting hedges,
effective January 1, 2015, we discontinued hedge accounting prospectively. Our current commodity derivative
instruments are not designated as hedges for accounting purposes. Accordingly, the changes in fair value are
recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives
are included in cash flows from operating activities.
See Item 7. “Commodity Price Risk” for a summary of our derivative instruments in place as of
December 31, 2017.
RESULTS OF OPERATIONS
Results of Operations
The markets for oil and natural gas have historically been, and will continue to be, volatile. Prices for oil
and natural gas may fluctuate in response to relatively minor changes in supply and demand, market uncertainty
and a variety of factors beyond our control.
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The following table presents our production volumes, average prices received and average production costs
during the periods indicated:
Natural gas sales
Natural gas production volumes (MMcf)
Total natural gas sales
Natural gas sales without the impact of derivatives ($/Mcf)
Impact from settled derivatives ($/Mcf)
2017
2016
2015
($ In thousands)
350,061
$ 845,999
2.42
$
0.07
$
227,594
$420,128
1.85
$
0.60
$
156,151
$324,733
2.08
$
0.71
$
Average natural gas sales price, including settled derivatives ($/Mcf)
$
2.49
$
2.45
$
2.79
Oil and condensate sales
Oil and condensate production volumes (MBbls)
Total oil and condensate sales
Oil and condensate sales without the impact of derivatives ($/Bbl)
Impact from settled derivatives ($/Bbl)
Average oil and condensate sales price, including settled derivatives
($/Bbl)
Natural gas liquids sales
Natural gas liquids production volumes (MGal)
Total natural gas liquids sales
Natural gas liquids sales without the impact of derivatives ($/Gal)
Impact from settled derivatives ($/Gal)
Average natural gas liquids sales price, including settled derivatives
($/Gal)
Natural gas, oil and condensate and natural gas liquids sales
Natural gas equivalents (MMcfe)
Total natural gas, oil and condensate and natural gas liquids sales
Natural gas, oil and condensate and natural gas liquids sales without the
impact of derivatives ($/Mcfe)
Impact from settled derivatives ($/Mcfe)
Average natural gas, oil and condensate and natural gas liquids sales
price, including settled derivatives ($/Mcfe)
Production Costs:
Average production costs (per Mcfe)
Average production taxes and midstream costs (per Mcfe)
Total production and midstream costs and production taxes (per Mcfe)
2,579
$ 124,568
48.29
$
1.59
$
2,126
$ 81,173
38.18
$
5.11
$
2,899
$122,615
42.29
$
3.12
$
$
49.88
$
43.29
$
45.41
185,792
161,562
224,038
$ 58,129
$ 59,115
$ 136,057
0.31
0.37
0.61
$
$
$
—
(0.01) $
(0.03) $
$
$
0.58
$
0.36
$
0.31
397,543
$1,106,624
263,430
$560,416
200,089
$505,477
$
$
$
$
$
$
2.78
0.07
2.85
0.20
0.68
0.88
$
$
$
$
$
$
2.13
0.56
2.69
0.26
0.68
0.94
$
$
$
$
$
$
2.53
0.60
3.13
0.35
0.77
1.12
The total volume hedged for 2017, 2016 and 2015 represented approximately 68%, 77% and 46%,
respectively, of our total sales volumes for the applicable year.
From 2016 to 2017, our net equivalent gas production increased 51% from 263,430 MMcfe to 397,543
MMcfe primarily as a result of the continued development of our Utica Shale acreage and the acquisition of our
SCOOP acreage. From 2015 to 2016, our net equivalent gas production increased 32% from 200,089 MMcfe to
263,430 MMcfe primarily as a result of the continued development of our Utica Shale acreage. We currently
estimate that our 2018 production will be between 456,250 and 474,500 MMcfe. However, our actual production
may be different due to changes in our currently anticipated drilling and recompletion activities, changing
economic climate, adverse weather conditions or other unforeseen events. See Item 1A. “Risk Factors.”
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Comparison of the Years Ended December 31, 2017 and December 31, 2016
We reported net income of $435.2 million for the year ended December 31, 2017 as compared to a net loss
of $979.7 million for the year ended December 31, 2016. This increase in period-to-period net income was due
primarily to no impairment charge for the year ended December 31, 2017 as compared to a $715.5 million
impairment of oil and natural gas properties for the year ended December 31, 2016 and a $934.4 million increase
in oil and natural gas revenues, partially offset by an $83.0 million increase in midstream gathering and
processing expenses, a $118.7 million increase in depreciation, depletion and amortization expense and a $44.7
million increase in interest expense for the year ended December 31, 2017, as compared to the year ended
December 31, 2016.
Oil and Natural Gas Revenues. For the year ended December 31, 2017, we reported oil and natural gas
revenues of $1.3 billion as compared to oil and natural gas revenues of $385.9 million during 2016. This $934.4
million, or 242%, increase in revenues was primarily attributable to the following:
• A $388.2 million increase in natural gas and oil sales due to a favorable change in gains and losses
from derivative instruments. Of the total change, $512.1 million was due to favorable changes in the
fair value of our open derivative positions in each period and $123.9 million was due to an unfavorable
change in settlements related to our derivative positions.
• A $425.9 million increase in natural gas sales without the impact of derivatives due to a 54% increase
in natural gas sales volumes and a 31% increase in natural gas market prices.
• A $43.4 million increase in oil and condensate sales without the impact of derivatives due to a 21%
increase in oil and condensate sales volumes and a 26% increase in oil and condensate market prices.
• A $76.9 million increase in natural gas liquids sales without the impact of derivatives due to a 39%
increase in natural gas liquids sales volumes and a 66% increase in natural gas liquids market prices.
Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes increased to
$80.2 million for the year ended December 31, 2017 from $68.9 million for the year ended December 31, 2016.
This increase was mainly the result of an increase in expenses related to supervision and labor, overhead, surface
rentals, water hauling and treatment, chemicals, ad valorem taxes and road, location and equipment repairs,
partially offset by decreases in compression and water disposal. However, due to increased efficiencies and a
51% increase in our production volumes for the year ended December 31, 2017 as compared to the year ended
December 31, 2016, our per unit LOE decreased by 23% from $0.26 per Mcfe to $0.20 per Mcfe.
Production Taxes. Production taxes increased to $21.1 million for the year ended December 31, 2017 from
$13.3 million for 2016. This increase was primarily related to an increase in realized prices and production
volumes.
Midstream Gathering and Processing Expenses. Midstream gathering and processing expenses increased by
$83.0 million to $249.0 million for the year ended December 31, 2017 from $166.0 million for 2016. This
increase was primarily the result of midstream expenses related to our increased production volumes in the Utica
Shale resulting from our 2017 and 2016 drilling activities, as well as production volumes resulting from our
SCOOP acquisition in February 2017.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense
increased to $364.6 million for the year ended December 31, 2017, and consisted of $358.8 million in depletion
of oil and natural gas properties and $5.8 million in depreciation of other property and equipment, as compared to
total DD&A expense of $246.0 million for 2016. This increase was due to an increase in our full cost pool as a
result of our SCOOP acquisition and an increase in our production, partially offset by an increase in our total
proved reserves volume used to calculate our total DD&A expense.
General and Administrative Expenses. Net general and administrative expenses increased to $52.9 million
for the year ended December 31, 2017 from $43.4 million for the year ended December 31, 2016. This
70
$9.5 million increase was due to an increase in salaries and benefits resulting from an increased number of
employees, consulting fees, bank service charges, computer support and franchise taxes, partially offset by a
decrease in employee stock compensation expense and legal fees. However, during the year ended December 31,
2017, we decreased our per unit general and administrative expense by 19% to $0.13 per Mcfe from $0.16 per
Mcfe during the year ended December 31, 2016.
Accretion Expense. Accretion expense increased to $1.6 million for the years ended December 31, 2017
from $1.1 million for the year ended December 31, 2016, primarily as a result of our SCOOP acquisition.
Interest Expense. Interest expense increased to $108.2 million for the year ended December 31, 2017 from
$63.5 million for the year ended December 31, 2016 due primarily to the issuance of $450.0 million of the 2026
Notes in October 2017 and the issuance of $600.0 million of the 2025 Notes in December 2016, partially offset
by our repurchase or redemption of our 7.75% Senior Notes due 2020, which we refer to as the 2020 Notes, of
which $600.0 million in aggregate principal amount was then outstanding, in October 2016 with the net proceeds
from our issuance of $650.0 million of the 2024 Notes. In addition, total weighted debt outstanding under our
revolving credit facility was $119.2 million for the year ended December 31, 2017 as compared to $0.2 million
outstanding under such facility for 2016. Additionally, we capitalized approximately $9.5 million and $8.7
million in interest expense to undeveloped oil and natural gas properties during the years ended December 31,
2017 and December 31, 2016, respectively. This increase in capitalized interest in the 2017 period was primarily
the result of our SCOOP acquisition and the development of this acreage.
Income Taxes. As of December 31, 2017, we had a net operating loss carry forward of approximately $574.4
million, in addition to numerous temporary differences, which gave rise to a net deferred tax asset. Periodically,
management performs a forecast of our taxable income to determine whether it is more likely than not that a
valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our
deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will not
be realized. At December 31, 2017, a valuation allowance of $298.8 million had been provided against the net
deferred tax asset, with the exception of certain state net operating losses that we expect to be able to utilize with
NOL carrybacks. We recognized an income tax expense from continuing operations of $1.8 million for the year
ended December 31, 2017.
Comparison of the Years Ended December 31, 2016 and December 31, 2015
We reported a net loss of $979.7 million for the year ended December 31, 2016 as compared to a net loss of
$1.2 billion for the year ended December 31, 2015. This decrease in period-to-period net loss was due primarily
to a $724.9 million decrease of impairment of oil and natural gas properties, a $91.7 million decrease in
depreciation, depletion and amortization expense and a $72.1 million decrease in loss from equity method
investments, partially offset by a $323.1 million decrease in oil and natural gas revenues, a $27.4 million increase
in midstream gathering and processing expenses, a $23.8 million loss on debt extinguishment and a $253.1
million decrease in income tax benefit for the year ended December 31, 2016, as compared to the year ended
December 31, 2015.
Oil and Gas Revenues. For the year ended December 31, 2016, we reported oil and natural gas revenues of
$385.9 million as compared to oil and natural gas revenues of $709.0 million during 2015. This $323.1 million,
or 46%, decrease in revenues was primarily attributable to the following:
• A $378.0 million decrease in natural gas and oil sales due to an unfavorable change in gains and losses
from derivative instruments. Of the total change, $407.0 million was due to unfavorable changes in the
fair value of our open derivative positions in each period and $29.0 million was due to a favorable
change in settlements related to our derivative positions.
• A $95.4 million increase in natural gas sales without the impact of derivatives due to a 46% increase in
natural gas sales volumes, partially offset by an 11% decrease in natural gas market prices.
71
•
a $41.4 million decrease in oil and condensate sales without the impact of derivatives due to a
27% decrease in oil and condensate sales volumes and a 10% decrease in oil and condensate market
prices.
• A $1.0 million increase in natural gas liquids sales without the impact of derivatives due to a
17% increase in natural gas liquids market prices, partially offset by a 13% decrease in natural gas
liquids sales volumes.
Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes decreased to
$68.9 million for the year ended December 31, 2016 from $69.5 million for the year ended December 31, 2015.
This decrease was mainly the result of a decrease in expenses related to contract labor and field supervision, field
telemetry, facility repairs and maintenance and water disposal, partially offset by increases in water hauling,
compression and ad valorem taxes.
Production Taxes. Production taxes decreased to $13.3 million for the year ended December 31, 2016 from
$14.7 million for 2015. This decrease was primarily related to changes in our product mix and production
location, as well as a decrease in commodity prices.
Midstream Gathering and Processing Expenses. Midstream gathering and processing expenses increased by
$27.4 million to $166.0 million for the year ended December 31, 2016 from $138.6 million for 2015. This
increase was primarily the result of midstream expenses related to our increased production volumes in the Utica
Shale resulting from our 2016 and 2015 drilling activities.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense
decreased to $246.0 million for the year ended December 31, 2016, and consisted of $243.1 million in depletion
of oil and natural gas properties and $2.9 million in depreciation of other property and equipment, as compared to
total DD&A expense of $337.7 million for 2015. This decrease was due to a decrease in our full cost pool as a
result of our 2015 and 2016 ceiling test impairments and an increase in our total proved reserves volume used to
calculate our total DD&A expense, partially offset by an increase in our production.
General and Administrative Expenses. Net general and administrative expenses increased to $43.4 million
for the year ended December 31, 2016 from $42.0 million for the year ended December 31, 2015. This $1.4
million increase was due to an increase in salaries and benefits resulting from an increased number of employees,
increases in fees for tax services, bank service charges, computer support, legal fees and consulting services,
partially offset by a decrease in stock compensation expense.
Accretion Expense. Accretion expense increased to $1.1 million for the year ended December 31, 2016 from
$0.8 million for the year ended December 31, 2015.
Interest Expense. Interest expense increased to $63.5 million for the year ended December 31, 2016 from
$51.2 million for the year ended December 31, 2015 due primarily to the issuance of $350.0 million of 6.625%
Senior Notes due 2023 on April 21, 2015 and the issuance of $600.0 million of the 2025 Notes on December 21,
2016, partially offset by our repurchase or redemption of the 2020 Notes in October 2016 with the net proceeds
from our issuance of $650.0 million of the 2024 Notes. Total weighted debt outstanding under our revolving
credit facility was $0.2 million for the year ended December 31, 2016 as compared to $46.6 million outstanding
under such facility for 2015. Additionally, we capitalized approximately $8.7 million and $13.3 million in
interest expense to undeveloped oil and natural gas properties during the years ended December 31, 2016 and
December 31, 2015, respectively. This decrease in capitalized interest in the 2016 period was the result of
changes to our development plan for our oil and natural gas properties.
Income Taxes. As of December 31, 2016, we had a net operating loss carry forward of approximately
$463.1 million, in addition to numerous temporary differences, which gave rise to a net deferred tax asset.
Periodically, management performs a forecast of our taxable income to determine whether it is more likely than
not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for
72
our deferred tax assets is established if, in management’s opinion, it is more likely than not that some portion will
not be realized. At December 31, 2016, a valuation allowance of $645.8 million was established against the net
deferred tax asset, with the exception of certain state NOL’s and AMT credits that we expect to be able to utilize
with net operating loss carrybacks and tax planning in the amount of $4.7 million. We recognized an income tax
benefit from continuing operations of $2.9 million for the year ended December 31, 2016.
Liquidity and Capital Resources
Overview. Historically, our primary sources of funds have been cash flow from our producing oil and
natural gas properties, borrowings under our credit facility and issuances of equity and debt securities. Our ability
to access any of these sources of funds can be significantly impacted by decreases in oil and natural gas prices or
oil and natural gas production.
Our primary uses of cash are for ongoing business operations, repayments of our debt, capital expenditures,
investments and acquisitions. During 2018, we also intend to purchase shares of our common stock under our
recently announced stock repurchase program opportunistically with available funds while maintaining sufficient
liquidity to fund our 2018 capital development program.
Net cash flow provided by operating activities was $679.9 million for the year ended December 31, 2017 as
compared to net cash flow provided by operating activities of $337.8 million for 2016. This increase was
primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to
a 60% increase in net revenues after giving effect to settled derivative instruments, partially offset by an increase
in our operating expenses.
Net cash flow provided by operating activities was $337.8 million for the year ended December 31, 2016, as
compared to net cash flow provided by operating activities of $322.2 million for 2015. This increase was
primarily the result of an increase in cash receipts from our oil and natural gas purchasers due to
a 13% increase in net revenues after giving effect to settled derivative instruments, partially offset by an increase
in our operating expenses.
Net cash used in investing activities for the year ended December 31, 2017 was $2.3 billion as compared to
$905.6 million for 2016. During the year ended December 31, 2017, we spent $1.1 billion in additions to oil and
natural gas properties, of which $750.6 million was spent on our 2017 drilling and recompletion programs,
$97.4 million was spent on expenses attributable to the wells spud, completed and recompleted during 2016,
$1.5 million was spent on facility enhancements, $4.3 million was spent on plugging costs, $119.8 million was
spent on lease related costs, primarily the acquisition of leases in the Utica Shale and the SCOOP and
$7.2 million was spent on seismic with the remainder attributable mainly to future location development and
capitalized general and administrative expenses. We also spent $1.3 billion to fund the cash portion of the
purchase price for our SCOOP acquisition. In addition, $2.3 million was invested in Grizzly and $46.1 million
was invested in Strike Force, net of distributions. We did not make any material investments in our our other
equity investments during the year ended December 31, 2017. During the year ended December 31, 2017, we
used cash from operations and proceeds from our 2016 equity and debt offerings and our 2017 debt offering for
our investing activities.
Net cash used in investing activities for the year ended December 31, 2016 was $905.6 million as compared
to $1.6 billion for 2015. During the year ended December 31, 2016, we spent $724.9 million in additions to oil
and natural gas properties, of which $346.7 million was spent on our 2016 drilling and recompletion programs,
$145.3 million was spent on expenses attributable to the wells spud, completed and recompleted during 2015,
$4.3 million was spent on facility enhancements, $3.7 million was spent on plugging costs, $154.5 million was
spent on lease related costs, primarily the acquisition of leases in the Utica Shale, with the remainder attributable
mainly to future location development and capitalized general and administrative expenses. In addition,
$15.5 million was invested in Grizzly and $11.0 million was invested in Strike Force. We did not make any
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material investments in our other equity investments during the year ended December 31, 2016. We also received
approximately $45.8 million from the sale of oil and gas properties, primarily the sale of non-producing
leasehold acreage in the non-core area of our Utica acreage, and spent $185.0 million to fund the escrow deposit
for our then pending SCOOP acquisition. During the year ended December 31, 2016, we used cash from
operations and proceeds from our 2015 and 2016 equity and debt offerings for our investing activities.
Net cash provided by financing activities for the year ended December 31, 2017 was $433.0 million as
compared to net cash provided by financing activities of $1.7 billion for 2016. The 2017 amount provided by
financing activities is primarily attributable to the net proceeds of $444.3 million from our 2017 debt offering.
Net cash provided by financing activities for the year ended December 31, 2016 was $1.7 billion as
compared to $1.2 billion for 2015. The 2016 amount provided by financing activities is primarily attributable to
the net proceeds of $1.2 billion from our 2016 debt offerings, partially offset by the repurchase and redemption
of our 2020 Notes, and net proceeds of $1.1 billion from our 2016 equity offerings.
Credit Facility. We have entered into a senior secured revolving credit facility, as amended, with The Bank
of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto.
The credit agreement provides for a maximum facility amount of $1.5 billion and matures on December 13,
2021. As of December 31, 2017, we had a borrowing base of $1.2 billion, with an elected commitment of
$1.0 billion, and no balance outstanding under our revolving credit facility. Total funds available for borrowing,
after giving effect to an aggregate of $241.0 million of letters of credit, were $759.0 million. This facility is
secured by substantially all of our assets. Our wholly-owned subsidiaries guarantee our obligations under our
revolving credit facility.
Advances under our revolving credit facility may be in the form of either base rate loans or eurodollar loans.
The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.50% to 1.50%, plus
(2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly
announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one
month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from
1.50% to 2.50%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the
Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as
administered by ICE Benchmark Administration (or any other person that takes over administration of such rate)
per annum equal to the offered rate on such other page or other service that displays an average London interbank
offered rate as administered by ICE Benchmark Administration (or any other person that takes over the
administration of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for
three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered
Rate” for deposits in U.S. dollars.
Our revolving credit facility contains customary negative covenants including, but not limited to,
restrictions on our and our subsidiaries’ ability to: incur indebtedness; grant liens; pay dividends and make other
restricted payments; make investments; make fundamental changes; enter into swap contracts; dispose of assets;
change the nature of their business; and enter into transactions with their affiliates. The negative covenants are
subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also
contains certain affirmative covenants, including, but not limited to the following financial covenants: (1) the
ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense associated
with swap contracts resulting from ASC 815 and (ii) any cash or non-cash revenue or expense attributable to
minority investment plus without duplication and, in the case of expenses, to the extent deducted from revenues
in determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period,
(b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) for
such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill
impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted in
determining net income under successful efforts accounting, (f) actual cash distributions received from minority
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investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty
events or business interruption, and (h) all reasonable transaction expenses related to dispositions and
acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any
unsuccessful dispositions will be limited to $3.0 million in the aggregate) for a twelve-month period may not be
greater than 4.00 to 1.00; and (2) the ratio of EBITDAX to interest expense for a twelve-month period may not
be less than 3.00 to 1.00. We were in compliance with these financial covenants at December 31, 2017.
Senior Notes. In October 2012, December 2012 and August 2014, we issued an aggregate of $600.0 million
in principal amount of our 7.75% senior notes due 2020 which were subsequently exchanged for substantially
identical senior notes registered under the Securities Act. These senior notes, which were issued under an
indenture among us, our subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, were
treated as a single class of debt securities under the senior note indenture and are referred to collectively as the
2020 Notes. Interest on the 2020 Notes accrued at a rate of 7.75% per annum on the outstanding principal amount
payable semi-annually on May 1 and November 1 of each year. The 2020 Notes were senior unsecured
obligations and ranked equally in the right of payment with all of our other senior indebtedness and were senior
in right of payment to any of our future subordinated indebtedness. We had the option to redeem some or all of
the 2020 Notes at any time on or after November 1, 2016, at the redemption prices listed in the senior note
indenture. Prior to November 1, 2016, we had the option to redeem the 2020 Notes at a price equal to 100% of
the principal amount plus a “make-whole” premium. In addition, prior to November 1, 2015, we had the option
to redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of certain equity
offerings, provided that at least 65% of the aggregate principal amount of the 2020 Notes initially issued
remained outstanding immediately after such redemption.
On October 6, 2016, we commenced a cash tender offer to purchase any and all of the 2020 Notes, which
tender offer expired on October 13, 2016 and settled on October 14, 2016. Holders of the 2020 Notes that were
validly tendered and accepted at or prior to the expiration time of the tender offer, or who delivered the 2020
Notes pursuant to the guaranteed delivery procedures, received total cash consideration of $1,042 per $1,000
principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date. An
aggregate of $403.5 million in principal amount of the 2020 Notes was validly tendered in the tender offer. The
remaining 2020 Notes that were not tendered in the tender offer were redeemed by us. The redemption payment
included approximately $196.5 million in aggregate principal amount at a redemption price of 103.875% of the
principal amount of the redeemed 2020 Notes, plus accrued and unpaid interest thereon to the redemption date.
Upon deposit of the redemption payment with the paying agent on October 14, 2016, the indenture governing the
2020 Notes was fully satisfied and discharged. The cash tender offer for the 2020 Notes and redemption of the
remaining 2020 Notes were funded with the net proceeds from the offering of the 2024 Senior Notes (as
discussed below) and cash on hand.
In April 2015, we issued an aggregate of $350.0 million in principal amount of our 6.625% senior notes due
2023 under a new indenture, dated as of April 21, 2015, among us, our subsidiary guarantors and Wells Fargo
Bank, N.A., as trustee. Interest on these senior notes, which we refer to as the 2023 Notes, accrues at a rate of
6.625% per annum on the outstanding principal amount thereof from April 21, 2015, payable semi-annually on
May 1 and November 1 of each year, commencing on November 1, 2015. The 2023 Notes will mature on May 1,
2023 and are our senior unsecured obligations and rank equally in right of payment with all of our other senior
indebtedness, including the 2020 Notes, and senior in right of payment to any of our future subordinated
indebtedness. We may redeem some or all of the 2023 Notes at any time on or after May 1, 2018, at the
redemption prices listed in the indenture relating to the 2023 Notes. Prior to May 1, 2018, we may redeem all or a
portion of the 2023 Notes at a price equal to 100% of the principal amount of the 2023 Notes plus a “make-
whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 1,
2018, we may redeem the 2023 Notes in an aggregate principal amount not to exceed 35% of the aggregate
principal amount of the 2023 Notes issued prior to such date at a redemption price of 106.625%, plus accrued and
unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity
offerings.
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On October 14, 2016, we issued the 2024 Notes in aggregate principal amount of $650.0 million. The 2024
Notes were issued under an indenture, dated as of October 14, 2016, among us, the subsidiary guarantors party
thereto and the senior note indenture, to qualified institutional buyers pursuant to Rule 144A under the Securities
Act, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under this
indenture, interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount
thereof from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on
April 15, 2017. The 2024 Notes will mature on October 15, 2024. We received approximately $638.9 million in
net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to purchase the
outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to redeem any of
the 2020 Notes that remained outstanding after the completion of the tender offer.
On December 21, 2016, we issued $600.0 million in aggregate principal amount of 2025 Notes. The 2025
Notes were issued under an indenture, dated as of December 21, 2016, among us, the subsidiary guarantors party
thereto and the senior note indenture, to qualified institutional buyers pursuant to Rule 144A under the Securities
Act of 1933, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under
this indenture, interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal
amount thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year,
commencing on May 15, 2017. The 2025 Notes will mature on May 15, 2025. We received approximately
$584.7 million in net proceeds from the offering of the 2025 Notes, which we used, together with the net
proceeds from our December 2016 offering of common stock and cash on hand, to fund the cash portion of the
purchase price for our acquisition of certain assets of Vitruvian.
On October 11, 2017, we issued $450.0 million in aggregate principal amount of 2026 Notes. The 2026
Notes were issued under an indenture to qualified institutional buyers pursuant to Rule 144A under the Securities
Act, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under this
indenture, interest on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount
thereof from October 11, 2017, payable semi-annually on January 15 and July 15 of each year, commencing on
January 15, 2018. The 2026 Notes will mature on January 15, 2026. We received approximately $444.3 million
in net proceeds from the offering of the 2026 Notes, a portion of which was used to repay all of our outstanding
borrowings under our secured revolving credit facility on October 11, 2017 and the balance was used to fund the
remaining outspend related to our 2017 capital development plans.
All of our existing and future restricted subsidiaries that guarantee our secured revolving credit facility or
certain other debt guarantee the 2023 Notes, 2024 Notes, 2025 Notes and the 2026 Notes, provided, however,
that the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes are not guaranteed by Grizzly Holdings, Inc. and
will not be guaranteed by any of our future unrestricted subsidiaries. The guarantees rank equally in the right of
payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any
future subordinated indebtedness of the subsidiary guarantors. The 2023 Notes, 2024 Notes, 2025 Notes and
2026 Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors’ secured
indebtedness (including all borrowings and other obligations under our amended and restated credit agreement)
to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all
indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2023 Notes, 2024 Notes,
2025 Notes and 2026 Notes.
If we experience a change of control (as defined in the senior note indentures relating to the 2023 Notes,
2024 Notes, 2025 Notes and 2026 Notes), we will be required to make an offer to repurchase the 2023 Notes,
2024 Notes, 2025 Notes and 2026 Notes and at a price equal to 101% of the principal amount thereof, plus
accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use the proceeds
in a manner specified in our senior note indentures, we will be required to use the remaining proceeds to make an
offer to repurchase the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes at a price equal to 100% of the
principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. The senior note
indentures relating to the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes contain certain covenants that,
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subject to certain exceptions and qualifications, among other things, limit our ability and the ability of our
restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay
dividends or make distributions on capital stock, prepay subordinated indebtedness, sell assets including capital
stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate,
merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates,
incur liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as
unrestricted subsidiaries. Under the indenture relating to the 2023 Notes, 2024 Notes, 2025 Notes and
2026 Notes, certain of these covenants are subject to termination upon the occurrence of certain events, including
in the event the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes are ranked as “investment grade” by
Standard & Poor’s and Moody’s.
In connection with the issuance of the 2024 Notes, the 2025 Notes and 2026 Notes, we and our subsidiary
guarantors entered into registration rights agreements, pursuant to which we agreed to file a registration
statement with respect to an offer to exchange the 2024 Notes, the 2025 Notes and the 2026, as applicable, for
new issues of substantially identical debt securities registered under the Securities Act. The exchange offers for
the 2024 Notes and the 2025 Notes were completed on September 13, 2017. On January 18, 2018, we filed a
registration statement on Form S-4 with respect to an offer to exchange the 2026 Notes for substantially identical
debt securities registered under the Securities Act, which registration statement was declared effective by the
SEC on February 12, 2018. We commenced the exchange offer relating to the 2026 notes on February 16, 2018,
which we expect to close in March of 2018.
Construction Loan. On June 4, 2015, we entered into a construction loan agreement, or the construction
loan, with InterBank for the construction of our new corporate headquarters in Oklahoma City, which was
substantially completed in December 2016. The construction loan allows for maximum principal borrowings of
$24.5 million and required us to fund 30% of the cost of the construction before any funds could be drawn, which
occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per
annum and was payable on the last day of the month through May 31, 2017. Monthly interest and principal
payments are due beginning June 30, 2017, with the final payment due June 4, 2025. As of December 31, 2017,
the total borrowings under the construction loan were approximately $23.7 million.
Capital Expenditures. Our recent capital commitments have been primarily for the execution of our drilling
programs, acquisitions in the Utica Shale, our SCOOP acquisition in February 2017 and for investments in
entities that may provide services to facilitate the development of our acreage. Our strategy is to continue to
(1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and
recompletion projects to exploit our existing properties, subject to economic and industry conditions, (2) pursue
acquisition and disposition opportunities and (3) pursue business integration opportunities.
Of our net reserves at December 31, 2017, 64.9% were categorized as proved undeveloped. Our proved
reserves will generally decline as reserves are depleted, except to the extent that we conduct successful
exploration or development activities or acquire properties containing proved developed reserves, or both. To
realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement
activities or use third parties to accomplish those activities.
During 2017, we spud 94 gross (88.7 net) and commenced sales from 68 gross (61.1 net) wells in the
Utica Shale for a total cost of approximately $599.8 million. In addition, 26 gross (8.4 net) wells were drilled and
45 gross (9.3 net) wells were turned to sales by other operators on our Utica Shale acreage during 2017 for a total
cost to us of approximately $114.8 million. We currently expect to drill 36 to 40 gross (26 to 29 net) horizontal
wells and commence sales from 33 to 37 gross (33 to 37 net) horizontal wells on our Utica Shale acreage. As of
February 9, 2018, we had three operated horizontal rigs drilling in the play and expect to release a rig in March of
2018 as our contract expires. We plan to run on average 2.5 operated horizontal rigs in the Utica Shale during
2018. We also anticipate an additional seven to eight net horizontal wells will be drilled, and sales commenced
from nine to ten net horizontal wells, on our Utica Shale acreage by other operators. We currently anticipate our
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2018 capital expenditures to be $425.0 million to $455.0 million related to our operated and non-operated
Utica Shale activities.
During 2017, we spud 19 gross (15.7 net) and commenced sales from 13 gross (11.0 net) wells in the
SCOOP for a total cost of approximately $250.0 million. In addition, 31 gross (0.9 net) wells were drilled and
23 gross (0.8 net) wells were turned to sales by other operators on our SCOOP acreage during 2017 for a total
cost to us of approximately $7.0 million. During 2018, we currently expect to drill 15 to 16 gross (10 to 11 net)
horizontal wells and commence sales from 20 to 22 gross (16 to 18 net) wells on our SCOOP acreage. We also
anticipate four to five net wells will be drilled, and sales commenced from two to three net wells on our SCOOP
acreage by other operators. As of February 9, 2018, we had four operated horizontal drilling rigs in the play and
expect to release two rigs mid-summer 2018 as our contracts expire. We plan to run on average approximately
three operated horizontal rigs in the SCOOP in 2018. We currently expect to spend $185.0 million to $210.0
million related to these activities for our operated and non-operated SCOOP acreage during 2018.
During 2017, we recompleted 60 existing wells and spud ten new wells at our WCBB field and recompleted
20 existing wells and spud five new wells in our Hackberry fields for a total aggregate cost of approximately
$35.1 million. During 2018, we plan to run one completion rig in our Southern Louisiana fields. We currently
expect to spend approximately $20.0 million in 2018 to perform recompletion activities in Southern Louisiana.
During 2017, no new wells were spud on our Niobrara Formation acreage. We do not currently anticipate
any capital expenditures in the Niobrara Formation in 2018.
During the third quarter of 2006, we purchased a 24.9% interest in Grizzly. As of December 31, 2017, our
net investment in Grizzly was approximately $57.6 million. Our capital requirements in 2017 for Grizzly were
approximately $2.3 million. Effective October 5, 2012, Grizzly entered into a $125.0 million revolving credit
facility, of which Grizzly paid the outstanding balance in full in July 2016. Gulfport paid its share of this amount
on June 30, 2016. We do not currently anticipate any material capital expenditures in 2018 related to Grizzly’s
activities.
We had no material capital expenditures during the during the year ended December 31, 2017 related to our
interests in Thailand. We do not currently anticipate any capital expenditures in Thailand in 2017.
In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in
entities that can provide services that are required to support our operations. See Item 1. “Business–Our Equity
Investments” and Note 4 to our consolidated financial statements included elsewhere in this report for additional
information regarding these other investments. During the years ended December 31, 2017 and 2016, we did not
make any additional investments in these entities, and we do not currently anticipate any capital expenditures
related to these entities in 2018. In the fourth quarter of 2014, we contributed our investments in Stingray
Pressure, Stingray Logistics, Bison and Muskie to Mammoth, in exchange for a 30.5% limited partner interest in
this newly formed limited partnership. On October 19, 2016, Mammoth Energy completed its IPO of
7,750,000 shares of its common stock at a public offering price of $15.00 per share, of which 7,500,000 shares
were sold by Mammoth Energy and 250,000 shares were sold by certain selling stockholders, including 76,250
shares sold by us for which we received net proceeds of $1.1 million. Prior to the completion of the IPO, we were
issued 9,150,000 shares of Mammoth Energy common stock in return for the contribution of our 30.5% interest
in Mammoth. Following the IPO, we owned an approximate 24.2% interest in Mammoth Energy. On June 5,
2017, we acquired approximately 2.0 million shares of Mammoth Energy common stock in connection with our
contribution of all of our membership interests in Sturgeon, Stingray Energy and Stingray Cementing, bringing
our equity interest in Mammoth Energy to approximately 25.1%.
In February 2016, we, through our wholly-owned subsidiary Midstream Holdings, entered into an
agreement with Rice to develop natural gas gathering assets in eastern Belmont County and Monroe County,
Ohio, which we refer to as the dedicated areas, through an entity called Strike Force. We own a 25% interest in
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Strike Force, and EQT, following its acquisition of Rice, acts as operator and owns the remaining 75% interest in
Strike Force. Construction of the gathering assets, which is ongoing, provides gathering services for wells
operated by Gulfport and other operators and connectivity of existing dry gas gathering systems. First flow for
Strike Force commenced on February 1, 2016. In connection with the formation of Strike Force, we contributed
certain assets, including an approximately 11 mile-long, 12-inch diameter gathering line in 2016. During the year
ended December 31, 2017, we paid $46.1 million in net cash calls related to Strike Force.
We currently expect to spend an aggregate of $140.0 million to $150.0 million in 2018 for non-drilling and
completion activities, which includes acreage expenses, primarily lease extensions in the Utica Shale, and net
cash contributions to Strike Force in 2018.
During 2015 and 2016, we continued to focus on operational efficiencies in an effort to reduce our overall
well costs and deliver better results in a more economical manner, particularly in light of the continued downturn
in commodity prices. We have successfully leveraged the lower commodity price environment to gain access to
higher-quality equipment and superior services for reduced costs, which has contributed to increased
productivity. In 2017, an increase in commodity prices allowed us to increase our capital budget as compared to
2016 and the resulting 2017 development activities enabled us to reach a size and scale, both financially and
operationally, where we can navigate the current commodity price environment and adjust our business model
accordingly. In response to current declining forward natural gas prices, we are focused on delivering growth
within cash flow by exercising strict capital discipline and, as such, currently expect to reduce our planned
capital expenditures by approximately 23% as compared to 2017.
Our total capital expenditures for 2018 are currently estimated to be in the range of $630.0 million to
$685.0 million for drilling and completion expenditures. In addition, we currently expect to spend $140.0 million
to $150.0 million in 2018 for non-drilling and completion expenditures, which includes acreage expenses,
primarily lease extensions in the Utica Shale, and funding of our investment in Strike Force. Approximately 70%
of our 2018 estimated drilling and completion capital expenditures are currently expected to be spent in the Utica
Shale. The 2018 range of capital expenditures is lower than the $1.2 billion spent in 2017, primarily due to the
decrease in current commodity prices, specifically natural gas prices, and our desire to fund our capital
development program within cash flow.
In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0 million
of our outstanding common stock during 2018. We intend to purchase shares under the repurchase program
opportunistically with available funds while maintaining sufficient liquidity to fund our 2018 capital
development program.
We continually monitor market conditions and are prepared to adjust our drilling program if commodity
prices dictate. Currently, we believe that our cash flow from operations, cash on hand and borrowings under our
loan agreements will be sufficient to meet our normal recurring operating needs and capital requirements for the
next twelve months, including the operations related to our pending acquisition. We believe that our strong
liquidity position, hedge portfolio and conservative balance sheet position us well to react quickly to changing
commodity prices and accelerate or decelerate our activity within the Utica Basin and the SCOOP as the market
conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels,
our capital or other costs increase, our equity investments require additional contributions and/or we pursue
additional equity method investments or acquisitions, we may be required to obtain additional funds which we
would seek to do through traditional borrowings, offerings of debt or equity securities or other means, including
the sale of assets. We regularly evaluate new acquisition opportunities. Needed capital may not be available to us
on acceptable terms or at all. Further, if we are unable to obtain funds when needed or on acceptable terms, we
may be required to delay or curtail implementation of our business plan or not be able to complete acquisitions
that may be favorable to us. If the current low commodity price environment worsens, our revenues, cash flows,
results of operations, liquidity and reserves may be materially and adversely affected.
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Commodity Price Risk
The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price
movements with any certainty. During 2016, WTI prices ranged from $26.19 to $54.01 per barrel and the
Henry Hub spot market price of natural gas ranged from $1.49 to $3.80 per MMBtu. During 2017, WTI prices
ranged from $42.48 to $60.46 per barrel and the Henry Hub spot market price of natural gas ranged from $2.44 to
$3.71 per MMBtu. If the prices of oil and natural gas continue at current levels or decline further, our operations,
financial condition and level of expenditures for the development of our oil and natural gas reserves may be
materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and
natural gas that we can produce economically. This may result in our having to make substantial downward
adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our
exploration or development activities are curtailed, full cost accounting rules may require us to write down, as a
non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions in our reserves
could also negatively impact the borrowing base under our revolving credit facility, which could further limit our
liquidity and ability to conduct additional exploration and development activities.
See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” for information regarding our
open fixed price swaps at December 31, 2017.
Commitments
In connection with our acquisition in 1997 of the remaining 50% interest in the WCBB properties, we
assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per month through March 2004,
to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells per year for 20 years
commencing March 11, 1997. Chevron retained a security interest in production from these properties until
abandonment obligations to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in
plugging and abandonment charges associated with the property. As of December 31, 2017, the plugging and
abandonment trust totaled approximately $3.1 million. At December 31, 2017, we have plugged 551 wells at
WCBB since we began our plugging program in 1997, which management believes fulfills our current minimum
plugging obligation.
In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0 million
of our outstanding common stock during 2018. Purchases under the repurchase program may be made from time
to time in open market or privately negotiated transactions, and will be subject to market conditions, applicable
legal requirements, contractual obligations and other factors. The repurchase program does not require us to
acquire any specific number of shares. We intend to purchase shares under the repurchase program
opportunistically with available funds while maintaining sufficient liquidity to fund our 2018 capital
development program. This repurchase program is authorized to extend through December 31, 2018 and may be
suspended from time to time, modified, extended or discontinued by our board of directors at any time. We did
not make any purchases of our common stock during the three months ended December 31, 2016 under any stock
repurchase program or otherwise, and have not made any such purchases of our common stock as of February 22,
2018.
80
Contractual and Commercial Obligations
The following table sets forth our contractual and commercial obligations at December 31, 2017:
Payment due by period
Contractual Obligations
Total
Less than 1 year
1-3 years
3-5 years
6.625% senior unsecured notes due 2023 (1)
6.000% senior unsecured notes due 2024 (2)
6.375% senior unsecured notes due 2025 (3)
6.375% senior unsecured notes due 2026 (4)
Asset retirement obligations
Building loan (5)
Firm transportation contracts
Purchase obligations (6)
Operating leases
$ 477,531
923,000
886,998
686,991
75,100
23,724
3,752,365
39,330
190
$ 23,188
39,000
38,250
21,834
120
622
248,047
39,330
136
(In thousands)
$ 46,375
78,000
76,500
57,375
9,510
1,233
499,225
—
54
$ 46,375
78,000
76,500
57,375
3,624
1,353
493,240
—
—
More than 5
years
$ 361,593
728,000
695,748
550,407
61,846
20,516
2,511,853
—
—
Total
$6,865,229
$410,527
$768,272
$756,467
$4,929,963
(1)
(2)
(3)
(4)
Includes estimated interest of $23.2 million due in less than one year; $46.4 million due in 1-3 years;
$46.4 million due in 3-5 years and $11.6 million due thereafter.
Includes estimated interest of $39.0 million due in less than one year; $78.0 million due in 1-3 years;
$78.0 million due in 3-5 years and $78.1 million due thereafter.
Includes estimated interest of $38.3 million due in less than one year; $76.5 million due in 1-3 years;
$76.5 million due in 3-5 years and $95.7 million due thereafter.
Includes estimated interest of $21.8 million due in less than one year; $57.4 million due in 1-3 years;
$57.4 million due in 3-5 years and $100.4 million due thereafter.
(5) Does not include estimated interest of $1.1 million due in less than one year; $2.1 million due in 1-3 years:
$1.9 million due in 3-5 years and $2.2 million due thereafter.
(6) The purchasing obligations reported above represent our minimum financial commitment pursuant to the
terms of these contracts.
Off-balance Sheet Arrangements
We had no off-balance sheet arrangements as of December 31, 2017.
New Accounting Pronouncements
In May 2014, the FASB issued Accounting Standards Update, or ASU, No. 2014-09, Revenue from
Contracts with Customers, which supersedes the revenue recognition requirements in Topic 605, Revenue
Recognition, and most industry-specific guidance. Subsequent to ASU 2014-09, the FASB issued several related
ASU’s to clarify the application of the revenue recognition standard. The core principle of the new standard is for
the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the
payment to which the company expects to be entitled in exchange for those goods or services. The new standard
will also result in enhanced revenue disclosures, provide guidance for transactions that were not previously
addressed comprehensively and improve guidance for multiple-element arrangements. The ASU is effective for
annual periods beginning after December 15, 2016, and interim periods within those years. The new standard
permits retrospective application using either of the following methodologies: (i) restatement of each prior
reporting period presented (full retrospective method) or (ii) recognition of a cumulative-effect adjustment as of
the date of initial application (modified retrospective method). In July 2015, the FASB decided to defer the
effective date by one year (until 2018). We have evaluated the impact of this ASU on our consolidated financial
statements. This evaluation required, among other things, a review of existing contracts we have with our
customers within each of the revenue streams identified within our business, including natural gas sales, oil and
81
condensate sales and natural gas liquid sales. Substantially all of our revenue is earned pursuant to agreements
under which we have currently interpreted one performance obligation, which is satisfied at a point-in-time. We
did not identify any changes to our revenue recognition policies that would result in a material effect on the
timing of our revenue recognition or its financial position, results of operations, net income or cash flows.
Additionally, we do not believe further disaggregation of revenue will be required under the new standard. The
adoption of this ASU will have an impact on our revenue related disclosures and internal controls over financial
reporting as our revenue recognition related disclosures will expand upon adoption of the new standard. We are
currently in the process of finalizing our documentation of new policies, procedures, systems, controls and data
requirements as the standard is implemented. We will be in a position to begin reporting under the new standard
beginning in the first quarter of 2018, using the modified retrospective method.
In February 2016, the FASB issued ASU No. 2016-02, Leases. The guidance requires the lessee to
recognize most leases on the balance sheet thereby resulting in the recognition of lease assets and liability for
those leases currently classified as operating leases. The accounting for lessors is largely unchanged. The
guidance is effective for periods after December 15, 2018, with early adoption permitted. We are in the process
of evaluating the impact of this guidance on our consolidated financial statements and related disclosures and as
contracts are reviewed under the new standard, this analysis could result in an impact to our financial statements;
however, that impact is currently not known.
In March 2016, the FASB issued ASU No. 2016-05, Effect of Derivative Contract Novations on Existing
Hedge Accounting Relationships. The guidance was issued to clarify that change in the counterparty to a
derivative instrument that had been designated as the hedging instrument under Topic 815, does not require
designation of that hedging relationship provided that all other hedge accounting criteria continue to be met. We
adopted the standard as of January 1, 2017. There was no impact on our consolidated financial statements
because all current derivative instruments are not designated for hedge accounting.
In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-Based Payment
Accounting. This guidance was intended to simplify the accounting for share-based payment transactions,
including the income tax consequences, classification of awards as either equity or liabilities and classification on
the statement of cash flows. We adopted the standard as of January 1, 2017. We elected to recognize forfeitures
of awards as they occur. The adoption of this standard did not have a material impact on our consolidated
financial statements.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses: Measurement of
Credit Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at
amortized cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU
eliminates the probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its
current estimate of all expected credit losses. The amendments affect loans, debt securities, trade receivables, net
investments in leases, off balance sheet credit exposure, reinsurance receivables and any other financial assets
not excluded from the scope that have the contractual right to receive cash. We are currently evaluating the
impact this standard will have on our financial statements and related disclosures and do not anticipate it to have
a material affect.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain
Cash Receipts and Cash Payments. This guidance provides guidance of eight specific cash flow issues. This
amendment is effective for periods after December 15, 2017, with early adoption permitted. We are in the
process of evaluating the impact of this guidance on our consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business. Under the
current business combination guidance, there are three elements of a business: inputs, processes and outputs. The
revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets
acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a
82
business. The new framework also specifies the minimum required inputs and processes necessary to be a
business. This amendment is effective for periods after December 15, 2017, with early adoption permitted. We
are in the process of evaluating the impact of this ASU on our consolidated financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and
natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and
natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand,
market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and
natural gas; the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring
for, developing, producing and delivering oil and natural gas; the expected rates of declining current production;
weather conditions, including hurricanes, that can affect oil and natural gas operations over a wide area; the level
of consumer demand; the price and availability of alternative fuels; technical advances affecting energy
consumption; risks associated with operating drilling rigs; the availability of pipeline capacity; the price and level
of foreign imports; domestic and foreign governmental regulations and taxes; the ability of the members of the
Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
political instability or armed conflict in oil and natural gas producing regions; and the overall economic
environment.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and
natural gas price movements with any certainty. During 2016, WTI prices ranged from $26.19 to $54.01 per
barrel and the Henry Hub spot market price of natural gas ranged from $1.49 to $3.80 per MMBtu. During 2017,
WTI prices ranged from $42.48 to $60.46 per barrel and the Henry Hub spot market price of natural gas ranged
from $2.44 to $3.71 per MMBtu. If the prices of oil and natural gas continue at current levels or decline further,
our operations, financial condition and level of expenditures for the development of our oil and natural gas
reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the
amount of oil and natural gas that we can produce economically. This may result in our having to make
substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates
change or our exploration or development activities are curtailed, full cost accounting rules may require us to
write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. Reductions
in our reserves could also negatively impact the borrowing base under our revolving credit facility, which could
further limit our liquidity and ability to conduct additional exploration and development activities.
To mitigate the effects of commodity price fluctuations on our oil and natural gas production, we had the
following open fixed price swap positions as of December 31, 2017.
2018
2019
2018
2018
2018
2018
Location
Daily Volume
(MMBtu/day)
Weighted
Average Price
NYMEX Henry Hub
NYMEX Henry Hub
908,000
269,000
$ 3.06
$ 2.93
Location
Daily Volume
(Bbls/day)
Weighted
Average Price
ARGUS LLS
NYMEX WTI
1,500
4,000
$56.22
$52.20
Location
Mont Belvieu C3
Mont Belvieu C5
Daily Volume
(Bbls/day)
Weighted
Average Price
3,500
500
$28.03
$46.62
We sold call options and used the associated premiums to enhance the fixed price for a portion of the fixed
price natural gas swaps listed above. Each short call option has an established ceiling price. When the referenced
83
settlement price is above the price ceiling established by these short call options, we pay our counterparty an
amount equal to the difference between the referenced settlement price and the price ceiling multiplied by the
hedged contract volumes.
January 2018 - March 2018
April 2018 - March 2019
April 2019 - December 2019
Location
Daily Volume
(MMBtu/day)
Weighted
Average Price
NYMEX Henry Hub
NYMEX Henry Hub
NYMEX Henry Hub
20,000
50,000
30,000
$2.91
$3.13
$3.10
For a portion of the natural gas fixed price swaps listed above, the counterparty has an option to extend the
original terms an additional twelve months for the period January 2019 through December 2019. The option to
extend the terms expires in December 2018. If executed, we would have additional fixed price swaps for 100,000
MMBtu per day at a weighted average price of $3.05.
In addition, we have entered into natural gas basis swap positions, which settle on the pricing index to basis
differential of Tetco M2 to the NYMEX Henry Hub natural gas price. As of December 31, 2017, we had the
following natural gas basis swap positions for Tetco M2.
2018
NPGL Mid-Continent
12,000
$(0.26)
Location
Daily Volume
(MMBtu/day)
Hedged
Differential
In January and February 2018, we entered into fixed price swaps for 2018 for approximately 1,000 barrels
of oil per day at a weighted average price of $62.18 per barrel and for approximately 500 barrels of C3 propane
per day at a weighted average price of $35.54 per barrel. For 2019, we entered into fixed price swaps for
approximately 242,000 MMBtu of natural gas per day at a weighted average price of $2.79 per MMBtu and for
approximately 2,000 barrels of oil per day at a weighted average price of $57.75 per barrel. Our fixed price swap
contracts are tied to the commodity prices on NYMEX for natural gas, NYMEX WTI for oil and Mont Belvieu
for propane. We will receive the fixed priced amount stated in the contract and pay to its counterparty the current
market price as listed on NYMEX for natural gas, NYMEX WTI for oil or Mont Belvieu for propane.
Under our 2018 contracts, we have hedged approximately 78% to 81% of our expected 2018 production.
Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where
production is less than expected or oil prices increase. At December 31, 2017, we had a net asset derivative
position of $52.0 million as compared to a net liability derivative position of $136.8 million as of December 31,
2016, related to our fixed price swaps. Utilizing actual derivative contractual volumes, a 10% increase in
underlying commodity prices would have reduced the fair value of these instruments by approximately $144.8
million, while a 10% decrease in underlying commodity prices would have increased the fair value of these
instruments by approximately $141.4 million. However, any realized derivative gain or loss would be
substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the
derivative instrument.
Our revolving credit facility is structured under floating rate terms, as advances under this facility may be in
the form of either base rate loans or eurodollar loans. As such, our interest expense is sensitive to fluctuations in
the prime rates in the U.S. or, if the eurodollar rates are elected, the eurodollar rates. At December 31, 2017, we
had no variable interest rate borrowings outstanding; therefore, an increase in interest rates would not have
impacted our interest expense. At October 11, 2017, the last day on which borrowings were outstanding under
our revolving credit facility, such borrowings bore interest at the Eurodollar rate of 3.74%. A 1% increase in
interest rates would have increased interest expense by approximately $1.2 million per year, based on $365.0
million in borrowings outstanding under our revolving credit facility as of that date. As of December 31, 2017,
we did not have any interest rate swaps to hedge our interest risks.
84
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item appears beginning on page F-1 following the signature pages of this
Report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Control and Procedures. Under the direction of our Chief Executive Officer and
President and our Chief Financial Officer, we have established disclosure controls and procedures that are
designed to ensure that information required to be disclosed by us in the reports that we file or submit under the
Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s
rules and forms. The disclosure controls and procedures are also intended to ensure that such information is
accumulated and communicated to management, including our Chief Executive Officer and President and our
Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.
As of December 31, 2017, an evaluation was performed under the supervision and with the participation of
management, including our Chief Executive Officer and President and our Chief Financial Officer, of the
effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b)
under the Exchange Act. Based upon our evaluation, our Chief Executive Officer and President and our Chief
Financial Officer have concluded that, as of December 31, 2017, our disclosure controls and procedures are
effective.
Changes in Internal Control over Financial Reporting. There have not been any changes in our internal
control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are
reasonably likely to materially affect, internal controls over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for the fair presentation of the consolidated financial statements of Gulfport
Energy Corporation. Management is also responsible for establishing and maintaining a system of adequate
internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities
Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the
reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in
the preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any
system of internal control, including the possibility of human error and overriding of controls. Consequently, an
effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting
financial information.
Management conducted an evaluation of the effectiveness of our internal control over financial reporting
based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the
2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in our
internal control over financial reporting and concluded that our internal control over financial reporting was
effective as of December 31, 2017.
85
Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements
for the year ended December 31, 2017 included with this Annual Report on Form 10-K, has also audited our
internal control over financial reporting as of December 31, 2017, as stated in their accompanying report.
/s/ Michael G. Moore
/s/ Keri Crowell
Name: Michael G. Moore
Title: Chief Executive Officer and President
Name: Keri Crowell
Title: Chief Financial Officer
86
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Gulfport Energy Corporation
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Gulfport Energy Corporation (a Delaware
corporation) and subsidiaries (the “Company”) as of December 31, 2017, based on criteria established in the
2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2017, based on criteria established in the 2013
Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31,
2017, and our report dated February 22, 2018 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for
its assessment of the effectiveness of internal control over financial reporting, included in the accompanying
Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the
Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered
with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
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 (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
February 22, 2018
87
ITEM 9B. OTHER INFORMATION
None.
88
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
For information concerning Item 10-Directors, Executive Officers and Corporate Governance, see our
definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days
after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of
portions noted therein that are not incorporated by reference).
ITEM 11. EXECUTIVE COMPENSATION
For information concerning Item 11-Executive Compensation, see our definitive proxy statement, which
will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal
year and is incorporated herein by this reference (with the exception of portions noted therein that are not
incorporated by reference).
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
For information concerning Item 12-Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters, see our definitive proxy statement, which will be filed with the Securities and
Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by
this reference (with the exception of portions noted therein that are not incorporated by reference).
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE
For information concerning Item 13-Certain Relationships and Related Transactions, and Director
Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange
Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference
(with the exception of portions noted therein that are not incorporated by reference).
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
For information concerning Item 14-Principal Accounting Fees and Services, see our definitive proxy
statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our
previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that
are not incorporated by reference).
89
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as part of this report or incorporated by reference herein:
(1) Financial Statements
Reference is made to the Index to Financial Statements appearing on Page F-1.
(2) Financial Statement Schedules
All financial statement schedules have been omitted because they are not applicable or the required
disclosure is presented in the financial statements or notes thereto.
(3) Exhibits
Exhibit
Number
2.1##
3.1
3.2
3.3
3.4
3.5
3.6
4.1
4.2
4.3
Description
Purchase and Sale Agreement, dated as of December 13, 2016, by and among Gulfport Energy
Corporation, SCOOP Acquisition Company, LLC and Vitruvian II Woodford, LLC (incorporated
by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with the
SEC on December 15, 2016).
Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File
No. 000-19514, filed by the Company with the SEC on April 26, 2006).
Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference
to Exhibit 3.2 to Form 10-Q, File No. 000-19514, filed by the Company with the SEC on
November 6, 2009).
Certificate of Amendment No. 2 to Restated Certificate of Incorporation (incorporated by reference
to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23,
2013).
Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No.
000-19514, filed by the Company with the SEC on July 12, 2006).
First Amendment to the Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to
the Form 8-K, File No. 000-19514, filed by the Company with the SEC on July 23, 2013).
Second Amendment to the Amended and Restated Bylaws of the Company (incorporated by
reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC
on May 2, 2014).
Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2
to the Registration Statement on Form SB-2, File No. 333-115396, filed by the Company with the
SEC on July 22, 2004).
Indenture, dated as of April 21, 2015, among the Company, the subsidiary guarantors party thereto
and Wells Fargo Bank, N.A., as trustee (including the form of the Company’s 6.625% Senior Notes
due 2023) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by
the Company with the SEC on April 21, 2015).
Indenture, dated as of October 14, 2016, among Gulfport Energy Corporation, the subsidiary
guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport
Energy Corporation’s 6.000% Senior Notes due 2024) (incorporated by reference to Exhibit 4.1 to
the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 19, 2016).
90
Exhibit
Number
4.4
4.5
4.6
4.7
4.8
10.1+
10.2+
10.3+
10.4+
10.5+
10.6+
10.7+
10.8
Description
Indenture, dated as of December 21, 2016, among Gulfport Energy Corporation, the subsidiary
guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport
Energy Corporation’s 6.375% Senior Notes due 2025) (incorporated by reference to Exhibit 4.1 to
the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 21, 2016).
Indenture, dated as of October 11, 2017, among Gulfport Energy Corporation, the subsidiary
guarantors party thereto and Wells Fargo Bank, N.A., as trustee (including the form of Gulfport
Energy Corporation’s 6.375% Senior Notes due 2026) (incorporated by reference to Exhibit 4.1 to
the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 11, 2017).
Registration Rights Agreement, dated as of October 11, 2017, among Gulfport Energy Corporation,
the subsidiary guarantors party and J.P. Morgan Securities LLC, as representative of the several
initial purchasers (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514,
filed by the Company with the SEC on October 11, 2017).
Registration Rights Agreement, dated as of February 17, 2017, by and between Gulfport Energy
Corporation and Vitruvian II Woodford, LLC (incorporated by reference to Exhibit 4.1 to the Current
Report on Form 8-K, File No. 000-19514, filed by the Company with the SEC on February 24,
2017).
Voting Rights Waiver Agreement, dated June 10, 2015, by and among Gulfport Energy Corporation,
Putnam Investment Management, LLC, The Putnam Advisory Company, LLC and Putnam Fiduciary
Trust Company (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed
by the Company with the SEC on June 12, 2015)
2013 Restated Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to the Form S-4, File
No. 333-189992, filed by the Company with the SEC on July 17, 2013).
2014 Executive Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to
the Form 8-K, File No. 000-19514, filed by the Company with the SEC on April 7, 2014).
Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No.
000-19514, filed by the Company with the SEC on April 26, 2006).
Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to the Form
10-K, File No. 000-19514, filed by the Company with the SEC on February 28, 2014).
Consulting Agreement, effective as of June 14, 2013, by and between the Company and Mike Liddell
(incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the
Company with the SEC on June 19, 2013).
Separation and Release Agreement, dated as of January 31, 2014, by and between the Company and
James D. Palm (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed
by the Company with the SEC on February 4, 2014).
Amended and Restated Employment Agreement, dated as of April 29, 2015, by and between the
Company and Michael G. Moore (incorporated by reference to Exhibit 10.3 to the Form 10-Q, File
No. 000-19514, filed by the Company with the SEC on May 7, 2015).
Amended and Restated Credit Agreement, dated as of December 27, 2013, by and among the
Company, as borrower, The Bank of Nova Scotia, as administrative agent, sole lead arranger and sole
bookrunner, Amegy Bank National Association, as syndication agent, KeyBank National
Association, as documentation agent, and the other lenders party thereto (incorporated by reference
to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on January 3,
2014).
91
Exhibit
Number
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
Description
First Amendment to Amended and Restated Credit Agreement, dated as of April 23, 2014, among
Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, sole
lead arranger and sole bookrunner, Amegy Bank National Association, as syndication agent,
KeyBank National Association, as documentation agent, and the other lenders party thereto
(incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company
with the SEC on April 28, 2014).
Second Amendment to Amended and Restated Credit Agreement, dated as of November 26, 2014,
among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-
19514, filed by the Company with the SEC on December 3, 2014).
Third Amendment to Amended and Restated Credit Agreement, dated as of April 10, 2015, among
the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party
thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the
Company with the SEC on April 15, 2015).
Fourth Amendment to Amended and Restated Credit Agreement, dated as of May 29, 2015, among
the Company, as borrower, the Bank of Nova Scotia, as administrative agent, and the lenders party
thereto (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the
Company with the SEC on August 7, 2015).
Fifth Amendment to Amended and Restated Credit Agreement, dated as of September 18, 2015,
among the Company, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders
party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed
by the Company with the SEC on September 24, 2015).
Sixth Amendment, dated February 19, 2016, to Amended and Restated Credit Agreement, dated as of
September 18, 2015, among the Company, as borrower, The Bank of Nova Scotia, as administrative
agent, and the lenders party thereto (incorporated by reference to Exhibit 10.2 to the Form 10-Q, File
No. 000-19514, filed by the Company with the SEC on May 5, 2016).
Seventh Amendment to Amended and Restated Credit Agreement, dated as of December 13, 2016,
among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No.
000-19514, filed by the Company with the SEC on December 15, 2016).
Eighth Amendment to Amended and Restated Credit Agreement, entered into as of March 29, 2017,
among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent
and L/C issuer, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form
8-K, File No. 000-19514, filed by the Company with the SEC on April 4, 2017).
Ninth Amendment to Amended and Restated Credit Agreement, entered into as of May 4, 2017,
among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent
and L/C issuer, the existing lenders named therein and JPMorgan Chase Bank, N.A., Commonwealth
Bank of Australia, ABN, AMRO Capital USA LLC, Fifth Third Bank and Canadian Imperial Bank
of Commerce, New York branch, as new lenders (incorporated by reference to Exhibit 10.2 to the
Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 9, 2017).
Tenth Amendment to Amended and Restated Credit Agreement, dated as of October 4, 2017, among
Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and
the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-
19514, filed by the Company with the SEC on October 5, 2017).
92
Exhibit
Number
10.19
10.20#
10.21#
10.22#
10.23#
10.24+
10.25+
10.26+
10.27+
10.28+
Description
Eleventh Amendment to Amended and Restated Credit Agreement, dated as of November 21, 2017,
among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent,
and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Form 8-K, File No.
000-19514, filed by the Company with the SEC on November 28, 2017).
Sand Supply Agreement, effective as of October 1, 2014, by and between Muskie Proppant LLC and
Gulfport Energy Corporation (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No.
000-19514, filed by the Company with the SEC on November 7, 2014).
Amendment to Sand Supply Agreement, dated as of November 3, 2015, by and between Muskie
Proppant LLC and Gulfport Energy Corporation (incorporated by reference to Exhibit 10.2 to the
Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 5, 2015).
Amended and Restated Master Services Agreement, effective as of October 1, 2014, by and between
Gulfport Energy Corporation and Stingray Pressure Pumping LLC (incorporated by reference to
Exhibit 10.2 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on
November 7, 2014).
Amendment to Amended and Restated Master Services Agreement, dated as of February 18, 2016 to
be effective as of January 1, 2016, by and between Gulfport Energy Corporation and Stingray
Pressure Pumping LLC.
Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Registration
Statement on Form S-4, File No. 333-199905, filed by the Company with the SEC on November 6,
2014).
Separation and Release Agreement by and between Gulfport Energy Corporation and Ross Kirtley
entered into November 2, 2016 (incorporated by reference to Exhibit 10.1 to the Form 10-Q, File No.
000-19514, filed by the Company with the SEC on November 3, 2016).
Employment Agreement, entered into as of April 28, 2017, effective as of January 1, 2017, by and
between Gulfport Energy Corporation and Keri Crowell (incorporated by reference to Exhibit 10.3 to
the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 9, 2017).
Employment Agreement, entered into as of April 28, 2017, effective as of January 1, 2017, by and
between Gulfport Energy Corporation and Stuart Maier (incorporated by reference to Exhibit 10.4 to
the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 9, 2017).
Employment Agreement, entered into as of April 28, 2017, effective as of January 1, 2017, by and
between Gulfport Energy Corporation and Steve Baldwin (incorporated by reference to Exhibit 10.5
to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on May 9, 2017).
14
Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by
the Company with the SEC on February 14, 2006).
21*
Subsidiaries of the Registrant.
23.1*
23.2*
31.1*
31.2*
Consent of Grant Thornton LLP.
Consent of Netherland, Sewell & Associates, Inc.
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated
under the Securities Exchange Act of 1934, as amended.
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated
under the Securities Exchange Act of 1934, as amended.
93
Exhibit
Number
32.1**
32.2**
Description
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated
under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title
18 of the United States Code.
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated
under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title
18 of the United States Code.
99.1*
Report of Netherland, Sewell & Associates, Inc.
101.INS*
XBRL Instance Document.
101.SCH*
XBRL Taxonomy Extension Schema Document.
101.CAL*
XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*
XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*
XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE*
XBRL Taxonomy Extension Presentation Linkbase Document.
Filed herewith.
*
** Furnished herewith, not filed.
+ Management contract, compensatory plan or arrangement.
#
Confidential treatment with respect to certain portions of this agreement was granted by the SEC which
portions have been omitted and filed separately with the SEC.
## The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with
Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished
supplementally to the Securities and Exchange Commission.
ITEM 16. FORM 10-K SUMMARY
None.
94
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Date: February 22, 2018
GULFPORT ENERGY CORPORATION
By:
/s/ KERI CROWELL
Keri Crowell
Chief Financial Officer
In accordance with the Exchange Act, this report has been signed below by the following persons on behalf
of the registrant and in the capacities and on the dates indicated.
Date: February 22, 2018
Date: February 22, 2018
Date: February 22, 2018
Date: February 22, 2018
Date: February 22, 2018
Date: February 22, 2018
Date: February 22, 2018
Date: February 22, 2018
/s/ MICHAEL G. MOORE
Michael G. Moore
Chief Executive Officer and President, Director
(Principal Executive Officer)
/s/ DAVID L. HOUSTON
David L. Houston
Chairman of the Board and Director
/s/ KERI CROWELL
Keri Crowell
Chief Financial Officer
(Principal Accounting and Financial Officer)
/s/ CRAIG GROESCHEL
Craig Groeschel
Director
/s/ C. DOUG JOHNSON
C. Doug Johnson
Director
/s/ BEN T. MORRIS
Ben T. Morris
Director
/s/ SCOTT E. STRELLER
Scott E. Streller
Director
/s/ PAUL WESTERMAN
Paul Westerman
Director
By:
By:
By:
By:
By:
By:
By:
By:
95
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets, December 31, 2017 and December 31, 2016
Consolidated Statements of Operations, Years Ended December 31, 2017, 2016, and 2015
Consolidated Statements of Comprehensive Income (Loss), Years Ended December 31, 2017, 2016, and
2015
Consolidated Statements of Stockholders’ Equity, Years Ended December 31, 2017, 2016, and 2015
Consolidated Statements of Cash Flows, Year Ended December 31, 2017, 2016, and 2015
Notes to Consolidated Financial Statements
Page
F-2
F-3
F-4
F-5
F-6
F-7
F-8
F-1
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Gulfport Energy Corporation
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation (a Delaware
corporation) and subsidiaries (the “Company”) as of December 31, 2017 and 2016, and the related consolidated
statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three
years in the period ended December 31, 2017, and the related notes (collectively referred to as the “financial
statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position
of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each
of the three years in the period ended December 31, 2017, in conformity with accounting principles generally
accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board
(United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2017,
based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 22, 2018
expressed an unqualified opinion.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express
an opinion on the Company’s financial statements based on our audits. We are a public accounting firm
registered with the PCAOB and are required to be independent with respect to the Company in accordance with
the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange
Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of
material misstatement of the financial statements, whether due to error or fraud, and performing procedures that
respond to those risks. Such procedures include examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. Our audits also included evaluating the accounting principles used and
significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2005.
Oklahoma City, Oklahoma
February 22, 2018
F-2
GULFPORT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
Assets
Current assets:
Cash and cash equivalents
Restricted cash
Accounts receivable - oil and natural gas
Accounts receivable - related parties
Prepaid expenses and other current assets
Short-term derivative instruments
Total current assets
Property and equipment:
Oil and natural gas properties, full-cost accounting, $2,912,974 and $1,580,305
excluded from amortization in 2017 and 2016, respectively
Other property and equipment
Accumulated depletion, depreciation, amortization and impairment
Property and equipment, net
Other assets:
Equity investments
Long-term derivative instruments
Deferred tax asset
Inventories
Other assets
Total other assets
Total assets
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities
Asset retirement obligation - current
Short-term derivative instruments
Current maturities of long-term debt
Total current liabilities
Long-term derivative instruments
Asset retirement obligation - long-term
Other non-current liabilities
Long-term debt, net of current maturities
Total liabilities
Commitments and contingencies (Notes 15 and 16)
Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable
12% cumulative preferred stock, Series A; 0 issued and outstanding
Stockholders’ equity:
Common stock, $.01 par value; 200,000,000 authorized, 183,105,910 issued and
outstanding in 2017 and 158,829,816 in 2016
Paid-in capital
Accumulated other comprehensive loss
Retained deficit
Total stockholders’ equity
Total liabilities and stockholders’ equity
December 31,
2017
December 31,
2016
(In thousands, except share data)
$
99,557
—
182,213
—
4,912
78,847
365,529
$ 1,275,875
185,000
136,761
16
3,135
3,488
1,604,275
9,169,156
86,754
(4,153,733)
5,102,177
6,071,920
68,986
(3,789,780)
2,351,126
302,112
8,685
1,208
8,227
19,814
340,046
$ 5,807,752
243,920
5,696
4,692
4,504
8,932
267,744
$ 4,223,145
$
553,609
120
32,534
622
586,885
2,989
74,980
2,963
2,038,321
2,706,138
$
265,124
195
119,219
276
384,814
26,759
34,081
—
1,593,599
2,039,253
—
—
1,831
4,416,250
(40,539)
(1,275,928)
3,101,614
$ 5,807,752
1,588
3,946,442
(53,058)
(1,711,080)
2,183,892
$ 4,223,145
See accompanying notes to consolidated financial statements.
F-3
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
Revenues:
Natural gas sales
Oil and condensate sales
Natural gas liquid sales
Net gain (loss) on natural gas, oil, and NGL derivatives
Costs and expenses:
Lease operating expenses
Production taxes
Midstream gathering and processing
Depreciation, depletion and amortization
Impairment of oil and natural gas properties
General and administrative
Accretion expense
Acquisition expense
INCOME (LOSS) FROM OPERATIONS
OTHER (INCOME) EXPENSE:
Interest expense
Interest income
Insurance proceeds
Loss on debt extinguishment
Loss from equity method investments, net
Other (income) expense
INCOME (LOSS) BEFORE INCOME TAXES
INCOME TAX EXPENSE (BENEFIT)
NET INCOME (LOSS)
NET INCOME (LOSS) PER COMMON SHARE:
Basic
Diluted
$
$
$
For the Year Ended December 31,
2017
2016
(In thousands, except share data)
2015
$
$
845,999
124,568
136,057
213,679
1,320,303
$
420,128
81,173
59,115
(174,506)
385,910
324,733
122,615
58,129
203,513
708,990
80,246
21,126
248,995
364,629
—
52,938
1,611
2,392
771,937
548,366
108,198
(1,009)
—
—
5,257
(1,041)
111,405
436,961
1,809
435,152
2.42
2.41
$
$
$
68,877
13,276
165,972
245,974
715,495
43,409
1,057
—
69,475
14,740
138,590
337,694
1,440,418
41,967
820
—
1,254,060
2,043,704
(868,150)
(1,334,714)
63,530
(1,230)
(5,718)
23,776
33,985
129
114,472
51,221
(643)
(10,015)
—
106,093
(485)
146,171
(982,622)
(2,913)
(1,480,885)
(256,001)
(979,709) $ (1,224,884)
(7.97) $
(12.27)
(7.97) $
(12.27)
Weighted average common shares outstanding - Basic
Weighted average common shares outstanding - Diluted
179,834,146
180,253,024
122,952,866
122,952,866
99,792,401
99,792,401
See accompanying notes to consolidated financial statements.
F-4
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Net income (loss)
Foreign currency translation adjustment (1)
Other comprehensive income (loss)
Comprehensive income (loss)
For the Year Ended December 31,
2017
2016
2015
$435,152
12,519
(In thousands)
$(979,709) $(1,224,884)
(28,502)
2,119
12,519
2,119
(28,502)
$447,671
$(977,590) $(1,253,386)
(1) Net of $1.3 million in taxes for the year ended December 31, 2016. No taxes were recorded for the years
ended December 31, 2017 and December 31, 2015.
See accompanying notes to consolidated financial statements.
F-5
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N
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
$
435,152
$ (979,709) $(1,224,884)
Year Ended December 31,
2017
2016
(In thousands)
2015
Accretion of discount - Asset Retirement Obligation
Depletion, depreciation and amortization
Impairment of oil and gas properties
Stock-based compensation expense
Loss from equity investments
Gain on debt extinguishment
Change in fair value of derivative instruments
Deferred income tax expense (benefit)
Amortization of loan commitment fees
Amortization of note discount and premium
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable
Decrease in accounts receivable - related party
Increase in prepaid expenses
Increase in other assets
Increase (decrease) in accounts payable and accrued liabilities and other
Settlement of asset retirement obligation
Net cash provided by operating activities
Cash flows from investing activities:
Deductions to cash held in escrow
Additions to other property and equipment
Acquisitions of oil and natural gas properties
Additions to oil and natural gas properties
Proceeds from sale of oil and gas properties
Proceeds from sale of other property and equipment
Contributions to equity method investments
Distributions from equity method investments
Funding of restricted cash
Net cash used in investing activities
Cash flows from financing activities:
Principal payments on borrowings
Borrowings on line of credit
Proceeds from bond issuance
Repayment of bonds
Borrowings on term loan
Debt issuance costs and loan commitment fees
Proceeds from issuance of common stock, net of offering costs and exercise of stock options
Net cash provided by financing activities
Net (decrease) increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Supplemental disclosure of cash flow information:
Interest payments
Income tax (receipts) payments
Supplemental disclosure of non-cash transactions:
Capitalized stock based compensation
Asset retirement obligation capitalized
Interest capitalized
Foreign currency translation gain (loss) on equity method investments
1,611
364,629
—
6,369
5,990
—
(188,802)
1,690
5,011
—
(45,452)
16
(1,777)
(7,866)
106,375
(3,057)
1,057
245,974
715,495
7,351
34,397
(1,108)
323,303
18,188
3,660
(1,716)
(64,889)
—
(3,734)
—
43,763
(4,189)
820
337,694
1,440,418
8,616
113,120
—
(83,671)
(254,493)
3,219
(2,165)
31,986
30
(191)
—
(47,199)
(1,121)
679,889
337,843
322,179
8
(19,372)
(1,348,657)
(1,064,678)
4,866
1,569
(55,280)
7,376
185,000
8
(33,152)
—
(724,925)
45,812
—
(26,472)
18,147
(185,000)
8
(13,572)
—
(1,579,129)
27,998
—
(14,472)
4,914
—
(2,289,168)
(905,582)
(1,574,253)
(365,276)
365,000
450,000
—
2,951
(14,350)
(5,364)
(87,685)
86,000
1,250,000
(624,561)
21,049
(24,718)
1,110,555
(350,172)
250,000
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981,568
432,961
1,730,640
1,222,708
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1,275,875
1,162,901
112,974
99,557
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101,958
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142,340
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$
$
$
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See accompanying notes to consolidated financial statements.
F-7
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2017, 2016 AND 2015
1.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Business
Gulfport Energy Corporation (“Gulfport” or the “Company”) is an independent oil and gas exploration,
development and production company with its principal properties located in the Utica Shale primarily in Eastern
Ohio and the SCOOP Woodford and SCOOP Springer plays in Oklahoma. The Company also holds an acreage
position along the Louisiana Gulf Coast in the West Cote Blanche Bay and Hackberry fields and has an interest
in producing properties in Northwestern Colorado in the Niobrara Formation and in Western North Dakota in the
Bakken Formation, and has investments in companies operating in the United States, Canada and Thailand.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original maturity of three months or less to be
cash equivalents for purposes of the statement of cash flows.
Principles of Consolidation
The consolidated financial statements include the Company and its wholly owned subsidiaries, Grizzly
Holdings Inc., Jaguar Resources LLC, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Westhawk Minerals LLC,
Puma Resources, Inc., Gulfport Appalachia LLC, Gulfport Midstream Holdings, LLC, and Gulfport MidCon,
LLC. All intercompany balances and transactions are eliminated in consolidation.
Accounts Receivable
The Company’s accounts receivable - oil and gas primarily are from companies in the oil and gas industry.
The majority of its receivables are from three purchasers of the Company’s oil and natural gas and receivables
from joint interest owners on properties the Company operates. Credit is extended based on evaluation of a
customer’s payment history and, generally, collateral is not required. Accounts receivable are due within 30 days
and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company
believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered
past due. The Company determines its allowance by considering a number of factors, including the length of time
accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its
obligation to the Company, amounts which may be obtained by an offset against production proceeds due the
customer and the condition of the general economy and the industry as a whole. The Company writes off specific
accounts receivable when they become uncollectible, and payments subsequently received on such receivables
are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2017
and December 31, 2016.
Oil and Gas Properties
The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs,
including nonproductive costs and certain general and administrative costs directly associated with acquisition,
exploration and development of oil and gas properties, are capitalized. Under the full cost method of accounting,
the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the
book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of
deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated
future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted
F-8
average of the first-day-of-the-month price for 2017, 2016 and 2015, adjusted for any contract provisions or
financial derivatives, if any, that hedge the Company’s oil and natural gas revenue, and excluding the estimated
abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of
properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included
in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the
oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an
impairment or noncash writedown is required. Ceiling test impairment can result in a significant loss for a
particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may result
in an impairment of oil and gas properties. The Company did not recognize a ceiling test impairment for the year
ended December 31, 2017.
Such capitalized costs, including the estimated future development costs and site remediation costs of
proved undeveloped properties are depleted by an equivalent units-of-production method, converting barrels to
gas at the ratio of one barrel of oil to six Mcf of gas. No gain or loss is recognized upon the disposal of oil and
gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven
oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds
and totaled approximately $2.9 billion and $1.6 billion at December 31, 2017 and December 31, 2016,
respectively. These costs are reviewed quarterly by management for impairment. If impairment has occurred, the
portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to
amortization. Factors considered by management in its impairment assessment include drilling results by
Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for
exploration and development.
The Company accounts for its abandonment and restoration liabilities under Financial Accounting Standards
Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 410, “Asset Retirement and Environmental
Obligations” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the
estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation
meets the definition of a liability, which is generally when the asset is placed into service. When the liability is
initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount
equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is
included in capitalized costs and depreciated consistent with depletion of reserves. Upon settlement of the
liability or the sale of the well, the liability is reversed. These liability amounts may change because of changes
in asset lives, estimated costs of abandonment or legal or statutory remediation requirements.
Other Property and Equipment
Depreciation of other property and equipment is provided on a straight-line basis over the estimated useful
lives of the related assets, which range from 3 to 30 years.
F-9
Foreign Currency
The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company
has an equity investment in a Canadian entity whose functional currency is the Canadian dollar. The assets and
liabilities of the Canadian investment are translated into U.S. dollars based on the current exchange rate in effect
at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented
and equity contributions are translated at the current exchange rate in effect at the date of the contribution. In
addition, the Company has an equity investment in a U.S. company that has a subsidiary that is a Canadian entity
whose functional currency is the Canadian dollar. Translation adjustments have no effect on net income and are
included in accumulated other comprehensive income in stockholders’ equity. The following table presents the
balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive
loss, exclusive of taxes.
December 31, 2014
December 31, 2015
December 31, 2016
December 31, 2017
Net Income per Common Share
(In thousands)
$(26,675)
$(55,175)
$(51,709)
$(39,190)
Basic net income per common share is computed by dividing income attributable to common stock by the
weighted average number of common shares outstanding for the period. Diluted net income per common share
reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised
or converted into common stock. Potential common shares are not included if their effect would be anti-dilutive.
Calculations of basic and diluted net income per common share are illustrated in Note 11.
Income Taxes
Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets
and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial
statement carrying amounts and the tax basis of existing assets and liabilities and (2) operating loss and tax credit
carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future
period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates
on deferred tax assets and liabilities is recognized in income during the period the rate change is enacted. Deferred
tax assets are recognized as income in the year in which realization becomes determinable. A valuation allowance is
provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.
The Company is subject to U.S. federal income tax as well as income tax of multiple jurisdictions. The
Company’s 2003 – 2016 U.S. federal and 1997 – 2016 state income tax returns remain open to examination by
tax authorities, due to net operating losses. As of December 31, 2017, the Company has no unrecognized tax
benefits that would have a material impact on the effective rate. The Company recognizes interest and penalties
related to income tax matters as interest expense and general and administrative expenses, respectively.
On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (“Tax
Act”). Further information on the tax impacts of the Tax Act is included in Note 10 of the Company’s
consolidated financial statements.
Revenue Recognition
Natural gas revenues are recorded in the month produced and delivered to the purchaser using the entitlement
method, whereby any production volumes received in excess of the Company’s ownership percentage in the
F-10
property are recorded as a liability. If less than Gulfport’s entitlement is received, the underproduction is recorded as
a receivable. At December 31, 2017 and 2016, the Company had a gas imbalance receivable of approximately
$0.2 million. Oil revenues are recognized when ownership transfers, which occurs in the month produced.
Investments - Equity Method
Investments in entities in which the Company owns an equity interest greater than 20% and less than 50%
and/or investments in which it has significant influence are accounted for under the equity method. Under the
equity method, the Company’s share of investees’ earnings or loss is recognized in the statement of operations.
The Company reviews its investments annually to determine if a loss in value which is other than a
temporary decline has occurred. If such loss has occurred, the Company recognizes an impairment provision. The
Company recognized impairment charges of $23.1 million and $101.6 million related to its investment in Grizzly
Oil Sands ULC for the years ended December 31, 2016 and December 31, 2015, respectively. There was no
impairment charge recorded for the year ended December 31, 2017.
Accounting for Stock-Based Compensation
The Company accounts for stock-based compensation in accordance with the provisions of FASB ASC 718,
“Compensation - Stock Compensation” (“FASB ASC 718”). FASB ASC 718 requires share-based payments to
employees, including grants of restricted stock, to be recognized as equity or liabilities at the fair value on the
date of grant and to be expensed over the applicable vesting period. The vesting periods for restricted shares
range between one to four years with annual vesting installments.
Derivative Instruments
The Company utilizes commodity derivatives to manage the price risk associated with forecasted sale of its
natural gas, crude oil and natural gas liquid production. The Company follows the provisions of FASB ASC 815,
“Derivatives and Hedging” (“FASB ASC 815”) as amended. It requires that all derivative instruments be
recognized as assets or liabilities in the balance sheet, measured at fair value.
The accounting for changes in the fair value of a derivative depends on the intended use of the derivative
and the resulting designation. While the Company has historically designated derivative instruments as
accounting hedges, effective January 1, 2015, the Company discontinued hedge accounting prospectively. The
Company’s current commodity derivative instruments are not designated as hedges for accounting purposes.
Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period
of change. Gains and losses on derivatives are included in cash flows from operating activities.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the
United States of America requires management to make estimates, judgments and assumptions that affect the
reported amounts of assets and liabilities as of the date of the financial statements and revenues and expenses
during the reporting period. Actual results could differ materially from those estimates. Significant estimates
with regard to these financial statements include the estimate of proved oil and gas reserve quantities and the
related present value of estimated future net cash flows there from, the amount and timing of asset retirement
obligations, the realization of deferred tax assets, the fair value determination of acquired assets and liabilities
and the realization of future net operating loss carryforwards available as reductions of income tax expense. The
estimate of the Company’s oil and gas reserves is used to compute depletion, depreciation, amortization and
impairment of oil and gas properties.
F-11
Reclassification
Certain reclassifications have been made to prior period financial statements and related disclosures to
conform to current period presentation. These reclassifications have no impact on previous reported total assets,
total liabilities, net income (loss) or total operating cash flows.
Recent Accounting Pronouncements
In May 2014, the FASB issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from
Contracts with Customers, which supersedes the revenue recognition requirements in Topic 605, Revenue
Recognition, and most industry-specific guidance. Subsequent to ASU 2014-09, the FASB issued several related
ASU’s to clarify the application of the revenue recognition standard. The core principle of the new standard is for
the recognition of revenue to depict the transfer of goods or services to customers in amounts that reflect the
payment to which the company expects to be entitled in exchange for those goods or services. The new standard
will also result in enhanced revenue disclosures, provide guidance for transactions that were not previously
addressed comprehensively and improve guidance for multiple-element arrangements. The ASU is effective for
annual periods beginning after December 15, 2016, and interim periods within those years. The new standard
permits retrospective application using either of the following methodologies: (i) restatement of each prior
reporting period presented (full retrospective method) or (ii) recognition of a cumulative-effect adjustment as of
the date of initial application (modified retrospective method). In July 2015, the FASB decided to defer the
effective date by one year (until 2018). The Company has evaluated the impact of this ASU on its consolidated
financial statements. This evaluation required, among other things, a review of existing contracts the Company
has with its customers within each of the revenue streams identified within its business, including natural gas
sales, oil and condensate sales and natural gas liquid sales. Substantially all of the Company’s revenue is earned
pursuant to agreements under which it has currently interpreted one performance obligation, which is satisfied at
a point-in-time. The Company did not identify any changes to its revenue recognition policies that would result
in a material effect on the timing of the Company’s revenue recognition or its financial position, results of
operations, net income or cash flows. Additionally, the Company does not believe further disaggregation of
revenue will be required under the new standard. The adoption of this ASU will have an impact on the
Company’s revenue related disclosures and internal controls over financial reporting as the Company’s revenue
recognition related disclosures will expand upon adoption of the new standard. The Company is currently in the
process of finalizing documentation of new policies, procedures, systems, controls and data requirements as the
standard is implemented. The Company will be in a position to begin reporting under the new standard beginning
in the first quarter of 2018, using the modified retrospective method.
In February 2016, the FASB issued ASU No. 2016-02, Leases. The guidance requires the lessee to
recognize most leases on the balance sheet thereby resulting in the recognition of lease assets and liability for
those leases currently classified as operating leases. The accounting for lessors is largely unchanged. The
guidance is effective for periods after December 15, 2018, with early adoption permitted. The Company is in the
process of evaluating the impact of this guidance on its consolidated financial statements and related disclosures
and as contracts are reviewed under the new standard, this analysis could result in an impact to the Company’s
financial statements; however, that impact is currently not known.
In March 2016, the FASB issued ASU No. 2016-05, Effect of Derivative Contract Novations on Existing
Hedge Accounting Relationships. The guidance was issued to clarify that change in the counterparty to a
derivative instrument that had been designated as the hedging instrument under Topic 815, does not require
designation of that hedging relationship provided that all other hedge accounting criteria continue to be met. The
Company adopted the standard as of January 1, 2017. There was no impact on the Company’s consolidated
financial statements because all current derivative instruments are not designated for hedge accounting.
In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share - Based Payment
Accounting. This guidance was intended to simplify the accounting for share-based payment transactions,
F-12
including the income tax consequences, classification of awards as either equity or liabilities and classification on
the statement of cash flows. The Company adopted the standard as of January 1, 2017. The Company has elected
to recognize forfeitures of awards as they occur. The adoption of this standard did not have a material impact on
the Company’s consolidated financial statements.
In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses: Measurement of Credit
Losses on Financial Instruments. This ASU amends guidance on reporting credit losses for assets held at amortized
cost basis and available for sale debt securities. For assets held at amortized cost basis, this ASU eliminates the
probable initial recognition threshold in current GAAP and instead, requires an entity to reflect its current estimate of
all expected credit losses. The amendments affect loans, debt securities, trade receivables, net investments in leases, off
balance sheet credit exposure, reinsurance receivables and any other financial assets not excluded from the scope that
have the contractual right to receive cash. The Company is currently evaluating the impact this standard will have on
its financial statements and related disclosures and does not anticipate it to have a material affect.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain
Cash Receipts and Cash Payments. This guidance provides guidance of eight specific cash flow issues. This
amendment is effective for periods after December 15, 2017, with early adoption permitted. The Company is in
the process of evaluating the impact of this guidance on its consolidated financial statements.
In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business. Under the
current business combination guidance, there are three elements of a business: inputs, processes and outputs. The
revised guidance adds an initial screen test to determine if substantially all of the fair value of the gross assets
acquired is concentrated in a single asset or group of similar assets. If that screen is met, the set of assets is not a
business. The new framework also specifies the minimum required inputs and processes necessary to be a
business. This amendment is effective for periods after December 15, 2017, with early adoption permitted. The
Company is in the process of evaluating the impact of this ASU on its consolidated financial statements.
2. ACQUISITIONS
In December 2016, the Company, through its wholly-owned subsidiary Gulfport MidCon LLC (“Gulfport
MidCon”) (formerly known as SCOOP Acquisition Company, LLC), entered into an agreement to acquire certain
assets of Vitruvian II Woodford, LLC (“Vitruvian”), an unrelated third-party seller (the “Vitruvian Acquisition”).
The assets included in the Vitruvian Acquisition include 46,400 net surface acres located in Grady, Stephens and
Garvin Counties, Oklahoma. On February 17, 2017, the Company completed the Vitruvian Acquisition for a total
initial purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain
adjustments, and approximately 23.9 million shares of the Company’s common stock (of which approximately
5.2 million shares were placed in an indemnity escrow). The cash portion of the purchase price was funded with the
net proceeds from the December 2016 common stock and senior note offerings and cash on hand. Acquisition costs
of $2.4 million were incurred during the year ended December 31, 2017 related to the Vitruvian Acquisition.
Allocation of Purchase Price
The Vitruvian Acquisition qualified as a business combination for accounting purposes and, as such, the
Company estimated the fair value of the acquired properties as of the February 17, 2017 acquisition date. The fair
value of the assets acquired and liabilities assumed was estimated using assumptions that represent Level 3
inputs. See Note 13 for additional discussion of the measurement inputs.
The Company estimated that the consideration paid in the Vitruvian Acquisition for these properties
approximated the fair value that would be paid by a typical market participant. As a result, no goodwill or
bargain purchase gain was recognized in conjunction with the purchase.
F-13
The following table summarizes the consideration paid by the Company in the Vitruvian Acquisition to
acquire the properties and the fair value amount of the assets acquired as of February 17, 2017.
Consideration:
Cash, net of purchase price adjustments
Fair value of Gulfport’s common stock issued
Total Consideration
Estimated Fair value of identifiable assets acquired and liabilities assumed:
Oil and natural gas properties
Proved properties
Unproved properties
Asset retirement obligations
Total fair value of net identifiable assets acquired
(In thousands)
$1,354,093
464,639
$1,818,732
$ 362,264
1,462,957
(6,489)
$1,818,732
The equity consideration included in the initial purchase price was based on an equity offering price of
$20.96 on December 15, 2016. The decrease in the price of Gulfport’s common stock from $20.96 on
December 15, 2016 to $19.48 on February 17, 2017 resulted in a decrease to the fair value of the total
consideration paid as compared to the initial purchase price of approximately $35.3 million, which resulted in a
closing date fair value lower than the initial purchase price.
Post-Acquisition Operating Results
For the period from the acquisition date of February 17, 2017 to December 31, 2017, the assets acquired in
the Vitruvian Acquisition have contributed the following amounts of revenue to the Company’s consolidated
statements of operations. The amount of net income contributed by the assets acquired is not presented below as
it is impracticable to calculate due to the Company integrating the acquired assets into its overall operations
using the full cost method of accounting.
Revenue
Pro Forma Information (Unaudited)
Period from
February 17, 2017
to
December 31, 2017
(In thousands)
$213,368
The following unaudited pro forma combined financial information presents the Company’s results as
though the Vitruvian Acquisition had been completed at January 1, 2016. The pro forma combined financial
information has been included for comparative purposes and is not necessarily indicative of the results that might
have actually occurred had the Vitruvian Acquisition taken place on January 1, 2016; furthermore, the financial
information is not intended to be a projection of future results.
Pro forma revenue
Pro forma net income (loss)
Pro forma earnings (loss) per share (basic)
Pro forma earnings (loss) per share (diluted)
F-14
December 31,
2017
2016
(In thousands, except share data)
$
$1,356,202
523,097
$(1,190,481)
$ 448,398
(8.11)
$
2.49
$
(8.11)
$
2.49
$
3.
PROPERTY AND EQUIPMENT
The major categories of property and equipment and related accumulated depletion, depreciation,
amortization and impairment as of December 31, 2017 and 2016 are as follows:
Oil and natural gas properties
Office furniture and fixtures
Building
Land
Total property and equipment
Accumulated depletion, depreciation, amortization and impairment
Property and equipment, net
December 31,
2017
2016
(In thousands)
$ 9,169,156
37,369
44,565
4,820
$ 6,071,920
21,204
42,530
5,252
9,255,910
(4,153,733)
6,140,906
(3,789,780)
$ 5,102,177
$ 2,351,126
No impairment of oil and natural gas properties was required under the ceiling test for the year ended
December 31, 2017. At December 31, 2016 and 2015, the net book value of the Company’s oil and natural gas
properties was above the calculated ceiling as a result of the reduced commodity prices during the years ended
December 31, 2016 and 2015, respectively. As a result, the Company recorded an impairment of its oil and
natural gas properties under the full cost method of accounting in the amount of $715.5 million and $1.4 billion
for the years ended December 31, 2016 and 2015, respectively.
Included in oil and natural gas properties at December 31, 2017 and 2016 is the cumulative capitalization of
$165.6 million and $129.9 million, respectively, in general and administrative costs incurred and capitalized to
the full cost pool. General and administrative costs capitalized to the full cost pool represent management’s
estimate of costs incurred directly related to exploration and development activities such as geological and other
administrative costs associated with overseeing the exploration and development activities. All general and
administrative costs not directly associated with exploration and development activities were charged to expense
as they were incurred. Capitalized general and administrative costs were approximately $35.7 million,
$29.3 million and $27.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. The
average depletion rate per Mcfe, which is a function of capitalized costs, future development costs and the related
underlying reserves in the periods presented, was $0.90, $0.92 and $1.68 per Mcfe for the years ended
December 31, 2017, 2016 and 2015, respectively.
The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of
December 31, 2017:
Acquisition costs
Exploration costs
Development costs
Capitalized interest
Costs Incurred in
2017
2016
2015
Prior to 2015
Total
$1,511,685
—
5,076
3,871
$129,741
(In thousands)
$429,897
$824,363
$2,895,686
—
4,607
(536)
—
3,635
(1,141)
—
2,214
(438)
—
15,532
1,756
Total oil and natural gas properties not subject
to amortization
$1,520,632
$133,812
$432,391
$826,139
$2,912,974
F-15
The following table summarizes the Company’s non-producing properties excluded from amortization by
area as of December 31, 2017:
Utica
MidContinent
Niobrara
Southern Louisiana
Bakken
Other
December 31, 2017
(In thousands)
$1,513,452
1,396,642
2,184
552
99
45
$2,912,974
As of December 31, 2016, approximately $1.6 billion of non-producing leasehold costs was not subject to
amortization.
The Company evaluates the costs excluded from its amortization calculation at least annually. Subject to
industry conditions and the level of the Company’s activities, the inclusion of most of the above referenced costs
into the Company’s amortization calculation typically occurs within three to five years. However, the majority of
the Company’s non-producing leases in the Utica Shale have five year extension terms which could extend this
time frame beyond five years.
A reconciliation of the Company’s asset retirement obligation for the years ended December 31, 2017 and
2016 is as follows:
Asset retirement obligation, beginning of period
Liabilities incurred
Liabilities settled
Accretion expense
Revisions in estimated cash flows
Asset retirement obligation as of end of period
Less current portion
Asset retirement obligation, long-term
December 31,
2017
2016
(In thousands)
$34,276
16,300
(3,057)
1,611
25,970
$26,437
10,971
(4,189)
1,057
—
75,100
120
34,276
195
$74,980
$34,081
F-16
4. EQUITY INVESTMENTS
Investments accounted for by the equity method consist of the following as of December 31, 2017 and 2016:
Carrying Value
Loss (income) from equity method
investments
December 31,
For the Year Ended December 31,
2017
2016
2017
2016
2015
Approximate
Ownership %
Investment in Tatex Thailand II, LLC
Investment in Tatex Thailand III, LLC
Investment in Grizzly Oil Sands ULC
Investment in Timber Wolf Terminals LLC
Investment in Windsor Midstream LLC
Investment in Stingray Cementing LLC(1)
Investment in Blackhawk Midstream LLC
Investment in Stingray Energy Services LLC (1)
Investment in Sturgeon Acquisitions LLC (1)
Investment in Mammoth Energy Services,
Inc.(1)
Investment in Strike Force Midstream LLC
23.5% $ — $ — $
—
—
17.9%
45,213
24.9999% 57,641
991
983
25,749
30
1,920
—
—
—
—
4,215
— 20,526
50.0%
22.5%
— %
48.5%
— %
— %
(In thousands)
(549) $
(183)
2,189
8
25,233
205
—
282
(71)
(412) $
—
25,150
8
(13,618)
263
—
1,044
993
189
—
115,544
14
(18,398)
147
(7,216)
557
(1,229)
25.1% 165,715 111,717
33,589
25.0% 77,743
(23,811)
1,954
20,646
(89)
16,485
—
$302,112 $243,920 $ 5,257 $ 33,985 $106,093
(1) On June 5, 2017, the Company contributed all of its membership interests in Stingray Cementing LLC,
Stingray Energy Services LLC and Sturgeon Acquisitions LLC to Mammoth Energy Services, Inc.
(“Mammoth Energy”). See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc. for
information regarding these transactions.
The tables below summarize financial information for the Company’s equity investments, as of
December 31, 2017 and 2016.
Summarized balance sheet information:
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
Summarized results of operations:
Gross revenue
Net (loss) income
Tatex Thailand II, LLC
December 31,
2017
2016
(In thousands)
$ 415,032
$1,542,090
$ 261,086
$ 148,839
$ 148,733
$1,305,407
57,173
$
67,680
$
December 31,
2017
2016
2015
(In thousands)
$430,729
$287,733
$755,374
$ (37,102) $ (65,070) $ 16,761
The Company has an indirect ownership interest in Tatex Thailand II, LLC (“Tatex”). Tatex holds an 8.5%
interest in APICO, LLC (“APICO”), an international oil and gas exploration company. APICO has a reserve base
F-17
located in Southeast Asia through its ownership of concessions covering approximately 180,000 acres which
includes the Phu Horm Field. The Company received $0.5 million and $0.4 million in distributions from Tatex II
during the years ended December 31, 2017 and 2016, respectively.
Tatex Thailand III, LLC
The Company has an ownership interest in Tatex Thailand III, LLC (“Tatex III”). Tatex III previously
owned a concession covering approximately 245,000 acres in Southeast Asia. As of December 31, 2014, the
Company reviewed its investment in Tatex III and, together with Tatex III, made the decision to allow the
concession to expire in January 2015. As such, the Company fully impaired the asset as of December 31, 2014.
In December 2017, Tatex III was dissolved and the Company received a final distribution of $0.2 million.
Grizzly Oil Sands ULC
The Company, through its wholly owned subsidiary Grizzly Holdings Inc. (“Grizzly Holdings”), owns an
interest in Grizzly Oil Sands ULC (“Grizzly”), a Canadian unlimited liability company. The remaining interest in
Grizzly is owned by Grizzly Oil Sands Inc. (“Oil Sands”). As of December 31, 2017, Grizzly had approximately
830,000 acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada.
Grizzly has high-graded three oil sands projects to various stages of development. Grizzly commenced
commercial production from its Algar Lake Phase I steam-assisted gravity drainage (“SAGD”) oil sand project
during the second quarter of 2014 and has regulatory approval for up to 11,300 barrels per day of bitumen
production. Algar Lake production peaked at 2,200 barrels per day during the ramp-up phase of the SAGD
facility, however, in April 2015, Grizzly made the decision to suspend operations at its Algar Lake facility due to
the commodity price drop and its effect on project economics. Grizzly continues to monitor market conditions as
it assesses start up plans for the facility. The Company reviewed its investment in Grizzly as of September 30,
2015 and December 31, 2015, and again at March 31, 2016, for impairment based on FASB ASC 323 due to
certain qualitative factors and as such, engaged an independent third party to assist management in determining
fair value calculations of its investment. As a result of the calculated fair values and other qualitative factors, the
Company concluded that an other than temporary impairment was required under FASB ASC 323, resulting in an
aggregate impairment loss of $101.6 million for the year ended December 31, 2015 and $23.1 million for the
year ended December 31, 2016, which is included in loss from equity method investments, net in the
accompanying consolidated statements of operations. As of and during the period ended December 31, 2017,
commodity prices had increased as compared to the quarter ended March 31, 2016, and there were no impairment
indicators that required further evaluation for impairment. If commodity prices decline in the future however,
further impairment of the investment in Grizzly may be necessary. During the years ended December 31, 2017
and 2016, Gulfport paid $2.3 million and $15.5 million, respectively, in cash calls. Grizzly’s functional currency
is the Canadian dollar. The Company’s investment in Grizzly was increased by $12.3 million and $4.2 million as
a result of a foreign currency translation gain and decreased by $28.5 million as a result of a foreign currency
translation loss for the years ended December 31, 2017, 2016, and 2015, respectively.
Effective October 5, 2012, Grizzly entered into a $125.0 million revolving credit facility, of which Grizzly
paid the outstanding balance in full in July 2016. Gulfport paid its share of this amount on June 30, 2016.
Timber Wolf Terminals LLC
During 2012, the Company invested in Timber Wolf Terminals LLC (“Timber Wolf”). Timber Wolf was
formed to operate a crude/condensate terminal and a sand transloading facility in Ohio. During the years ended
December 31, 2017 and 2016, the Company paid no cash calls to Timber Wolf.
Windsor Midstream LLC
At December 31, 2017, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an
entity controlled and managed by an unrelated third party. Midstream previously owned a 28.4% interest in
F-18
Coronado Midstream LLC (“Coronado”), a gas processing plant in West Texas. In March 2015, Coronado was
sold to Enlink Midstream Partners, LP (“Enlink”). As a result of the sale of Coronado to EnLink, Midstream
received common units of EnLink, which were subsequently sold by Midstream. During the year ended
December 31, 2017, the Company was informed that Midstream had not recorded certain activity and fair value
treatment of Midstream’s investment in EnLink common units in a timely manner. The corresponding effect of
this treatment was immaterial to the Company’s previously issued financial statements and the recording of the
correction in the current periods’ financial statements was not material to the Company’s estimated net income
for the current full fiscal year. For the year ended December 31, 2017, approximately $23.4 million of the loss
from equity method investments, net was related to the out-of-period activity associated with the accounting for
Midstream’s investment in EnLink common units. The Company received $0.5 million and $15.8 million in
distributions from Midstream during the years ended December 31, 2017 and 2016, respectively.
Stingray Cementing LLC
During 2012, the Company invested in Stingray Cementing LLC (“Stingray Cementing”). Stingray
Cementing provides well cementing services. The loss (income) from equity method investments presented in the
table above reflects any intercompany profit eliminations. On June 5, 2017, the Company contributed all of its
membership interests in Stingray Cementing to Mammoth Energy. See below under Mammoth Energy Partners
LP/Mammoth Energy Services, Inc. for information regarding this transaction.
Blackhawk Midstream LLC
During 2012, the Company invested in Blackhawk Midstream LLC (“Blackhawk”). Blackhawk coordinated
gathering, compression, processing and marketing activities for the Company in connection with the
development of its Utica Shale acreage. During the year ended December 31, 2015, the Company received net
proceeds of approximately $7.2 million from the release of escrow from the Blackhawk sale, which is included in
loss from equity investments, net in the accompanying consolidated statements of operations. Blackhawk does
not have any current activities.
Stingray Energy Services LLC
During 2013, the Company invested in Stingray Energy Services LLC (“Stingray Energy”). Stingray Energy
provides rental tools for land-based oil and natural gas drilling, completion and workover activities as well as the
transfer of fresh water to wellsites. The loss (income) from equity method investments presented in the table
above reflects any intercompany profit eliminations. On June 5, 2017, the Company contributed all of its
membership interests in Stingray Energy to Mammoth Energy. See below under Mammoth Energy Partners LP/
Mammoth Energy Services, Inc. for information regarding this transaction.
Sturgeon Acquisitions LLC
During 2014, the Company invested $20.7 million and received an ownership interest of 25% in Sturgeon
Acquisitions LLC (“Sturgeon”). Sturgeon owns and operates sand mines that produce hydraulic fracturing grade
sand. During the year ended December 31, 2016, the Company received approximately $1.3 million in
distributions from Sturgeon. On June 5, 2017, the Company contributed all of its membership interests in
Sturgeon to Mammoth Energy. See below under Mammoth Energy Partners LP/Mammoth Energy Services, Inc.
for information regarding this transaction.
Mammoth Energy Partners LP/Mammoth Energy Services, Inc.
In the fourth quarter of 2014, the Company contributed its investments in four entities to Mammoth Energy
Partners LP (“Mammoth”) for a 30.5% interest in this entity. Mammoth originally intended to pursue its initial
public offering in 2014 or 2015; however, due to low commodity prices, the offering was postponed. In October
F-19
2016, Mammoth converted from a limited partnership into a limited liability company named Mammoth Energy
Partners LLC (“Mammoth LLC”) and the Company and the other members of Mammoth LLC contributed their
interests in Mammoth LLC to Mammoth Energy. The Company received 9,150,000 shares of Mammoth Energy
common stock in return for its contribution. Following the contribution, Mammoth Energy completed its initial
public offering (the “IPO”) of 7,750,000 shares of its common stock at a public offering price of $15.00 per
share, of which 7,500,000 shares were sold by Mammoth Energy and 250,000 shares were sold by certain selling
stockholders, including 76,250 shares sold by the Company for which it received net proceeds of $1.1 million. At
December 31, 2016, the Company owned an approximate 24.2% interest in Mammoth Energy. To reflect the
dilution of the Company’s shares of Mammoth Energy stock after the IPO, the Company recognized a gain of
$3.4 million, which is included in loss from equity method investments, net in the accompanying consolidated
statements of operations.
On June 5, 2017, the Company contributed all of its membership interests in Sturgeon (which owns Taylor
Frac, LLC, Taylor Real Estate Investments, LLC and South River Road, LLC), Stingray Energy and Stingray
Cementing to Mammoth Energy in exchange for approximately 2.0 million shares of Mammoth Energy common
stock. As of December 31, 2017, the Company held approximately 25.1% of Mammoth Energy’s outstanding
common stock. The Company accounted for the transactions as a sale of financial assets under FASB ASC 860.
The Company valued the shares of Mammoth Energy common stock it received in the transactions at $18.50 per
share, which was the closing price of Mammoth Energy common stock on June 5, 2017. The Company
recognized a gain of $12.5 million from the transactions, which is included in loss from equity method
investments, net in the accompanying consolidated statements of operations.
The Company’s investment in Mammoth Energy was increased by a $0.2 million foreign currency gain and
decreased by a $0.8 million foreign currency loss resulting from Mammoth Energy’s foreign subsidiary for the
years ended December 31, 2017 and 2016. The loss (income) from equity method investments presented in the
table above reflects any intercompany profit eliminations.
Strike Force Midstream LLC
In February 2016, the Company, through its wholly owned subsidiary Gulfport Midstream Holdings, LLC
(“Midstream Holdings”), entered into an agreement with Rice Midstream Holdings LLC (“Rice”), a subsidiary of
Rice Energy Inc., to develop natural gas gathering assets in eastern Belmont County and Monroe County, Ohio
through an entity called Strike Force Midstream LLC (“Strike Force”). In 2017, Rice was acquired by EQT
Corporation (“EQT”). The Company owns a 25% interest in Strike Force and EQT acts as operator and owns the
remaining 75% interest in Strike Force. Construction of the gathering assets, which is ongoing, provides
gathering services for wells operated by Gulfport and other operators and connectivity of existing dry gas
gathering systems. During the years ended December 31, 2017 and 2016, Gulfport paid $53.0 million and $11.0
million, respectively, in cash calls to Strike Force. For the year ended December 31, 2017, Gulfport received
distributions of $6.9 million from Strike Force.
The Company accounted for its initial contribution to Strike Force at fair value under applicable codification
guidance. The Company estimated the fair market value of its investment in Strike Force as of the contribution
date using the discounted cash flow method under the income approach, based on an independently prepared
valuation of the contributed assets. The fair market value was reduced by a discount factor for the lack of
marketability due to the Company’s minority interest, resulting in a fair value of $22.5 million for the
Company’s 25% interest. The fair value of the assets contributed was estimated using assumptions that represent
Level 3 inputs. See Note 13—Fair Value Measurements for additional discussion of the measurement inputs. The
Company has elected to report its proportionate share of Strike Force’s earnings on a one-quarter lag as permitted
under FASB ASC 323. The loss (income) from equity method investments presented in the table above reflects
any intercompany profit eliminations.
F-20
5. VARIABLE INTEREST ENTITIES
As of December 31, 2017, the Company held variable interests in the following variable interest entities
(“VIEs”), but was not the primary beneficiary: Midstream and Timber Wolf. These entities have governing
provisions that are the functional equivalent of a limited partnership and are considered VIEs because the limited
partners or non-managing members lack substantive kick-out or participating rights which causes the equity
owners, as a group, to lack a controlling financial interest. The Company is a limited partner or non-managing
member in each of these VIEs and is not the primary beneficiary because it does not have a controlling financial
interest. The general partner or managing member has power to direct the activities that most significantly impact
the VIEs’ economic performance. The Company also held a variable interest in Strike Force due to the fact that it
does not have sufficient equity capital at risk. The Company is not the primary beneficiary of this entity. Prior to
Mammoth Energy’s IPO, Mammoth LLC was considered a VIE. As a result of the Company’s contribution of its
interest in Mammoth LLC to Mammoth Energy in exchange for Mammoth Energy common stock and the
completion of Mammoth Energy’s IPO, the Company determined that it no longer held an interest in a VIE. Prior
to the contribution of Stingray Energy, Stingray Cementing and Sturgeon to Mammoth Energy, these entities
were considered VIEs. As a result of the Company’s contribution of its membership interests in Stingray Energy,
Stingray Cementing and Sturgeon to Mammoth Energy in exchange for Mammoth Energy common stock, the
Company determined that it no longer held an interest in a VIE.
The Company accounts for its investment in these VIEs following the equity method of accounting. The
carrying amounts of the Company’s equity investments are classified as other non-current assets on the
accompanying consolidated balance sheets. The Company’s maximum exposure to loss as a result of its
involvement with these VIEs is based on the Company’s capital contributions and the economic performance of
the VIEs, and is equal to the carrying value of the Company’s investments which is the maximum loss the
Company could be required to record in the consolidated statements of operations. See Note 4 for further
discussion of these entities, including the carrying amounts of each investment.
6. LONG-TERM DEBT
Long-term debt consisted of the following items as of December 31:
Revolving credit agreement (1)
Building loans (2)
7.75% senior unsecured notes due 2020 (3)
6.625% senior unsecured notes due 2023 (4)
6.000% senior unsecured notes due 2024 (5)
6.375% senior unsecured notes due 2025 (6)
6.375% senior unsecured notes due 2026 (7)
Net unamortized original issue premium (discount) (8)
Net unamortized debt issuance costs (9)
Construction loan (10)
Less: current maturities of long term debt
Debt reflected as long term
$
2017
2016
(In thousands)
— $
—
—
350,000
650,000
600,000
450,000
—
(34,781)
23,724
(622)
—
—
—
350,000
650,000
600,000
—
—
(27,174)
21,049
(276)
$2,038,321
$1,593,599
F-21
Maturities of long-term debt (excluding unamortized debt issuance costs) as of December 31, 2017 are as
follows:
2018
2019
2020
2021
2022
Thereafter
Total
(In thousands)
622
$
604
629
661
692
2,070,516
$2,073,724
(1) The Company has entered into a senior secured revolving credit facility as amended, with the Bank of
Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto.
The credit agreement provides for a maximum facility amount of $1.5 billion and matures on December 31,
2021. On February 19, 2016, the Company further amended its revolving credit facility to, among other things,
(a) increase the basket for unsecured debt issuances to $1.4 billion from $1.2 billion (of which $950 million was
then outstanding), (b) reaffirm the Company’s borrowing base of $700.0 million, and (c) increase the percentage
of projected oil and gas production that may be hedged by the Company during 2016. On December 13, 2016, the
Company further amended its revolving credit facility to, among other things, (a) reset the maturity date to
December 31, 2021, (b) adjust lenders, (c) increase the basket for unsecured debt issuances to $1.6 billion,
(d) increase the interest rates by 50 basis points, (e) increase the mortgage requirement to 85% (from 80%), and
(f) add deposit account control agreement language. On March 29, 2017, the Company further amended its
revolving credit facility to, among other things, amend the definition of the term EBITDAX to permit pro forma
treatment of acquisitions that involve the payment of consideration by Gulfport and its subsidiaries in excess of
$50.0 million and of dispositions of property or series of related dispositions of properties that yields gross
proceeds to Gulfport or any of its subsidiaries in excess of $50.0 million. On May 4, 2017, the revolving credit
facility was further amended to increase the borrowing base from $700.0 million to $1.0 billion, adjust certain of
the Company’s investment baskets and add five additional banks to the syndicate. On November 21, 2017, the
Company further amended its revolving credit facility to, among other things, (a) decrease the applicable rate for
all loans by 0.5% and (b) add a provision that allows Gulfport to elect a commitment amount (the “Elected
Commitment Amount”) that is less than the borrowing base. In connection with this amendment, the borrowing
base was set at $1.2 billion, with an elected commitment of $1.0 billion.
As of December 31, 2017, the Company did not have any outstanding borrowing under the revolving credit
facility and the total availability for future borrowings under this facility, after giving effect to an aggregate of
$241.0 million of letters of credit, was $759.0 million. The Company’s wholly-owned subsidiaries have
guaranteed the obligations of the Company under the revolving credit facility.
Advances under the revolving credit facility may be in the form of either base rate loans or eurodollar loans.
The interest rate for base rate loans is equal to (1) the applicable rate, which ranges from 0.50% to 1.50%, plus
(2) the highest of: (a) the federal funds rate plus 0.50%, (b) the rate of interest in effect for such day as publicly
announced from time to time by agent as its “prime rate,” and (c) the eurodollar rate for an interest period of one
month plus 1.00%. The interest rate for eurodollar loans is equal to (1) the applicable rate, which ranges from
1.50% to 2.50%, plus (2) the London interbank offered rate that appears on pages LIBOR01 or LIBOR02 of the
Reuters screen that displays such rate for deposits in U.S. dollars, or, if such rate is not available, the rate as
administered by ICE Benchmark Administration (or any other person that takes over administration of such rate)
per annum equal to the offered rate on such other page or service that displays on average London interbank
offered rate as determined by ICE Benchmark Administration (or any other person that takes over administration
of such rate) for deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major
New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” for
deposits in U.S. dollars.
F-22
The revolving credit facility contains customary negative covenants including, but not limited to,
restrictions on the Company’s and its subsidiaries’ ability to:
•
•
•
•
•
•
•
•
•
incur indebtedness;
grant liens;
pay dividends and make other restricted payments;
make investments;
make fundamental changes;
enter into swap contracts;
dispose of assets;
change the nature of their business; and
enter into transactions with affiliates.
The negative covenants are subject to certain exceptions as specified in the revolving credit facility. The
revolving credit facility also contains certain affirmative covenants, including, but not limited to the following
financial covenants:
(i) the ratio of net funded debt to EBITDAX (net income, excluding (i) any non-cash revenue or expense
associated with swap contracts resulting from ASC 815 and (ii) any cash or noncash revenue or expense
attributable to minority investments plus without duplication and, in the case of expenses, to the extent deducted
from revenues in determining net income, the sum of (a) the aggregate amount of consolidated interest expense
for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad
valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or
goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) exploration costs deducted
in determining net income under successful efforts accounting, (f) actual cash distributions received from
minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on
casualty events or business interruption, and (h) all reasonable transaction expenses related to dispositions and
acquisitions of assets, investments and debt and equity offerings (provided that expenses related to any
unsuccessful disposition will be limited to $3.0 million in the aggregate) for a twelve-month period may not be
greater than 4.00 to 1.00; and
(ii) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00.
The Company was in compliance with all covenants at December 31, 2017.
(2) In March 2011, the Company entered into a building loan agreement for its former headquarters building
in Oklahoma City, Oklahoma. This loan agreement refinanced the $2.4 million outstanding under the previous
building loan agreement. The new agreement, as amended in 2014, matured in December 2018 and bore interest
at the rate of 4.00% per annum, required monthly interest and principal payments of approximately $20,000 and
was collateralized by the Oklahoma City office building and associated land. The Company paid the balance of
the loan in full in February 2016.
(3) On October 17, 2012, the Company issued $250.0 million in aggregate principal amount of 7.75%
Senior Notes due 2020 (the “October Notes”) under an indenture among the Company, its subsidiary guarantors
and Wells Fargo Bank, National Association, as the trustee, (the “senior note indenture”). On December 21,
2012, the Company issued an additional $50.0 million in aggregate principal amount of 7.75% Senior Notes due
2020 (the “December Notes”) as additional securities under the senior note indenture. On August 18, 2014, the
Company issued an additional $300.0 million in aggregate principal amount of 7.75% Senior Notes due 2020
(the “August Notes”). The August Notes were issued as additional securities under the senior note indenture. The
October Notes, December Notes and the August Notes are collectively referred to as the “2020 Notes.”
F-23
On October 6, 2016, the Company commenced a cash tender offer to purchase any and all of its 2020 Notes,
which tender offer expired on October 13, 2016 and settled on October 14, 2016. Holders of the 2020 Notes that
were validly tendered and accepted at or prior to the expiration time of the tender offer, or who delivered the
2020 Notes pursuant to the guaranteed delivery procedures, received total cash consideration of $1,042 per
$1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement
date. An aggregate of $403.5 million in principal amount of the 2020 Notes was validly tendered in the tender
offer. The remaining 2020 Notes that were not tendered in the tender offer were redeemed by the Company. The
redemption payment included approximately $196.5 million in aggregate principal amount at a redemption price
of 103.875% of the principal amount of the redeemed 2020 Notes, plus accrued and unpaid interest thereon to the
redemption date. Upon deposit of the redemption payment with the paying agent on October 14, 2016, the
indenture governing the 2020 Notes was fully satisfied and discharged. The cash tender offer for the 2020 Notes
and redemption of the remaining 2020 Notes were funded with the net proceeds from the offering of the 6.000%
Senior Notes due 2024 (the “2024 Notes”) as discussed below and cash on hand.
(4) On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of 6.625% Senior
Notes due 2023 (the “2023 Notes”) to qualified institutional buyers pursuant to Rule 144A under the Securities
Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the “2023 Notes
Offering”). The Company received net proceeds of approximately $343.6 million after initial purchaser discounts
and commissions and estimated offering expenses.
The 2023 Notes were issued under an indenture, dated as of April 21, 2015, among the Company, the
subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee. In October 2015, the
2023 Notes were exchanged for a new issue of substantially identical debt securities registered under the
Securities Act. Pursuant to the indenture relating to the 2023 Notes, interest on the 2023 Notes accrues at a rate
of 6.625% per annum on the outstanding principal amount thereof, payable semi-annually on May 1 and
November 1 of each year. The 2023 Notes are not guaranteed by Grizzly Holdings, Inc. and will not be
guaranteed by any of the Company’s future unrestricted subsidiaries.
In connection with the 2023 Notes Offering, the Company and its subsidiary guarantors entered into a
registration rights agreement, dated as of April 21, 2015, pursuant to which the Company agreed to file a
registration statement with respect to an offer to exchange the 2023 Notes for a new issue of substantially
identical debt securities registered under the Securities Act. The exchange offer for the 2023 Notes was
completed on October 13, 2015.
(5) On October 14, 2016, the Company issued the 2024 Notes in aggregate principal amount of $650.0
million. The 2024 Notes were issued under an indenture, dated as of October 14, 2016, among the Company, the
subsidiary guarantors party thereto and the senior note indenture trustee (the “2024 Indenture”), to qualified
institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in
accordance with Regulation S under the Securities Act (the “2024 Notes Offering”). Under the 2024 Indenture,
interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof
from October 14, 2016, payable semi-annually on April 15 and October 15 of each year, commencing on
April 15, 2017. The 2024 Notes will mature on October 15, 2024. The Company received approximately $638.9
million in net proceeds from the offering of the 2024 Notes, which was used, together with cash on hand, to
purchase the outstanding 2020 Notes in a concurrent cash tender offer, to pay fees and expenses thereof, and to
redeem any of the 2020 Notes that remained outstanding after the completion of the tender offer.
(6) On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of 6.375%
Senior Notes due 2025 (the “2025 Notes”). The 2025 Notes were issued under an indenture, dated as of
December 21, 2016, among the Company, the subsidiary guarantors party thereto and the senior note indenture
trustee (the “2025 Indenture”), to qualified institutional buyers pursuant to Rule 144A under the Securities Act of
1933, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Under the 2025
Indenture, interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount
F-24
thereof from December 21, 2016, payable semi-annually on May 15 and November 15 of each year, commencing
on May 15, 2017. The 2025 Notes will mature on May 15, 2025. The Company received approximately $584.7
million in net proceeds from the offering of the 2025 Notes, which was used, together with the net proceeds from
the Company’s December 2016 common stock offering and cash on hand, to fund the cash portion of the
purchase price for the Vitruvian Acquisition. See Note 2 for additional discussion of the Vitruvian Acquisition.
In connection with each of the 2024 and 2025 Notes Offering, the Company and its subsidiary guarantors
entered into a registration rights agreement pursuant to which the Company agreed to file a registration statement
with respect to offers to exchange the 2024 Notes and 2025 Notes for a new issue of substantially identical debt
securities registered under the Securities Act. The exchange offers for the 2024 Notes and 2025 Notes were
completed on September 12, 2017.
(7) On October 11, 2017, the Company issued $450.0 million in aggregate principal amount of its 6.375%
Senior Notes due 2026 (the “2026 Notes”) to qualified institutional buyers pursuant to Rule 144A under the
Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. Interest
on the 2026 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof from
October 11, 2017, payable semi-annually on January 15 and July 15 of each year, commencing on January 15,
2018. The 2026 Notes will mature on January 15, 2026. The Company received approximately $444.3 million in
net proceeds from the offering of the 2026 Notes, a portion of which was used to repay all of the Company’s
outstanding borrowings under its secured revolving credit facility on October 11, 2017 and the balance was used
to fund the remaining outspend related to the Company’s 2017 capital development plans.
In connection with the 2026 Notes offering, the Company and its subsidiary guarantors entered into a
registration rights agreement pursuant to which the Company agreed to file a registration statement with respect
to an offer to exchange the 2026 Notes for a new issue of substantially identical debt securities registered under
the Securities Act. On January 18, 2018, the Company filed a registration statement on Form S-4 with respect to
an offer to exchange the 2026 Notes for substantially identical debt securities registered under the Securities Act,
which registration statement was declared effective by the SEC on February 12, 2018. The Company commenced
the exchange offer relating to the 2026 notes on February 16, 2018, which it expects to close in March of 2018.
(8) The October Notes were issued at a price of 98.534% resulting in a gross discount of $3.7 million and an
effective rate of 8.000%. The December Notes were issued at a price of 101.000% resulting in a gross premium
of $0.5 million and an effective rate of 7.531%. The August Notes were issued at a price of 106.000% resulting
in a gross premium of $18.0 million and an effective rate of 6.561%. The 2023 Notes, 2024 Notes, 2025 Notes
and 2026 Notes were issued at par. The premium and discount was amortized using the effective interest method
until the bonds were redeemed, at which point the remaining premium and discount of $10.8 million was written
off and is included in loss on debt extinguishment on the consolidated statements of operations.
(9) In accordance with ASU 2015-03, loan issuance cost related to the 2023 Notes, the 2024 Notes, the 2025
Notes and the 2026 Notes (collectively the “Notes”) have been presented as a reduction to the Notes. At
December 31, 2017, total unamortized debt issuance costs were $5.2 million for the 2023 Notes, $9.9 million for
the 2024 Notes, $14.0 million for the 2025 Notes and $5.5 million for the 2026 Notes. In addition, loan
commitment fee costs for the construction loan agreement described immediately below were $0.1 million at
December 31, 2017.
(10) On June 4, 2015, the Company entered into a construction loan agreement (the “Construction Loan”)
with InterBank for the construction of a new corporate headquarters in Oklahoma City, which was substantially
completed in December 2016. The Construction Loan allows for maximum principal borrowings of $24.5 million
and required the Company to fund 30% of the cost of the construction before any funds could be drawn, which
occurred in January 2016. Interest accrues daily on the outstanding principal balance at a fixed rate of 4.50% per
annum and was payable on the last day of the month through May 31, 2017. Starting June 30, 2017, the Company
began making monthly payments of principal and interest, with the final payment due June 4, 2025. At
December 31, 2017, the total borrowings under the Construction loan were approximately $23.7 million.
F-25
Interest Expense
The following schedule shows the components of interest expense for the year ended December 31:
Cash paid for interest
Change in accrued interest
Capitalized interest
Amortization of loan costs
Amortization of note discount and premium
Total interest expense
2017
2016
2015
$101,958
10,699
(9,470)
5,011
(In thousands)
$68,966
1,768
(9,148)
3,660
— (1,716)
$ 59,736
4,011
(13,580)
3,219
(2,165)
$108,198
$63,530
$ 51,221
The Company capitalized approximately $9.5 million and $8.7 million in interest expense to undeveloped
oil and natural gas properties during the years ended December 31, 2017 and 2016, respectively. During the year
ended December 31, 2016, the Company also capitalized approximately $0.4 million in interest expense related
to building construction. Construction on the building was completed in December 2016 and, as such, the
Company did not capitalize any interest expense related to building construction for the year ended December 31,
2017.
7. COMMON STOCK OPTIONS, RESTRICTED STOCK AND CHANGES IN CAPITALIZATION
Options
In January 2005, the Company adopted the 2005 Stock Incentive Plan (“2005 Plan”), which is administered
by the Compensation Committee (the “Committee”). Under the terms of the 2005 Plan, the Committee may
determine when options shall be granted, to which eligible participants options shall be granted, the number of
shares covered by such options, the purchase price or exercise price of such options, the vesting periods of such
options and the exercisable period of such options. Eligible participants are defined as employees, consultants,
and directors of the Company.
On April 20, 2006, the Company amended and restated the 2005 Plan to (i) include (a) incentive stock
options, (b) nonstatutory stock options, (c) restricted awards (restricted stock and restricted stock units),
(d) performance awards and (e) stock appreciation rights and (ii) increase the maximum aggregate amount of
common stock that may be issued under the 2005 Plan from 1,904,606 shares to 3,000,000 shares, including the
627,337 shares underlying options granted to employees under the Plan prior to adoption of the 2005 Plan. As of
December 31, 2017, the Company had granted 997,269 options for the purchase of shares of the Company’s
common stock and 1,143,217 shares of restricted stock under the 2005 Plan. No additional securities will be
issued under the Plan.
On April 19, 2013, the Company amended and restated the 2005 Plan with the 2013 Restated Stock
Incentive Plan (“2013 Plan”). The 2013 Plan increased the numbers of shares that may be awarded from
3,000,000 to 7,500,000 shares, including the 627,337 shares underlying options granted to employees under the
2005 Plan. The shares of stock issued once the options are exercised will be from authorized but unissued
common stock. As of December 31, 2017, the Company had granted 1,939,053 shares of restricted stock under
the 2013 Plan.
Issuance of Common Stock
On April 21, 2015, the Company issued 10,925,000 shares of its common stock in an underwritten public
offering. The net proceeds from this equity offering were approximately $501.8 million after underwriting
discounts and commissions and offering expenses. The Company used a portion of these net proceeds, together
F-26
with a portion of the net proceeds from its concurrent senior notes offering (see Note 6), to repay all amounts
outstanding at that time under its revolving credit facility and to fund the acquisition of Paloma Partners III, LLC
and used the remaining net proceeds from these offerings for general corporate purposes, including the funding
of a portion of its 2015 capital development plans.
On June 12, 2015, the Company issued 11,500,000 shares of its common stock in an underwritten public
offering. The net proceeds from this equity offering were approximately $479.7 million after underwriting
discounts and commissions and offering expenses. The Company used a portion of the net proceeds to fund the
purchase of acreage in Monroe County, Ohio and used the remaining funds for general corporate purposes,
including the funding of a portion of its 2015 capital development plans.
On March 15, 2016, the Company issued 16,905,000 shares of its common stock in an underwritten public
offering (which included 2,205,000 shares sold pursuant to an option to purchase additional shares of the
Company’s common stock granted by the Company to, and exercised in full by, the underwriters). The net
proceeds from this equity offering were approximately $411.7 million, after underwriting discounts and
commissions and offering expenses. The Company used the net proceeds from this offering primarily to fund a
portion of its 2017 capital development plan and for general corporate purposes.
On December 21, 2016, the Company issued an aggregate 33,350,000 shares of its common stock in an
underwritten public offering (which included 4,350,000 shares subject to an option to purchase additional shares
exercised by the underwriters). The net proceeds from this equity offering were approximately $698.8 million,
after deducting underwriting discounts and commissions and estimated offering expenses. The Company used the
net proceeds from this offering, together with the net proceeds from the offering of the 2025 Notes and cash on
hand, to fund the cash portion of the purchase price for the Vitruvian Acquisition (see Note 2).
On February 17, 2017, the Company completed the Vitruvian Acquisition for a total initial purchase price of
approximately $1.85 billion, consisting of $1.35 billion in cash, subject to certain adjustments, and
approximately 23.9 million shares of the Company’s common stock (of which approximately 5.2 million shares
are subject to the indemnity escrow). See Note 2 for additional discussion of the Vitruvian Acquisition.
8.
STOCK-BASED COMPENSATION
During the years ended December 31, 2017, 2016 and 2015 the Company’s stock-based compensation cost
was $10.6 million, $12.3 million and $14.4 million, respectively, of which the Company capitalized $4.2 million,
$4.9 million and $5.7 million, respectively, relating to its exploration and development efforts.
The fair value of each option award is estimated on the date of grant using the Black-Scholes option
valuation model. Expected volatilities are based on the historical volatility of the market price of Gulfport’s
common stock over a period of time ending on the grant date. Based upon the historical experience of the
Company, the expected term of options granted is equal to the vesting period plus one year. The risk-free rate for
periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of
the grant. The 2013 Restated Stock Incentive Plan (which amended and restated the 2005 Plan) provides that all
options must have an exercise price not less than the fair value of the Company’s common stock on the date of
the grant.
No stock options were issued during the years ended December 31, 2017, 2016 and 2015.
The Company has not declared dividends and does not intend to do so in the foreseeable future, and thus did
not use a dividend yield. In each case, the actual value that will be realized, if any, depends on the future
performance of the common stock and overall stock market conditions. There is no assurance that the value an
optionee actually realizes will be at or near the value estimated using the Black-Scholes model.
F-27
A summary of the status of stock options and related activity for the years ended December 31, 2017, 2016
and 2015 is presented below:
Options outstanding at January 1, 2015
Granted
Exercised
Forfeited/expired
Options outstanding at December 31, 2015
Granted
Exercised
Forfeited/expired
Options outstanding at December 31, 2016
Granted
Exercised
Forfeited/expired
Options outstanding at December 31, 2017
Options exercisable at December 31, 2017
Shares
5,000
—
(5,000)
—
—
—
—
—
—
—
—
—
—
—
Weighted
Average
Exercise Price
per Share
$9.07
Weighted
Average
Remaining
Contractual Term
0.69
Aggregate
Intrinsic
Value
(In thousands)
$ 163
—
9.07
—
—
—
—
—
—
—
—
—
$ —
$ —
124
$ —
—
$ —
—
$ —
$ —
—
—
—
—
The following table summarizes restricted stock activity for the twelve months ended December 31, 2017,
2016 and 2015:
Number of
Unvested
Restricted Shares
Weighted
Average
Grant Date
Fair Value
387,245
352,605
(236,812)
(18,799)
484,239
451,241
(252,566)
(69,858)
613,056
876,846
(423,977)
(89,898)
976,027
$55.87
35.99
52.39
45.21
$43.51
$27.78
43.94
33.43
$32.90
$15.14
29.90
27.91
$18.71
Granted
Vested
Forfeited
Granted
Vested
Forfeited
Granted
Vested
Forfeited
Unvested shares as of January 1, 2015
Unvested shares as of December 31, 2015
Unvested shares as of December 31, 2016
Unvested shares as of December 31, 2017
F-28
Unrecognized compensation expense as of December 31, 2017 related to outstanding stock options and
restricted shares was $14.4 million. The expense is expected to be recognized over a weighted average period of
1.46 years.
9.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents,
accounts receivable, accounts payable and accrued liabilities, and current debt are carried at cost, which
approximates market value due to their short-term nature. Long-term debt related to the building loan is carried at
cost, which approximates market value based on the borrowing rates currently available to the Company with
similar terms and maturities.
At December 31, 2017, the carrying value of the outstanding debt represented by the Notes was $2.0 billion
including the unamortized debt issuance cost of approximately $5.2 million related to the 2023 Notes,
approximately $9.9 million related to the 2024 Notes, approximately $14.0 million related to the 2025 Notes, and
approximately $5.5 million related to the 2026 Notes. Based on the quoted market price, the fair value of the
Notes was determined to be approximately $2.1 billion at December 31, 2017.
10. INCOME TAXES
The income tax provision consists of the following:
Current:
State
Federal
Deferred:
State
Federal
Total income tax expense (benefit) provision
2017
2016
2015
(In thousands)
$ 2,167
3,362
$ (1,330) $
(19,770)
(1,069)
(439)
(118)
(3,602)
(386)
18,573
(14,218)
(240,275)
$ 1,809
$ (2,913) $(256,001)
A reconciliation of the statutory federal income tax amount to the recorded expense follows:
Income (loss) before federal income taxes
Expected income tax at statutory rate
State income taxes
Other differences
Intraperiod tax allocation
Remeasurement due to Tax Cut and Jobs Act
Change in valuation allowance due to current year activity
Change in valuation allowance due to Tax Cuts and Jobs Act
2017
2016
2015
$ 436,961
(In thousands)
$(982,622) $(1,480,885)
152,936
2,299
5,731
—
190,034
(158,704)
(190,487)
(343,918)
(5,883)
4,293
(1,349)
—
343,944
—
(518,310)
(15,908)
(420)
—
—
278,637
—
Income tax expense (benefit) recorded
$
1,809
$
(2,913) $ (256,001)
F-29
The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred
tax assets and liabilities at December 31, 2017, 2016 and 2015 are estimated as follows:
Deferred tax assets:
Net operating loss carryforward
Oil and gas property basis difference
Investment in pass through entities
FASB ASC 718 compensation expense
Business energy investment tax credit
AMT credit
Charitable contributions carryover
Unrealized loss on hedging activities
Foreign tax credit carryforwards
Accrued liabilities
ARO liability
Non-oil and gas property basis difference
State net operating loss carryover
Total deferred tax assets
Valuation allowance for deferred tax assets
Deferred tax assets, net of valuation allowance
Deferred tax liabilities:
Non-oil and gas property basis difference
Unrealized gain on hedging activities
Total deferred tax liabilities
Net deferred tax asset
2017
2016
2015
(In thousands)
$ 120,626
151,260
12,343
813
369
—
255
—
2,074
285
15,897
171
6,954
$ 162,073
386,302
27,469
2,084
369
3,842
303
48,317
2,074
397
12,107
—
5,351
$ 46,209
292,838
14,034
1,922
—
23,629
146
—
2,074
—
9,415
—
4,344
311,047
(298,830)
650,688
(645,841)
394,611
(303,246)
12,217
4,847
91,365
—
11,009
11,009
155
—
155
715
66,422
67,137
$
1,208
$
4,692
$ 24,228
The Company has an available federal tax net operating loss carryforward estimated at approximately
$574.4 million as of December 31, 2017. This carryforward will begin to expire in the year 2023. Based upon the
December 31, 2017 net deferred tax asset position and a recent history of cumulative losses, management
believes that there is sufficient negative evidence to place a valuation allowance on the net deferred tax asset that
may not be utilized based upon a more likely than not basis. The Company also has state net operating loss
carryovers of $121.3 million that began to expire in 2017 and federal foreign tax credit carryovers of $2.1 million
which began to expire in 2017. The Company believes that it can utilize an Oklahoma state NOL through
carrybacks. Therefore, the Company has recorded a total valuation allowance of $298.8 million related to the
remaining net deferred tax asset.
The Tax Act was enacted on December 22, 2017. The Tax Act reduces the US federal corporate tax rate
from 35% to 21% effective January 1, 2018. Deferred tax assets and liabilities are measured using the enacted tax
rates expected to apply to taxable income in the years in which those temporary differences are expected to
reverse. As a result of the reduction in the statutory rate, the Company has remeasured its deferred tax balances,
the effects of which are reflected in the rate reconciliation shown in the table above. The Company has applied
the provisions of SEC Staff Accounting Bulletin No. 118 (“SAB 118”). SAB 118 allows for a measurement
period in which companies can either use provisional estimates for changes resulting from the Tax Act or apply
the tax laws that were in effect immediately prior to the Tax Act being enacted if estimates cannot be determined
at the time of the preparation of the financial statements until the actual impacts can be determined. The
Company has recorded a provisional estimate of $0.5 million benefit for the impact of the Tax Act within its
December 31, 2017 financial statements. The Company will continue to evaluate the impacts of the Tax Act on
deferred taxes, compensation and international provisions and will record adjustments, as needed, based on
changes to its estimates.
F-30
The Company’s income tax benefit in 2016 and 2015 was primarily attributable to the Company recording a
full cost ceiling impairment of $715.5 million and $1.4 billion against the oil and gas assets. The Company’s
income tax expense in 2017 is primarily the result of a change in state income tax positions.
As of December 31, 2017, the amount of unrecognized tax benefits related to federal and state tax liabilities
associated with uncertain tax positions was immaterial.
11. EARNINGS PER SHARE
Reconciliations of the components of basic and diluted net income per common share are presented in the
tables below:
Basic:
For the Year Ended December 31,
2017
2016
2015
Income
Shares
Per
Share
Loss
Shares
Per
Share
Loss
Shares
Per
Share
(In thousands, except share data)
Net income (loss)
$435,152 179,834,146 $2.42 $(979,709) 122,952,866 $(7.97) $(1,224,884) 99,792,401 $(12.27)
Effect of dilutive securities:
Stock options and
awards
—
418,878
—
—
—
—
Diluted:
Net income (loss)
$435,152 180,253,024 $2.41 $(979,709) 122,952,866 $(7.97) $(1,224,884) 99,792,401 $(12.27)
There were no potential shares of common stock that were considered anti-dilutive for the year ended
December 31, 2017. There were 539,988 and 449,880 shares of common stock that were considered anti-dilutive
for the years ended 2016 and 2015, respectively.
•
DERIVATIVE INSTRUMENTS
Natural Gas, Oil and Natural Gas Liquids Derivative Instruments
The Company seeks to reduce its exposure to unfavorable changes in natural gas, oil and natural gas liquids
prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed
price swaps, basis swaps and various types of option contracts. These contracts allow the Company to predict
with greater certainty the effective oil, natural gas and natural gas liquids prices to be received for hedged
production and benefit operating cash flows and earnings when market prices are less than the fixed prices
provided in the contracts. However, the Company will not benefit from market prices that are higher than the
fixed prices in the contracts for hedged production.
F-31
Fixed price swaps are settled monthly based on differences between the fixed price specified in the contract
and the referenced settlement price. When the referenced settlement price is less than the price specified in the
contract, the Company receives an amount from the counterparty based on the price difference multiplied by the
volume. Similarly, when the referenced settlement price exceeds the price specified in the contract, the Company
pays the counterparty an amount based on the price difference multiplied by the volume. The prices contained in
these fixed price swaps are based on the NYMEX Henry Hub for natural gas, Argus Louisiana Light Sweet
Crude for oil, the NYMEX West Texas Intermediate for oil, and Mont Belvieu for propane and pentane. Below is
a summary of the Company’s open fixed price swap positions as of December 31, 2017.
2018
2019
2018
2018
2018
2018
Location
Daily Volume
(MMBtu/day)
Weighted
Average Price
NYMEX Henry Hub
NYMEX Henry Hub
908,000
269,000
$ 3.06
$ 2.93
Location
ARGUS LLS
NYMEX WTI
Location
Mont Belvieu C3
Mont Belvieu C5
Daily Volume
(Bbls/day)
Weighted
Average Price
1,500
4,000
$56.22
$52.20
Daily Volume
(Bbls/day)
Weighted
Average Price
3,500
500
$28.03
$46.62
The Company sold call options and used the associated premiums to enhance the fixed price for a portion of
the fixed price natural gas swaps listed above. Each short call option has an established ceiling price. When the
referenced settlement price is above the price ceiling established by these short call options, the Company pays
its counterparty an amount equal to the difference between the referenced settlement price and the price ceiling
multiplied by the hedged contract volumes.
January 2018 - March 2018
April 2018 - March 2019
April 2019 - December 2019
Location
Daily Volume
(MMBtu/day)
Weighted
Average Price
NYMEX Henry Hub
NYMEX Henry Hub
NYMEX Henry Hub
20,000
50,000
30,000
$2.91
$3.13
$3.10
For a portion of the natural gas fixed price swaps listed above, the counterparty has an option to extend the
original terms an additional twelve months for the period January 2019 through December 2019. The option to
extend the terms expires in December 2018. If executed, the Company would have additional fixed price swaps
for 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu.
In addition, the Company has entered into natural gas basis swap positions, which settle on the pricing index
to basis differential of NPGL Mid-Continent to NYMEX Henry Hub. As of December 31, 2017, the Company
had the following natural gas basis swap positions for NPGL Mid-Continent.
2018
Balance sheet presentation
Location
Daily Volume
(MMBtu/day)
Hedged
Differential
NPGL Mid-Continent
12,000
$(0.26)
The Company reports the fair value of derivative instruments on the consolidated balance sheets as
derivative instruments under current assets, noncurrent assets, current liabilities, and noncurrent liabilities on a
gross basis. The Company determines the current and noncurrent classification based on the timing of expected
F-32
future cash flows of individual trades. The following table presents the fair value of the Company’s derivative
instruments on a gross basis at December 31, 2017 and 2016:
Short-term derivative instruments - asset
Long-term derivative instruments - asset
Short-term derivative instruments - liability
Long-term derivative instruments - liability
Gains and losses
December 31,
2017
2016
(In thousands)
3,488
$
$
5,696
$119,219
$ 26,759
$78,847
$ 8,685
$32,534
$ 2,989
The following table presents the gain and loss recognized in net gain (loss) on natural gas, oil and NGL
derivatives in the accompanying consolidated statements of operations for the years ended December 31, 2017,
2016, and 2015.
Natural gas derivatives
Oil derivatives
Natural gas liquids derivatives
Total
Gain (loss) on derivative instruments
For the Year Ended December 31,
2017
2016
2015
$232,143
(3,350)
(15,114)
(In thousands)
$(165,933) $182,993
19,201
1,319
(5,387)
(3,186)
$213,679
$(174,506) $203,513
The Company delivered approximately 68% of its 2017 production under fixed price swaps.
Offsetting of derivative assets and liabilities
As noted above, the Company records the fair value of derivative instruments on a gross basis. The
following table presents the gross amounts of recognized derivative assets and liabilities in the consolidated
balance sheets and the amounts that are subject to offsetting under master netting arrangements with
counterparties, all at fair value.
Derivative instruments, gross Netting adjustments Derivative instruments, net
As of December 31, 2017
$ 87,532
$ (35,523)
(In thousands)
$(22,199)
$ 22,199
$ 65,333
$ (13,324)
Derivative instruments, gross Netting adjustments Derivative instruments, net
As of December 31, 2016
$
9,184
$(145,978)
(In thousands)
$ (9,184)
$ 9,184
$
—
$(136,794)
Derivative assets
Derivative liabilities
Derivative assets
Derivative liabilities
Concentration of Credit Risk
By using derivative instruments that are not traded on an exchange, the Company is exposed to the credit
risk of its counterparties. Credit risk is the risk of loss from counterparties not performing under the terms of the
derivative instrument. When the fair value of a derivative instrument is positive, the counterparty is expected to
F-33
owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the
Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial
institutions deemed by management as competent and competitive market makers. The Company’s derivative
contracts are with multiple counterparties to lessen its exposure to any individual counterparty. Additionally, the
Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the
Company’s counterparties is subject to periodic review. None of the Company’s derivative instrument contracts
contain credit-risk related contingent features. Other than as provided by the Company’s revolving credit facility,
the Company is not required to provide credit support or collateral to any of its counterparties under its derivative
instruments, nor are the counterparties required to provide credit support to the Company.
13. FAIR VALUE MEASUREMENTS
The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair
value in accordance with FASB ASC 820, “Fair Value Measurement and Disclosures” (“FASB ASC 820”).
FASB ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability
(exit price) in an orderly transaction between market participants at the measurement date. The statement
establishes market or observable inputs as the preferred sources of values, followed by assumptions based on
hypothetical transactions in the absence of market inputs. The statement requires fair value measurements be
classified and disclosed in one of the following categories:
Level 1 - Quoted prices in active markets for identical assets and liabilities.
Level 2 - Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or
similar instruments in markets that are not active and model-derived valuations whose inputs are observable or
whose significant value drivers are observable.
Level 3 - Significant inputs to the valuation model are unobservable.
Valuation techniques that maximize the use of observable inputs are favored. Financial assets and liabilities
are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.
The assessment of the significance of a particular input to the fair value measurement requires judgment and may
affect the placement of assets and liabilities within the levels of the fair value hierarchy. Reclassifications of fair
value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each
quarter.
The following tables summarize the Company’s financial and non-financial liabilities by FASB ASC
820 valuation level as of December 31, 2017 and 2016:
Assets:
Derivative Instruments
Liabilities:
Derivative Instruments
Assets:
Derivative Instruments
Liabilities:
Derivative Instruments
F-34
December 31, 2017
Level 1
Level 2
Level 3
(In thousands)
$— $87,532
$—
$— $35,523
$—
December 31, 2016
Level 1
Level 2
Level 3
(In thousands)
$— $
9,184
$—
$— $145,978
$—
The Company estimates the fair value of all derivative instruments using industry-standard models that
considered various assumptions including current market and contractual prices for the underlying instruments,
implied volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially
all of these inputs are observable in the marketplace throughout the full term of the instrument and can be
supported by observable data.
The estimated fair values of proved oil and gas properties assumed in business combinations are based on a
discounted cash flow model and 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. The estimated fair values of unevaluated oil and gas properties was based on geological studies, historical
well performance, location and applicable mineral lease terms. Based on the unobservable nature of certain of the
inputs, the estimated fair value of the oil and gas properties assumed is deemed to use Level 3 inputs. The asset
retirement obligations assumed as part of the business combination were estimated using the same assumptions
and methodology as described below. See Note 2 for further discussion of the Company’s acquisitions.
The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410,
“Asset Retirement and Environmental Obligations” (“FASB ASC 410”). The initial measurement of asset
retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal
estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the
inputs, including plugging costs and reserve lives, the initial measurement of the asset retirement obligation
liability is deemed to use Level 3 inputs. See Note 3 for further discussion of the Company’s asset retirement
obligations. Asset retirement obligations incurred or revised during the year ended December 31, 2017 were
approximately $16.3 million and $26.0 million, respectively.
The fair value of the common stock received from Mammoth Energy in connection with the Company’s
contribution of all of its membership interests in Sturgeon, Stingray Energy and Stingray Cementing was
estimated using Level 1 inputs, as the price per share was a quoted price in an active market for identical
Mammoth Energy common shares.
Due to the unobservable nature of the inputs, the fair value of the Company’s investment in Grizzly was
estimated using assumptions that represent Level 3 inputs. The Company estimated the fair value of the
investment as of March 31, 2016 to be approximately $39.1 million. See Note 4 for further discussion of the
Company’s investment in Grizzly.
Due to the unobservable nature of the inputs, the fair value of the Company’s investment in Strike Force
was estimated using assumptions that represent Level 3 inputs. The Company’s estimated fair value of the
investment as of the February 1, 2016 contribution date was $22.5 million. See Note 4 for further discussion of
the Company’s contribution to Strike Force.
14. RELATED PARTY TRANSACTIONS
In the ordinary course of business, the Company has conducted business activities with certain related
parties.
Stingray Cementing provides well cementing services. Stingray Cementing was previously 50% owned by
the Company until its contribution to Mammoth Energy in June 2017 as discussed above in Note 4. At the date of
the contribution, the Company owed Stingray Cementing approximately $0.5 million. As of December 31, 2016,
the Company owed Stingray Cementing approximately $0.5 million related to these services.
Stingray Energy provides rental tools for land-based oil and natural gas drilling, completion and workover
activities as well as the transfer of fresh water to wellsites. Stingray Energy was previously 50% owned by the
F-35
Company until its contribution to Mammoth Energy in June 2017 as discussed above in Note 4. At the date of the
contribution, the Company owed Stingray Energy approximately $1.6 million. As of December 31, 2016, the
Company owed Stingray Energy approximately $3.6 million related to these services.
As of December 31, 2017, the Company held approximately 25.1% of Mammoth Energy’s outstanding
common stock as discussed above in Note 4. Approximately $2.1 million of services provided by Mammoth
Energy are included in lease operating expenses in the consolidated statements of operations for the year ended
December 31, 2017. Approximately $196.5 million and $110.5 million of services provided by Mammoth
Energy are included in oil and natural gas properties before elimination of intercompany profits on the
accompanying consolidated balance sheets at December 31, 2017 and 2016, respectively. At December 31, 2017
and 2016, the Company owed Mammoth Energy approximately $32.0 million and $23.5 million, respectively,
related to these services.
Strike Force, which is 25% owned by the Company, develops natural gas gathering assets in dedicated areas
as discussed above in Note 4. At December 31, 2017 and 2016 the Company owed approximately $8.4 million
and $1.6 million, respectively, to Strike Force for these related services. Approximately $23.1 million and
$1.8 million of services provided by Strike Force are included in midstream gathering and processing on the
accompanying consolidated statement of operations for the years ended December 31, 2017 and 2016,
respectively.
15. COMMITMENTS
Plugging and Abandonment Funds
In connection with the Company’s acquisition in 1997 of the remaining 50% interest in its WCBB
properties, the Company assumed the seller’s (Chevron) obligation to contribute approximately $18,000 per
month through March 2004 to a plugging and abandonment trust and the obligation to plug a minimum of
20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production
from these properties until abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the
Company could access the trust for use in plugging and abandonment charges associated with the property,
although it has not yet done so. As of December 31, 2017, the plugging and abandonment trust totaled
approximately $3.1 million. At December 31, 2017, the Company had plugged 551 wells at WCBB since it
began its plugging program in 1997, which management believes fulfills its current minimum plugging
obligation.
Contributions to 401(k) Plan
Gulfport sponsors a 401(k) and Profit Sharing plan under which eligible employees may contribute up to
100% of their total compensation up to the maximum pre-tax threshold through salary deferrals. Also under the
plan, the Company will make a bi-weekly contribution on behalf of each employee equal to at least 3% of his or
her salary, regardless of the employee’s participation in salary deferrals and may also make additional
discretionary contributions. During the years ended December 31, 2017, 2016 and 2015, Gulfport incurred
$3.0 million, $1.7 million, and $1.4 million, respectively, in contributions expense related to this plan.
Employment Agreements
On April 22, 2014, the Board of Directors appointed Michael G. Moore as Chief Executive Officer of the
Company. The Company and Mr. Moore entered into an amended and restated employment agreement. The
agreement has a three-year term commencing effective April 22, 2014, which was amended effective as of
April 29, 2015. The employment agreement, as amended and restated as of April 29, 2015, provides, among
other things, for a minimum salary level, subject to review and potential increase by the Compensation
Committee and/or the Board of Directors, as well as participation in the Company’s incentive plans and other
employee benefits.
F-36
On March 13, 2015, the Company entered into an employment agreement with Ross Kirtley, the Company’s
Chief Operating Officer. The agreement had a two-year term commencing effective April 22, 2014. This
agreement provided, among other things, for a minimum salary level, subject to review and potential increase by
the Compensation Committee and/or the Board of Directors, as well as participation in the Company’s incentive
plans and other employee benefits. On August 5, 2016, Mr. Kirtley’s employment as the Company’s Chief
Operating Officer terminated.
In connection with Mr. Kirtley’s termination, the Company entered into a separation and release agreement
with Mr. Kirtley, dated as of November 2, 2016 (the “Separation Agreement”), pursuant to which the Company
agreed to provide Mr. Kirtley with (i) the cash compensation specified in his employment agreement, (ii) health
care benefits for Mr. Kirtley and his eligible dependents for up to eighteen (18) months following the termination
date, (iii) his company vehicle, (iv) the vesting of 3,000 shares of restricted stock and (v) the vesting of 14,820
restricted stock units provided that such restricted stock units will be settled in four substantially equal annual
installments beginning in March 2017 in accordance with the original vesting schedule. All other restricted stock
and restricted stock unit awards granted to Mr. Kirtley were forfeited and terminated.
Under the Separation Agreement, Mr. Kirtley is subject to certain covenants regarding confidentiality, non-
solicitation, non-competition, trade secrets, unfair competition and inventions. The Separation Agreement also
contains customary waiver and release provisions pursuant to which Mr. Kirtley waived, released and discharged
the Company and certain other related parties from any and all claims that Mr. Kirtley may have had against the
Company or such other parties as of the date of the Separation Agreement.
On March 13, 2015, the Company entered into an employment agreement with Aaron Gaydosik, the
Company’s Chief Financial Officer. The agreement had a three-year term commencing effective August 11,
2014. This agreement provided, among other things, for a minimum salary level, subject to review and potential
increase by the Compensation Committee and/or the Board of Directors, as well as participation in the
Company’s incentive plans and other employee benefits. Mr. Gaydosik’s employment agreement was terminated
upon his resignation as the Company’s Chief Financial Officer, effective January 4, 2017. As provided in such
employment agreement, upon resignation, Mr. Gaydosik was entitled to any of his earned but unpaid salary
through the date of resignation. Any unvested awards granted to Mr. Gaydosik under the Company’s equity
incentive plan lapsed.
The Company has also entered into employment agreements with certain members of management that
provide for one-year terms commencing as of January 1, 2017 (the “Initial Period”), which automatically extend
for successive one-year periods unless the Company or the executive elects to not extend the term by giving
written notice to the other party at least 30 days’ prior to the end of the Initial Period or any anniversary thereof.
The agreements provide for, among other things, compensation, benefits and severance payments. The
employment agreements also contains certain termination and change of control provisions.
Firm Transportation Commitments
The Company had approximately 2,629,800 MMBtu per day of firm sales contracted with third parties. The
table below presents these commitments at December 31, 2017 as follows:
2018
2019
2020
2021
2022
Thereafter
Total
F-37
(MMBtu per day)
560,800
659,000
526,000
372,000
272,000
240,000
2,629,800
The Company also had approximately $3.8 billion of firm transportation contracted with third parties. The
table below presents these commitments at December 31, 2017 as follows:
2018
2019
2020
2021
2022
Thereafter
Total
Operating Leases
(In thousands)
$ 248,047
251,644
247,581
246,620
246,620
2,511,853
$3,752,365
The Company leases office facilities under non-cancellable operating leases exceeding one year. Future
minimum lease commitments under these leases at December 31, 2017 are as follows:
2018
2019
Total
(In thousands)
$136
54
$190
Presented below is rent expense for the years ended December 31, 2017, 2016 and 2015, respectively.
Minimum rentals
Less: Sublease rentals
Other Commitments
For the years ended December 31,
2017
2016
2015
$343
—
$343
(In thousands)
$840
—
$840
$759
8
$751
Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie that expires on
September 30, 2018. Pursuant to this agreement, the Company has agreed to purchase annual and monthly
amounts of proppant sand subject to exceptions specified in the agreement at a fixed price per ton, subject to
certain adjustments, plus agreed costs and expenses. Failure by either Muskie or the Company to deliver or
accept the minimum monthly amount results in damages calculated per ton based on the difference between the
monthly obligation amount and the amount actually delivered or accepted, as applicable. The Company incurred
$1.9 million related to non-utilization fees during the year ended 2016. The Company did not incur any non-
utilization fees during the year ended December 31, 2017.
Effective October 1, 2014, the Company entered into an Amended and Restated Master Services Agreement
for pressure pumping services with Stingray Pressure that expires on September 30, 2018. Pursuant to this
agreement, Stingray Pressure has agreed to provide hydraulic fracturing, stimulation and related completion and
rework services to the Company and the Company has agreed to pay Stingray Pressure a monthly service fee plus
the associated costs of the services provided.
F-38
Future minimum commitments under these agreements at December 31, 2017 are as follows:
2018
Total
16. CONTINGENCIES
(In thousands)
$39,330
$39,330
In two separate complaints, one filed by the State of Louisiana and the Parish of Cameron in the 38th
Judicial District Court for the Parish of Cameron on February 9, 2016 and the other filed by the State of
Louisiana and the District Attorney for the 15th Judicial District of the State of Louisiana in the 15th Judicial
District Court for the Parish of Vermilion on July 29, 2016, the Company was named as a defendant, among
26 oil and gas companies, in the Cameron Parish complaint and among more than 40 oil and gas companies in
the Vermilion Parish complaint, or the Complaints. The Complaints were filed under the State and Local Coastal
Resources Management Act of 1978, as amended, and the rules, regulations, orders and ordinances adopted
thereunder, which the Company referred to collectively as the CZM Laws, and allege that certain of the
defendants’ oil and gas exploration, production and transportation operations associated with the development of
the East Hackberry and West Hackberry oil and gas fields, in the case of the Cameron Parish complaint, and the
Tigre Lagoon and Lac Blanc oil and gas fields, in the case of the Vermilion Parish complaint, were conducted in
violation of the CZM Laws. The Complaints allege that such activities caused substantial damage to land and
waterbodies located in the coastal zone of the relevant Parish, including due to defendants’ design, construction
and use of waste pits and the alleged failure to properly close the waste pits and to clear, re-vegetate, detoxify
and return the property affected to its original condition, as well as the defendants’ alleged discharge of waste
into the coastal zone. The Complaints also allege that the defendants’ oil and gas activities have resulted in the
dredging of numerous canals, which had a direct and significant impact on the state coastal waters within the
relevant Parish and that the defendants, among other things, failed to design, construct and maintain these canals
using the best practical techniques to prevent bank slumping, erosion and saltwater intrusion and to minimize the
potential for inland movement of storm-generated surges, which activities allegedly have resulted in the erosion
of marshes and the degradation of terrestrial and aquatic life therein. The Complaints also allege that the
defendants failed to re-vegetate, refill, clean, detoxify and otherwise restore these canals to their original
condition. In these two petitions, the plaintiffs seek damages and other appropriate relief under the CZM Laws,
including the payment of costs necessary to clear, re-vegetate, detoxify and otherwise restore the affected coastal
zone of the relevant Parish to its original condition, actual restoration of such coastal zone to its original
condition, and the payment of reasonable attorney fees and legal expenses and pre-judgment and post judgment
interest.
The Company was served with the Cameron complaint in early May 2016 and with the Vermilion
Complaint in early September 2016. The Louisiana Attorney General and the Louisiana Department of Natural
Resources intervened in both the Cameron Parish suit and the Vermilion Parish suit. Shortly after the Complaints
were filed, certain defendants removed the cases to the lawsuit to the United States District Court for the Western
District of Louisiana. In both cases, the plaintiffs filed a motion to remand, and the plaintiffs agreed to an
extension of time for all defendants to file responsive pleadings until the District Courts ruled on the motions to
remand. In the Vermilion Parish case, the District Court entered an order on September 26, 2017 remanding the
lawsuit to the 15th Judicial District Court, State of Louisiana, Parish of Vermilion. In the Cameron Parish
lawsuit, the federal magistrate, on January 18, 2018, issued a report and recommendation that the Cameron
Parish lawsuit be remanded to the 38th Judicial District Court, State of Louisiana, Parish of Cameron. It is
anticipated that one or more of the defendants will object to the magistrate’s report and recommendation, in
which case the report and recommendation will be reviewed by the District Court after additional briefing by the
parties. Due to the procedural posture of lawsuits, the fact that responsive pleadings have not been filed and the
fact that the parties have not begun discovery and the Company has not had the opportunity to evaluate the
applicability of the allegations made in plaintiffs’ complaints to the Company’s operations, management cannot
determine the amount of loss, if any, that may result.
F-39
In addition, due to the nature of the Company’s business, it is, from time to time, involved in routine
litigation or subject to disputes or claims related to its business activities, including workers’ compensation
claims and employment related disputes. In the opinion of the Company’s management, none of the pending
litigation, disputes or claims against the Company, if decided adversely, will have a material adverse effect on its
financial condition, cash flows or results of operations.
Insurance Proceeds
For the years ended December 31, 2016 and 2015 the Company was reimbursed $5.7 million and $10.0
million, respectively, net of related legal fees by its insurance provider, which is included in insurance proceeds
in the accompanying consolidated statements of operations.
Concentration of Credit Risk
Gulfport operates in the oil and natural gas industry principally in the states of Ohio, Oklahoma and
Louisiana with sales to refineries, re-sellers such as marketers, and other end users. While certain of these
customers are affected by periodic downturns in the economy in general or in their specific segment of the oil
and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has
been immaterial and will continue to be immaterial to the Company’s results of operations in the long term.
The Company maintains cash balances at several banks. Accounts at each institution are insured by the
Federal Deposit Insurance Corporation up to $250,000. At December 31, 2017, Gulfport held cash in excess of
insured limits in these banks totaling $97.6 million.
The Company’s sales to major customers (purchases of 10% or more of total sales before the effects of
hedging) for the years ended December 31, 2017, 2016 and 2015 are as follows:
Company A
Company B
Company C
All others
December 31,
2017
2016
2015
40%
5%
7%
48%
59%
12%
10%
19%
62%
23%
12%
3%
17. CONDENSED CONSOLIDATING FINANCIAL INFORMATION
On October 17, 2012, December 21, 2012 and August 18, 2014, the Company issued the 2020 Notes in an
aggregate of $600.0 million principal amount. The 2020 Notes were subsequently exchanged for substantially
identical notes in the same aggregate principal amount that were registered under the Securities Act. In October
2016, the Company repurchased (in a cash tender offer) or redeemed all of the 2020 Notes, of which $600.0
million in aggregate principal amount was then outstanding, with the net proceeds from the issuance of the 2024
Notes discussed below and cash on hand.
On April 21, 2015, the Company issued $350.0 million in aggregate principal amount of the 2023 Notes to
qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in
accordance with Regulation S under the Securities Act. In connection with the 2023 Notes Offering, the
Company and its subsidiary guarantors entered into a registration rights agreement, dated as of April 21, 2015,
pursuant to which the Company agreed to file a registration statement with respect to an offer to exchange the
2023 Notes for a new issue of substantially identical debt securities registered under the Securities Act. The
exchange offer for the 2023 Notes was completed on October 13, 2015.
On October 14, 2016, the Company issued $650.0 million in aggregate principal amount of the 2024 Notes
to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons
F-40
in accordance with Regulation S under the Securities Act. The net proceeds from the issuance of the 2024 Notes,
together with cash on hand, were used to repurchase or redeem all of the then-outstanding 2020 Notes in October
2016.
On December 21, 2016, the Company issued $600.0 million in aggregate principal amount of the 2025
Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S.
persons in accordance with Regulation S under the Securities Act. The Company used the net proceeds from the
issuance of the 2025 Notes, together with the net proceeds from the December 2016 underwritten offering of the
Company’s common stock and cash on hand, to fund the cash portion of the purchase price for the Vitruvian
Acquisition.
In connection with the 2024 Notes Offering and the 2025 Notes Offering, the Company and its subsidiary
guarantors entered into two registration rights agreements, pursuant to which the Company agreed to file a
registration statement with respect to offers to exchange the 2024 Notes and the 2025 Notes for new issues of
substantially identical debt securities registered under the Securities Act. The exchange offers for the 2024 Notes
and the 2025 Notes were completed on September 13, 2017.
On October 11, 2017, the Company issued $450.0 million in aggregate principal amount of the 2026 Notes
to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons
in accordance with Regulation S under the Securities Act. A portion of the net proceeds from the issuance of the
2026 Notes was used to repay all of the Company’s outstanding borrowings under its secured revolving credit
facility on October 11, 2017 and the balance was used to fund the remaining outspend related to the Company’s
2017 capital development plans.
The 2020 Notes were, and the 2023 Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes are,
guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee the Company’s
secured revolving credit facility or certain other debt (the “Guarantors”). The 2020 Notes were not, and the 2023
Notes, the 2024 Notes, the 2025 Notes and the 2026 Notes are not, guaranteed by Grizzly Holdings, Inc. (the
“Non-Guarantor”). The Guarantors are 100% owned by Gulfport (the “Parent”), and the guarantees are full,
unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors
to obtain funds from each other in the form of a dividend or loan.
The following condensed consolidating balance sheets, statements of operations, statements of
comprehensive (loss) income and statements of cash flows are provided for the Parent, the Guarantors and the
Non-Guarantor and include the consolidating adjustments and eliminations necessary to arrive at the information
for the Company on a condensed consolidated basis. The information has been presented using the equity method
of accounting for the Parent’s ownership of the Guarantors and the Non-Guarantor.
F-41
CONDENSED CONSOLIDATING BALANCE SHEETS
(Amounts in thousands)
Parent
Guarantors Non-Guarantor Eliminations Consolidated
December 31, 2017
Current assets:
Assets
Cash and cash equivalents
Restricted cash
Accounts receivable - oil and natural gas
Accounts receivable - related parties
Accounts receivable - intercompany
Prepaid expenses and other current assets
Short-term derivative instruments
Total current assets
$
67,908 $
—
128,121
—
554,439
4,719
78,847
834,034
$
31,649
—
54,092
—
63,374
193
—
149,308
— $
—
—
—
—
—
—
—
— $
—
—
—
(617,813)
—
—
(617,813)
99,557
—
182,213
—
—
4,912
78,847
365,529
Property and equipment:
Oil and natural gas properties, full-cost
accounting
Other property and equipment
Accumulated depletion, depreciation,
amortization and impairment
Property and equipment, net
Other assets:
Equity investments and investments in
subsidiaries
Long-term derivative instruments
Deferred tax asset
Inventories
Other assets
Total other assets
Total assets
6,562,147 2,607,738
43
86,711
(4,153,696)
(37)
2,495,162 2,607,744
—
—
—
—
(729) 9,169,156
86,754
—
— (4,153,733)
(729) 5,102,177
2,361,575
8,685
1,208
5,816
12,483
2,389,767
77,744
—
—
2,411
7,331
87,486
$ 5,718,963 $2,844,538
57,641
—
—
—
—
57,641
$ 57,641
—
—
—
—
(2,194,848)
302,112
8,685
1,208
8,227
19,814
(2,194,848)
340,046
$(2,813,390)$ 5,807,752
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities
Accounts payable - intercompany
Asset retirement obligation - current
Short-term derivative instruments
Current maturities of long-term debt
$
Total current liabilities
Long-term derivative instruments
Asset retirement obligation - long-term
Other non-current liabilities
Long-term debt, net of current maturities
Total liabilities
Stockholders’ equity:
Common stock
Paid-in capital
Accumulated other comprehensive (loss)
income
Retained (deficit) earnings
Total stockholders’ equity
Total liabilities and
$
416,249 $ 137,361
554,313
63,373
—
120
—
32,534
—
622
691,674
512,898
—
2,989
11,839
63,141
2,963
—
—
2,038,321
706,476
2,617,349
— $
127
—
—
—
127
—
—
—
—
127
(1)$
—
—
—
(617,814)
(617,813)
553,609
—
120
32,534
622
586,885
2,989
—
74,980
—
—
2,963
— 2,038,321
(617,814) 2,706,138
1,831
—
—
4,416,250 1,915,598
259,307
—
1,831
(2,174,905) 4,416,250
(40,539)
(1,275,928)
222,464
3,101,614 2,138,062
—
(38,593)
(163,200)
57,514
38,593
(40,539)
(59,264) (1,275,928)
(2,195,576) 3,101,614
stockholders’ equity
$ 5,718,963 $2,844,538
$ 57,641
$(2,813,390)$ 5,807,752
F-42
CONDENSED CONSOLIDATING BALANCE SHEETS
(Amounts in thousands)
Parent
Guarantors Non-Guarantor Eliminations Consolidated
December 31, 2016
Current assets
Assets
Cash and cash equivalents
Restricted cash
Accounts receivable - oil and natural gas
Accounts receivable - related parties
Accounts receivable - intercompany
Prepaid expenses and other current assets
Short-term derivative instruments
Total current assets
$
$ 1,273,882 $
185,000
137,087
16
449,517
3,135
3,488
2,052,125
1,993
—
37,496
—
1,151
—
—
40,640
— $
—
—
—
—
—
—
—
(37,822)
—
(450,668)
— $ 1,275,875
185,000
— $
136,761
16
—
3,135
3,488
1,604,275
—
—
(488,490)
Property and equipment:
Oil and natural gas properties, full-cost
accounting,
Other property and equipment
Accumulated depletion, depreciation,
amortization and impairment
Property and equipment, net
Other assets:
Equity investments and investments in
subsidiaries
Long-term derivative instruments
Deferred tax asset
Inventories
Other assets
Total other assets
Total assets
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities
Accounts payable - intercompany
Asset retirement obligation - current
Short-term derivative instruments
Current maturities of long-term debt
Total current liabilities
Long-term derivative instruments
Asset retirement obligation - long-term
Long-term debt, net of current maturities
Total liabilities
Stockholders’ equity:
Common stock
Paid-in capital
Accumulated other comprehensive (loss)
income
Retained (deficit) earnings
Total stockholders’ equity
Total liabilities and
5,655,125
68,943
417,524
43
(3,789,746)
1,934,322
(34)
417,533
—
—
—
—
(729)
—
6,071,920
68,986
— (3,789,780)
2,351,126
(729)
236,327
5,696
4,692
3,095
8,932
258,742
33,590
—
—
1,409
—
34,999
$ 4,245,189 $493,172
45,213
—
—
—
—
45,213
$ 45,213
(71,210)
—
—
—
—
(71,210)
243,920
5,696
4,692
4,504
8,932
267,744
$(560,429) $ 4,223,145
$
$
255,966 $
31,202
195
119,219
276
406,858
26,759
34,081
1,593,599
2,061,297
9,158
457,163
—
—
—
466,321
—
—
—
466,321
— $
126
—
—
—
126
—
—
—
126
(488,491)
(488,491)
— $
—
—
—
265,124
—
195
119,219
276
384,814
26,759
—
—
34,081
— 1,593,599
2,039,253
(488,491)
1,588
3,946,442
—
33,822
—
—
257,026
(290,848)
1,588
3,946,442
(53,058)
(1,711,080)
2,183,892
—
(6,971)
26,851
(50,931)
(161,008)
45,087
50,931
167,979
(71,938)
(53,058)
(1,711,080)
2,183,892
stockholders’ equity
$ 4,245,189 $493,172
$ 45,213
$(560,429) $ 4,223,145
F-43
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)
INCOME (LOSS) FROM OPERATIONS
320,958
227,411
Total revenues
Costs and expenses:
Lease operating expenses
Production taxes
Midstream gathering and processing
Depreciation, depletion and
amortization
General and administrative
Accretion expense
Acquisition expense
OTHER (INCOME) EXPENSE:
Interest expense
Interest income
(Income) loss from equity method
investments and investments in
subsidiaries
Other (income) expense
INCOME (LOSS) BEFORE INCOME
TAXES
INCOME TAX EXPENSE
NET INCOME (LOSS)
Year Ended December 31, 2017
Parent
Guarantors Non-Guarantor Eliminations Consolidated
$1,010,989
$309,314
$ —
$
— $1,320,303
65,793
15,100
187,678
364,625
55,589
1,246
—
690,031
14,453
6,026
61,317
4
(2,654)
365
2,392
81,903
112,732
(988)
(4,534)
(21)
—
—
—
3
—
—
—
3
(3)
—
—
—
—
—
—
—
—
—
—
—
—
—
80,246
21,126
248,995
364,629
52,938
1,611
2,392
771,937
548,366
108,198
(1,009)
(226,130)
(1,617)
1,955
(324)
(116,003)
(2,924)
2,189
—
2,189
227,243
900
228,143
5,257
(1,041)
111,405
436,961
1,809
230,335
—
(2,192)
—
(228,143)
—
436,961
1,809
$ 435,152
$230,335
$(2,192)
$(228,143) $ 435,152
F-44
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)
Year Ended December 31, 2016
Parent
Guarantors Non-Guarantor Eliminations Consolidated
$ 381,931
$3,979
$ —
$ — $ 385,910
Total revenues
Costs and expenses:
Lease operating expenses
Production taxes
Midstream gathering and processing
Depreciation, depletion and
amortization
Impairment of oil and natural gas
properties
General and administrative
Accretion expense
68,034
13,121
165,400
245,970
715,495
43,896
1,057
1,252,973
(LOSS) INCOME FROM OPERATIONS
(871,042)
OTHER (INCOME) EXPENSE:
Interest expense
Interest income
Insurance proceeds
Loss on debt extinguishment
Loss (income) from equity method
investments and investments in
subsidiaries
Other expense (income)
63,529
(1,230)
(5,718)
23,776
31,078
145
111,580
843
155
572
4
—
(490)
—
1,084
2,895
1
—
—
—
(89)
(16)
(104)
—
—
—
—
—
—
3
3
(3)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
68,877
13,276
165,972
245,974
715,495
43,409
1,057
1,254,060
(868,150)
63,530
(1,230)
(5,718)
23,776
25,150
—
25,150
(22,154)
—
(22,154)
33,985
129
114,472
(LOSS) INCOME BEFORE INCOME
TAXES
INCOME TAX BENEFIT
NET (LOSS) INCOME
(982,622)
(2,913)
2,999
—
(25,153)
—
22,154
—
(982,622)
(2,913)
$ (979,709)
$2,999
$(25,153)
$ 22,154
$ (979,709)
F-45
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)
Year Ended December 31, 2015
Parent
Guarantors Non-Guarantor Eliminations Consolidated
Total revenues
Costs and expenses:
Lease operating expenses
Production taxes
Midstream gathering and processing
Depreciation, depletion and
amortization
Impairment of oil and natural gas
properties
General and administrative
Accretion expense
$
707,868
$1,122
$
68,632
14,618
138,526
337,689
1,440,418
41,892
820
843
122
64
5
—
55
—
2,042,595
1,089
(LOSS) INCOME FROM OPERATIONS
(1,334,727)
33
51,221
(643)
(10,015)
—
—
—
—
—
—
—
—
—
20
—
20
(20)
—
—
—
$
— $
708,990
—
—
—
—
—
—
—
—
69,475
14,740
138,590
337,694
1,440,418
41,967
820
2,043,704
— (1,334,714)
—
—
—
51,221
(643)
(10,015)
OTHER (INCOME) EXPENSE:
Interest expense
Interest income
Insurance proceeds
Loss (income) from equity method
investments and investments in
subsidiaries
Other (income) expense
(LOSS) INCOME BEFORE INCOME
TAXES
INCOME TAX BENEFIT
NET (LOSS) INCOME
107,252
(1,657)
146,158
—
(346)
(346)
115,544
—
115,544
(116,703)
1,518
106,093
(485)
(115,185)
146,171
(1,480,885)
(256,001)
379
—
(115,564)
—
115,185
—
(1,480,885)
(256,001)
$(1,224,884)
$ 379
$(115,564)
$ 115,185 $(1,224,884)
F-46
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Amounts in thousands)
Year Ended December 31, 2017
Parent
Guarantors Non-Guarantor Eliminations Consolidated
Net income (loss)
Foreign currency translation adjustment
$
435,152 $230,335
182
12,519
$
(2,192) $(228,143) $
12,337
(12,519)
435,152
12,519
Other comprehensive income (loss)
12,519
182
12,337
(12,519)
12,519
Comprehensive income (loss)
$
447,671 $230,517
$ 10,145
$(240,662) $
447,671
Year Ended December 31, 2016
Parent
Guarantors Non-Guarantor Eliminations Consolidated
Net (loss) income
Foreign currency translation adjustment
Other comprehensive income (loss)
$ (979,709) $
2,119
2,119
2,999
778
778
$ (25,153) $ 22,154 $ (979,709)
2,119
(2,119)
1,341
1,341
(2,119)
2,119
Comprehensive (loss) income
$ (977,590) $
3,777
$ (23,812) $ 20,035 $ (977,590)
Year Ended December 31, 2015
Parent
Guarantors Non-Guarantor Eliminations Consolidated
Net (loss) income
Foreign currency translation adjustment
Other comprehensive (loss) income
$(1,224,884) $
(28,502)
(28,502)
379
—
—
$(115,564) $ 115,185 $(1,224,884)
(28,502)
28,502 $
(28,502)
(28,502)
28,502
(28,502)
Comprehensive (loss) income
$(1,253,386) $
379
$(144,066) $ 143,687 $(1,253,386)
F-47
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Amounts in thousands)
Year Ended December 31, 2017
Parent
Guarantors Non-Guarantor Eliminations Consolidated
Net cash provided by operating activities
$
392,680 $
287,209
$ — $
— $
679,889
Net cash (used in) provided by investing
activities
(2,031,615) (1,674,690)
(2,280)
1,419,417 (2,289,168)
Net cash provided by (used in) financing
activities
Net (decrease) increase in cash and cash
equivalents
Cash and cash equivalents at beginning of
period
432,961
1,417,137
2,280
(1,419,417)
432,961
(1,205,974)
29,656
1,273,882
1,993
—
—
— (1,176,318)
— 1,275,875
Cash and cash equivalents at end of period
$
67,908 $
31,649
$ — $
— $
99,557
Net cash provided by (used in) operating
activities
$
336,330 $
(9,486) $
(2) $
11,001 $
337,843
Year Ended December 31, 2016
Parent
Guarantors Non-Guarantor Eliminations Consolidated
Net cash (used in) provided by investing
activities
Net cash provided by (used in) financing
(905,582)
(22,500)
(15,472)
37,972
(905,582)
activities
1,730,640
33,500
15,473
(48,973) 1,730,640
Net increase (decrease) in cash and cash
equivalents
Cash and cash equivalents at beginning of
period
1,161,388
1,514
112,494
479
(1)
1
— 1,162,901
—
112,974
Cash and cash equivalents at end of period
$ 1,273,882 $
1,993
$ — $
— $ 1,275,875
Year Ended December 31, 2015
Parent
Guarantors Non-Guarantor Eliminations Consolidated
Net cash provided by (used in) operating
activities
$
344,018 $
(21,839) $
(2) $
2 $
322,179
Net cash (used in) provided by investing
activities
(1,595,767)
21,514
(14,472)
14,472 (1,574,253)
Net cash provided by (used in) financing
activities
Net decrease in cash and cash equivalents
Cash and cash equivalents at beginning of
period
1,222,708
(29,041)
141,535
Cash and cash equivalents at end of period
$
112,494 $
—
(325)
804
479
$
14,474
(14,474) 1,222,708
—
1
1
—
—
(29,366)
142,340
$
— $
112,974
F-48
18. SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION
ACTIVITIES (UNAUDITED)
The Company owns a 24.9999% interest in Grizzly, which interest is shown below.
The following is historical revenue and cost information relating to the Company’s oil and gas operations
located entirely in the United States:
Capitalized Costs Related to Oil and Gas Producing Activities
Proven properties
Unproven properties
Accumulated depreciation, depletion, amortization and impairment reserve
Net capitalized costs
Equity investment in Grizzly Oil Sands ULC
Proven properties
Unproven properties
Accumulated depreciation, depletion, amortization and impairment reserve
Net capitalized costs
Costs Incurred in Oil and Gas Property Acquisition and Development Activities
2017
2016
(In thousands)
$ 6,256,182
2,912,974
$ 4,491,615
1,580,305
9,169,156
(4,136,777)
6,071,920
(3,778,043)
$ 5,032,379
$ 2,293,877
$
73,818
86,540
$
70,266
80,892
160,358
(1,693)
151,158
(1,578)
$
158,665
$
149,580
Acquisition
Development of proved undeveloped properties
Exploratory
Recompletions
Capitalized asset retirement obligation
Total
Equity investment in Grizzly Oil Sands ULC
Acquisition
Development of proved undeveloped properties
Exploratory
Capitalized asset retirement obligation
Total
2017
2016
2015
$1,951,281
994,237
(In thousands)
$152,887
423,998
$ 810,755
642,811
—
14,289
42,270
—
16,386
10,971
—
13,894
8,800
$3,002,077
$604,242
$1,476,260
$
$
$
503
—
—
(524)
$
357
—
—
784
(21) $
1,141
$
396
47
—
282
725
F-49
Results of Operations for Producing Activities
The following schedule sets forth the revenues and expenses related to the production and sale of oil and
gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after
deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the
permanent differences. The results of operations exclude general office overhead and interest expense
attributable to oil and gas production.
Revenues
Production costs
Depletion
Impairment
Income tax expense (benefit)
Current
Deferred
2017
2016
2015
$1,320,303
(350,367)
(358,792)
—
(In thousands)
$ 385,910
(248,125)
(243,098)
(715,495)
$
708,990
(222,805)
(335,288)
(1,440,418)
611,144
(820,808)
(1,289,521)
3,362
(3,602)
(240)
—
—
—
—
(220,201)
(220,201)
Results of operations from producing activities
$ 611,384
$(820,808) $(1,069,320)
Depletion per Mcf of gas equivalent (Mcfe)
Results of Operations from equity method investment in Grizzly Oil
Sands ULC
Revenues
Production costs
Depletion
Income tax expense
$
$
0.90
$
0.92
$
1.68
— $
—
—
—
—
— $
(13)
—
(13)
—
1,436
(1,549)
(625)
(738)
—
(738)
Results of operations from producing activities
$
— $
(13) $
Oil and Gas Reserves
The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves
as of December 31, 2017, 2016 and 2015 and changes in proved reserves during the last three years. The reserve
reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a
field-by-field basis on the first day of each month within the 12-month period ended December 31, 2017, 2016
and 2015, in accordance with guidelines of the SEC applicable to reserves estimates. Volumes for oil are stated
in thousands of barrels (MBbls) and volumes for natural gas are stated in millions of cubic feet (MMcf). The
prices used for the 2017 reserve report are $51.34 per barrel of oil, $2.98 per MMbtu and $18.40 per barrel for
NGLs, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves,
respectively. The prices used at December 31, 2016 and 2015 for reserve report purposes are $42.75 per barrel,
$2.48 per MMbtu and $9.91 per barrel for NGLs and $50.28 per barrel, $2.59 per MMbtu and $13.21 per barrel
for NGLs, respectively.
Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are
subject to revision. The estimates are made using all available geological and reservoir data, as well as
production performance data. These estimates are reviewed annually and revised, either upward or downward, as
warranted by additional performance data.
F-50
2017
2016
2015
Oil
Natural
Gas
Natural
Gas
Liquids
Oil
Natural
Gas
Natural
Gas
Liquids
Oil
Natural
Gas
Natural
Gas
Liquids
(MBbls)
(MMcf)
(MBbls) (MBbls)
(MMcf)
(MBbls) (MBbls)
(MMcf)
(MBbls)
5,546 2,167,068 20,127
6,458 1,560,145 17,736
9,497
719,006 26,268
15,132 1,098,644 53,617 —
951 1,594,734
4,619
—
1,217 1,082,220
—
7,677
— 371,663 —
5,486
997,057
2,413
107
(2,579)
314,925
(3)
2,737
(350,061) (5,334) (2,126)
(247,703) (1,439)
(227,594) (3,847)
(2,553) (371,430) (9,594)
(2,899) (156,151) (4,424)
19,157 4,825,310 75,766
5,546 2,167,068 20,127
6,458 1,560,145 17,736
Proved Reserves
Beginning of the period
Purchases in oil and natural gas
reserves in place
Extensions and discoveries
Revisions of prior reserve
estimates
Current production
End of period
Proved developed reserves
10,245 1,616,930 36,247
4,882
744,797 14,299
6,120
652,961 12,910
Proved undeveloped reserves
8,912 3,208,380 39,519
664 1,422,271
5,828
338
907,184
4,826
Equity investment in Grizzly Oil Sands
ULC
Beginning of the period
Purchases in oil and natural gas
reserves in place
Extensions and discoveries
Revisions of prior reserve
estimates
Current production
End of period
Proved developed reserves
Proved undeveloped reserves
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 14,558
—
—
—
—
— (14,530)
(28)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
In 2017, the Company purchased 1.5 Tcfe through our acquisition of SCOOP properties discussed in Note 2.
Also in 2017, the Company experienced extensions and discoveries of 1.6 Tcfe of estimated proved reserves
primarily attributable to the continued development of the Company’s Utica Shale acreage. In 2017, the
Company experienced upward revisions of 201.3 Bcfe in estimated proved reserves due to an increase in well
performance, 214.1 Bcfe due to the increase in pricing and 95.9 Bcfe due to changes in its ownership interests.
These positive revisions are partially offset by downward revisions of 133.0 Bcfe due to a decline in well
performance specific to one area in the Company’s Utica field and a decline of 45.7 Bcfe in estimated proved
reserves in 2017 primarily due to the exclusion of ten PUD locations in the Company’s Utica field, five of which
are operated by the Company and five of which are operated by other operators, that were excluded due to
changes in drilling schedules. Additional downward revision of 0.6 Bcfe was due to the removal of two PUD
locations in the Company’s Southern Louisiana fields that had not been drilled within five years of initial
booking. In 2016, the Company experienced extensions and discoveries of 1.1 Tcfe of estimated proved reserves
attributable to the continued development of the Company’s Utica Shale acreage. The Company experienced
downward revisions of 227.9 Bcfe due to lower commodity prices on 67 PUD locations, including the loss of 35
of the 67 PUD locations as they were no longer economic, as well as downward revisions of 17.4 Bcfe due to
rescheduling the drilling timeline of four PUD locations in excess of five years of initial booking resulting in the
removal of these four PUD locations. In addition, the Company experienced upward revisions of 26.7 Bcfe
attributable to improved performance of 34 PUD locations as a result of 14.5% production increases due to well
performance of offset producers as well as lower lease operated and capital expenditures. In 2015, the Company
experienced extensions and discoveries of 1,044.5 Bcfe of estimated proved reserves attributable to the continued
development of the Company’s Utica Shale acreage. In addition, the Company experienced downward revisions
of 444,314 MMcfe in estimated proved reserves in 2015 primarily due to the exclusion of PUD locations in its
F-51
Utica and Southern Louisiana fields that became uneconomic due to the continued decline in commodity prices.
In 2015, the Company also purchased 371,663 MMcfe of proved reserves as a result of acquisitions.
Discounted Future Net Cash Flows
The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven
oil and gas reserves as of December 31, 2017, 2016 and 2015 using an unweighted average first-of-the-month
price for the period January through December 31, 2017, 2016 and 2015.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Future cash flows
Future development and abandonment costs
Future production costs
Future production taxes
Future income taxes
Future net cash flows
10% discount to reflect timing of cash flows
Year ended December 31,
2017
2016
2015
$11,202,692
(3,005,217)
(2,152,821)
(289,944)
(573,965)
(In thousands)
$ 3,354,168
(1,165,025)
(924,167)
(69,447)
(14,545)
$3,043,450
(877,660)
(941,243)
(58,169)
(2,648)
5,180,745
(2,537,181)
1,180,984
(492,944)
1,163,730
(399,399)
Standardized measure of discounted future net cash flows
$ 2,643,564
$
688,040
$ 764,331
Equity investment in Grizzly Oil Sands ULC Standardized measure of
discounted cash flows
Future cash flows
Future development and abandonment costs
Future production costs
Future production taxes
Future income taxes
Future net cash flows
10% discount to reflect timing of cash flows
$
— $
—
—
—
—
—
— $
—
—
—
—
—
Standardized measure of discounted future net cash flows
$
— $
— $
—
—
—
—
—
—
—
In order to develop its proved undeveloped reserves according to the drilling schedule used by the engineers
in Gulfport’s reserve report, the Company will need to spend $551.0 million, $458.8 million and $514.5 million
during years 2018, 2019 and 2020, respectively.
F-52
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas
Reserves
Year ended December 31,
Sales and transfers of oil and gas produced, net of production costs
Net changes in prices, production costs, and development costs
Acquisition of oil and gas reserves in place
Extensions and discoveries
Previously estimated development costs incurred during the period
Revisions of previous quantity estimates, less related production costs
Accretion of discount
Net changes in income taxes
Change in production rates and other
Total change in standardized measure of discounted future net cash
2017
2015
2016
(In thousands)
$ (756,257) $(312,291) $ (486,185)
(1,412,181)
(146,518)
83,340
262,895
117,540
(98,162)
142,717
412,240
314,960
913,714
703,866
618,039
390,673
155,200
68,804
(231,545)
93,030
186,909
176,218
(38,448)
76,433
(6,495)
(12,099)
—
flows
$1,955,524
$ (76,291) $ (662,836)
Equity investment in Grizzly Oil Sands ULC Changes in standardized
measure of discounted cash flows
Sales and transfers of oil and gas produced, net of production costs
Net changes in prices, production costs, and development costs
Acquisition of oil and gas reserves in place
Extensions and discoveries
Previously estimated development costs incurred during the period
Revisions of previous quantity estimates, less related production costs
Accretion of discount
Net changes in income taxes
Change in production rates and other
Total change in standardized measure of discounted future net cash
$
— $
—
—
—
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
114
—
—
—
47
(103,282)
9,375
—
—
flows
$
— $
— $
(93,746)
F-53
19. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table summarizes quarterly financial data for the years ended December 31, 2017 and 2016:
2017
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
(In thousands)
$ 333,004
181,683
$ 323,953
143,175
—
154,455
—
105,936
$ 265,498
50,483
2,763
18,235
$ 397,848
173,025
(954)
156,526
$
$
0.91
0.91
$
$
0.58
0.58
$
$
0.10
0.10
$
$
0.85
0.85
2016
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
$ 156,961
(195,794)
(191)
(242,267)
(In thousands)
$ (28,158) $ 193,691
(157,995)
(3,407)
(157,296)
(323,412)
(157)
(339,776)
$ 63,416
(190,949)
842
(240,370)
$
$
(2.17) $
(2.71) $
(1.25) $
(1.86)
(2.17) $
(2.71) $
(1.25) $
(1.86)
Revenues
Income from operations
Income tax expense (benefit)
Net income
Income per share:
Basic
Diluted
Revenues
Loss from operations
Income tax (benefit) expense
Net loss
Loss per share:
Basic
Diluted
20. SUBSEQUENT EVENTS
Derivatives
In January and February 2018, the Company entered into fixed price swaps for 2018 for approximately 1,000
barrels of oil per day at a weighted average price of $62.18 per barrel and for approximately 500 barrels of C3 propane
per day at a weighted average price of $35.54 per barrel. For 2019, the Company entered into fixed price swaps for
approximately 242,000 MMBtu of natural gas per day at a weighted average price of $2.79 per MMBtu and for
approximately 2,000 barrels of oil per day at a weighted average price of $57.75 per barrel. The Company’s fixed price
swap contracts are tied to the commodity prices on NYMEX for natural gas, NYMEX WTI for oil and Mont Belvieu
for propane. The Company will receive the fixed priced amount stated in the contract and pay to its counterparty the
current market price as listed on NYMEX for natural gas, NYMEX WTI for oil or Mont Belvieu for propane.
Stock Repurchase Program
In January 2018, the board of directors of the Company approved a stock repurchase program to acquire up
to $100.0 million of the Company’s outstanding common stock during 2018. Purchases under the repurchase
program may be made from time to time in open market or privately negotiated transactions, and will be subject
to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase
program does not require the Company to acquire any specific number of shares. The Company intends to
purchase shares under the repurchase program opportunistically with available funds while maintaining sufficient
liquidity to fund its 2018 capital development program. This repurchase program is authorized to extend through
December 31, 2018 and may be suspended from time to time, modified, extended or discontinued by the board of
directors of the Company at any time. The Company did not make any purchases of its common stock during the
year ended December 31, 2017 under any stock repurchase program or otherwise, and has not made any such
purchases of its common stock as of February 22, 2018.
F-54
CORPORATE INFORMATION
Deborah G. Adams
Independent Director
Paul D. Westerman
Independent Director
Scott Streller
Independent Director
Michael G. Moore
Director
Rob Jones
Senior Vice President,
Drilling
Steve Baldwin
Vice President,
Reservoir Engineering
Stuart Maier
Senior Vice President,
Geosciences
Ty Peck
Senior Vice President,
Midstream and Marketing
DIRECTORS
David Houston
Chairman of the Board
Ben T. Morris
Independent Director
Craig Groeschel
Independent Director
C. Doug Johnson
Independent Director
SENIOR MANAGEMENT
Michael G. Moore
Chief Executive Officer
and President
Donnie Moore
Chief Operating Officer
Keri Crowell
Chief Financial Officer
Lester Zitkus
Senior Vice President,
Land
Mark Malone
Senior Vice President,
Operations
Paul Heerwagen
Senior Vice President,
Corporate Development
and Strategy
COMPARISON OF 5-YEAR CUMULATIVE TOTAL RETURN
ANNUAL MEETING
The annual meeting of shareholders is scheduled for 10:00 a.m.
Wednesday, May 30th, 2018, at the company headquarters at
3001 Quail Springs Parkway, Oklahoma City, OK 73134.
TRANSFER AGENT
For information regarding change of address, lost certificates or similar
inquiries, please contact our transfer agent:
FIRST CLASS/REGISTERED/
CERTIFIED MAIL:
Computershare Investor Services
P.O. Box 505002
Louisville, KY 40233-5022
COURIER SERVICES:
Computershare Investor Services
250 Royall St.
Canton, MA 02021
MARKET INFORMATION
SHAREHOLDER SERVICES
NUMBER:
800-962-4284
OUTSIDE THE US:
781-575-3120
INVESTOR CENTRE™ PORTAL:
www.computershare.com/investor
Gulfport Energy’s common stock is traded on the NASDAQ Global
Select Market under the symbol GPOR.
INVESTOR RELATIONS
For additional information concerning Gulfport Energy’s operational and
financial results, investors and analysts, please contact Gulfport Investor
Relations at 405-252-4550.
MORE INFORMATION
Additional company information, such as company presentations, press
releases and other material, can be found on the company website at:
www.gulfportenergy.com
$25 0
$2 00
$150
$1 00
$50
$0
2012
2013
2014
201 5
2016
2017
GULFPORT
ENERGY
S&P 500
2017 PEER
GROUP
2016 PEER
GROUP
DJ INDEX
The graph to the left represents the Company’s cumulative
total return relative to the performance of its peers during
the period from 12/31/2012 through 12/29/2017. The graph
assumes $100 invested at the closing price of the Company’s
common stock and that all dividends were reinvested on
the date paid. The points on the graph at left represent
fiscal year end amounts based on the last trading day in
each fiscal year.
2017 peer group includes CNX, COG, CXO, EGN, EPE, GPOR,
MUR, NFX, OAS, QEP, RRC, RICE, SM, WPX, WLL, XEC
2016 peer group includes AR, CLR, CNX, CRZO, EGN, FANG,
GPOR, HK, LPI, MTDR, OAS, PDCE, RICE, RRC, SM, XEC
3001 QUAIL SPRINGS PARKWAY
OKLAHOMA CITY, OK 73134
40 5-252-4600
WWW.GULFPORTENERGY.COM