Table of Contents
Index to Financial Statements
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ý
¨
ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
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
Common Stock, par value $0.01 per share
Securities registered pursuant to Section 12(g) of the Act: None
Name of Each Exchange on Which Registered
The Nasdaq Stock Market LLC
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ý 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 ý
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 ý No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such
files). Yes ý 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. ý
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):
Large Accelerated filer ý Accelerated filer ¨ Non-accelerated filer ¨ Smaller reporting company ¨ Emerging growth company ¨
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period 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 ý
The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of
June 30, 2018, based on the
closing price of the common stock on the NASDAQ Global Select Market on June 29, 2018, the last business day of the registrant’s most recently completed second
fiscal quarter ($12.57 per share), was $2,178,406,831.
As of February 18, 2019 , 162,986,045 shares of the registrant’s common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Gulfport Energy Corporation’s Proxy Statement for the 2018 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13
and 14 of Part III of this Form 10-K.
Table of Contents
Index to Financial Statements
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
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Index to Financial Statements
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.
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Index to Financial Statements
ITEM 1.
General
BUSINESS
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 21.9% equity interest in Mammoth Energy Services, Inc., or Mammoth Energy, a company listed on the Nasdaq Global Select
Market (TUSK) that serves the electric utility and oil and natural gas industries. We seek to achieve reserve growth and increase our cash
flow through our annual drilling programs.
As of February 15, 2019, we held leasehold interests in approximately 241,000 gross (210,000 net) acres in the Utica Shale primarily in
Eastern Ohio. In 2018, we spud 23 gross (19.5 net) wells, of which three were completed as producing wells and, as of December 31, 2018,
20 were in various stages of completion. We commenced sales from 35 gross and net wells in the Utica Shale during 2018. During 2019
(through February 15, 2019), we spud five gross (3.7 net) wells. As of February 15, 2019, three of these wells were in various stages of
completion and the other two were still drilling. In addition, other operators drilled 28 gross (4.4 net) wells and commenced sales from 32
gross (9.4 net) wells on our Utica Shale acreage in 2018.
We currently intend to drill 13 to 15 gross (10 to 11 net) horizontal wells, and commence sales from 47 to 51 gross (40 to 45 net)
horizontal wells on our Utica Shale acreage in 2019. We currently anticipate two to three net horizontal wells will be drilled, and sales
commenced from two to three net horizontal wells, by other operators on our Utica Shale acreage in 2019.
Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2018 was approximately 102,665
million cubic feet of natural gas equivalent, or MMcfe, or 1,115.9 MMcfe per day, of which 97% was from natural gas and 3% was from oil
and NGLs.
As of February 15, 2019, we held leasehold interests in approximately 50,000 net surface acres in the SCOOP. In 2018, we spud 13
gross (12.1 net) wells, of which four were completed as producing wells and, as of December 31, 2018, nine were in various stages of
completion. We commenced sales from 15 gross (12.8 net) wells in the SCOOP during 2018. During 2019 (through February 15, 2019), we
spud two gross (1.6 net) wells. As of February 15, 2019, both of these wells were still drilling. In addition, other operators drilled 40 gross
(3.1 net) wells and commenced sales from 47 gross (3.6 net) wells on our SCOOP acreage during 2018.
We currently intend to drill nine to ten gross (seven to eight net) horizontal wells, and commence sales from 15 to 17 gross (14 to 15
net) horizontal wells on our SCOOP acreage in 2019. We currently anticipate one to two net horizontal wells will be drilled, and sales
commenced from one to two net horizontal wells, by other operators on our SCOOP acreage in 2019.
Aggregate net production from our SCOOP acreage during the three months ended December 31, 2018 was approximately 24,406
MMcfe, or an average of 265.3 MMcfe per day, of which 70% was from natural gas and 30% was from oil and NGLs.
In 2018, at our WCBB field, we did not spud any new wells and recompleted 32 existing wells. In the fourth quarter of 2018, net
production at WCBB was approximately 837 MMcfe, or an average of 9.1 MMcfe per day, all of which was from oil.
In 2018, at our East Hackberry field, we did not spud any new wells and recompleted 15 existing wells. In the fourth quarter of 2018,
net production at East Hackberry was approximately 115 MMcfe, or an average of 1.2 MMcfe per day, all of which was from oil.
In 2018, at our West Hackberry field, we did not spud any new wells. In the fourth quarter of 2018, net production at West Hackberry
was approximately 17 MMcfe, or an average of 186.2 thousand cubic feet of natural gas equivalent, or Mcfe, per day, all of which was from
oil.
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Index to Financial Statements
We do not anticipate any material activities in our Southern Louisiana fields during 2019.
As of December 31, 2018, we held leasehold interests in approximately 2,900 net acres in the Niobrara Formation in Northwestern
Colorado. During the year ended December 31, 2018, there were no wells spud on our Niobrara Formation acreage. In the fourth quarter of
2018, net production from our Niobrara Formation acreage was approximately 23 MMcfe, or an average of 251.0 Mcfe per day, all of
which was from oil.
As of December 31, 2018, we held leasehold interests in approximately 780 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 2018, our net production from this acreage was approximately 76 MMcfe, or an average of 827.1 Mcfe per day, of which 86% was from
oil and 14% was from natural gas and natural gas liquids.
We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of December 31, 2018, 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 108,000 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, 2018, we had 4.7 trillion cubic feet of natural gas equivalent, or Tcfe, of proved reserves with a present value of
estimated future net revenues, discounted at 10%, or PV-10, of approximately $3.4 billion and associated standardized measure of
discounted future net cash flows of approximately $3.0 billion, excluding reserves attributable to our interests in Grizzly and Tatex II. 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.
Principal Oil and Natural Gas Properties
The following table presents certain information as of December 31, 2018 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.
Proved Reserves
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
Average
NRI/WI (1)
Productive
Wells
Non-Productive
Wells
Developed
Acreage (2)
Percentages
Gross
Net
Gross
Net
Gross
44.26/54.44
24.34/30.20
567
308
576 173.27
5
33
4.23
27.83
92,594
48,658
Gas
MMcf
Net
72,693 3,123,629
34,532 1,009,971
Oil
MBbls
5,289
12,937
NGLs
MBbls
Total
MMcfe
32,500 3,350,363
48,020 1,375,713
69
146
146
5,668
5,668
18
1,834
—
11,022
80.108/100
82.33/100
87.50/100
34.52/48.61
1.51/1.83
69
14
2
3
18
14
130
130
2,910
2,910
2
1.46
0.3
7
727
727
1,998
386
999
77
7
—
—
—
—
—
—
35
—
—
227
276
391
128
195
—
—
—
—
—
1,692
2,346
768
1,398
9
Various
673
0.9
—
—
9
—
Total
1,922 568.93
321 315.06 152,941 117,606 4,133,889
21,050
80,520 4,743,311
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Index to Financial Statements
(1) Net Revenue Interest (NRI)/Working Interest (WI) for producing
wells.
(2) Developed acres are acres spaced or assigned to productive wells. Approximately 43% of our acreage is developed acreage and has
been held by production.
(3) Includes NRI/WI from wells that have been drilled or in which we have elected to participate. Includes 245 gross (41.44 net) wells
drilled by other operators on our acreage.
(4) Includes NRI/WI from wells that have been drilled or in which we have elected to participate. Includes 392 gross (30.02 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, 2018, we held leasehold interests in approximately 241,000 gross (210,000 net) acres in the Utica Shale.
Area History
As of December 31, 2018, the Ohio Department of Natural Resources reported that there were 2,138 producing horizontal wells, 246
horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 116 horizontal wells that were being drilled
and an additional 449 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.
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 800 feet. There is a general thinning from east to
west. Across our position, the Utica Shale ranges in thickness from over 600 to over 750 feet.
The application of horizontal drilling, combined with multi-staged hydraulic fracturing to create permeable flow paths from shale units
into wellbores, were the key technologies that unlocked development of 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.
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, 2018, had spud 385
gross wells, 290 of which were completed and were producing. In 2018, we spud 23 gross (19.5 net) wells, of which three were completed
as producing wells and, as of December 31, 2018, 20 were in various stages of completion. We commenced sales from 35 gross and net
wells in the Utica Shale during 2018. During 2019 (through February 15, 2019), we spud five gross (3.7 net) wells. As of February 15,
2019, three of these wells were in various stages of completion and the other two were still drilling. In addition, other operators drilled 28
gross (4.4 net) wells and commenced sales from 32 gross (9.4 net) wells on our Utica Shale acreage in 2018.
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Index to Financial Statements
We currently intend to drill 13 to 15 gross (10 to 11 net) horizontal wells, and commence sales from 47 to 51 gross (40 to 45 net)
horizontal wells, on our Utica Shale acreage in 2019. We currently anticipate two to three net horizontal wells will be drilled, and sales
commenced from two to three net horizontal wells, by other operators on our Utica Shale acreage during 2019. As of February 15, 2019,
we had two operated horizontal rig drilling in the play. We plan to run, on average, approximately one operated horizontal rig in the Utica
Shale in 2019.
Production Status
Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2018 was approximately 102,665
MMcfe, or 1,115.9 MMcfe per day, of which 97% was from natural gas and 3% was from oil and NGLs.
SCOOP (Oklahoma)
Location and Land
As of December 31, 2018, we held leasehold interests in approximately 66,000 gross (50,000 net) surface acres in the SCOOP and
approximately 92,000 net reservoir acres, which includes 50,000 net Woodford acres and 42,000 net Springer acres.
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 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. Improved well performance has also been realized with enhanced completion designs compared to
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Index to Financial Statements
historical practices for the area. Our 2018 drilling program concentrated on SCOOP Woodford wells, however, during 2018, we also spud
and commenced sales from one upper Sycamore well.
In 2018, we spud 13 gross (12.1 net) wells, of which four were completed as producing wells and, as of December 31, 2018, nine were
in various stages of completion. We commenced sales from 15 gross (12.8 net) wells in the SCOOP during 2018. During 2019 (through
February 15, 2019), we spud two gross (1.6 net) wells. As of February 15, 2019, both of these wells were still drilling. In addition, other
operators drilled 40 gross (3.1 net) wells and commenced sales from 47 gross (3.6 net) wells on our SCOOP acreage in 2018.
We currently intend to drill nine to ten gross (seven to eight net) horizontal wells, and commence sales from 15 to 17 gross (14 to 15
net) horizontal wells, on our SCOOP acreage in 2019. We currently anticipate one to two net horizontal wells will be drilled, and sales
commenced from one to two net horizontal wells, by other operators on our SCOOP acreage during 2019. As of February 15, 2019, we had
two operated horizontal rigs drilling in the play. We intend to run, on average, approximately 1.5 operated horizontal rigs in the SCOOP
during 2019.
Production Status
Aggregate net production from our SCOOP acreage during the three months ended December 31, 2018 was approximately 24,406 net
MMcfe, or 265.3 MMcfe per day, of which 70% was from natural gas and 30% 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 part of 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,
2018, 980 were completed as producing wells. From the date of our acquisition of WCBB in 1997 through December 31, 2018, we drilled
273 new wells, 240 of which were productive, for an 88% success rate. As of December 31, 2018, estimated field cumulative gross
production was 200 MMBO and 238 Bcf of gas. Of the 1,093 wells drilled in WCBB as of December 31, 2018, 69 were producing, 146
were shut-in, and six were being used as salt water disposal wells. The other 872 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, 2018, 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 be, directionally drilled using steering tools and downhole motors.
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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 2018, at our WCBB field, we recompleted 32 existing wells and spud no new wells. As of February 15, 2019, no existing wells had
been recompleted during 2019 in our WCBB field.
Production Status
In the fourth quarter of 2018, our net production at WCBB was approximately 837 MMcfe, or an average of 9.1 MMcfe per day, all of
which was from oil.
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, 2018, 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 2018 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, 2018, 14 wells had
daily production, 130 were shut-in and three had been converted to salt water disposal wells. The remaining 125 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.
Facilities
We have a field office that serves both the East and West Hackberry fields. In addition, we own and operate two production facilities at
East Hackberry that include one land based tank batteries, a production barge, two natural gas compressors, dehydration units and salt
water disposal systems.
Recent Activity
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During 2018 at East Hackberry, we recompleted 15 existing wells and spud no new wells. As of February 15, 2019, no existing wells
had been recompleted during 2019 in our East Hackberry field.
Production Status
In the fourth quarter of 2018, our net production at East Hackberry was approximately 115 MMcfe, or an average of 1.2 MMcfe per
day, all of which was from oil.
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 2018 was 493 MBO
and 140 Bcf of natural gas. As of December 31, 2018, 42 wells had been drilled on our portion of West Hackberry. As of December 31,
2018, two of such wells were producing, seven were shut-in and one was being used as a salt water disposal well. The remaining 32 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 2018 at West Hackberry, we did not spud any new wells. As of February 15, 2019, no existing wells had been recompleted
during 2019 in our West Hackberry field.
Production Status
In the fourth quarter of 2018, our net production at West Hackberry was approximately 17 MMcfe, or an average of 186.2 Mcfe per
day, all of which was from oil.
Facilities
We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system.
We do not anticipate any material activities in our Southern Louisiana fields during 2019.
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, 2018, we held leases for approximately 2,900 net acres. In 2018, no wells were spud on our Niobrara Formation acreage.
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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 2018, net production from our Niobrara Formation acreage was approximately 23 MMcfe, or an average of
251.0 Mcfe per day, all 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 2018. We do not anticipate drilling any wells in the Niobrara
Formation during 2019.
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,
2018, we held approximately 780 net acres, interests in 18 wells and overriding royalty interests in certain existing and future wells.
Production Status
In the fourth quarter of 2018, our net production from this acreage was approximately 76 MMcfe, or an average of 827.1 Mcfe per day,
of which 86% was from oil and 14% was from natural gas and 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.
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Recent Activities
There were no new wells drilled on our Bakken Formation acreage in 2018. We do not anticipate drilling any wells in the Bakken
Formation during 2019.
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, 2018:
Field
Deer Island
Napoleonville
Crest
Eagle City South
Fay South
Fay East
Squaw Cheek
Watonga Chickasha Trend
Green River Basin
Our Equity Investments
State
Louisiana
Louisiana
Texas
Oklahoma
Oklahoma
Oklahoma
Oklahoma
Oklahoma
Colorado
Parish/County
Terrebonne
Assumption
Ochiltree
Dewey
Blaine
Blaine
Blaine
Canadian
Moffat
Average Working
Interest
Overriding Royalty
Interests
Producing
Wells
Non-Producing
Wells
3.13 %
—
2.00 %
1.04 %
0.30 %
0.15 %
0.13 %
0.05 %
0.07 %
—
2.5 %
—
—
—
—
—
—
—
—
3
1
1
1
1
1
1
2
1
—
—
—
—
—
—
—
—
Grizzly Oil Sands. We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of
December 31, 2018, 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 application covering the eastern portion of the May River lease has been deemed complete from the Alberta
Energy Regulator and is awaiting final approval. 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 108,000 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 2018, net gas production was
approximately 78 MMcf per day and condensate production was 245 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 connection with Mammoth Energy's initial public offering, or IPO, in October 2016, we received 9,150,000
shares of Mammoth Energy common stock in return for our contribution to Mammoth Energy of our 30.5% interest
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in Mammoth Energy Partners LLC. In June 2017, we received an additional 2,000,000 shares of Mammoth Energy common stock in
connection with our contribution of all of our equity interests in three other entities to Mammoth Energy. We sold 76,250 shares of our
Mammoth Energy common stock in the IPO and an additional 1,354,574 shares in a subsequent underwritten public offering in 2018. As a
result, as of December 31, 2018, we owned 9,829,548 shares, or approximately 21.9%, of Mammoth Energy’s outstanding common stock.
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. Prior to the sale of the Company's interest in Strike Force
(discussed below), the Company owned a 25% interest in Strike Force, and EQT acted as operator and owned the remaining 75% interest.
Strike Force's gathering assets provide 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 May 2018, the Company sold its 25% interest in
Strike Force to EQT Midstream Partners, LP for proceeds of $175.0 million in cash.
See Note 4 to our consolidated financial statements included elsewhere in this report for additional information regarding these and our
other equity 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 Southern Hills and purchased at the
fractionation facility. For the year ended December 31, 2018, sales to BP Energy Company, or BP, and ECO-Energy accounted for
approximately 17% and 10%, respectively, of our total oil, natural gas and NGL revenues, before the effects of hedging.
As of December 31, 2018, we had an average of approximately 663,000 MMBtu per day of firm sales contracted with third parties for
2019. We had an average of approximately 526,000 MMBtu per day, 372,000 MMBtu per day, 272,000 MMBtu per day, 255,000 MMBtu
per day and 212,000 MMBtu per day contracted with third parties for 2020, 2021, 2022, 2023 and thereafter, respectively.
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Transportation and Takeaway Capacity
In Ohio and Oklahoma, as of December 31, 2018, we had entered into firm transportation contracts to deliver approximately 1,205,000
MMBtu to 1,405,000 MMBtu per day for 2019 and 2020. 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
2019. Our primary long-haul firm transportation commitments include the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
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 of which began 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
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
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•
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 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
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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 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. The rules are subject to ongoing litigation and have been stayed in more than half the
States. Also, on December 11, 2018, the EPA and the Corps released a proposed rule that would replace the 2015 rule, and significantly
reduce the waters subject to federal regulation under the Clean Water Act. Such proposal is currently subject to public review and comment,
after which additional legal challenges are anticipated. As a result of such recent developments, substantial uncertainty exists regarding 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.
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
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Index to Financial Statements
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 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 recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The
EPA has finalized a series of greenhouse gas monitoring, reporting and emission control rules for the oil and natural gas industry and 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 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
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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, tornadoes 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, though, in December 2017, the U.S. Fish and Wildlife
Service provided guidance limiting the reach of the 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 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.
Additionally, 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
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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 rule making 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. Also, on October 15, 2018, the
EPA published a proposed rule to significantly reduce regulatory burdens imposed by the 2016 regulations, including, for example,
reducing the monitoring frequency for fugitive emissions and revising the requirements for pneumatic pumps at well sites. The above
standards, to the extent implemented, 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. Also, on November 15, 2016, the BLM
finalized a waste prevention 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. 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; however, a coalition of environmentalists, tribal advocates and the state
of California filed lawsuits challenging the rule rescission. Also, on February 22, 2018, the LM published proposed amendments to the
waste prevention rule that would eliminate certain air quality provisions and, on April 4, 2018, a federal district court stayed certain
provisions of the 2016 rule. 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
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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, 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:
•
•
•
•
•
•
•
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
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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.
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 spacing and operation of wells
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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.
Also, on November 20, 2018, Ohio EPA announced that it intends to develop new rules that would cover air pollution emissions associated
with non-conventional oil and gas facilities.
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 $101.0 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 $52.0 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 $16.0 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 ($1.75 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 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
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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 2018 and 2017 were
approximately $0.6 million and $0.2 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 an office building with 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 foot 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, 2018, we had 350 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 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:
•
worldwide and domestic supplies of oil and natural
gas;
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•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
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 2017, West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or 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.
During 2018, WTI prices ranged from $44.48 to $77.41 per barrel and the Henry Hub spot market price of natural gas ranged from $2.49 to
$6.24 per MMBtu. If the prices of oil and natural gas decline, 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 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 2019
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 2019 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
22
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Index to Financial Statements
growth rate may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 2019
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 EQT. 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.
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 2019
to be in the range of $525.0 million to $550.0 million and an additional $40.0 million to $50.0 million for leasehold expenditures, primarily
lease extensions and infill leasing within our Utica Shale and Scoop development plans.
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:
•
•
•
•
•
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 2019 could exceed our capital expenditure budget. In the
event our capital expenditure requirements at any time are greater than the amount of capital we
23
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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:
•
•
•
•
recoverable
reserves;
future oil and natural gas prices and their applicable
differentials;
operating costs;
and
potential environmental and other
liabilities.
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.
24
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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 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:
•
•
denial of or delay in receiving requisite regulatory approvals and/or
permits;
unplanned increases in the cost of construction materials or
labor;
25
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Index to Financial Statements
•
•
•
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.
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, 2018, 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 for impairment, resulting in an aggregate other than temporary impairment write down of $23.1 million for the year ended
December 31, 2016. As of and during the years ended December 31, 2018 and 2017, commodity prices had increased as compared to 2016.
We engaged an independent third party to perform a sensitivity analysis based on updated pricing as of December 31, 2018, and concluded
that 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 David M. Wood, 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
26
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Index to Financial Statements
operations. Our executives are not restricted from competing with us if 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, 2018, 2017 and 2016, our SCOOP
acreage at December 31, 2018 and 2017 and our Niobrara field and our overriding royalty and non-operated interests at December 31, 2018
and (ii) our personnel with respect to our Niobrara field and our overriding royalty and non-operated interests 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 2018, 2017 and 2016 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, 2018, 2017 and 2016, 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 2018, 2017 and
2016 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, 2018, 2017 and 2016, 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:
•
•
•
•
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 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
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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 55.4% of our total estimated proved reserves at December 31, 2018, 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.
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.
28
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As of December 31, 2018, we had entered into firm transportation contracts to deliver approximately 1,205,000 MMBtu to 1,405,000
MMBtu per day for 2019 and 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 and Oklahoma 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.
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:
•
•
•
•
•
•
•
•
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.
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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 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.
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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 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
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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 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:
•
•
•
•
•
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:
•
•
•
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:
•
•
•
•
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;
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•
•
selection of technology;
and
the rate of production of the
reserves.
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 18% of our Utica Shale undeveloped acreage that is subject to expiration will be
subject to expiration in 2019, with 16% of such acreage expiring in 2020, 15% in 2021 and 51% 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, 2018, leases representing 88%,
8% and 4% of our SCOOP undeveloped acreage that is subject to expiration are scheduled to expire in 2019, 2020 and 2021, respectively.
As of December 31, 2018, leases representing 66% of our total Niobrara Formation undeveloped acreage are scheduled to expire in 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 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-
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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 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.
In our Utica operations, we attempt to reuse/recycle all produced water from production and completion activities through our fracture
stimulation operations when active. While our objective is to recycle 100% of all produced water, we do inject water into third party
commercially operated disposal wells in line with all state and federal mandated practices and cease
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produced water recycle whenever fracture stimulation operations are idle. In the state of Ohio, all water used during drilling operations is
disposed of through injection into third party salt water disposal wells regulated by applicable state agencies.
In our SCOOP operations, state regulations allow for the storage of produced water in permitted, above ground, lined and monitored
impoundments. These storage impoundments allow the recycle of approximately two-thirds of our produced water from all production and
completion operations and approximately 80% of water used in the drilling phase of our operations. The limited water disposed of during
drilling operations is injected into state regulated commercial disposal wells.
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.
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.
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
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(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 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, tornadoes 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,
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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 two largest purchasers of our oil and natural gas during the year ended December 31, 2018 accounted for approximately 17% and
10%, respectively, of our total oil, natural gas and NGL revenues. If these purchasers 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.
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 2018, 2017 and 2016 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 result in 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 recorded 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
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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 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
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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.
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, 2018, we had total indebtedness (net of unamortized debt issuance costs) of approximately $2.1 billion, primarily
attributable to our senior notes. We had $45.0 million in borrowings outstanding under our secured revolving credit facility and our
borrowing base availability was $638.4 million after giving effect to an aggregate of $316.6 million of letters of credit.
Our outstanding indebtedness could have important consequences to you, including the following:
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•
•
•
•
•
•
•
•
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 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.
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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 $1.4 billion, with an elected commitment of
$1.0 billion. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on
our oil and natural gas reserves and other factors. As of December 31, 2018, we had $45.0 million in borrowings and $316.6 million of
letters of credit outstanding under our revolving credit facility. 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
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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, 2018, our borrowing base under our revolving credit facility was set at $1.4 billion, with an elected commitment of $1.0
billion, and we had $45.0 million in borrowings under this facility. Total funds available for borrowing under our revolving credit facility as
of December 31, 2018, after giving effect to $316.6 million of outstanding letters of credit, were $638.4 million. 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, 2018, amounts borrowed under our revolving credit facility bore interest at the weighted average rate of
4.23%. A 1% increase in the average interest rate would have increased our interest expense by approximately $0.8 million based on
outstanding borrowings under our revolving credit facility throughout the year ended December 31, 2018. An increase in our interest rate at
the time we 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, 2018, 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.
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:
•
•
•
changes in oil and natural gas
prices;
changes in production
levels;
changes in governmental regulations and
taxes;
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•
•
•
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, and in May 2018 expanded this program to acquire up to an additional $100.0 million of our common stock during 2018 for
a total of up to $200.0 million. This repurchase program was authorized to extend through December 31, 2018 and was fully executed
2018. In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400.0 million of our outstanding
common stock within the next 24 months. The repurchase program does not require us to acquire any specific number of shares. From
January 1, 2019 through February 28, 2019, we did not repurchase any shares of our common stock under our new stock repurchase
program. An aggregate of $400.0 million remains available for future stock repurchases under our new stock repurchase program. Our
board of director’s determination to repurchase shares of our common stock under our new stock repurchase program 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, 2018, we had a net operating loss, or NOL, carry forward of approximately $782.7 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
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 for resale by
certain of our stockholders. Sales of these or other 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 18, 2019, there were 162,986,045 shares of
our common stock issued and outstanding, excluding 1,534,688 shares of unvested restricted stock awarded under our Amended and
Restated 2005 Stock Incentive Plan.
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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.
None.
UNRESOLVED STAFF COMMENTS
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, 2018 were prepared by NSAI with respect to our assets in the Utica Shale in Eastern Ohio (71% of
our proved reserves at December 31, 2018), the SCOOP Woodford and SCOOP Springer plays in Oklahoma (29% of our proved reserves at
December 31, 2018), our WCBB, Hackberry and Niobrara fields, as well as our overriding royalty and non-operated interests (less than 1%
of our proved reserves at December 31, 2018). Reserve estimates at December 31, 2017 were prepared by NSAI with respect to our assets
in the Utica Shale in Eastern Ohio, the SCOOP Woodford and SCOOP Springer plays in Oklahoma and our WCBB and Hackberry fields.
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. Our personnel prepared reserve estimates with respect to our Niobrara field as well as our overriding royalty
and non-operated interests at December 31, 2017 and 2016.
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, operating and development costs and
other considerations, including availability and costs of infrastructure
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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 Senior 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 20 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 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:
•
•
•
•
•
•
•
•
•
•
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 NSAI in coordination with our experienced reservoir
engineers;
direct reporting responsibilities by our reservoir engineering department to our Chief Operating
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;
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, 2018, 2017 and 2016:
Year Ended December 31,
2018
Natural
Gas
(MMcf)
1,813,184
2,320,705
4,133,889
Natural
Gas
Liquids
(MBbls)
40,810
39,710
80,520
Oil
(MBbls)
9,570
11,480
21,050
2017
Natural
Gas
(MMcf)
1,616,930
3,208,380
4,825,310
Natural
Gas
Liquids
(MBbls)
36,247
39,519
75,766
Oil
(MBbls)
10,245
8,912
19,157
Proved developed
Proved undeveloped
Total (1)
2016
Oil
(MBbls)
Natural
Gas
(MMcf)
744,797
664 1,422,271
5,546 2,167,068
4,882
Natural
Gas
Liquids
(MBbls)
14,299
5,828
20,127
Total net proved oil and natural gas reserves (MMcfe) (1)
PV-10 value (in millions) (2)
Standardized measure (in millions) (3)
_____________________
Year Ended December 31,
2018
4,743,311
3,407.3 $
2,982.7 $
2017
5,394,851
2,883.0 $
2,643.6 $
$
$
2016
2,321,108
696.0
688.0
(1) Estimates of reserves as of year-end 2018, 2017 and 2016 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-
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month period ended December 31, 2018, 2017 and 2016, respectively, in accordance with revised guidelines of the SEC applicable to
reserves estimates as of year-end 2018, 2017 and 2016. 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, 2018, 2017 and 2016 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 $65.56 per barrel and $3.10 per MMBtu for 2018, $51.34 per barrel and $2.98 per MMBtu for 2017 and $42.75 per barrel and
$2.48 per MMBtu for 2016, 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.
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%
PV-10 value
December 31,
2018
2017
2016
(In thousands)
$
$
2,982,725 $
424,596
3,407,321 $
2,643,564 $
239,468
2,883,032 $
688,040
7,927
695,967
(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, 2018 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 2018 of $65.56 per barrel and $3.10 per MMBtu.
Holding production and development costs constant, if our 2018 reserves were calculated using the December 31, 2018 price of $45.41 per
barrel and $2.94 per MMBtu, our discounted future net cash flows before income taxes would have been approximately $2.5 billion, or
$0.9 billion less than our actual PV-10 value of $3.4 billion at December 31, 2018.
The table below provides the 2018 SEC pricing of benchmark prices as well as the unweighted average of the months ended
December 31, 2018 and January 31, 2019:
Henry Hub Natural Gas (per MMBtu)
WTI Crude Oil (per Bbl)
$
$
SEC Pricing 2018
2-month Average 2019
3.90
48.17
3.10 $
65.56 $
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
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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.
Changes in Proved Reserves during 2018.
The following table summarizes the changes in our estimated proved reserves during 2018 (in Bcfe):
Proved Reserves, December 31, 2017
Sales of oil and gas reserves in place
Extensions and discoveries
Revisions of prior reserve estimates
Current production
Proved Reserves, December 31, 2018
5,395
(45 )
711
(821 )
(497 )
4,743
Sales of oil and natural gas reserves in place. These are revisions to proved reserves resulting from the divestiture of minerals in place
during a period. During 2018, we sold approximately 44.9 Bcfe of proved oil and natural gas reserves through various sales of non-operated
interests in both our Utica and SCOOP fields.
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 approximately 711.2 Bcfe of proved
reserves were primarily attributable to the continued development of our Utica Shale and SCOOP acreage. We added 76 locations in our
Utica field, 59 locations in our SCOOP field and 13 new locations in our Southern Louisiana fields. Total extensions and discoveries of
approximately 569.8 Bcfe were attributed to our Utica field, which was primarily a result of our current development plan which refocuses
development within our existing fields. This change reflects our ongoing efforts to optimize the development program with well selection
based on economic returns, commodity mix and surface considerations.
Revisions of prior reserve estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting
from development plan changes, new information normally obtained from development drilling and production history or a change in
economic factors, such as commodity prices, operating costs or development costs.
We experienced downward revisions of approximately 1.0 Tcfe in estimated proved reserves with the exclusion of 127 PUD locations
in our Utica field and 12 PUD locations in our SCOOP field, which was primarily a result of changes in our schedule which moved
development of these PUD locations beyond five years of initial booking. The development plan change, as approved by our senior
management and board of directors, is a result of continued focus on free cash flow generation, thereby reducing the number of wells
included in our development plan. This downward revision was partially offset by upward revisions of approximately 82.4 Bcfe in
estimated proved reserves in 2018 due to changes in wellbore lateral length, 67.6 Bcfe due to changes in ownership interest, 27.9 Bcfe due
to an increase in pricing and 8.3 Bcfe due to changes in our well performance.
While commodity prices experienced volatility throughout 2018, the 12-month average price for natural gas increased from $2.98 per
MMBtu for 2017 to $3.10 per MMBtu for 2018, the 12-month average price for NGLs increased from $18.40 per barrel for 2017 to $32.02
per barrel for 2018, and the 12-month average price for crude oil increased from $51.34 per barrel for 2017 to $65.56 per barrel for 2018.
Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at
December 31, 2018, 2017 and 2016 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 19 to our consolidated financial
statements included in this report.
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Proved Undeveloped Reserves (PUDs)
As of December 31, 2018, our proved undeveloped reserves totaled 11,480 MBbls of oil, 2,320,705 MMcf of natural gas and 39,710
MBbls of NGLs, for a total of 2,627,845 MMcfe. Approximately 68% and 32% of our PUDs at year-end 2018 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.
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 changes in commodity price outlook and costs,
delays in the availability of infrastructure, well permitting delays and new data from recently completed wells.
The current development plan approved by our senior management and board of directors represents a decrease in drilling activity from
our previous plans with a focus on free cash flow generation. As a result, drilling of certain previously booked PUD locations in both our
Utica and SCOOP development plans has been extended beyond five years of initial booking. This change was not a result of well
performance or economics.
The following table summarizes the changes in our estimated proved undeveloped reserves during 2018 (in Bcfe):
Proved Undeveloped Reserves, December 31, 2017
Sales 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, 2018
3,499
(45 )
649
(576 )
(899 )
2,628
Sales of oil and natural gas reserves in place. During 2018, we sold approximately 44.9 Bcfe of proved undeveloped oil and natural
gas reserves associated with various non-operated interests, the majority of which were in our Utica field.
Extensions and discoveries. Our extensions and discoveries of approximately 649.4 Bcfe were primarily attributed to the addition of 75
PUD locations in the Utica field and 11 PUD locations in the SCOOP field as a result of our current development plan that refocused some
activity within our existing fields. This change reflects our ongoing efforts to optimize the development program with well selection based
on economic returns, commodity mix and surface considerations.
Conversion to proved developed reserves. We converted approximately 575.9 Bcfe attributable to 62 PUD locations into proved
developed reserves and 16 PUD locations into proved developed not producing. These 78 PUDs represent a conversion rate of 18% for
2018.
Revision of prior reserve estimates. We experienced negative revisions of approximately 1.0 Tcfe from the exclusion of 127 PUD
locations in our Utica field and 12 PUD locations in our SCOOP field, which were primarily a result of changes in our development plan
which moved development of these PUD locations beyond five years of initial booking. The development plan change, as approved by our
senior management and board of directors, is a result of a focus on free cash flow generation. This negative revision was partially offset by
positive revisions of 82.4 Bcfe in estimated proved reserves in 2018 due to changes in wellbore lateral length and 26.3 Bcfe due to change
in our ownership interest.
Costs incurred relating to the development of PUDs were approximately $370.3 million in 2018.
All PUD drilling locations included in our 2018 reserve report are scheduled to be drilled within five years of initial booking.
As of December 31, 2018, 1% of our total proved reserves were classified as proved developed non-producing.
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As noted above, our December 31, 2018 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 2018 of $65.56 per barrel and $3.10 per MMBtu.
Holding production and development costs constant, if SEC pricing were $50.00 per barrel and $2.50 per MMBtu, this would have resulted
in a loss of 1.3 Tcfe of our PUD volumes at December 31, 2018. Holding production and development costs constant, if SEC pricing were
$40.00 per barrel and $2.00 per MMBtu, this would have resulted in a loss of 2.3 Tcfe of our PUD volumes at December 31, 2018.
Production, Prices and Production Costs
The following table presents our production volumes, average prices received and average production costs during the periods
indicated:
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Natural gas sales
Natural gas production volumes (MMcf)
Total natural gas sales
Natural gas sales without the impact of derivatives ($/Mcf)
Impact from settled derivatives ($/Mcf)
Average natural gas sales price, including settled derivatives
($/Mcf)
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 ($/Mcfe)
Production Costs:
Average production costs ($/Mcfe)
Average production taxes ($/Mcfe)
Average midstream gathering and processing ($/Mcfe)
Total production costs, midstream costs and production taxes ($/Mcfe)
50
2018
2017
2016
($ In thousands)
443,742
350,061
227,594
1,121,815 $
845,999 $
420,128
2.53 $
(0.04) $
2.42 $
0.07 $
2.49 $
2.49 $
1.85
0.60
2.45
2,801
2,579
2,126
177,793 $
124,568 $
81,173
63.48 $
(9.51) $
48.29 $
1.59 $
53.97 $
49.88 $
38.18
5.11
43.29
251,720
224,038
161,562
178,915 $
136,057 $
59,115
0.71 $
(0.05) $
0.61 $
(0.03) $
0.37
(0.01)
0.66 $
0.58 $
0.36
496,505
397,543
263,430
1,478,523 $
1,106,624 $
560,416
2.98 $
(0.12) $
2.78 $
0.07 $
2.86 $
2.85 $
0.18 $
0.07 $
0.58 $
0.83 $
0.20 $
0.05 $
0.63 $
0.88 $
2.13
0.56
2.69
0.26
0.05
0.63
0.94
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
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Index to Financial Statements
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, 2018:
Utica Shale
Net Production
Oil (MBbls)
Natural gas (MMcf)
NGL (Mgal)
Total (MMcfe)
Average Sales Price Without the Impact of Derivatives:
Oil ($/Bbl)
Natural gas ($/Mcf)
NGL ($/Gal)
Average Production Costs ($/Mcfe)
SCOOP
Net Production
Oil (MBbls)
Natural gas (MMcf)
NGL (Mgal)
Total (MMcfe)
Average Sales Price Without the Impact of Derivatives:
Oil ($/Bbl)
Natural gas ($/Mcf)
NGL ($/Gal)
Average Production Costs ($/Mcfe)
Year Ended December 31,
2018
2017
2016
299
379,417
113,379
397,406
60.22 $
2.50 $
0.67 $
0.14 $
473
309,450
139,634
332,238
44.26 $
2.38 $
0.60 $
0.15 $
870
227,447
161,494
255,740
34.59
1.85
0.37
0.18
$
$
$
$
Year Ended December 31,
2018
2017 (1)
1,710
64,258
138,261
94,268
62.36 $
2.67 $
0.75 $
0.20 $
$
$
$
$
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, 2018.
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Average
Productive
NRI/WI (1)
Oil Wells
Percentages Gross Net
44.26/54.44
24.34/30.20
74 36.14
110 18.58
Productive
Gas Wells
Gross Net
493 271.86
466 154.69
Non-Productive
Oil Wells
Gross Net
3
3
2.66
2.59
Non-Productive
Gas Wells
Gross Net
Gross
2 1.57
30 25.24
92,594
48,658
Developed
Acreage (2)
Undeveloped
Acreage
Gross
Net
72,693 148,417 136,839
17,625
34,532
15,517
Net
80.108/100
69
69 —
—
146
146 — —
5,668
5,668
—
—
82.33/100
14
14 —
—
130
130 — —
2,910
2,910
1,206
1,206
87.50/100
2
2 —
—
7
7 — —
727
727
306
306
34.52/48.61
3
1.46 —
—
—
— — —
1,998
999
3,816
1,908
1.51/1.83
18
0.3 —
—
—
— — —
386
77
3,505
701
Various
673
963 142.38
0.9 —
—
959 426.55
—
289 288.25
— — —
—
32 26.81 152,941 117,606 174,875 156,477
—
—
—
Field
Utica Shale (3)
SCOOP (4)
West Cote
Blanche Bay
Field (5)
E. Hackberry
Field (6)
W. Hackberry
Field
Niobrara
Formation (7)
Bakken
Formation (8)
Overrides/Royalty
Non-operated
Total
(1) Net Revenue Interest (NRI)/Working Interest
(WI).
(2) Developed acres are acres spaced or assigned to productive wells. Approximately 43% 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, 2018, leases representing 11%, 10%, 9% and 32% are
currently scheduled to expire in 2019, 2020, 2021 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 216 gross (38.12 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, 2018, leases representing 53%, 5% and 1% are currently
scheduled to expire in 2019, 2020 and 2021, respectively. NRI/WI is from wells that have been drilled or in which we have elected to
participate. Includes 296 gross (22.20 net) gas well and 96 gross (7.82 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 66% of our total Niobrara undeveloped acreage are currently scheduled to expire in 2019 .
(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.
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Recompletions:
Productive
Dry
Total
Development:
Productive
Dry
Total
Exploratory:
Productive
Dry
Total
2018
2017
2016
Gross
Net
Gross
Net
Gross
Net
47
—
47
34
—
34
2
—
2
47
—
47
30
—
30
1.5
—
1.5
81
—
81
124
2
126
—
—
—
81
—
81
115.4
2
117.4
—
—
—
77
—
77
49
1
50
—
—
—
77
—
77
42.5
1.0
43.5
—
—
—
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 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 United States District Court for
the Western District of Louisiana. In both cases, the plaintiffs filed motions to remand the
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lawsuits to state court, which were ultimately granted by the district courts. However, on May 23, 2018, a group of defendants again
removed the Cameron Parish and Vermilion Parish lawsuits to federal court. In response, the plaintiffs again filed motions to remand the
cases to state court. The removing defendants have opposed plaintiffs' motions to remand. On January 16, 2019, the federal district court
held a hearing on plaintiff's motion to remand. The court took the matter under advisement and has not yet issued a ruling. Further action in
the cases will be stayed until the courts rule on the motions to remand. Also, shortly after the May 23, 2018 removal, the removing
defendants filed motions with the United States Judicial Panel on Multidistrict Litigation, or the MDL Panel, requesting that the Cameron
Parish and Vermilion Parish lawsuits be consolidated with 40 similar lawsuits so that pre-trial proceedings in the cases could be
coordinated. The MDL Panel denied the motion to consolidate the lawsuits. Due to the procedural posture of the lawsuits, the cases are
still in their early stages and the parties have conducted very little discovery. As a result, 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. While the outcome of the pending litigation, disputes or claims cannot be predicted with certainty, in the
opinion of our management, none of these matters, 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.
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:
2017
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
2018
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Price Range of
Common Stock
High
Low
$
$
22.35 $
17.82
15.09
15.08
13.74 $
12.70
13.41
11.67
15.66
12.47
10.90
11.73
8.11
8.60
10.07
6.18
Unregistered Sales of Equity Securities and Use of Proceeds
None.
Issuer Repurchases of Equity Securities
Our common stock repurchase activity for the three months ended December 31, 2018 was as follows:
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Period
October 2018
November 2018
December 2018
Total
Total number of
shares
purchased(2)
Average price paid
per share
— $
28,584 $
10,212,483 $
10,241,067 $
—
8.81
8.81
8.81
Total number of shares
purchased as part of
publicly announced
plans or programs (2)
Approximate maximum
dollar value of shares that
may yet be purchased
under the plans or
programs (1)
— $
— $
10,212,483 $
10,212,483
90,003,000
90,003,000
—
(1) In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0 million of our outstanding
common stock, and in May 2018 expanded this program authorizing us to acquire up to an additional $100.0 million of our
outstanding common stock during 2018 for a total of up to $200.0 million. This repurchase program was authorized to extend
through December 31, 2018 and was fully executed in December 2018.
(2) In November 2018, we repurchased and canceled 28,584 shares at a weighted average price of $8.81 to satisfy tax withholding
requirements incurred upon the vesting of restricted stock. Additionally, in December 2018, we repurchased and canceled
approximately 10,212,483 shares under the repurchase program at a weighted average price of $8.81 per share.
In January 2019, our board of directors approved a new stock repurchase program to acquire up to $400.0 million of our outstanding
common stock within the next 24 months. Our board of director’s determination to repurchase shares of our common stock under our new
stock repurchase program 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.
Holders of Record
At the close of business on February 18, 2019, there were 319 stockholders of record holding 162,986,045 shares of our outstanding
common stock. There were approximately 20,540 beneficial owners of our common stock as of February 18, 2019.
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.
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,
2018, December 31, 2017 and December 31, 2016 and the selected consolidated balance sheet data at December 31, 2018 and
December 31, 2017 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, 2015 and December 31, 2014 and the selected
consolidated balance sheet data at December 31, 2016, December 31, 2015 and December 31, 2014 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.
55
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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 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
Gain on sale of equity method
investments
(Income) loss from equity method
investments
Other expense (income)
Income (Loss) from Continuing
Operations before Income Taxes
Income Tax (Benefit) Expense
Income (Loss) from Continuing
Operations
Net Income (Loss) Available to Common
Stockholders
Net Income (Loss) Per Common Share—
Basic:
Net Income (Loss) Per Common Share—
Diluted:
$
$
$
Fiscal Year Ended December 31,
2018
2017
2016
2015
2014
(In thousands, except share data)
$
1,355,044 $
1,320,303 $
385,910 $
708,990 $
670,762
91,640
33,480
290,188
80,246
21,126
248,995
68,877
13,276
165,972
69,475
14,740
138,590
52,191
24,006
64,467
486,664
364,629
245,974
337,694
265,431
—
56,633
4,119
—
—
962,724
392,320
135,273
(314)
1,075
(231)
—
—
—
52,938
1,611
2,392
—
771,937
548,366
108,198
(1,009)
—
—
—
—
715,495
43,409
1,057
—
—
1,254,060
(868,150)
63,530
(1,230)
—
(5,718)
23,776
—
1,440,418
41,967
820
—
—
2,043,704
(1,334,714)
51,221
(643)
—
(10,015)
—
—
—
38,290
761
—
(11)
445,135
225,627
23,986
(195)
25,500
—
—
(84,470)
(124,768)
(12,523)
(3,391)
—
—
(49,904)
698
(38,171)
17,780
(1,041)
111,405
37,376
129
114,472
106,093
(485)
146,171
430,491
436,961
(982,622)
(1,480,885)
(69)
1,809
(2,913)
(256,001)
(139,434)
(504)
(175,117)
400,744
153,341
430,560
435,152
(979,709)
(1,224,884)
247,403
430,560 $
435,152 $
(979,709) $
(1,224,884) $
247,403
2.46 $
2.42 $
(7.97) $
(12.27) $
2.45 $
2.41 $
(7.97) $
(12.27) $
2.90
2.88
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2018
2017
2016
2015
2014
(In thousands)
At December 31,
Selected Consolidated Balance Sheet
Data:
Total assets
Total debt, including current maturities
Total liabilities
Stockholders’ equity
$
$
$
$
6,051,036 $
2,087,416 $
2,723,268 $
3,327,768 $
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
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 21.9% 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 four 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 response to current declining forward
natural gas prices, we are shifting to building an organization that is focused on disciplined capital allocation, cash flow generation and a
commitment to executing a thoughtful, clearly communicated business plan that enhances value for all of our shareholders. We plan to
maximize results with the core assets in our portfolio today and focus on returns that will allow us to operate within our cash flow in 2019.
2018 and 2019 Year to Date Highlights
•
•
•
•
Production increased 25% to approximately 496,505 MMcfe for the year ended December 31, 2018 from approximately 397,543
MMcfe for the year ended December 31, 2017.
During 2018, we spud 36 gross (31.6 net) wells, turned to sales 50 gross (47.8 net) operated wells, participated in an additional 68
gross (7.5 net) wells that were drilled by other operators on our Utica Shale and SCOOP acreage and recompleted 47 existing
wells in our Southern Louisiana fields. Of our 36 new wells spud during 2018, seven were completed as producing wells and, at
year end, 29 were in various stages of completion.
Oil and natural gas revenues, before the impact of derivatives, increased 36% to $1.5 billion for the year ended December 31,
2018 from $1.1 billion for the year ended December 31, 2017.
During the year ended December 31, 2018, we reduced our unit lease operating expense by 10% to $0.18 per Mcfe from $0.20 per
Mcfe during the year ended December 31, 2017.
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•
•
•
•
•
•
•
During the year ended December 31, 2018, we reduced our unit general and administrative expense by 15% to $0.11 per Mcfe
from $0.13 per Mcfe during the year ended December 31, 2017.
During the year ended December 31, 2018, we reduced our unit midstream gathering and processing expense by 8% to $0.58 per
Mcfe from $0.63 per Mcfe during the year ended December 31, 2017.
In January 2018, our board of directors approved a stock repurchase program to acquire up to $100.0 million of our outstanding
common stock, and in May 2018 expanded this program to acquire up to an additional $100.0 million of our common stock during
2018 for a total of up to $200.0 million, which we believe underscores the confidence we have in our business model, financial
performance and asset base. During 2018, we purchased 20.7 million shares of our outstanding common stock for a total of
approximately $200.0 million.
On May 1, 2018, we sold our 25% equity interest in Strike Force Midstream LLC, or Strike Force, to EQT Midstream Partners, LP
for $175.0 million in cash.
On June 29, 2018, we sold 1,235,600 shares, and on July 30, 2018, we sold an additional 118,974 shares, of our Mammoth Energy
common stock in an underwritten public offering and related partial exercise of the underwriters' option to purchase additional
shares for an aggregate net proceeds to us of approximately $51.5 million. Following the sale of these shares, we owned 9,829,548
shares, or 21.9% at December 31, 2018, of Mammoth Energy’s outstanding common stock.
During 2019 (through February 15, 2019), we spud seven gross (5.3 net) wells. As of February 15, 2019, three wells were waiting
on completion and four were still being drilled.
In January 2019, our board of directors approved a stock repurchase program to acquire up to $400.0 million of our outstanding
common stock within the next 24 months, which we believe underscores the confidence we have in our business model, financial
performance and asset base.
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 (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
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totaled $2.9 billion at both December 31, 2018 and December 31, 2017. 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 years ended December 31,
2018 and 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 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 & Associates, Inc. has prepared reserve reports of our reserve estimates at
December 31, 2018 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.
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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. Quarterly, 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, 2018, a valuation allowance of $212.0 million had been established for the net deferred tax asset. On
December 22, 2018, we finalized the provisional accounting for the Tax Cuts and Jobs Act, which was enacted in 2017. Further
information on the tax impacts of the Tax Cut and Jobs Act is included in Note 11 of our consolidated financial statements.
Revenue Recognition. We derive almost all of our revenue from the sale of crude oil, natural gas and natural gas liquids 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 year ended December 31, 2016, we recognized an impairment loss related to our
investment in Grizzly of approximately $23.1 million.
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. All derivative instruments are 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.
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, 2018.
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.
60
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Index to Financial Statements
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 ($/Mcf)
Average natural gas sales price, including settled derivatives ($/Mcf)
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 ($/Mcfe)
Production Costs:
Average production costs ($/Mcfe)
Average production taxes ($/Mcfe)
Average midstream gathering and processing ($/Mcfe)
Total production costs, midstream costs and production taxes ($/Mcfe)
61
2018
2017
2016
($ In thousands)
443,742
350,061
227,594
1,121,815 $
845,999 $
420,128
2.53 $
(0.04) $
2.49 $
2.42 $
0.07 $
2.49 $
1.85
0.60
2.45
2,801
2,579
2,126
177,793 $
124,568 $
81,173
63.48 $
(9.51) $
48.29 $
1.59 $
53.97 $
49.88 $
38.18
5.11
43.29
251,720
224,038
161,562
178,915 $
136,057 $
59,115
0.71 $
(0.05) $
0.61 $
(0.03) $
0.37
(0.01)
0.66 $
0.58 $
0.36
496,505
397,543
263,430
1,478,523 $
1,106,624 $
560,416
2.98 $
(0.12) $
2.78 $
0.07 $
2.86 $
2.85 $
0.18 $
0.07 $
0.58 $
0.83 $
0.20 $
0.05 $
0.63 $
0.88 $
2.13
0.56
2.69
0.26
0.05
0.63
0.94
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Table of Contents
Index to Financial Statements
The total volume hedged for 2018, 2017 and 2016 represented approximately 78%, 68% and 77%, respectively, of our total sales
volumes for the applicable year.
From 2017 to 2018, our net equivalent gas production increased 25% from 397,543 MMcfe to 496,505 MMcfe primarily as a result of
the continued development of our Utica Shale and SCOOP acreage. 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. We currently estimate that our 2019 production will be between 496,400 and 511,000 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."
Comparison of the Years Ended December 31, 2018 and December 31, 2017
We reported net income of $430.6 million for the year ended December 31, 2018 as compared to net income of $435.2 million for the
year ended December 31, 2017. This decrease in period-to-period net income was due primarily to a $41.2 million increase in midstream
gathering and processing expenses, a $122.0 million increase in depreciation, depletion and amortization expense and a $27.1 million
increase in interest expense, partially offset by a $34.7 million increase in oil and natural gas revenues, a $112.2 million increase in gain on
sale of equity method investments and a $67.7 million increase in income from equity method investments for the year ended December 31,
2018, as compared to the year ended December 31, 2017.
Oil and Natural Gas Revenues. For the year ended December 31, 2018, we reported oil and natural gas revenues of $1.4 billion as
compared to oil and natural gas revenues of $1.3 billion during 2017. This $34.7 million, or 3%, increase in revenues was primarily
attributable to the following:
•
•
•
•
A $275.8 million increase in natural gas sales without the impact of derivatives due to a 27% increase in natural gas sales volumes
and a 5% increase in natural gas market prices.
A $53.2 million increase in oil and condensate sales without the impact of derivatives due to a 9% increase in oil and condensate
sales volumes and a 32% increase in oil and condensate market prices.
A $42.9 million increase in natural gas liquids sales without the impact of derivatives due to a 12% increase in natural gas liquids
sales volumes and a 17% increase in natural gas liquids market prices.
A $337.2 million decrease in natural gas and oil sales due to an unfavorable change in gains and losses from derivative
instruments. Of the total change, $253.9 million was due to unfavorable changes in the fair value of our open derivative positions
in each period and $83.3 million was due to an unfavorable change in settlements related to our derivative positions.
Lease Operating Expenses. Lease operating expenses, or LOE, not including production taxes increased to $91.6 million for the year
ended December 31, 2018 from $80.2 million for the year ended December 31, 2017. This increase was mainly the result of an increase in
expenses related to overhead, water hauling and disposal and ad valorem taxes, partially offset by decreases in road, location and equipment
repairs, surface rentals and compression. However, due to increased efficiencies and a 25% increase in our production volumes for the year
ended December 31, 2018 as compared to the year ended December 31, 2017, our per unit LOE decreased by 10% from $0.20 per Mcfe to
$0.18 per Mcfe.
Production Taxes. Production taxes increased to $33.5 million for the year ended December 31, 2018 from $21.1 million for 2017.
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 $41.2 million to $290.2
million for the year ended December 31, 2018 from $249.0 million for 2017. This increase was primarily the result of midstream expenses
related to our increased production volumes in the Utica Shale and SCOOP resulting from our 2018 and 2017 drilling activities.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increased to $486.7 million
for the year ended December 31, 2018, and consisted of $476.4 million in depletion of oil and natural gas properties and $10.3 million in
depreciation of other property and equipment, as compared to total DD&A expense of $364.6
62
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Index to Financial Statements
million for 2017. This increase was due to an increase in our production and our full cost pool and a decrease 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 $56.6 million for the year ended
December 31, 2018 from $52.9 million for the year ended December 31, 2017. This $3.7 million increase was due to an increase in salaries,
benefits and employee stock compensation expense resulting from an increased number of employees, legal fees and computer support,
partially offset by a decrease in consulting fees. However, during the year ended December 31, 2018, we decreased our per unit general and
administrative expense by 15% to $0.11 per Mcfe from $0.13 per Mcfe during the year ended December 31, 2017 as a result of increases in
production.
Accretion Expense. Accretion expense increased to $4.1 million for the years ended December 31, 2018 from $1.6 million for the year
ended December 31, 2017, primarily as a result of changes in our asset retirement obligation assumptions during 2017.
Interest Expense. Interest expense increased to $135.3 million for the year ended December 31, 2018 from $108.2 million for the year
ended December 31, 2017 due primarily to the issuance of $450.0 million of the 2026 Notes in October 2017. In addition, total weighted
debt outstanding under our revolving credit facility was $83.6 million for the year ended December 31, 2018 as compared to $119.2 million
outstanding under such facility for 2017. Additionally, we capitalized approximately $4.5 million and $9.5 million in interest expense to
undeveloped oil and natural gas properties during the years ended December 31, 2018 and December 31, 2017, respectively. This decrease
in capitalized interest in the 2018 period was primarily the result of changes to our development plan for our oil and natural gas properties.
Income Taxes. As of December 31, 2018, we had a net operating loss carry forward of approximately $782.7 million, in addition to
numerous temporary differences, which gave rise to a net deferred tax asset. Quarterly, 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, 2018, a valuation allowance of $212.0 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 benefit from continuing operations of $0.1 million for the year ended December 31, 2018.
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 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.
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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 $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 year 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.
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.
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Our primary uses of cash are for ongoing business operations, repayments of our debt, capital expenditures, investments and
acquisitions. During 2018, we initiated a stock repurchase program to purchase shares of our common stock. During 2019, we intend to
purchase additional shares of our common stock under our recently announced stock repurchase program opportunistically with available
funds or non-core asset sales while maintaining sufficient liquidity to fund our 2019 capital development program.
Net cash flow provided by operating activities was $752.5 million for the year ended December 31, 2018 as compared to net cash flow
provided by operating activities of $679.9 million for 2017. This increase was primarily the result of an increase in cash receipts from our
oil and natural gas purchasers due to a 26% 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 $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 used in investing activities for the year ended December 31, 2018 was $643.1 million as compared to $2.5 billion for 2017.
During the year ended December 31, 2018, we spent $865.3 million in additions to oil and natural gas properties, of which $461.8 million
was spent on our 2018 drilling and recompletion programs, $193.9 million was spent on expenses attributable to the wells spud, completed
and recompleted during 2017, $125.6 million was spent on lease related costs, primarily the acquisition of leases in the Utica Shale, $2.6
million was spent on facility enhancements and $2.1 million was spent on plugging costs, with the remainder attributable mainly to future
location development and capitalized general and administrative expenses. During the year ended December 31, 2018, we received $175.0
million from the sale of our equity investment in Strike Force and $51.5 million from the sale of Mammoth Energy's common stock. In
addition, we invested $2.3 million in Grizzly, and we received $0.4 million in distributions from our investment in Timber Wolf during the
year ended December 31, 2018. We did not make any material investments in our other equity investments during the year ended
December 31, 2018. During the year ended December 31, 2018, we used cash from operations and proceeds from sales of our investments
to fund our investing activities.
Net cash used in investing activities for the year ended December 31, 2017 was $2.5 billion as compared to $720.6 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, $119.8 million was spent on lease related costs, primarily the acquisition of leases in
the Utica Shale and the SCOOP, $97.4 million was spent on expenses attributable to the wells spud, completed and recompleted during
2016, $7.2 million was spent on seismic, $4.3 million was spent on plugging costs and $1.5 million was spent on facility enhancements,
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 (prior to our sale of our equity interest in Strike Force in May 2018), net of distributions. We did
not make any material investments in 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 financing activities for the year ended December 31, 2018 was $156.7 million as compared to net cash provided by
financing activities of $433.0 million for 2017. The 2018 amount used by financing activities is primarily attributable to repurchases under
our stock repurchase program of approximately $200.0 million, partially offset by net borrowings under our credit facility.
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.
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, 2018, we had a borrowing base of $1.4 billion, with an
elected commitment of $1.0 billion, and $45.0 million in borrowings outstanding under our revolving credit facility. Total funds available
for borrowing, after giving effect to an aggregate of $316.6 million of letters of credit, were $638.4 million. This facility is secured by
substantially all of our assets. Our wholly-owned subsidiaries guarantee our obligations under our revolving credit facility.
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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 0.25% to 1.25%, 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 1.25% to 2.25%, 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. As of December 31, 2018, amounts borrowed under our revolving credit facility bore interest at the weighted average rate of
4.23%.
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 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, 2018.
Senior Notes. In April 2015, we issued an aggregate of $350.0 million in principal amount of our Senior Notes due 2023, or the 2023
Notes. Interest on 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.
On October 14, 2016, we issued an aggregate of $650.0 million in principal amount of our Senior Notes due 2024, or the 2024 Notes.
Interest on the 2024 Notes accrues at a rate of 6.000% per annum on the outstanding principal amount thereof, 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.
On December 21, 2016, we issued an aggregate of $600.0 million in principal amount of our Senior Notes due 2025, or the 2025
Notes. Interest on the 2025 Notes accrues at a rate of 6.375% per annum on the outstanding principal amount thereof, 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.
On October 11, 2017, we issued $450.0 million in aggregate principal amount of our 2026 Notes. Interest on the 2026 Notes accrues at
a rate of 6.375% per annum on the outstanding principal amount thereof, 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 $444.1 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
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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, 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.
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, after which date we began making monthly payments of
interest and principal. The final payment is due June 4, 2025. As of December 31, 2018, the total borrowings under the construction loan
were approximately $23.1 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 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, 2018, 55.4% 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 2018, we spud 23 gross (19.5 net) and commenced sales from 35 gross and net wells in the Utica Shale for a total cost of
approximately $305.8 million. In addition, 28 gross (4.4 net) wells were drilled and 32 gross (9.4 net) wells were turned to sales by other
operators on our Utica Shale acreage during 2018 for a total cost to us of approximately $90.1 million. We currently expect to drill 13 to 15
gross (10 to 11 net) horizontal wells and commence sales from 47 to 51 gross (40 to 45 net) horizontal wells on our Utica Shale acreage. As
of February 15, 2019, we had two operated horizontal rig drilling in the play. We plan to run on average one operated horizontal rig in the
Utica Shale during 2019. We also anticipate an additional two to three net horizontal wells will be drilled, and sales commenced from two
to three net horizontal wells, on our Utica Shale acreage by other operators.
During 2018, we spud 13 gross (12.1 net) and commenced sales from 15 gross (12.8 net) wells in the SCOOP for a total cost of
approximately $141.3 million. In addition, 40 gross (3.1 net) wells were drilled and 47 gross (3.6 net) wells were turned to sales by other
operators on our SCOOP acreage during 2018 for a total cost to us of approximately $39.0 million. During 2019, we currently expect to
drill nine to 10 gross (seven to eight net) horizontal wells and commence sales from 15 to
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17 gross (14 to 15 net) wells on our SCOOP acreage. We also anticipate one to two net wells will be drilled, and sales commenced from one
to two net wells on our SCOOP acreage by other operators. As of February 15, 2019, we had two operated horizontal drilling rigs in the
play. We plan to run on average approximately 1.5 operated horizontal rigs in the SCOOP in 2019.
During 2018, we recompleted 32 existing wells and spud no new wells at our WCBB field and recompleted 15 existing wells and spud
no new wells in our Hackberry fields for a total aggregate cost of approximately $7.9 million. During 2019, we do not anticipate any
activities in our Southern Louisiana fields.
During 2018, no new wells were spud on our Niobrara Formation acreage. We do not currently anticipate any capital expenditures in
the Niobrara Formation in 2019.
During the third quarter of 2006, we purchased a 24.9% interest in Grizzly. As of December 31, 2018, our net investment in Grizzly
was approximately $44.3 million. Our capital requirements in 2018 for Grizzly were approximately $2.3 million. We do not currently
anticipate any material capital expenditures in 2019 related to Grizzly's activities.
We had no material capital expenditures during the during the year ended December 31, 2018 related to our interests in Thailand. We
do not currently anticipate any capital expenditures in Thailand in 2019.
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, 2018 and 2017, we did not make any additional investments in these entities, and we do not currently anticipate any capital
expenditures related to these entities in 2019. 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%. On June 29, 2018, we sold 1,235,600 shares, and on
July 30, 2018, we sold an additional 118,974 shares, of our Mammoth Energy common stock in an underwritten public offering and related
partial exercise of the underwriters' option to purchase additional shares for net proceeds to us of approximately $47.0 million and $4.5
million, respectively. Following the sale of these shares, we owned 9,829,548 shares, or 21.9% at December 31, 2018, of Mammoth
Energy’s outstanding common stock.
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. In 2017, Rice was acquired by EQT Corporation, or EQT. Prior to the sale of the Company's interest in Strike
Force (discussed below), the Company owned a 25% interest in Strike Force, and EQT acted as operator and owned the remaining 75%
interest in Strike Force. Strike Force's gathering assets provide gathering services for wells operated by Gulfport and other operators and
connectivity of existing dry gas gathering systems. During the year ended December 31, 2017, we paid $46.1 million in net cash calls
related to Strike Force. On May 1, 2018, we sold our 25% equity interest in Strike Force to EQT Midstream Partners, LP for $175.0 million
in cash.
In response to current declining forward natural gas prices, we are shifting to building an organization that is focused on disciplined
capital allocation, cash flow generation and a commitment to executing a thoughtful, clearly communicated business plan that enhances
value for all of our shareholders. We plan to maximize results with the core assets in our portfolio today and focus on returns that will
allow us to operate within our cash flow in 2019. As a result, we currently expect to reduce our planned capital expenditures by
approximately 29% as compared to 2018.
Our total capital expenditures for 2019 are currently estimated to be in the range of $525.0 million to $550.0 million for drilling and
completion expenditures. In addition, we currently expect to spend $40.0 million to $50.0 million in 2019 for non-drilling and completion
expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale. The 2019 range of capital expenditures is
lower than the $814.7 million spent in 2018, primarily due to the decrease in current commodity
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prices, specifically natural gas prices, and our desire to fund our capital development program within cash flow, as well as to generate free
cash flow.
In January 2019, our board of directors approved a stock repurchase program to acquire up to $400.0 million of our outstanding
common stock within the next 24 months. We intend to purchase shares under the repurchase program opportunistically with available
funds primarily from cash flow from operations and sale of non-core assets while maintaining sufficient liquidity to fund our capital
development programs.
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. 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.
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 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. During 2018, WTI prices ranged from $44.48 to $77.41 per barrel and the Henry Hub spot market price of
natural gas ranged from $2.49 to $6.24 per MMBtu. If the prices of oil and natural gas 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, 2018.
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, 2018, the plugging and abandonment trust totaled
approximately $3.1 million. At December 31, 2018, we have plugged 555 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, and in May 2018 expanded this program authorizing us to acquire up to an additional $100.0 million of our
outstanding common stock during 2018 for a total of up to $200.0 million. The Company fully executed the program during the year ended
December 31, 2018, and repurchased 20.7 million shares for a cost of approximately $200.0 million. In January 2019, our board of directors
approved a stock repurchase program to acquire up to $400.0 million of our outstanding common stock within the next 24 months.
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
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number of shares. The Company intends to purchase shares under the repurchase program opportunistically with available funds while
maintaining sufficient liquidity to fund its 2019 capital development program. This repurchase program is authorized to extend through
December 31, 2020 and may be suspended from time to time, modified, extended or discontinued by the board of directors of the Company
at any time. We did not make any purchases of our common stock during the year ended December 31, 2017 under any stock repurchase
program or otherwise.
Contractual and Commercial Obligations
The following table sets forth our contractual and commercial obligations at December 31, 2018:
Contractual Obligations
Total
Less than 1 year
1-3 years
3-5 years
More than 5
years
Payment due by period
Revolving credit agreement (1)
6.625% senior unsecured notes due 2023 (2)
6.000% senior unsecured notes due 2024 (3)
6.375% senior unsecured notes due 2025 (4)
6.375% senior unsecured notes due 2026 (5)
Asset retirement obligations (6)
Building loan (7)
Firm transportation contracts
Drilling and purchase obligations (8)
Operating leases
Total
_____________________
$
45,000 $
454,344
884,101
848,748
665,156
79,952
23,149
3,504,318
204,969
271
$
6,710,008 $
(In thousands)
— $
23,188
39,000
38,250
28,687
—
651
251,644
89,022
144
470,586 $
45,000 $
46,375
78,000
76,500
57,375
—
1,290
494,201
115,947
127
— $
384,781
78,000
76,500
57,375
—
1,416
490,972
—
—
914,815 $ 1,089,044 $
—
—
689,101
657,498
521,719
79,952
19,792
2,267,501
—
—
4,235,563
(1) Does not include future loan advances, repayments, commitment fees or other fees on our revolving credit facility as we cannot
determine with accuracy the timing of such items. Additionally, this table does not include interest expense as it is a floating rate
instrument and we cannot determine with accuracy the future interest rates to be charge.
(2) Includes estimated interest of $23.2 million due in less than one year; $46.4 million due in 1-3 years and $34.8 million due in 3-5 years.
(3) 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
$39.1 million due thereafter.
(4) 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
$57.5 million due thereafter.
(5) Includes estimated interest of $28.7 million due in less than one year; $57.4 million due in 1-3 years; $57.4 million due in 3-5 years and
$71.7 million due thereafter.
(6) Amount represents the estimated discounted cost for future abandonment of oil and natural gas properties. Due to the uncertainty in
timing of the obligation and no current contractual obligation, the liability is included in the "More than 5 years" category.
(7) Does not include estimated interest of $1.0 million due in less than one year; $2.0 million due in 1-3 years: $1.9 million due in 3-5
years and $1.3 million due thereafter.
(8) Drilling and purchasing obligations reported above represent our minimum financial commitment pursuant to the terms of these
contracts. A portion of these future costs will be borne by other interest owners.
Off-balance Sheet Arrangements
We had no off-balance sheet arrangements as of December 31, 2018.
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-
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specific guidance with Topic 606. 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. We adopted ASC 606 as of January 1, 2018 using the modified retrospective transition method applied to contracts that were not
completed as of that date. Results for reporting periods beginning after January 1, 2018 are presented under the new revenue standard.
Under the modified retrospective method, we recognize the cumulative effect of initially applying the new revenue standard as an
adjustment to the opening balance of retained earnings; however, no adjustment was required as a result of adopting the new revenue
standard. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect
for those periods. The impact of the adoption of the new revenue standard is not expected to be material to our net income on an ongoing
basis. See Note 10 to our consolidated financial statements for further discussion of the revenue standard.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The standard supersedes the previous lease guidance by
requiring lessees to recognize a right-to-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one
year while maintaining substantially similar classifications for financing and operating leases. The guidance is effective for periods after
December 15, 2018, and we will adopt beginning January 1, 2018 using the transition method permitted by ASU No. 2018-11, Leases
(Topic 842): Targeted Improvements, issued in August 2018, which permits an entity to recognize a cumulative-effect adjustment to the
opening balance of retained earnings in the period of adoption with no adjustment made to the comparative periods presented in the
consolidated financial statements. We will also utilize the practical expedient provided by ASU 2018-11 to not separate non-lease
components from the associated lease component and, instead, to account for those components as a single component if the non-lease
components would be accounted for under ASC 606 and other conditions are met.
We have identified our portfolio of leased assets under the new standard and has evaluated the impact of this guidance on our
consolidated financial statements and related disclosures. Offsetting right-of-use assets and corresponding lease liabilities recognized by us
on the adoption date totaled approximately $110 million, representing minimum payment obligations associated with identified leases with
contractual durations longer than one year. Adoption of the new standard will not result in a material impact to the consolidated statement
of operations. We have implemented processes and controls needed to comply with the requirements of the new standard, which includes
the implementation of a lease accounting software solution to support lease portfolio management and accounting and disclosures.
Additionally, in January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for
Transition to Topic 842. The amendments in this update provide an optional expedient to not evaluate existing or expired land easements
that were not previously accounted for under current leases guidance in Topic 840. An entity that elects this practical expedient should
evaluate new or modified land easements beginning at the date of adoption. We do not currently account for any land easements under
Topic 840 and plan to utilize this practical expedient in conjunction with the adoption of ASU 2016-02.
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 guidance is effective for periods after December 15, 2019, with early
adoption permitted. 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 effect.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash
Payments. This ASU clarifies how certain cash receipts and cash payments should be classified and presented in the statement of cash
flows. We adopted this standard in the first quarter of 2018 and have made an accounting policy election to classify distributions received
from equity method investees using the nature of the distribution approach, which classifies distributions received from investees as either
cash inflows from operating activities or cash inflows from investing activities in the statement of cash flows based on the nature of the
activities of the investee that generated the distribution. The impact of adopting this ASU was not material to prior periods presented.
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires
that amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash
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equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows and to provide a
reconciliation of the totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents,
restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. We adopted this standard in
the first quarter of 2018 using the retrospective transition method. The adoption of this standard had no impact on the statement of cash
flows for the year ended December 31, 2018. As a result of the adoption, $185.0 million in restricted cash was removed from net cash used
in investing resulting in an increase to the ending cash balance for the year ended December 31, 2016. The adoption also resulted in an
addition of $185.0 million in restricted cash to the net cash used in investing activities for the year ended December 31, 2017. This addition
and the resulting decrease to ending cash was offset by the increase to beginning cash balance of $185.0 million due to the changes at
December 31, 2016. Therefore, there was no net impact on the statement of cash flows as of December 31, 2017.
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. We adopted this standard in the first quarter of 2018 with no significant effect on our financial statements or related disclosures.
In February 2018, the FASB issued ASU No. 2018-02, Income statement - Reporting Comprehensive Income (Topic 220) -
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated
other comprehensive income to retained earnings for standard tax effects resulting from the Tax Cuts and Jobs Act of 2017. The
amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. We assessed the
impact of the ASU on our consolidated financial statements and related disclosures, and determined there was no material impact.
In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the
Disclosure Requirements for Fair Value Measurement, which removes, modifies, and adds certain disclosure requirements on fair value
measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted.
We are currently assessing the impact of the ASU on our consolidated financial statements and related disclosures
In August 2018, the FASB also issued ASU No. 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-
40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which
aligns the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service
contract with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective
for reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently assessing the impact of the
ASU on our consolidated financial statements and related disclosures.
In August 2018, the Securities and Exchange Commission ("SEC") issued Final Rule Release No. 33-10532, Disclosure Update and
Simplification, which amends certain disclosure requirements that were redundant, duplicative, overlapping or superseded. Under these
amendments, the annual disclosure requirements on the analysis of stockholders' equity is extended to interim financial statements. We
will present an analysis of changes in stockholders' equity for the current and comparative year-to-date interim periods. The final rule is
effective November 5, 2018, and we will begin presenting this analysis beginning with the quarter ended March 31, 2019.
In November 2018, the FASB also issued ASU No. 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction
Between Topic 808 and Topic 606, which provides guidance on how to assess whether certain transactions between participants in a
collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. The
amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. We are currently
assessing the impact of the ASU on its consolidated financial statements and related disclosures.
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
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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 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. During 2018, WTI prices ranged from $44.48 to $77.41 per barrel and the Henry Hub spot market
price of natural gas ranged from $2.49 to $6.24 per MMBtu. If the prices of oil and natural gas 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, 2018.
2019
2020
2019
2019
2019
Location
Daily Volume
(MMBtu/day)
Weighted
Average Price
NYMEX Henry Hub
NYMEX Henry Hub
1,254,000 $
204,000 $
2.83
2.77
Location
Mont Belvieu C2
Mont Belvieu C3
Mont Belvieu C5
Daily Volume
(Bbls/day)
1,000
$
4,000 $
500 $
Weighted
Average Price
18.48
28.87
54.08
During the fourth quarter of 2018, we early terminated all of our fixed price swaps for oil based on both Argus Louisiana Light Sweet
Crude and NYMEX West Texas Intermediate scheduled to settle during 2019 covering 5,000 Bbls/day. These early terminations resulted in
approximately $0.4 million of settlement losses which is included in net (loss) gain on natural gas, oil, and NGL derivatives in the
accompanying consolidated statement of operations.
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 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 2019 - March 2019
April 2019 - December 2019
Location
NYMEX Henry Hub
NYMEX Henry Hub
Daily Volume
(MMBtu/day)
Weighted
Average Price
50,000 $
30,000 $
3.13
3.10
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For a portion of the natural gas fixed price swaps listed above, the counterparties had the option to extend the original terms an
additional twelve months for the period January 2019 through December 2019. In December 2018, the counterparties chose to exercise all
natural gas fixed price swaps, resulting in an additional 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu, which is
included in the natural gas fixed price swaps listed above.
In addition, we have entered into natural gas basis swap positions, which settle on the pricing index to basis differential of Transco
Zone 4 to the NYMEX Henry Hub natural gas price. As of December 31, 2018, we had the following natural gas basis swap positions for
Transco Zone 4.
2019
2020
Location
Transco Zone 4
Transco Zone 4
Daily Volume
(MMBtu/day)
Hedged
Differential
60,000 $
60,000 $
(0.05)
(0.05)
In February 2019, we entered into a natural gas basis swap position for 2020, which settles on the pricing index to basis differential of
Inside FERC to the NYMEX Henry Hub natural gas price, for approximately 10,000 MMBtu of natural gas per day at a differential of
$0.54 per MMBtu. Our fixed price swap contracts are tied to the commodity prices on NYMEX Henry Hub for natural gas and Mont
Belvieu for propane, pentane and ethane. We will receive the fixed priced amount stated in the contract and pay to its counterparty the
current market price as listed on NYMEX Henry Hub for natural gas or Mont Belvieu for propane, pentane and ethane.
Under our 2019 contracts, we have hedged approximately 94% to 97% of our expected 2019 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, 2018, we had a net liability derivative position of $13.0 million as compared to a net asset derivative position of $52.0
million as of December 31, 2017, 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 $155.1 million, while a 10%
decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $154.6 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, 2018, we had $45.0 million in borrowings outstanding under our credit facility which
bore interest at the weighted average rate of 4.23%. A 1% increase in the average interest rate would have increased interest expense by
approximately $0.8 million based on outstanding borrowings under our revolving credit facility throughout the year ended December 31,
2018. As of December 31, 2018, we did not have any interest rate swaps to hedge our interest risks.
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
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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, 2018, 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, 2018, 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, 2018.
Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended
December 31, 2018 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of
December 31, 2018, as stated in their accompanying report.
/s/ David M. Wood
Name:
Title:
David M. Wood
Chief Executive Officer and President
/s/ Keri Crowell
Name:
Title:
Keri Crowell
Chief Financial Officer
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Board of Directors and Stockholders
Gulfport Energy Corporation
Report of Independent Registered Public Accounting Firm
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, 2018, 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, 2018, 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, 2018, and our report dated February 28,
2019 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 28, 2019
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ITEM 9B.
OTHER INFORMATION
None.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
PART III
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).
77
Table of Contents
Index to Financial Statements
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
PART IV
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
4.4
4.5
4.6
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).
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 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).
78
Table of Contents
Index to Financial Statements
4.7
10.1+
10.2+
10.3+
10.4+
10.5+
10.6+
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
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).
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).
Separation and Release Agreement, effective October 29, 2018, by and between Gulfport Energy Corporation 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 November 1, 2018).
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).
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).
79
Table of Contents
Index to Financial Statements
10.15
10.16
10.17
10.18
10.19
10.20
10.21#
10.22#
10.23
10.24#
10.25#
10.26#
10.27+
10.28+
10.29+
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).
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).
Twelfth Amendment to Amended and Restated Credit Agreement, dated as of May 21, 2018, 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 May 25,
2018).
Thirteenth Amendment to the Amended and Restated Credit Agreement, dated as of November 28, 2018, between
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 4, 2018).
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).
Second Amendment to Sand Supply Agreement, dated as of August 6, 2018, between Gulfport Energy Corporation and
Muskie Proppant 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 1, 2018).
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.
Amendment No. 2, dated as of July 10, 2018, between Stingray Pressure Pumping, LLC and Gulfport Energy
Corporation to that certain Amended & Restated Master Services Agreement for Pressure Pumping Services, effective
as of October 1, 2014, as amended effective January 1, 2016 (incorporated by reference to Exhibit 10.2 to the Quarterly
Report on Form 10-Q, File No. 000-19514, filed by the Company with the SEC on August 2, 2018).
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).
80
Table of Contents
Index to Financial Statements
10.30+
10.31+
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*
32.1**
32.2**
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.
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.
81
Table of Contents
Index to Financial Statements
ITEM 16.
FORM 10-K SUMMARY
None.
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
SIGNATURES
undersigned, thereunto duly authorized.
Date: February 28, 2019
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.
82
Table of Contents
Index to Financial Statements
Date:
February 28, 2019
Date:
February 28, 2019
Date:
February 28, 2019
Date:
February 28, 2019
Date:
February 28, 2019
Date:
February 28, 2019
Date:
February 28, 2019
Date:
February 28, 2019
Date:
February 28, 2019
/s/ DAVID M. WOOD
David M. Wood
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/ DEBORAH G. ADAMS
Deborah G. Adams
Director
/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:
By:
S-1
Table of Contents
Index to Financial Statements
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets, December 31, 2018 and December 31, 2017
Consolidated Statements of Operations, Years Ended December 31, 2018, 2017, and 2016
Consolidated Statements of Comprehensive Income (Loss), Years Ended December 31, 2018, 2017, and 2016
Consolidated Statements of Stockholders' Equity, Years Ended December 31, 2018, 2017, and 2016
Consolidated Statements of Cash Flows, Year Ended December 31, 2018, 2017, and 2016
Notes to Consolidated Financial Statements
F-1
Page
F-2
F-3
F-4
F-5
F-6
F-7
F-9
Table of Contents
Index to Financial Statements
Board of Directors and Stockholders
Gulfport Energy Corporation
Report of Independent Registered Public Accounting Firm
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, 2018 and 2017, 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, 2018, 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, 2018 and 2017, and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 2018, 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, 2018, 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 28, 2019 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 included 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 28, 2019
F-2
Table of Contents
Index to Financial Statements
GULFPORT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
Assets
Current assets:
Cash and cash equivalents
Accounts receivable—oil and natural gas sales
Accounts receivable—joint interest and other
Prepaid expenses and other current assets
Short-term derivative instruments
Total current assets
Property and equipment:
Oil and natural gas properties, full-cost accounting, $2,873,037 and $2,912,974
excluded from amortization in 2018 and 2017, 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
Deferred tax liability
Other non-current liabilities
Long-term debt, net of current maturities
Total liabilities
Commitments and contingencies (Notes 16 and 17)
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, 162,986,045 issued and
outstanding in 2018 and 183,105,910 in 2017
Paid-in capital
Accumulated other comprehensive loss
Accumulated deficit
Total stockholders’ equity
Total liabilities and stockholders’ equity
December 31, 2018
December 31, 2017
(In thousands, except share data)
$
52,297 $
210,200
22,497
10,607
21,352
316,953
99,557
146,773
35,440
4,912
78,847
365,529
10,026,836
92,667
(4,640,098)
5,479,405
9,169,156
86,754
(4,153,733)
5,102,177
236,121
—
—
4,754
13,803
254,678
6,051,036 $
518,380 $
—
20,401
651
539,432
13,992
79,952
3,127
—
2,086,765
2,723,268
302,112
8,685
1,208
8,227
19,814
340,046
5,807,752
553,609
120
32,534
622
586,885
2,989
74,980
—
2,963
2,038,321
2,706,138
—
—
1,630
4,227,532
(56,026)
(845,368)
3,327,768
6,051,036 $
1,831
4,416,250
(40,539)
(1,275,928)
3,101,614
5,807,752
$
$
$
See accompanying notes to consolidated financial statements.
F-3
Table of Contents
Index to Financial Statements
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Year Ended December 31,
2018
2017
2016
(In thousands, except share data)
Revenues:
Natural gas sales
Oil and condensate sales
Natural gas liquid sales
Net (loss) gain on natural gas, oil, and NGL derivatives
Costs and expenses:
Lease operating expenses
Production taxes
Midstream gathering and processing expenses
Depreciation, depletion and amortization
Impairment of oil and natural gas properties
General and administrative expenses
Accretion expense
Acquisition expense
INCOME (LOSS) FROM OPERATIONS
OTHER (INCOME) EXPENSE:
Interest expense
Interest income
Litigation settlement
Insurance proceeds
Loss on debt extinguishment
Gain on sale of equity method investments
(Income) loss from equity method investments, net
Other expense (income), net
INCOME (LOSS) BEFORE INCOME TAXES
INCOME TAX (BENEFIT) EXPENSE
NET INCOME (LOSS)
NET INCOME (LOSS) PER COMMON SHARE:
Basic
Diluted
Weighted average common shares outstanding—Basic
Weighted average common shares outstanding—Diluted
$
1,121,815 $
177,793
178,915
(123,479)
1,355,044
845,999 $
124,568
136,057
213,679
1,320,303
91,640
33,480
290,188
486,664
—
56,633
4,119
—
962,724
392,320
135,273
(314)
1,075
(231)
—
(124,768)
(49,904)
698
(38,171)
430,491
(69)
430,560 $
80,246
21,126
248,995
364,629
—
52,938
1,611
2,392
771,937
548,366
108,198
(1,009)
—
—
—
(12,523)
17,780
(1,041)
111,405
436,961
1,809
435,152 $
420,128
81,173
59,115
(174,506)
385,910
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
(3,391)
37,376
129
114,472
(982,622)
(2,913)
(979,709)
$
$
$
2.46 $
2.45 $
2.42 $
2.41 $
174,675,840
175,398,706
179,834,146
180,253,024
(7.97)
(7.97)
122,952,866
122,952,866
See accompanying notes to consolidated financial statements.
F-4
Table of Contents
Index to Financial Statements
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
Net income (loss)
Foreign currency translation adjustment (1)
Other comprehensive (loss) income
Comprehensive income (loss)
For the Year Ended December 31,
2018
2017
2016
(In thousands)
$
$
430,560 $
(15,487)
(15,487)
415,073 $
435,152 $
12,519
12,519
447,671 $
(979,709)
2,119
2,119
(977,590)
(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, 2018 and
December 31, 2017.
See accompanying notes to consolidated financial statements.
F-5
Table of Contents
Index to Financial Statements
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Common Stock
Shares
Amount
Paid-in
Capital
Accumulated
Other
Comprehensive
Loss
Accumulated
Deficit
Total
Stockholders’
Equity
(In thousands, except share data)
Balance at January 1, 2016 108,322,250 $
1,082 $ 2,824,303 $
Net Loss
Other Comprehensive Income
Stock-based Compensation
Issuance of Common Stock in public offerings,
net of related expenses
Issuance of Restricted Stock
50,255,000
252,566
Balance at December 31, 2016 158,829,816
—
—
—
Net Income
Other Comprehensive Income
Stock-based Compensation
Issuance of Common Stock for the Vitruvian
Acquisition, net of related expenses
Issuance of Restricted Stock
23,852,117
423,977
Balance at December 31, 2017 183,105,910
—
—
—
(20,746,536)
626,671
Net Income
Other Comprehensive Loss
Stock-based Compensation
Shares Repurchased
Issuance of Restricted Stock
—
—
—
—
—
—
—
—
12,251
503
3
1,588
—
—
—
239
4
1,831
—
—
—
(207)
6
1,109,891
(3)
3,946,442
—
—
10,615
459,197
(4)
4,416,250
—
—
11,332
(200,044)
(6)
Balance at December 31, 2018 162,986,045 $
1,630 $ 4,227,532 $
See accompanying notes to consolidated financial statements.
F-6
(55,177) $ (731,371) $ 2,038,837
(979,709)
(979,709)
2,119
—
12,251
—
—
2,119
—
—
—
(53,058)
—
12,519
—
—
—
(1,711,080)
435,152
—
—
1,110,394
—
2,183,892
435,152
12,519
10,615
—
—
459,436
—
3,101,614
430,560
(15,487)
11,332
(200,251)
—
(56,026) $ (845,368) $ 3,327,768
(1,275,928)
430,560
—
—
—
—
(40,539)
—
(15,487)
—
—
—
Table of Contents
Index to Financial Statements
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,
2018
2017
2016
(In thousands)
$
430,560 $
435,152 $
(979,709 )
4,119
486,664
—
6,799
(49,625 )
—
65,051
1,208
6,121
—
(124,768 )
3,206
(63,427 )
12,943
—
(5,695 )
4,066
(24,015 )
(719)
752,488
—
(7,870 )
—
(865,300 )
5,114
351
226,487
(2,319 )
446
(643,091 )
(220,575 )
265,000
—
—
—
(831)
(200,251 )
—
(156,657 )
(47,260 )
99,557
52,297 $
1,611
364,629
—
6,369
18,513
—
(188,802 )
1,690
5,011
—
(12,523 )
—
(35,879 )
(9,573 )
16
(1,777 )
(7,866 )
106,375
(3,057 )
679,889
8
(19,372 )
(1,348,657)
(1,064,678)
4,866
1,569
—
(55,280 )
7,376
(2,474,168)
(365,276 )
365,000
450,000
—
2,951
(14,350 )
—
(5,364 )
432,961
(1,361,318)
1,460,875
99,557 $
1,057
245,974
715,495
7,351
37,788
(1,108 )
323,303
18,188
3,660
(1,716 )
(3,391 )
—
(76,269 )
11,380
—
(3,734 )
—
43,763
(4,189 )
337,843
8
(33,152 )
—
(724,925 )
45,812
—
—
(26,472 )
18,147
(720,582 )
(87,685 )
86,000
1,250,000
(624,561 )
21,049
(24,718 )
—
1,110,555
1,730,640
1,347,901
112,974
1,460,875
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Accretion expense
Depletion, depreciation and amortization
Impairment of oil and gas properties
Stock-based compensation expense
(Income) loss from equity investments
Gain on debt extinguishment
Change in fair value of derivative instruments
Deferred income tax expense
Amortization of loan costs
Amortization of note discount and premium
Gain on sale of equity method investments
Distributions from equity method investments
Changes in operating assets and liabilities:
Increase in accounts receivable—oil and natural gas sales
Decrease (increase) in accounts receivable—joint interest and other
Decrease in accounts receivable—related parties
Increase in prepaid expenses and other current assets
Decrease (increase) in other assets
(Decrease) increase in accounts payable, 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
Proceeds from sale of equity method investments
Contributions to equity method investments
Distributions from equity method investments
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
Payments on repurchase of stock
Proceeds from issuance of common stock, net of offering costs and exercise of stock options
Net cash (used in) provided by financing activities
Net (decrease) increase in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
(Continued on next page)
$
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Index to Financial Statements
GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
Supplemental disclosure of cash flow information:
Interest payments
Income tax receipts
Supplemental disclosure of non-cash transactions:
Capitalized stock-based compensation
Asset retirement obligation capitalized
Interest capitalized
Foreign currency translation (loss) gain on equity method investments
$
$
$
$
$
$
126,342 $
— $
101,958 $
(1,105 ) $
68,966
(19,770 )
4,533 $
1,452 $
4,470 $
(15,487 ) $
4,246 $
42,270 $
9,470 $
12,519 $
4,900
10,971
9,148
3,468
See accompanying notes to consolidated financial statements.
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Index to Financial Statements
GULFPORT ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2018, 2017 AND 2016
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 sells oil and natural gas to various purchasers and participates in drilling, completion and operation of oil and natural gas
wells with joint interest owners on properties the Company operates. The related receivables are classified as accounts receivable—oil and
natural gas sales and accounts receivable—joint interest and other, respectively. 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, 2018 and December 31, 2017.
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 average of the first-day-of-the-month price for
2018, 2017 and 2016, 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
F-9
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Index to Financial Statements
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, 2018.
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 at both December 31, 2018 and December 31, 2017. 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 by recording 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.
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, 2015
December 31, 2016
December 31, 2017
December 31, 2018
Net Income per Common Share
(In thousands)
(55,175)
(51,709)
(39,190)
(54,677)
$
$
$
$
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 12.
Income Taxes
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Index to Financial Statements
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 2004 – 2017 U.S.
federal and 1998 - 2017 state income tax returns remain open to examination by tax authorities, due to net operating losses. As of
December 31, 2018, 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, 2018, the Company finalized the provisional accounting for the Tax Cuts and Jobs Act ("Tax Act"), which was
enacted in 2017. Further information on the tax impacts of the Tax Act is included in Note 11 of the Company's consolidated financial
statements.
Revenue Recognition
The Company’s revenues are primarily derived from the sale of natural gas, oil and condensate and NGLs. Sales of natural gas, oil and
condensate and NGLs are recognized in the period that the performance obligations are satisfied. The Company generally considers the
delivery of each unit (MMBtu or Bbl) to be separately identifiable and represents a distinct performance obligation that is satisfied at a
point-in-time once control of the product has been transferred to the customer. The Company considers a variety of facts and circumstances
in assessing the point of control transfer, including but not limited to (i) whether the purchaser can direct the use of the product, (ii) the
transfer of significant risks, (iii) the Company’s right to payment and (iv) transfer of legal title.
Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf
of third parties. These contracts typically include variable consideration that is based on pricing tied to market indices and volumes
delivered in the current month. As such, this market pricing may be constrained (i.e., not estimable) at the inception of the contract but will
be recognized based on the applicable market pricing, which will be known upon transfer of the goods to the customer. The payment date is
usually within 30 days of the end of the calendar month in which the commodity is delivered.
The recognition of gains or losses on derivative instruments is outside the scope of Accounting Standards Codification ("ASC") 606,
Revenue from Contracts with Customers ("ASC 606") and is not considered revenue from contracts with customers subject to ASC 606.
The Company may use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with
normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be
treated as normal sales.
The Company has elected to exclude from the measurement of the transaction price all taxes assessed by governmental authorities that
are both imposed on and concurrent with a specific revenue-producing transaction and collected by the Company from a customer, such as
sales tax, use tax, value-added tax and similar taxes.
See Note 10 for additional discussion of revenue from contracts with customers.
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 an impairment charge of $23.1 million
related to its investment in Grizzly Oil Sands ULC for the year ended December 31, 2016. There were no impairment charges recorded for
the years ended December 31, 2017 and December 31, 2018.
F-11
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Index to Financial Statements
Accounting for Stock-based Compensation
Share-based payments to employees, including grants of restricted stock, are 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. The Company does not recognize expense based on an estimate of forfeitures, but rather recognizes
the impact of forfeitures only as they occur.
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. All derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value.
The Company does not apply hedge accounting to derivative instruments. 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.
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 Financial Accounting Standards Board ("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 with Topic 606. 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 Company adopted ASC 606 as of January 1, 2018 using the modified retrospective transition method applied
to contracts that were not completed as of that date. Results for reporting periods beginning after January 1, 2018 are presented under the
new revenue standard. Under the modified retrospective method, the Company recognizes the cumulative effect of initially applying the
new revenue standard as an adjustment to the opening balance of retained earnings; however, no adjustment was required as a result of
adopting the new revenue standard. The comparative information has not been restated and continues to be reported under the historic
accounting standards in effect for those periods. The impact of the adoption of the new revenue standard is not expected to be material to
the Company’s net income on an ongoing basis. See Note 10 for further discussion of the revenue standard.
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). The standard supersedes the previous lease guidance by
requiring lessees to recognize a right-to-use asset and lease liability on the balance sheet for all leases with lease terms of greater than one
year while maintaining substantially similar classifications for financing and operating leases. The guidance is effective for periods after
December 15, 2018, and the Company will adopt beginning January 1, 2019 using the transition method permitted by ASU No. 2018-11,
Leases (Topic 842): Targeted Improvements, issued in August 2018, which permits an entity to recognize a cumulative-effect adjustment to
the opening balance of retained earnings in the period of adoption with no adjustment made to the comparative periods presented in the
consolidated financial statements. The Company
F-12
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Index to Financial Statements
will also utilize the practical expedient provided by ASU 2018-11 to not separate non-lease components from the associated lease
component and, instead, to account for those components as a single component if the non-lease components would be accounted for under
ASC 606 and other conditions are met.
The Company has identified its portfolio of leased assets under the new standard and has evaluated the impact of this guidance on its
consolidated financial statements and related disclosures. Offsetting right-of-use assets and corresponding lease liabilities recognized by
the Company on the adoption date totaled approximately $110 million, representing minimum payment obligations associated with
identified leases with contractual durations longer than one year. Adoption of the new standard will not result in a material impact to the
consolidated statement of operations. The Company has implemented processes and controls needed to comply with the requirements of
the new standard, which includes the implementation of a lease accounting software solution to support lease portfolio management and
accounting and disclosures.
Additionally, in January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for
Transition to Topic 842. The amendments in this update provide an optional expedient to not evaluate existing or expired land easements
that were not previously accounted for under current leases guidance in Topic 840. An entity that elects this practical expedient should
evaluate new or modified land easements beginning at the date of adoption. The Company does not currently account for any land
easements under Topic 840 and plans to utilize this practical expedient in conjunction with the adoption of ASU 2016-02.
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 guidance is effective for periods after December 15, 2019, with early
adoption permitted. 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 effect.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash
Payments. This ASU clarifies how certain cash receipts and cash payments should be classified and presented in the statement of cash
flows. The Company adopted this standard in the first quarter of 2018 and has made an accounting policy election to classify distributions
received from equity method investees using the nature of the distribution approach, which classifies distributions received from investees
as either cash inflows from operating activities or cash inflows from investing activities in the statement of cash flows based on the nature
of the activities of the investee that generated the distribution. The impact of adopting this ASU was not material to prior periods presented.
In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash. This ASU requires
that amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when
reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows and to provide a reconciliation of the
totals in the statement of cash flows to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and
restricted cash equivalents are presented in more than one line item on the balance sheet. The Company adopted this standard in the first
quarter of 2018 using the retrospective transition method. The adoption of this standard had no impact on the statement of cash flows for
the year ended December 31, 2018. As a result of the adoption, $185.0 million in restricted cash was removed from net cash used in
investing resulting in an increase to the ending cash balance for the year ended December 31, 2016. The adoption also resulted in an
addition of $185.0 million in restricted cash to the net cash used in investing activities for the year ended December 31, 2017. This addition
and the resulting decrease to ending cash was offset by the increase to beginning cash balance of $185.0 million due to the changes at
December 31, 2016. Therefore, there was no net impact on the statement of cash flows as of December 31, 2017.
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. The Company adopted this standard in the first quarter of 2018 with no significant effect on its financial statements or related
disclosures.
F-13
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Index to Financial Statements
In February 2018, the FASB issued ASU No. 2018-02, Income statement - Reporting Comprehensive Income (Topic 220) -
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated
other comprehensive income to retained earnings for standard tax effects resulting from the Tax Cuts and Jobs Act of 2017. The
amendment will be effective for reporting periods beginning after December 15, 2018, and early adoption is permitted. The Company
assessed the impact of the ASU on its consolidated financial statements and related disclosures, and determined there was no material
impact.
In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the
Disclosure Requirements for Fair Value Measurement, which removes, modifies, and adds certain disclosure requirements on fair value
measurements. The amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted.
The Company is currently assessing the impact of the ASU on its consolidated financial statements and related disclosures.
In August 2018, the FASB issued ASU No. 2018-15, Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40):
Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract, which aligns
the accounting for costs associated with implementing a cloud computing arrangement in a hosting arrangement that is a service contract
with the accounting for implementation costs incurred to develop or obtain internal-use software. The amendment will be effective for
reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is currently assessing the impact of
the ASU on its consolidated financial statements and related disclosures.
In August 2018, the Securities and Exchange Commission ("SEC") issued Final Rule Release No. 33-10532, Disclosure Update and
Simplification, which amends certain disclosure requirements that were redundant, duplicative, overlapping or superseded. Under these
amendments, the annual disclosure requirements on the analysis of stockholders' equity is extended to interim financial statements. The
Company will present an analysis of changes in stockholders' equity for the current and comparative year-to-date interim periods. The final
rule is effective November 5, 2018, and the Company will begin presenting this analysis beginning with the quarter ended March 31, 2019.
In November 2018, the FASB also issued ASU No. 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction
Between Topic 808 and Topic 606, which provides guidance on how to assess whether certain transactions between participants in a
collaborative arrangement should be accounted for within the ASU No. 2014-09 revenue recognition standard discussed above. The
amendment will be effective for reporting periods beginning after December 15, 2019, and early adoption is permitted. The Company is
currently assessing the impact of the ASU on its consolidated financial statements and related disclosures.
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. No acquisition costs were incurred during the year ended December 31, 2018.
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 14 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-14
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Index to Financial Statements
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-15
December 31,
2017
2016
(In thousands, except share data)
$
$
$
$
1,356,202 $
448,398 $
2.49 $
2.49 $
523,097
(1,190,481)
(8.11)
(8.11)
Table of Contents
Index to Financial Statements
3.
PROPERTY AND
EQUIPMENT
The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of
December 31, 2018 and 2017 are as follows:
Oil and natural gas properties
Office furniture and fixtures
Buildings
Land
Total property and equipment
Accumulated depletion, depreciation, amortization and impairment
Property and equipment, net
December 31,
2018
2017
(In thousands)
$
$
10,026,836 $
42,581
44,565
5,521
10,119,503
(4,640,098)
5,479,405 $
9,169,156
37,369
44,565
4,820
9,255,910
(4,153,733)
5,102,177
No impairment of oil and natural gas properties was required under the ceiling test for the years ended December 31, 2018 and 2017.
At December 31, 2016, 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 year ended December 31, 2016. 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 for the year ended December 31, 2016.
Included in oil and natural gas properties at December 31, 2018 and 2017 is the cumulative capitalization of $203.3 million and $165.6
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 $37.7 million, $35.7 million and $29.3 million for the years ended
December 31, 2018, 2017 and 2016, 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 $0.96, $0.90 and $0.92 per Mcfe for the years ended
December 31, 2018, 2017 and 2016, respectively.
The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, 2018:
Acquisition costs
Exploration costs
Development costs
Capitalized interest
Total oil and natural gas properties not
subject to amortization
$
$
Costs Incurred in
2018
2017
2016
Prior to 2016
Total
(In thousands)
128,415 $
9,027
548
2,120
1,469,820 $
122,399 $
1,128,975 $
—
869
2,915
—
4,536
(657)
—
5,789
(1,719)
2,849,609
9,027
11,742
2,659
140,110 $
1,473,604 $
126,278 $
1,133,045 $
2,873,037
F-16
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Index to Financial Statements
The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31,
2018:
Utica
MidContinent
Niobrara
Southern Louisiana
Bakken
December 31, 2018
(In thousands)
$
$
1,483,194
1,388,706
451
586
100
2,873,037
As of December 31, 2017, approximately $2.9 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, 2018 and 2017 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
F-17
December 31,
2018
2017
(In thousands)
75,100 $
1,827
(719)
4,119
(375)
79,952
—
79,952 $
34,276
16,300
(3,057)
1,611
25,970
75,100
120
74,980
$
$
Table of Contents
Index to Financial Statements
4.
EQUITY
INVESTMENTS
Investments accounted for by the equity method consist of the following as of December 31, 2018 and 2017:
Approximate
Ownership %
Carrying Value
December 31,
(Income) loss from equity method
investments
For the Year Ended December 31,
2018
2017
2018
2017
2016
(In thousands)
Investment in Tatex Thailand II, LLC
Investment in Tatex Thailand III, LLC
Investment in Grizzly Oil Sands ULC
Investment in Timber Wolf Terminals LLC(3)
Investment in Windsor Midstream LLC
Investment in Stingray Cementing LLC(1)
Investment in Blackhawk Midstream LLC(4)
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(2)
23.5% $
—%
24.9999%
—%
22.5%
—%
—%
—%
—%
21.9%
—%
(241) $
—
510
536
(9)
—
(38)
—
— $
—
44,259
—
39
—
—
—
—
191,823
—
(412)
—
25,150
8
(13,618)
263
—
1,044
993
24,037
(89)
$ 236,121 $ 302,112 $ (49,904) $ 17,780 $ 37,376
— $
—
57,641
983
30
—
—
—
—
165,715
77,743
(549) $
(183)
2,189
8
25,233
205
—
282
(71)
(11,288)
1,954
(49,969)
(693)
(1) On June 5, 2017, Mammoth Energy Services, Inc. ("Mammoth Energy") acquired Stingray Cementing LLC, Stingray
Energy Services LLC and Sturgeon Acquisitions LLC. See below under Mammoth Energy Partners LP/Mammoth Energy
Services, Inc. for information regarding these transactions.
(2) On May 1, 2018, the Company sold its 25% interest in Strike Force Midstream to EQT Midstream Partners, LP. See below
under under Strike Force Midstream LLC for information regarding this transaction.
(3) On June 5, 2018, the Company received its final distribution from Timber Wolf Terminals LLC ("Timber Wolf"). See below
under Timber Wolf Terminals LLC for information regarding this distribution.
(4) On December 31, 2018, the Company received its final distribution from Blackhawk Midstream LLC ("Blackhawk"). See
below under Blackhawk Midstream LLC for information regarding this distribution.
The tables below summarize financial information for the Company's equity investments, as of December 31, 2018 and 2017.
Summarized balance sheet information:
Current assets
Noncurrent assets
Current liabilities
Noncurrent liabilities
December 31,
2018
2017
(In thousands)
$
$
$
$
471,733 $
1,302,488 $
239,975 $
94,575 $
415,032
1,542,090
261,086
148,839
F-18
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Index to Financial Statements
Summarized results of operations:
Gross revenue
Net income (loss)
Tatex Thailand II, LLC
December 31,
2018
2017
2016
(In thousands)
$
$
1,729,778 $
253,451 $
755,374 $
(37,102) $
287,733
(65,070)
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 located in Southeast Asia through its ownership of
concessions covering approximately 108,000 acres which includes the Phu Horm Field. The Company received $0.2 million and $0.5
million in distributions from Tatex during the years ended December 31, 2018 and 2017, respectively.
Tatex Thailand III, LLC
The Company had 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, 2018, 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 December 31, 2016 for impairment 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, resulting in an aggregate impairment loss of $23.1 million for the year ended December 31, 2016, which is
included in (income) loss from equity method investments, net in the accompanying consolidated statements of operations. As of and
during the periods ended December 31, 2018 and 2017, commodity prices had increased as compared to 2016. The Company engaged an
independent third party to perform a sensitivity analysis based on updated pricing as of December 31, 2018, and concluded that 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. Gulfport paid $2.3 million in cash calls during each of the years ended
December 31, 2018 and December 31, 2017. Grizzly’s functional currency is the Canadian dollar. The Company's investment in Grizzly
was decreased by a $15.2 million foreign currency translation loss for the year ended December 31, 2018, and increased by a $12.3 million
and $4.2 million foreign currency translation gain for the years ended December 31, 2017 and 2016, 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, 2018 and 2017, the
F-19
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Index to Financial Statements
Company paid no cash calls to Timber Wolf. During the year ended December 31, 2018, Timber Wolf was dissolved and the Company
received a final distribution of $0.4 million.
Windsor Midstream LLC
At December 31, 2018, the Company held a 22.5% interest in Windsor Midstream LLC (“Midstream”), an entity controlled and
managed by an unrelated third party. The Company received no distributions from Midstream during the year ended December 31, 2018
and $0.5 million in distributions during the same period in 2017.
Stingray Cementing LLC
During 2012, the Company invested in Stingray Cementing LLC ("Stingray Cementing"). Stingray Cementing provides well
cementing services. The (income) loss 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, 2018, Blackhawk was dissolved and the Company received a final distribution of $0.04 million.
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 (income)
loss 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 in Sturgeon Acquisitions LLC ("Sturgeon") and received an ownership interest of 25% in
Sturgeon. Sturgeon owns and operates sand mines that produce hydraulic fracturing grade sand. 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 Mammoth. 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 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. Immediately following the IPO, 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 gain on sale of equity method investments 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 (the "June 2017 Transactions").
F-20
Table of Contents
Index to Financial Statements
Following the June 2017 transactions, 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. The Company valued the shares of Mammoth Energy common stock
it received in the June 2017 Transactions at $18.50 per share, which was the closing price of Mammoth Energy common stock on June 5,
2017. During the second quarter of 2017, the Company recognized a gain of $12.5 million from the June 2017 Transactions, which is
included in gain on sale of equity method investments in the accompanying consolidated statements of operations.
On June 29, 2018, the Company sold 1,235,600 shares of its Mammoth Energy common stock in an underwritten public offering for
net proceeds of approximately $47.0 million. In connection with the Company's public offering of a portion of its shares of Mammoth
Energy common stock, the Company granted the underwriters an option to purchase additional shares of its Mammoth Energy common
stock. On July 26, 2018, the underwriters exercised this option, in part, and on July 30, 2018, the Company sold an additional 118,974
shares for net proceeds of approximately $4.5 million. Following the sales of these shares, the Company owned 9,829,548 shares, or 21.9%
at December 31, 2018, of Mammoth Energy's outstanding common stock. As a result of the sales, the Company recorded a gain of $28.3
million, which is included in gain on sale of equity method investments in the accompanying consolidated statements of operations. The
approximate fair value of the Company's investment in Mammoth Energy's common stock at December 31, 2018 was $176.7 million based
on the quoted market price of Mammoth Energy's common stock.
The Company's investment in Mammoth Energy was decreased by a $0.4 million foreign currency loss and increased by a $0.2 million
foreign currency gain resulting from Mammoth Energy's foreign subsidiary for the years ended December 31, 2018 and 2017, respectively.
During the year ended December 31, 2018, Gulfport received distributions of $2.5 million from Mammoth Energy as a result of dividends
in August 2018 and November 2018. The (income) loss 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"). Prior to the sale of the Company's interest in Strike Force (discussed below), the
Company owned a 25% interest in Strike Force, and EQT acted as operator and owned the remaining 75% interest in Strike Force. Strike
Force's gathering assets provide gathering services for wells operated by Gulfport and other operators and connectivity of existing dry gas
gathering systems. Prior to the sale of its interest in Strike Force, the Company elected to report its proportionate share of Strike Force's
earnings on a one-quarter lag as permitted under ASC 323. The (income) loss from equity method investments presented in the table above
reflects any intercompany profit eliminations.
During the year ended December 31, 2018, Gulfport received distributions of $0.8 million from Strike Force. For the year ended
December 31, 2017, Gulfport paid $53.0 million in cash calls to Strike Force and received distributions of $6.9 million from Strike Force.
On May 1, 2018, the Company sold its 25% interest in Strike Force to EQT Midstream Partners, LP for proceeds of $175.0 million in
cash. As a result of the sale, the Company recognized a gain of $96.4 million net of transaction fees, which is included in gain on sale of
equity method investments in the accompanying consolidated statement of operations.
5.
VARIABLE INTEREST
ENTITIES
As of December 31, 2018, the Company held a variable interest in Midstream, a variable interest entity ("VIE"), but was not the
primary beneficiary. This entity has governing provisions that are the functional equivalent of a limited partnership and is considered a VIE
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 this VIE 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 VIE's economic performance. The Company held a variable interest in Timber Wolf before
the entity was dissolved. The Company was a limited partner or non-managing member in Timber Wolf and was not the primary
beneficiary because it did not have a controlling financial interest. The Company also held a variable interest in Strike Force prior to the
sale of that interest due to the fact that it does not have sufficient equity capital at risk. The Company was 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
F-21
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Index to Financial Statements
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 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 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)
6.625% senior unsecured notes due 2023 (2)
6.000% senior unsecured notes due 2024 (3)
6.375% senior unsecured notes due 2025 (4)
6.375% senior unsecured notes due 2026 (5)
Net unamortized debt issuance costs (6)
Construction loan (7)
Less: current maturities of long term debt
Debt reflected as long term
2018
2017
$
(In thousands)
45,000 $
350,000
650,000
600,000
450,000
(30,733)
23,149
(651)
$
2,086,765 $
—
350,000
650,000
600,000
450,000
(34,781)
23,724
(622)
2,038,321
Maturities of long-term debt (excluding unamortized debt issuance costs) as of December 31, 2018 are as follows:
2019
2020
2021
2022
2023
Thereafter
Total
(In thousands)
651
629
45,661
692
350,724
1,719,792
2,118,149
$
$
(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 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
F-22
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Index to Financial Statements
borrowing base was set at $1.2 billion, with an elected commitment of $1.0 billion. On May 21, 2018, the Company further amended its
revolving credit facility to, among other things, (a) decrease the applicable rate for all loans by 0.25%, (b) permit Gulfport and each of its
subsidiaries to use the proceeds from dispositions of certain investments to acquire the common stock or other equity interests of Gulfport,
subject to certain limitations and (c) increase the borrowing base to $1.4 billion, with an elected commitment of $1.0 billion. On November
28, 2018, the Company further amended its revolving credit facility to, amount other things, (a) permit Gulfport and each of its subsidiaries
to directly or indirectly purchase, redeem or otherwise acquire equity interests of Gulfport, subject to certain limitations and (b) reaffirm the
borrowing base of $1.4 billion, with an elected commitment of $1.0 billion.
As of December 31, 2018, $45.0 million was outstanding under the revolving credit facility and the total availability for future
borrowings under this facility, after giving effect to an aggregate of $316.6 million of letters of credit, was $638.4 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 0.25% to 1.25%, 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 1.25% to 2.25%, 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. At
December 31, 2018, amounts borrowed under the credit facility bore interest at a weighted average rate of 4.23%.
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 non-cash 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
F-23
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Index to Financial Statements
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, 2018.
(2) 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.
(3) On October 14, 2016, the Company issued $650.0 million in aggregate principal amount of 6.000% Senior Notes due 2024 (the
"2024 Notes"). 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.
(4) 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 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.
(5) 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
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Index to Financial Statements
approximately $444.1 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 exchange offer relating to the 2026 Notes
closed on March 22, 2018.
(6) 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, 2018, total unamortized debt issuance costs were $4.4 million for the 2023
Notes, $8.7 million for the 2024 Notes, $12.5 million for the 2025 Notes and $5.0 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, 2018.
(7) 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, 2018, the total borrowings
under the Construction loan were approximately $23.1 million.
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
2018
2017
2016
$
(In thousands)
126,342 $
7,280
(4,470)
6,121
—
101,958 $
10,699
(9,470)
5,011
—
$
135,273 $
108,198 $
68,966
1,768
(9,148)
3,660
(1,716)
63,530
The Company capitalized approximately $4.5 million and $9.5 million in interest expense to undeveloped oil and natural gas properties
during the years ended December 31, 2018 and 2017, respectively.
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
F-25
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Index to Financial Statements
under the Plan prior to adoption of the 2005 Plan. As of December 31, 2018, 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, 2018, the Company had granted 3,518,964 shares of restricted stock under the
2013 Plan.
Issuance of Common Stock
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.
Stock Repurchases
In January 2018, the board of directors of the Company approved a stock repurchase program to acquire up to $100 million of the
Company's outstanding stock during 2018. In May 2018, the Company's board of directors authorized the expansion of its stock repurchase
program, authorizing the Company to acquire up to an additional $100 million of its outstanding common stock during 2018 for a total of
up to $200 million. The repurchase program does not require the Company to acquire any specific number of shares. This repurchase
program was authorized to extend through December 31, 2018 and was fully executed. For the year ended December 31, 2018, the
Company repurchased 20.7 million shares for a cost of approximately $200.0 million under this repurchase program. Additionally, for the
year ended December 31, 2018, the Company repurchased approximately 29,000 shares for a cost of approximately $0.3 million to satisfy
tax withholding requirements incurred upon the vesting of restricted stock. All repurchased shares have been canceled.
8.
STOCK-BASED
COMPENSATION
During the years ended December 31, 2018, 2017 and 2016 the Company’s stock-based compensation cost was $11.3 million, $10.6
million and $12.3 million, respectively, of which the Company capitalized $4.5 million, $4.2 million and $4.9 million, respectively,
relating to its exploration and development efforts.
The following table summarizes restricted stock activity for the twelve months ended December 31, 2018, 2017 and 2016:
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Index to Financial Statements
Unvested shares as of January 1, 2016
Granted
Vested
Forfeited
Granted
Vested
Forfeited
Granted
Vested
Forfeited
Number of
Unvested
Restricted Shares
Weighted
Average
Grant Date
Fair Value
484,239 $
451,241
(252,566)
(69,858)
613,056 $
876,846 $
(423,977)
(89,898)
976,027 $
1,579,911
(626,671)
(393,456)
1,535,811 $
43.51
27.78
43.94
33.43
32.90
15.14
29.90
27.91
18.71
9.90
18.05
12.23
11.57
Unvested shares as of December 31, 2016
Unvested shares as of December 31, 2017
Unvested shares as of December 31, 2018
Unrecognized compensation expense as of December 31, 2018 related to outstanding stock options and restricted shares was $13.9
million. The expense is expected to be recognized over a weighted average period of 1.60 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 Construction 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, 2018, the carrying value of the outstanding debt represented by the Notes was $ 2.0 billion including the unamortized
debt issuance cost of approximately $4.4 million related to the 2023 Notes, approximately $8.7 million related to the 2024 Notes,
approximately $12.5 million related to the 2025 Notes, and approximately $5.0 million related to the 2026 Notes. Based on the quoted
market price, the fair value of the Notes was determined to be approximately $1.8 billion at December 31, 2018.
10. REVENUE FROM CONTRACTS WITH
CUSTOMERS
On January 1, 2018, the Company adopted ASC 606 using the modified retrospective transition applied to contracts that were not
completed as of that date. The adoption did not result in a material change in the Company’s accounting or have a material effect on the
Company’s financial position, including measurement of revenue, the timing of revenue recognition and the recognition of contract assets,
liabilities and related costs. For periods through December 31, 2017, the Company accounted for its revenue using ASC 605, Revenue
Recognition.
Transaction Price Allocated to Remaining Performance Obligations
A significant number of the Company's product sales are short-term in nature generally through evergreen contracts with contract
terms of one year or less. These contracts typically automatically renew under the same provisions. For those contracts, the Company has
utilized the practical expedient allowed in the new revenue accounting standard that exempts the Company from disclosure of the
transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original
expected duration of one year or less.
For product sales that have a contract term greater than one year, the Company has utilized the practical expedient that exempts the
Company from disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is allocated
entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate
performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining
performance obligations is not required. Currently, the Company's product sales
F-27
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Index to Financial Statements
that have a contractual term greater than one year have no long-term fixed consideration.
Contract Balances
Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when
control of the product has been transferred to the customer. Receivables from contracts with customers were $210.2 million and $146.8
million as of December 31, 2018 and December 31, 2017, respectively, and are reported in accounts receivable - oil and natural gas sales on
the consolidated balance sheet. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or
rights to deficiency payments.
Contract Modifications
For contracts modified prior to the beginning of the earliest reporting period presented under ASC 606, the Company has elected to
reflect the aggregate of the effect of all modifications that occurred before the beginning of the earliest period presented under the new
standard when identifying the satisfied and unsatisfied performance obligations, determining the transaction price and allocating the
transaction price to the satisfied and unsatisfied performance obligations for the modified contracts at transition.
Prior-Period Performance Obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain gas
and NGLs sales may be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to
estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The
differences between the estimates and the actual amounts for product sales is recorded in the month that payment is received from the
purchaser. The Company has internal controls in place for the estimation process and any identified differences between revenue estimates
and actual revenue received historically have not been significant. For the year ended December 31, 2018, revenue recognized in the
reporting period related to performance obligations satisfied in prior reporting periods was not material.
11.
INCOME
TAXES
The income tax provision consists of the following:
Current:
State
Federal
Deferred:
State
Federal
Total income tax (benefit) expense provision
2018
2017
(In thousands)
2016
$
$
(1,530) $
253
2,167 $
3,362
(1,330)
(19,771)
1,530
(322)
(69) $
(118)
(3,602)
1,809 $
(386)
18,574
(2,913)
A reconciliation of the statutory federal income tax amount to the recorded expense follows:
F-28
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Index to Financial Statements
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
Income tax (benefit) expense recorded
2018
2017
(In thousands)
430,491 $
90,403
(511)
1,078
—
—
(91,039)
—
(69) $
436,961 $
152,936
2,299
5,731
—
190,034
(158,704)
(190,487)
1,809 $
2016
(982,622)
(343,918)
(5,883)
4,293
(1,349)
—
343,944
—
(2,913)
$
$
The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at
December 31, 2018, 2017 and 2016 are estimated as follows:
Deferred tax assets:
Net operating loss carryforward
Oil and gas property basis difference
Investment in pass through entities
Stock-based compensation expense
Business energy investment tax credit
AMT credit
Charitable contributions carryover
Change in fair value of derivative instruments
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
Change in fair value of derivative instruments
Total deferred tax liabilities
Net deferred tax asset
2018
2017
2016
(In thousands)
164,363 $
3,595
8,620
616
369
—
269
2,761
2,009
834
16,923
104
11,526
211,989
(211,987)
120,626 $
151,260
12,343
813
369
—
255
—
2,074
285
15,897
171
6,954
311,047
(298,830)
2
12,217
—
2
2
— $
—
11,009
11,009
1,208 $
162,073
386,302
27,469
2,084
369
3,842
303
48,317
2,074
397
12,107
—
5,351
650,688
(645,841)
4,847
155
—
155
4,692
$
$
There was a decrease to the valuation allowance of $86.8 million and $347.0 million during 2018 and 2017, respectively, and an
increase to the valuation allowance of $342.6 million during 2016. The decrease in the valuation allowance in 2018 was primarily due to
decreases in net deferred tax assets due to pretax income. The decrease in the valuation allowance in 2017 was primarily due to decreases in
net deferred tax assets due to pretax income and remeasurement of deferred tax assets due to the Tax Cuts and Jobs Act. The increase in the
valuation allowance in 2016 was primarily due to increases in deferred tax assets from pre-tax losses resulting from impairments to the full
cost pool.,
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Index to Financial Statements
As December 31, 2018, the Company maintains full valuation allowances related to the total net deferred tax assets, as they cannot
objectively assert that these deferred tax assets are more likely than not to be realized. It is reasonably possible that a portion of this
valuation allowance could be reversed within the next year due to increased book profitability levels. Future provisions for income taxes
will include no tax benefits with respect to losses incurred and tax expense only to the extent of current taxes payable until the valuation
allowances are eliminated.
All available positive and negative evidence is weighed to determine whether a valuation allowance should be recorded. The more
significant evidential matter relates to the Company’s recent cumulative losses resulting from impairments to the full cost pool in 2016.
Management currently estimates that pretax income in 2019 will result in the Company emerging from a cumulative loss position in the
first quarter of 2019, at which point there may no longer be any significant negative evidence regarding the realizability of deferred tax
assets and the determination around the need for a valuation allowance will primarily depend on management’s ability to objectively
project sufficient future taxable income exclusive of reversing temporary differences to ensure realization of deferred tax assets. As such, it
is reasonably possible that a material change in valuation allowance may be recorded during an interim period for the year ending
December 31, 2019.
The Company has an available federal tax net operating loss carryforward estimated at approximately $782.7 million as of
December 31, 2018. This carryforward will begin to expire in the year 2023. Based upon the December 31, 2018 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 $205.7 million that began to expire in 2017 and federal foreign tax credit carryovers of $1.8 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 $212.0 million related to the remaining net deferred tax asset.
The Company’s ability to utilize NOL carryforwards and other tax attributes to reduce future federal taxable income is subject to
potential limitations under Internal Revenue Code Section 382 (“Section 382”) and its related tax regulations. The utilization of these
attributes may be limited if certain ownership changes by 5% stockholders (as defined in Treasury regulations pursuant to Section 382) and
the effects of stock issuances by the Company during any three-year period result in a cumulative change or more than 50% in the
beneficial ownership of Gulfport. The Company is currently conducting Section 382 analysis to determine if an ownership change has
occurred. If it is determined that an ownership change has occurred under these rules, the Company would generally be subject to an annual
limitation on the use of pre-ownership change NOL carryforwards and certain other losses and/or credits. In addition, certain future
transactions regarding the Company's equity, including the cumulative effects of small transactions as well as transactions beyond the
Company’s control, could cause an ownership change and therefore a potential limitation on the annual utilization of their deferred tax
assets.
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 finalized its accounting for the impact of the Tax Act within its December 31, 2018
financial statements. The net impact of the finalization was immaterial.
The Company's income tax benefit in 2016 was primarily attributable to the Company recording a full cost ceiling impairment of
$715.5 million 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, 2018, the amount of unrecognized tax benefits related to federal and state tax liabilities associated with uncertain
tax positions was immaterial.
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Index to Financial Statements
12.
EARNINGS PER
SHARE
Reconciliations of the components of basic and diluted net income per common share are presented in the tables below:
For the Year Ended December 31,
2018
2017
2016
Income
Shares
Per
Share
Loss
Shares
Per
Share
(In thousands, except share data)
Loss
Shares
Per
Share
Basic:
Net income (loss)
$430,560 174,675,840 $ 2.46 $435,152 179,834,146 $ 2.42 $(979,709) 122,952,866 $ (7.97)
Effect of dilutive securities:
Stock options and awards
Diluted:
—
722,866
—
418,878
—
—
Net income (loss)
$430,560 175,398,706 $ 2.45 $435,152 180,253,024 $ 2.41 $(979,709) 122,952,866 $ (7.97)
There were no potential shares of common stock that were considered anti-dilutive for the years ended December 31, 2018 and 2017.
There were 539,988 shares of common stock that were considered anti-dilutive for the year ended 2016.
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Index to Financial Statements
13. 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 NGLs 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 NGLs 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.
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 and Mont Belvieu for propane, pentane
and ethane. Below is a summary of the Company's open fixed price swap positions as of December 31, 2018.
2019
2020
2019
2019
2019
Location
Daily Volume
(MMBtu/day)
Weighted
Average Price
NYMEX Henry Hub
NYMEX Henry Hub
1,254,000 $
204,000 $
2.83
2.77
Location
Mont Belvieu C2
Mont Belvieu C3
Mont Belvieu C5
Daily Volume
(Bbls/day)
1,000 $
4,000 $
500 $
Weighted
Average Price
18.48
28.87
54.08
During the fourth quarter of 2018, the Company early terminated all of its fixed price swaps for oil based on both Argus Louisiana
Light Sweet Crude and NYMEX West Texas Intermediate scheduled to settle during 2019 covering 5,000 Bbls/day. These early
terminations resulted in approximately $0.4 million of settlement losses which are included in net (loss) gain on natural gas, oil, and NGL
derivatives in the accompanying consolidated statement of operations.
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 2019 - March 2019
April 2019 - December 2019
Location
NYMEX Henry Hub
NYMEX Henry Hub
Daily Volume
(MMBtu/day)
50,000 $
30,000 $
Weighted
Average Price
3.13
3.10
For a portion of the natural gas fixed price swaps listed above, the counterparties had the option to extend the original terms an
additional twelve months for the period January 2019 through December 2019. In December 2018, the counterparties chose to exercise all
natural gas fixed price swaps, resulting in an additional 100,000 MMBtu per day at a weighted average price of $3.05 per MMBtu, which is
included in the natural gas fixed price swaps listed above.
In addition, the Company has entered into natural gas basis swap positions, which settle on the pricing index to basis differential of
Transco Zone 4 to NYMEX Henry Hub. As of December 31, 2018, the Company had the following natural gas basis swap positions for
Transco Zone 4.
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Index to Financial Statements
2019
2020
Balance sheet presentation
Location
Transco Zone 4
Transco Zone 4
Daily Volume
(MMBtu/day)
Hedged
Differential
60,000 $
60,000 $
(0.05)
(0.05)
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 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, 2018 and 2017:
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,
2018
2017
(In thousands)
$
$
$
$
21,352 $
— $
20,401 $
13,992 $
78,847
8,685
32,534
2,989
The following table presents the gain and loss recognized in net (loss) gain on natural gas, oil and NGL derivatives in the
accompanying consolidated statements of operations for the years ended December 31, 2018, 2017, and 2016.
Natural gas derivatives
Oil derivatives
Natural gas liquids derivatives
Total
Net (loss) gain on derivative instruments
For the Year Ended December 31,
2018
2017
2016
(In thousands)
$
$
(116,130) $
(13,084)
5,735
(123,479) $
232,143 $
(3,350)
(15,114)
213,679 $
(165,933)
(5,387)
(3,186)
(174,506)
The Company delivered approximately 78% of its 2018 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 assets
Derivative liabilities
$
$
Derivative instruments, gross
Netting adjustments
Derivative instruments, net
As of December 31, 2018
(In thousands)
(19,289 ) $
19,289 $
2,063
(15,104 )
21,352 $
(34,393 ) $
F-33
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Index to Financial Statements
Derivative assets
Derivative liabilities
$
$
Concentration of Credit Risk
Derivative instruments, gross
Netting adjustments
Derivative instruments, net
As of December 31, 2017
(In thousands)
87,532 $
(35,523 ) $
(22,199 ) $
22,199 $
65,333
(13,324 )
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 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.
14.
FAIR VALUE
MEASUREMENTS
The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value. Fair value is 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. Market or observable inputs are the preferred sources of values, followed by assumptions based on hypothetical
transactions in the absence of market inputs. Fair value measurements are 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 valuation level as of December 31, 2018 and
2017:
Assets:
Derivative Instruments
Liabilities:
Derivative Instruments
December 31, 2018
Level 1
Level 2
Level 3
(In thousands)
$
$
— $
21,352 $
— $
34,393 $
—
—
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Index to Financial Statements
Assets:
Derivative Instruments
Liabilities:
Derivative Instruments
December 31, 2017
Level 1
Level 2
Level 3
(In thousands)
$
$
— $
87,532 $
— $
35,523 $
—
—
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 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 and downward revisions
recognized during the year ended December 31, 2018 were approximately $1.8 million and $0.4 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.
15. 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.
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 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, 2018, the Company held approximately 21.9% of Mammoth Energy's outstanding common stock as discussed
above in Note 4. Approximately $2.0 million and $2.1 million of services provided by Mammoth Energy are included in lease operating
expenses in the consolidated statements of operations for the years ended December 31, 2018 and 2017, respectively. Approximately
$139.7 million and $196.5 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
F-35
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Index to Financial Statements
December 31, 2018 and 2017, respectively. At December 31, 2018 and 2017, the Company owed Mammoth Energy approximately $10.9
million and $32.0 million, respectively, related to these services.
The Company previously held a 25% interest in Strike Force, who develops natural gas gathering assets in dedicated areas. In May
2018, the Company sold its interest in Strike Force as discussed above in Note 4. At December 31, 2017, the Company owed approximately
$8.4 million to Strike Force for these related services. Approximately $18.5 million and $23.1 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, 2018 and 2017, respectively.
16. 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. 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, 2018, the plugging and abandonment trust totaled approximately $3.1 million. At December 31, 2018, the Company had
plugged 555 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, 2018, 2017 and 2016, Gulfport
incurred $2.6 million, $3.0 million, and $1.7 million, respectively, in contributions expense related to this plan.
Employment and Separation Agreements
The Company was party to an employment agreement with Michael G. Moore, its former Chief Executive Officer and President,
which provided for a minimum salary level, subject to review and potential increases by the Compensation Committee and/or the Board of
Directors, as well as participation in the Company's incentive plans and other employee benefits. Effective October 29, 2018, Mr. Moore
stepped down from his position as the Chief Executive Officer and President of the Company and as a member of its board of directors. In
connection with Mr. Moore's departure, the Company entered into a separation and release agreement with Mr. Moore, effective as that
date. Under the terms of his separation agreement the Company paid Mr. Moore separation payments in the aggregate amount of $400,000
in December 2018. Also, the Company agreed to reimburse Mr. Moore's portion of COBRA premiums for a maximum of six months,
which reimbursement will cease at any time he becomes eligible for group medical coverage from another employer. The separation
agreement also includes a release of claims by Mr. Moore against the Company, its directors, stockholders, employees, agents, attorneys,
consultants and affiliates.
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.
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Index to Financial Statements
Firm Transportation and Sales Commitments
The Company had approximately 2,300,000 MMBtu per day of firm sales contracted with third parties. The table below presents
these commitments at December 31, 2018 as follows:
2019
2020
2021
2022
2023
Thereafter
Total
(MMBtu per day)
663,000
526,000
372,000
272,000
255,000
212,000
2,300,000
The Company also had approximately $3.5 billion of firm transportation contracted with third parties. The table below presents these
commitments at December 31, 2018 as follows:
2019
2020
2021
2022
2023
Thereafter
Total
Operating Leases
(In thousands)
251,644
247,581
246,620
246,620
244,352
2,267,501
3,504,318
$
$
The Company leases office facilities under non-cancellable operating leases exceeding one year. Future minimum lease commitments
under these leases at December 31, 2018 are as follows:
2019
2020
2021
Total
(In thousands)
144
90
37
271
$
$
Presented below is rent expense for the years ended December 31, 2018, 2017 and 2016, respectively.
Rent expense
Other Commitments
For the years ended December 31,
2018
2017
2016
$
196
(In thousands)
$
343
$
840
Effective October 1, 2014, the Company entered into a Sand Supply Agreement with Muskie Proppant LLC (“Muskie”), a subsidiary
of Mammoth Energy. Effective August 3, 2018, the Company extended the agreement through December 31, 2021.
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Index to Financial Statements
Pursuant to this agreement, as amended, the Company has agreed to purchase annual and monthly amounts of proppant sand subject to
exceptions specified in the agreement at agreed pricing 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 $2.2 million related to non-utilization fees
during the year ended December 31, 2018. The Company did not incur any non-utilization fees during the year ended 2017.
Effective October 1, 2014, the Company entered into an Amended and Restated Master Services Agreement for pressure pumping
services with Stingray Pressure Pumping LLC (“Stingray Pressure”), a subsidiary of Mammoth Energy. Pursuant to this agreement, as
amended effective July 1, 2018, 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. The Company has the right to suspend services of one crew and only one crew at any point in time without payment,
fee or other obligation associated with the suspended crew, given appropriate notification of suspension. See Note 15 for further discussion
of amounts paid by the Company to Mammoth Energy.
As of December 31, 2018, the Company has drilling rig contracts with various terms extending to February 2021 to ensure rig
availability in its key operating areas. A portion of these future costs will be borne by other interest owners.
Future minimum commitments under these agreements at December 31, 2018 are as follows:
2019
2020
2021
Total
17. CONTINGENCIES
(In thousands)
89,022
67,203
48,744
204,969
$
$
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 15 th 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
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Index to Financial Statements
Cameron Parish suit and the Vermilion Parish suit. Shortly after the Complaints were filed, certain defendants removed the cases to the
United States District Court for the Western District of Louisiana. In both cases, the plaintiffs filed motions to remand the lawsuits to state
court, which were ultimately granted by the district courts. However, on May 23, 2018, a group of defendants again removed the Cameron
Parish and Vermilion Parish lawsuits to federal court. In response, the plaintiffs again filed motions to remand the cases to state court. The
removing defendants have opposed plaintiffs’ motions to remand. On January 16, 2019, the federal district court held a hearing on plaintiffs
motion to remand. The court took the matter under advisement and has not yet issued a ruling. Further action in the cases will be stayed
until the courts rule on the motions to remand. Also, shortly after the May 23, 2018 removal, the removing defendants filed motions with
the United States Judicial Panel on Multidistrict Litigation (the “MDL Panel”) requesting that the Cameron Parish and Vermilion Parish
lawsuits be consolidated with 40 similar lawsuits so that pre-trial proceedings in the cases could be coordinated. The MDL Panel denied the
motion to consolidate the lawsuits. Due to the procedural posture of the lawsuits, the cases are still in their early stages and the parties have
conducted very little discovery. As a result, the Company has not had the opportunity to evaluate the applicability of the allegations made
in plaintiffs' complaints to the Company's operations and management cannot determine the amount of loss, if any, that may result.
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. While the outcome of the pending litigation, disputes or claims cannot be predicted with certainty, in
the opinion of the Company's management, none of these matters, 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, 2018 and 2016 the Company was reimbursed $0.2 million and $5.7 million, respectively, net of
related legal fees by its insurance provider, which is included in insurance proceeds in the accompanying consolidated statements of
operations. There were no insurance proceeds received in the year ended December 31, 2017.
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, 2018, Gulfport held cash in excess of insured limits in these banks totaling $50.3 million.
During the year ended December 31, 2018, two customers accounted for approximately 17% and 10% of the Company's total sales.
During the year ended December 31, 2017, one customer accounted for approximately 40% of the Company's total sales. During the year
ended December 31, 2016, three customers accounted for approximately 59%, 12% and 10% of the Company's total sales. The Company
does not believe that the loss of any of these customers would have a material adverse effect on its oil, natural gas and NGL sales as
alternative customers are readily available.
18. CONDENSED CONSOLIDATING FINANCIAL
INFORMATION
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 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.
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Index to Financial Statements
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.
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 exchange offer relating to the 2026 notes
closed on March 22, 2018.
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 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.
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Index to Financial Statements
CONDENSED CONSOLIDATING BALANCE SHEETS
(Amounts in thousands)
Parent
Guarantors
December 31, 2018
Non-Guarantor
Eliminations
Consolidated
Current assets:
Assets
Cash and cash equivalents
$
Accounts receivable - oil and natural gas sales
Accounts receivable - joint interest and other
Accounts receivable - intercompany
Prepaid expenses and other current assets
Short-term derivative instruments
Total current assets
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
$
$
Inventories
Other assets
Total other assets
Total assets
Liabilities and stockholders' equity
Current liabilities:
Accounts payable and accrued liabilities
Accounts payable - intercompany
Short-term derivative instruments
Current maturities of long-term debt
Total current liabilities
Long-term derivative instruments
Asset retirement obligation - long-term
Deferred tax liability
Long-term debt, net of current maturities
Total liabilities
Stockholders' equity:
Common stock
Paid-in capital
Accumulated other comprehensive loss
(Accumulated deficit) retained earnings
Total stockholders' equity
Total liabilities and stockholders' equity
$
26,711 $
64,125
6,285
319,464
2,174
—
418,759
2,983,015
751
(39)
2,983,727
—
1,134
1,178
2,312
3,404,798 $
99,273 $
670,708
—
—
769,981
—
13,093
—
—
783,074
1 $
—
—
—
—
—
1
—
—
—
—
— $
—
—
(991,097 )
—
—
(991,097 )
(729)
—
—
(729)
44,259
—
—
44,259
44,260 $
(2,665,126)
—
1
(2,665,125)
(3,656,951) $
— $
130
—
—
130
—
—
—
—
130
— $
(991,097 )
—
—
(991,097 )
—
—
—
—
(991,097 )
—
1,915,598
—
706,126
2,621,724
3,404,798 $
—
261,626
(53,783 )
(163,713 )
44,130
44,260 $
—
(2,177,224)
53,783
(542,413 )
(2,665,854)
(3,656,951) $
52,297
210,200
22,497
—
10,607
21,352
316,953
10,026,836
92,667
(4,640,098)
5,479,405
236,121
4,754
13,803
254,678
6,051,036
518,380
—
20,401
651
539,432
13,992
79,952
3,127
2,086,765
2,723,268
1,630
4,227,532
(56,026 )
(845,368 )
3,327,768
6,051,036
25,585 $
146,075
16,212
671,633
8,433
21,352
889,290
7,044,550
91,916
(4,640,059)
2,496,407
2,856,988
3,620
12,624
2,873,232
6,258,929 $
419,107 $
320,259
20,401
651
760,418
13,992
66,859
3,127
2,086,765
2,931,161
1,630
4,227,532
(56,026 )
(845,368 )
3,327,768
6,258,929 $
F-41
Table of Contents
Index to Financial Statements
CONDENSED CONSOLIDATING BALANCE SHEETS
(Amounts in thousands)
Parent
Guarantors
December 31, 2017
Non-Guarantor
Eliminations
Consolidated
Current assets
Assets
Cash and cash equivalents
$
Accounts receivable - oil and natural gas
Accounts receivable - joint interest and other
Accounts receivable - intercompany
Prepaid expenses and other current assets
Short-term derivative instruments
Total current assets
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
Other non-current liabilities
Long-term debt, net of current maturities
Total liabilities
Stockholders' equity:
Common stock
Paid-in capital
Accumulated other comprehensive loss
(Accumulated deficit) retained earnings
Total stockholders' equity
Total liabilities and stockholders' equity
$
67,908 $
112,686
15,435
554,439
4,719
78,847
834,034
6,562,147
86,711
(4,153,696)
2,495,162
2,361,575
8,685
1,208
5,816
12,483
2,389,767
5,718,963 $
416,249 $
63,373
120
32,534
622
512,898
2,989
63,141
—
2,038,321
2,617,349
31,649 $
34,087
20,005
63,374
193
—
149,308
2,607,738
43
(37)
2,607,744
77,744
—
—
2,411
7,331
87,486
2,844,538 $
137,361 $
554,313
—
—
—
691,674
—
11,839
2,963
—
706,476
— $
—
—
—
—
—
—
—
—
—
—
— $
—
—
(617,813 )
—
—
(617,813 )
(729)
—
—
(729)
57,641
—
—
—
—
57,641
57,641 $
(2,194,848)
—
—
—
—
(2,194,848)
(2,813,390) $
99,557
146,773
35,440
—
4,912
78,847
365,529
9,169,156
86,754
(4,153,733)
5,102,177
302,112
8,685
1,208
8,227
19,814
340,046
5,807,752
— $
127
—
—
—
127
—
—
—
—
127
(1) $
553,609
(617,813 )
—
—
—
(617,814 )
—
—
—
—
(617,814 )
—
120
32,534
622
586,885
2,989
74,980
2,963
2,038,321
2,706,138
1,831
4,416,250
(40,539 )
(1,275,928)
3,101,614
5,718,963 $
—
1,915,598
—
222,464
2,138,062
2,844,538 $
—
259,307
(38,593 )
(163,200 )
57,514
57,641 $
—
(2,174,905)
38,593
(59,264 )
(2,195,576)
(2,813,390) $
1,831
4,416,250
(40,539 )
(1,275,928)
3,101,614
5,807,752
F-42
Table of Contents
Index to Financial Statements
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)
Parent
Guarantors
Eliminations
Consolidated
Year Ended December 31, 2018
Non-Guarantor
Total revenues
$
839,241 $
515,803 $
— $
— $
1,355,044
Costs and expenses:
Lease operating expenses
Production taxes
Midstream gathering and processing expenses
Depreciation, depletion and amortization
General and administrative expenses
Accretion expense
66,947
17,140
199,607
486,661
59,303
3,228
832,886
24,693
16,340
90,581
3
(2,673 )
891
129,835
INCOME (LOSS) FROM OPERATIONS
6,355
385,968
OTHER (INCOME) EXPENSE:
Interest expense
Interest income
Litigation settlement
Insurance proceeds
Gain on sale of equity method investments
(Income) loss from equity method investments and
investments in subsidiaries
Other (income) expense, net
INCOME (LOSS) BEFORE INCOME TAXES
INCOME TAX BENEFIT
137,894
(287)
1,075
(231)
(28,349 )
(532,869 )
(1,369 )
(424,136 )
430,491
(69)
(2,621 )
(27)
—
—
(96,419 )
(694)
(33)
(99,794 )
485,762
—
—
—
—
—
3
—
3
(3)
—
—
—
—
—
510
—
510
(513)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
483,149
2,100
485,249
(485,249 )
—
91,640
33,480
290,188
486,664
56,633
4,119
962,724
392,320
135,273
(314)
1,075
(231)
(124,768 )
(49,904 )
698
(38,171 )
430,491
(69)
NET INCOME (LOSS)
$
430,560 $
485,762 $
(513) $
(485,249 ) $
430,560
F-43
Table of Contents
Index to Financial Statements
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)
Parent
Guarantors
Eliminations
Consolidated
Year Ended December 31, 2017
Non-Guarantor
Total revenues
$
1,010,989 $
309,314 $
— $
— $
1,320,303
Costs and expenses:
Lease operating expenses
Production taxes
Midstream gathering and processing expenses
Depreciation, depletion and amortization
General and administrative expenses
Accretion expense
Acquisition expense
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
INCOME (LOSS) FROM OPERATIONS
320,958
227,411
OTHER (INCOME) EXPENSE:
Interest expense
Interest income
Gain on sale of equity method investments
(Income) loss from equity method investments and
investments in subsidiaries
Other (income) expense, net
INCOME (LOSS) BEFORE INCOME TAXES
INCOME TAX EXPENSE
112,732
(988)
(12,523 )
(213,607 )
(1,617 )
(116,003 )
436,961
1,809
(4,534 )
(21)
—
1,955
(324)
(2,924 )
230,335
—
—
—
—
—
3
—
—
3
(3)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2,189
—
2,189
(2,192 )
—
227,243
900
228,143
(228,143 )
—
80,246
21,126
248,995
364,629
52,938
1,611
2,392
771,937
548,366
108,198
(1,009 )
(12,523 )
17,780
(1,041 )
111,405
436,961
1,809
NET INCOME (LOSS)
$
435,152 $
230,335 $
(2,192 ) $
(228,143 ) $
435,152
F-44
Table of Contents
Index to Financial Statements
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)
Parent
Guarantors
Eliminations
Consolidated
Year Ended December 31, 2016
Non-Guarantor
Total revenues
$
381,931 $
3,979 $
— $
— $
385,910
Costs and expenses:
Lease operating expenses
Production taxes
Midstream gathering and processing expenses
Depreciation, depletion and amortization
Impairment of oil and natural gas properties
General and administrative expenses
Accretion expense
68,034
13,121
165,400
245,970
715,495
43,896
1,057
1,252,973
843
155
572
4
—
(490)
—
1,084
(LOSS) INCOME FROM OPERATIONS
(871,042 )
2,895
OTHER (INCOME) EXPENSE:
Interest expense
Interest income
Insurance proceeds
Loss on debt extinguishment
Gain on sale of equity method investments
Loss (income) from equity method investments and
investments in subsidiaries
Other expense (income), net
(LOSS) INCOME BEFORE INCOME TAXES
INCOME TAX BENEFIT
63,529
(1,230 )
(5,718 )
23,776
(3,391 )
34,469
145
111,580
(982,622 )
(2,913 )
1
—
—
—
—
(89)
(16)
(104)
2,999
—
—
—
—
—
—
3
—
3
(3)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
25,150
—
25,150
(25,153 )
—
(22,154 )
—
(22,154 )
22,154
—
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
(3,391 )
37,376
129
114,472
(982,622 )
(2,913 )
NET (LOSS) INCOME
$
(979,709 ) $
2,999
$
(25,153 ) $
22,154
$
(979,709 )
F-45
Table of Contents
Index to Financial Statements
CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Amounts in thousands)
Parent
Guarantors
Eliminations
Consolidated
Year Ended December 31, 2018
Non-Guarantor
Net income (loss)
Foreign currency translation adjustment
Other comprehensive loss (income)
Comprehensive income (loss)
Net income (loss)
Foreign currency translation adjustment
Other comprehensive income (loss)
Comprehensive income (loss)
Net (loss) income
Foreign currency translation adjustment
Other comprehensive income (loss)
Comprehensive (loss) income
$
$
$
$
$
$
430,560 $
(15,487 )
(15,487 )
415,073 $
485,762 $
(297)
(297)
485,465 $
(513) $
(15,190 )
(15,190 )
(15,703 ) $
(485,249 ) $
15,487
15,487
(469,762 ) $
430,560
(15,487 )
(15,487 )
415,073
Parent
Guarantors
Eliminations
Consolidated
Year Ended December 31, 2017
Non-Guarantor
435,152 $
12,519
12,519
447,671 $
230,335 $
182
182
230,517 $
(2,192 ) $
12,337
12,337
10,145 $
(228,143 ) $
(12,519 )
(12,519 )
(240,662 ) $
435,152
12,519
12,519
447,671
Parent
(979,709 ) $
2,119
2,119
(977,590 ) $
Year Ended December 31, 2016
Non-Guarantor
Guarantors
Eliminations
Consolidated
2,999 $
778
778
3,777 $
(25,153 ) $
1,341
1,341
(23,812 ) $
22,154 $
(2,119 ) $
(2,119 )
20,035 $
(979,709 )
2,119
2,119
(977,590 )
F-46
Table of Contents
Index to Financial Statements
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Amounts in thousands)
Parent
Guarantors
Non-Guarantor
Eliminations
Consolidated
Year Ended December 31, 2018
Net cash provided by operating activities
$
543,817 $
208,670 $
— $
1
$
752,488
Net cash (used in) provided by investing activities
(429,483 )
(213,608 )
(2,318 )
2,318
(643,091 )
Net cash (used in) provided by financing activities
(156,657 )
—
2,319
(2,319 )
(156,657 )
Net (decrease) increase in cash and cash equivalents
(42,323 )
(4,938 )
Cash and cash equivalents at beginning of period
67,908
31,649
1
—
—
—
(47,260 )
99,557
Cash and cash equivalents at end of period
$
25,585 $
26,711 $
1 $
— $
52,297
Parent
Guarantors
Non-Guarantor
Eliminations
Consolidated
Year Ended December 31, 2017
Net cash provided by operating activities
$
392,680 $
287,209 $
— $
— $
679,889
Net cash (used in) provided by investing activities
(2,216,615)
(1,674,690)
(2,280 )
1,419,417
(2,474,168)
Net cash provided by (used in) financing activities
432,961
1,417,137
2,280
(1,419,417)
432,961
Net (decrease) increase in cash and cash equivalents
(1,390,974)
29,656
Cash and cash equivalents at beginning of period
1,458,882
1,993
—
—
—
—
(1,361,318)
1,460,875
Cash and cash equivalents at end of period
$
67,908 $
31,649 $
— $
— $
99,557
Parent
Guarantors
Eliminations
Consolidated
Year Ended December 31, 2016
Non-Guarantor
Net cash provided by (used in) operating activities
$
336,330 $
(9,486 ) $
(2) $
11,001 $
337,843
Net cash (used in) provided by investing activities
(720,582 )
(22,500 )
(15,472 )
37,972
(720,582 )
Net cash provided by (used in)financing activities
1,730,640
33,500
15,473
(48,973 )
1,730,640
Net increase (decrease) in cash and cash equivalents
1,346,388
1,514
Cash and cash equivalents at beginning of period
112,494
479
(1)
1
—
—
1,347,901
112,974
Cash and cash equivalents at end of period
$
1,458,882 $
1,993 $
— $
— $
1,460,875
F-47
Table of Contents
Index to Financial Statements
19.
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
2018
2017
(In thousands)
7,153,799 $
2,873,037
10,026,836
(4,613,293)
5,413,543 $
6,256,182
2,912,974
9,169,156
(4,136,777)
5,032,379
67,475 $
79,605
147,080
(1,553)
145,527 $
73,818
86,540
160,358
(1,693)
158,665
$
$
$
$
Acquisition
Development
Exploratory
Recompletions
Capitalized asset retirement obligation
Total
Equity investment in Grizzly Oil Sands ULC
Acquisition
Development
Exploratory
Capitalized asset retirement obligation
Total
2018
2017
2016
$
$
$
$
(In thousands)
124,558 $
603,676
21,840
7,915
1,452
759,441 $
1,951,281 $
994,237
—
14,289
42,270
3,002,077 $
238 $
—
—
(285)
(47) $
503 $
—
—
(524)
(21) $
152,887
423,998
—
16,386
10,971
604,242
357
—
—
784
1,141
F-48
Table of Contents
Index to Financial Statements
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
Results of operations from producing activities
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
Results of operations from producing activities
Oil and Gas Reserves
2018
2017
2016
(In thousands)
$
$
$
$
$
1,355,044 $
(415,308)
(476,517)
—
463,219
254
(322)
(68)
463,287 $
0.96 $
1,320,303 $
(350,367)
(358,792)
—
611,144
3,362
(3,602)
(240)
611,384 $
0.90 $
— $
—
—
—
—
— $
— $
—
—
—
—
— $
385,910
(248,125)
(243,098)
(715,495)
(820,808)
—
—
—
(820,808)
0.92
—
(13)
—
(13)
—
(13)
The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2018,
2017 and 2016 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, 2018, 2017 and 2016, 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 2018
reserve report are $65.56 per barrel of oil, $3.10 per MMbtu and $32.02 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, 2017 and 2016 for reserve report
purposes are $51.34 per barrel, $2.98 per MMbtu and $18.40 per barrel for NGLs and $42.75 per barrel, $2.48 per MMbtu and $9.91 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-49
Table of Contents
Index to Financial Statements
Proved Reserves
Beginning of the
period
Purchases in oil
and natural gas
reserves in place
Extensions and
discoveries
Sales of oil and
natural gas
reserves in place
Revisions of prior
reserve estimates
Current
production
End of period
Proved developed
reserves
Proved
undeveloped
reserves
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
2018
2017
2016
Oil
(MBbls)
Natural Gas
(MMcf)
Natural
Gas
Liquids
(MBbls)
Oil
(MBbls)
Natural
Gas
Liquids
Oil
(MBbls) (MBbls)
Natural
Gas
Liquids
(MBbls)
Natural Gas
(MMcf)
Natural Gas
(MMcf)
19,157
4,825,310
75,766
5,546
2,167,068
20,127
6,458 1,560,145
17,736
—
—
—
15,132
1,098,644
53,617
—
—
—
5,205
622,271
9,631
951
1,594,734
4,619
1,217 1,082,220
7,677
(134)
(43,444 )
(112)
—
—
—
—
—
—
(377)
(826,506)
1,228
107
314,925
2,737
(3)
(247,703)
(1,439)
(2,801)
21,050
(443,742)
4,133,889
(5,993)
80,520
(2,579)
19,157
(350,061)
4,825,310
(5,334)
75,766
(227,594)
(2,126)
5,546 2,167,068
(3,847)
20,127
9,570
1,813,184
40,810
10,245
1,616,930
36,247
4,882
744,797
14,299
11,480
2,320,705
39,710
8,912
3,208,380
39,519
664 1,422,271
5,828
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
In 2018, the Company experienced extensions and discoveries of 711.2 Bcfe of estimated proved reserves, which were primarily
attributable to the Company's continued development of its Utica Shale and SCOOP acreages. Of the total extensions and discoveries,
556.3 Bcfe was attributable to the addition of 75 PUD locations in the Utica field, 90.1 Bcfe was attributable to the addition of 11 PUD
locations in the SCOOP field and 3.0 Bcfe was attributable to the addition of 13 PUD locations in the Southern Louisiana fields as a result
of the Company's current development plan that refocused some activity within existing fields. This change reflects the Company's ongoing
efforts to optimize the development program with well selection based on economic returns, commodity mix and surface considerations.
In 2018, the Company experienced downward revisions of 1.0 Tcfe in estimated proved reserves with the exclusion of 127 PUD
locations in the Company's Utica field and 12 PUD locations in the Company's SCOOP field, which was primarily the result of changes in
the Company's development schedule moving development in excess of five years from initial booking. The development plan change, as
approved by the Company's senior management and board of directors, is a result of continued focus on free cash flow generation. This
downward revision was partially offset by upward revisions of 82.4 Bcfe in estimated proved reserves in 2018 due to changes in wellbore
lateral length, 67.6 Bcfe due to changes in ownership interest, 27.9 Bcfe due to an increase in pricing and 8.3 Bcfe due to changes in well
performance. In addition, the Company sold
F-50
Table of Contents
Index to Financial Statements
approximately 44.9 Bcfe of proved undeveloped oil and natural gas reserves associated with various non-operated interests, the majority of
which were in the Company's Utica field.
In 2017, the Company purchased 1.5 Tcfe through its 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.
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, 2018, 2017 and 2016 using an unweighted average first-of-the-month price for the period January through December 31,
2018, 2017 and 2016.
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
Standardized measure of discounted future net cash flows
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
F-51
$
$
$
$
Year ended December 31,
2018
2017
2016
(In thousands)
14,483,197 $
(2,437,853)
(5,067,554)
(455,840)
(943,293)
5,578,657
(2,595,932)
2,982,725 $
11,202,692 $
(3,005,217)
(2,152,821)
(289,944)
(573,965)
5,180,745
(2,537,181)
2,643,564 $
3,354,168
(1,165,025)
(924,167)
(69,447)
(14,545)
1,180,984
(492,944)
688,040
— $
—
—
—
—
—
— $
— $
—
—
—
—
—
— $
—
—
—
—
—
—
—
Table of Contents
Index to Financial Statements
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
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
Sales of oil and gas reserves in place
Accretion of discount
Net changes in income taxes
Change in production rates and other
Total change in standardized measure of discounted future net cash flows
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 flows
$
$
$
$
F-52
Year ended December 31,
2018
2017
2016
(In thousands)
(1,063,215) $
590,519
—
519,137
402,156
(356,933)
(25,882)
264,356
(185,157)
194,180
339,161 $
(756,257) $
913,714
703,866
618,039
390,673
155,200
—
68,804
(231,545)
93,030
1,955,524 $
(312,291)
(146,518)
—
186,909
176,218
(38,448)
—
76,433
(6,495)
(12,099)
(76,291)
— $
—
—
—
—
—
—
—
—
— $
— $
—
—
—
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
—
—
Table of Contents
Index to Financial Statements
20.
SELECTED QUARTERLY FINANCIAL DATA
(UNAUDITED)
The following table summarizes quarterly financial data for the years ended December 31, 2018 and 2017:
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
2018
325,392 $
110,318
(69)
90,090
0.50 $
0.50 $
(In thousands)
252,740 $
13,791
—
111,319
0.64 $
0.64 $
2017
360,962 $
113,576
—
95,150
0.55 $
0.55 $
415,950
154,635
—
134,001
0.78
0.78
First
Quarter
Second
Quarter
Third
Quarter
Fourth
Quarter
333,004 $
181,683
—
154,455
(In thousands)
323,953 $
143,175
—
105,936
0.91 $
0.91 $
0.58 $
0.58 $
265,498 $
50,483
2,763
18,235
0.10 $
0.10 $
397,848
173,025
(954)
156,526
0.85
0.85
$
$
$
$
$
$
Revenues
Income from operations
Income tax benefit
Net income
Income per share:
Basic
Diluted
Revenues
Income from operations
Income tax expense (benefit)
Net income
Income per share:
Basic
Diluted
21.
SUBSEQUENT
EVENTS
Derivatives
In February 2019, the Company entered into a natural gas basis swap position for 2020, which settles on the pricing index to basis
differential of Inside FERC to the NYMEX Henry Hub natural gas price, for approximately 10,000 MMBtu of natural gas per day at a
differential of $0.54 per MMBtu.
Stock Repurchase Program
In January 2019, the board of directors of the Company approved a stock repurchase program to acquire up to $400.0 million of the
Company's outstanding common stock within the next 24 months. 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 2019 capital development program. This repurchase program is authorized to extend through December 31, 2020 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 has not made any such purchases of its common stock under this program as of February 28, 2019.
F-53
SUBSIDIARIES OF GULFPORT ENERGY CORPORATION
Exhibit 21
Name of Subsidiary
Grizzly Holdings, Inc.
Jaguar Resources LLC
Puma Resources, Inc.
Gator Marine, Inc.
Gator Marine Ivanhoe, Inc.
Westhawk Minerals LLC
Gulfport Appalachia, LLC (formerly known as Gulfport Buckeye
LLC)
Gulfport Midstream Holdings, LLC
Gulfport MidCon, LLC
Jurisdiction of Organization
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We have issued our reports dated February 28, 2019, with respect to the consolidated financial statements and internal control over
financial reporting included in the Annual Report of Gulfport Energy Corporation on Form 10-K for the year ended December 31, 2018.
We consent to the incorporation by reference of said reports in the Registration Statements of Gulfport Energy Corporation on Forms S-8
(File No. 333-206564, effective August 25, 2015; File No. 333-135728, effective July 12, 2006; File No. 333-129178, effective October
21, 2005; and File No. 333-55738, effective February 16, 2001) and on Forms S-3ASR (File No. 333-215078, automatically effective
December 14, 2016, and File No. 333-217362, automatically effective April 18, 2017).
Exhibit 23.1
/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
February 28, 2019
CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC.
Exhibit 23.2
We hereby consent to the inclusion in the Form 10-K of Gulfport Energy Corporation (the “Form 10-K”) of our report dated February 1,
2019 on oil and gas reserves of Gulfport Energy Corporation and its subsidiaries as of December 31, 2018 located in the United States and
information from our prior reserve reports referenced in the Form 10-K, to all references to our firm included in the Form 10-K and to the
incorporation by reference of such reports in the Registration Statements of Gulfport Energy Corporation on Forms S-8 (File No. 333-
206564, effective August 25, 2015; File No. 333-135728, effective July 12, 2006; File No. 333-129178, effective October 21, 2005; and
File No. 333-55738, effective February 16, 2001) and on Forms S-3ASR (File No. 333-215078, automatically effective December 14,
2016, and File No. 333-217362, automatically effective April 18, 2017).
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ Danny D. Simmons
Danny D. Simmons, P.E.
President and Chief Operating Officer
Houston, Texas
February 28, 2019
Exhibit 31.1
I, David M. Wood, Chief Executive Officer of Gulfport Energy Corporation, certify that:
1. I have reviewed this Annual Report on Form 10-K of Gulfport Energy Corporation;
CERTIFICATION
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to
make the statement made, in light of the circumstances under which such statements were made, not misleading with respect to the period
covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I am responsible for establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in the Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made
known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed
under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions
about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on
such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the
registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial
reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent
functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting
which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial
information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal controls over financial reporting.
Date: February 28, 2019
/s/ David M. Wood
David M. Wood
Chief Executive Officer and President
Exhibit 31.2
I, Keri Crowell, Chief Financial Officer of Gulfport Energy Corporation, certify that:
1. I have reviewed this Annual Report on Form 10-K of Gulfport Energy Corporation;
CERTIFICATION
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to
make the statement made, in light of the circumstances under which such statements were made, not misleading with respect to the period
covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I am responsible for establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in the Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made
known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed
under our supervision, 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;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions
about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on
such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the
registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial
reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent
functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting
which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial
information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal controls over financial reporting.
Date: February 28, 2019
/s/ Keri Crowell
Keri Crowell
Chief Financial Officer
CERTIFICATION OF PERIODIC REPORT
Exhibit 32.1
I, David M. Wood, Chief Executive Officer of Gulfport Energy Corporation (the “Company”), certify, pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:
(1) the Annual Report on Form10-K of the Company for the year ended December 31, 2018 (the “Report”) fully complies with
the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and
(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
Dated: February 28, 2019
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the
Company and furnished to the Securities and Exchange Commission or its staff upon request.
/s/ David M. Wood
David M. Wood
Chief Executive Officer and President
CERTIFICATION OF PERIODIC REPORT
Exhibit 32.2
I, Keri Crowell, Chief Financial Officer of Gulfport Energy Corporation (the “Company”), certify, pursuant to Section 906 of the Sarbanes-
Oxley Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge:
(1) the Annual Report on Form 10-K of the Company for the year ended December 31, 2018 (the “Report”) fully complies with
the requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and
(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
Dated: February 28, 2019
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the
Company and furnished to the Securities and Exchange Commission or its staff upon request.
/s/ Keri Crowell
Keri Crowell
Chief Financial Officer
Exhibit 99.1
February 1, 2019
Mr. David M. Wood
Gulfport Energy Corporation
3001 Quail Springs Parkway
Oklahoma City, Oklahoma 73134
Dear Mr. Wood:
In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2018, to the
Gulfport Energy Corporation (Gulfport) interest in certain oil and gas properties located in the United States. We completed our
evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute
all of the proved reserves owned by Gulfport. The estimates in this report have been prepared in accordance with the
definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of
future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas.
Definitions are presented immediately following this letter. This report has been prepared for Gulfport's use in filing with the
SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for
such purpose.
We estimate the net reserves and future net revenue to the Gulfport interest in these properties, as of December 31, 2018,
to be:
Category
Oil
(MBBL)
Net Reserves
NGL
(MBBL)
Gas
(MMCF)
Future Net Revenue (M$)
Present Worth
Total
at 10%
Proved Developed Producing
Proved Developed Non-Producing
Proved Undeveloped
8,203.2
1,367.1
11,479.6
38,847.7
1,962.5
39,710.3
1,771,758.8
41,425.1
2,320,704.4
3,426,599.6
153,108.1
2,942,241.4
2,179,951.5
109,218.8
1,118,150.7
Total Proved
Totals may not add because of rounding.
21,049.9
80,520.6
4,133,888.3
6,521,949.1
3,407,320.9
The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in
thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic
feet (MMCF) at standard temperature and pressure bases.
Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and
production status. The estimates of reserves and future revenue included herein have not been adjusted for risk. As requested,
probable and possible reserves that exist for the properties have not been included. This report does not include any value that
could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been
estimated.
Gross revenue is Gulfport's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net
revenue is after deductions for Gulfport's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and
operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual
rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future
net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market
value of the properties.
Exhibit 99.1
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for
each month in the period January through December 2018. For oil and NGL volumes, the average West Texas Intermediate
spot price of $65.56 per barrel is adjusted for quality, transportation fees, and market differentials. For gas volumes, the
average Henry Hub spot price of $3.100 per MMBTU is adjusted for energy content, transportation fees, and market
differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted
by production over the remaining lives of the properties are $64.02 per barrel of oil, $32.02 per barrel of NGL, and $2.554 per
MCF of gas.
Operating costs used in this report are based on operating expense records of Gulfport. These costs include the per-well
overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the
district and field levels. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production
costs. Headquarters general and administrative overhead expenses of Gulfport are included to the extent that they are covered
under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.
Capital costs used in this report were provided by Gulfport and are based on authorizations for expenditure and actual costs
from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment.
Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar
properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Gulfport's
estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment
costs are not escalated for inflation.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical
operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the
properties; therefore, our estimates do not include any costs due to such possible liability.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the
Gulfport interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any
such imbalances; our projections are based on Gulfport receiving its net revenue interest share of estimated future gross
production. Additionally, we have made no specific investigation of any firm transportation contracts that may be in place for
these properties; our estimates of future revenue include the effects of such contracts only to the extent that the associated
fees are accounted for in the historical field- and lease-level accounting statements.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are
those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable
certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially
less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market
conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic
assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the
properties will be developed consistent with current development plans as provided to us by Gulfport, that the properties will be
operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of
the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual
performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than
the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices
received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing
this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps,
well test data, production data, historical price and cost information, and property ownership interests. The reserves in this
report have been estimated using deterministic methods; these estimates have been prepared in
Exhibit 99.1
accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by
the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a
combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be
appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A
substantial portion of these reserves are for undeveloped locations; such reserves are based on estimates of reservoir
volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all
aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data;
therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from Gulfport, public data sources, and the nonconfidential files of Netherland,
Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. We have not
examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical
persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications,
independence, objectivity, and confidentiality set forth in the SPE Standards. Mr. Richard B. Talley, Jr., a Licensed
Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2004 and has
over 5 years of prior industry experience. Mr. Edward C. Roy III, a Licensed Professional Geoscientist in the State of Texas,
has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 years of prior industry experience.
We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these
properties nor are we employed on a contingent basis.
Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
/s/ C.H. (Scott) Rees III
By:
C.H. (Scott) Rees III, P.E.
Chairman and Chief Executive Officer
/s/ Richard B. Talley, Jr. /s/ Edward C. Roy III
By: By:
Richard B. Talley, Jr., P.E. 102425 Edward C. Roy III, P.G. 2364
Senior Vice President Vice President
Date Signed: February 1, 2019 Date Signed: February 1, 2019
RBT:TTS
Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our
clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is
subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and
the original document, the original document shall control and supersede the digital document.
Exhibit 99.1
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also
included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the Society of Petroleum
Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance
and Disclosure Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and
options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee,
brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir
conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the
reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When
used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir
of interest:
(i) Same geological formation (but not necessarily in pressure communication with the reservoir of
interest);
(ii) Same
environment
of
deposition;
(iii) Similar geological structure;
and
(iv) Same
mechanism.
drive
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of
interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a
viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In
its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure,
but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter
(from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively
minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by
means not involving a well.
Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing at the effective date of
the estimate. Improved recovery Reserves are considered producing only after the improved recovery project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion
intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or
pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones
in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these
reserves. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and
storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment
and facilities and other costs of development activities, are costs incurred to:
(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific
development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the
extent necessary in developing the proved reserves.
(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms
and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
Definitions
- Page 1 of 6
Exhibit 99.1
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring
devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.
(iv) Provide
systems.
improved
recovery
(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically
producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated
development of a group of several fields and associated facilities with a common ownership may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be
productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue
that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be
determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative
production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are
considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type
stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as
prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable
operating costs of support equipment and facilities and other costs of exploration activities, are:
(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and
salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are
sometimes referred to as geological and geophysical or "G&G" costs.
(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title
defense, and the maintenance of land and lease records.
(iii) Dry
hole
contributions
and
bottom
hole
contributions.
(iv) Costs of drilling and equipping exploratory
wells.
(v) Costs of drilling exploratory-type stratigraphic test
wells.
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a
service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by
intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or
adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic
condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-
of-interest, etc.
(16) Oil and gas producing activities.
(i) Oil and gas producing activities
include:
(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states
and original locations;
(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or
gas from such properties;
(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the
acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:
(1) Lifting the oil and gas to the surface;
and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons);
and
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other
nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a
view to such extraction.
Definitions
- Page 2 of 6
Exhibit 99.1
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the
outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard
the terminal point for the production function as:
a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery,
b.
or a marine terminal; and
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered
to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier,
a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that
are saleable in the state in which the hydrocarbons are delivered.
(ii) Oil and gas producing activities do not
include:
(A) Transporting, refining, or marketing oil and
gas;
(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does
not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and
gas can be extracted; or
(D) Production
steam.
of
geothermal
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding
proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that
the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations
of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are
unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place
than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative
technical and commercial interpretations within the reservoir or subject project that are clearly documented, including
comparisons to results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir
within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness
or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent
portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are
structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and
the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the
reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology.
Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas
based on reservoir fluid properties and pressure gradient interpretations.
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but
which, together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of
estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that
the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of
available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the
reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if
these areas are in communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the
hydrocarbons in place than assumed for proved reserves.
Definitions
- Page 3 of 6
Exhibit 99.1
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this
section.
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that
could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of
possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating
costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and
facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:
(A) Costs of labor to operate the wells and related equipment and
facilities.
(B) Repairs
maintenance.
and
(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and
facilities.
(D) Property taxes and insurance applicable to proved properties and wells and related equipment and
facilities.
(E) Severance
taxes.
(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation,
refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing
activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate.
Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs
but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and
engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known
reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or
probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be
reasonably certain that it will commence the project within a reasonable time.
(i) The area of
includes:
the reservoir considered as proved
(A) The area identified by drilling and limited by fluid contacts, if any,
and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to
contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as
seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower
contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an
associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience,
engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to,
fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a
whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable
technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental
entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The
price shall be the average price during the 12-month period prior to the ending date of the period covered by the report,
determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless
prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Definitions
- Page 4 of 6
Exhibit 99.1
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(23) Proved properties. Properties with proved reserves.
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities
will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will
equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as
changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are
made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to
decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been
field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being
evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically
producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must
be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of
delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those
reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated
from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results).
Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed
as of the end of the year:
a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity
participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see
paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting
purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are
disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the
year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in
existence at year-end.
b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in
developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of
existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated
production costs.
c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with
consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less
the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances
relating to the entity's proved oil and gas reserves.
d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax
expenses from future cash inflows.
e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash
flows relating to proved oil and gas reserves.
f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is
confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Definitions
- Page 5 of 6
Exhibit 99.1
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources
may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and
undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells
include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection
for in-situ combustion.
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific
geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification
also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are
classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain
of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic
producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that
they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally
sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination
must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any
extension beyond five years should be the exception, and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may
extend past five years include, but are not limited to, the following:
The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum
number of wells necessary to maintain the lease generally would not constitute significant development activities);
The company's historical record at completing development of comparable long-term projects;
The amount of time in which the company has maintained the leases, or booked the reserves, without significant development
activities;
The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its
development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves
typically would not be appropriate); and
The extent to which delays in development are caused by external factors related to the physical operating environment (for example,
restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting
resources to develop properties with higher priority).
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual
projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using
reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.
Definitions
- Page 6 of 6