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, 2019
OR
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                     
For the transition period from                      to
Commission File Number 000-19514
 
Gulfport Energy CorporationCorporation
(Exact Name of Registrant As Specified in Its Charter)
 
Delaware73-1521290
(State or Other Jurisdiction of
Incorporation or Organization)
(IRS Employer
Identification Number)
3001 Quail Springs Parkway
Oklahoma City, OklahomaOklahoma73134
(Address of Principal Executive Offices)(Zip Code)
(405) (405) 252-4600
(Registrant Telephone Number, Including Area Code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each ClassTrading Symbol(s) Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share GPORThe Nasdaq Stock Market LLC
Securities registered pursuant to Section 12(g) of the Act:    None
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes  ☐No☒
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  ¨☐Noý☒
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.     Yesý☒    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).
Yesý☒    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 filerý☒    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-votingour common stock held by non-affiliates on June 28, 2019 was $782,634,443. As of the registrant computed asFebruary 14, 2020, there were 159,710,955 shares of June 30, 2018, based on the closing price of theour $0.01 par value 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.outstanding.
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 20182020 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
  Page
  
FORWARD-LOOKING STATEMENTS
1
  
PART I
2
   
ITEM 1.
BUSINESS
2
   
ITEM 1A.
RISK FACTORS
2117
   
ITEM 1B.
UNRESOLVED STAFF COMMENTS
4439
   
ITEM 2.
PROPERTIES
4439
   
ITEM 3.
LEGAL PROCEEDINGS
5339
   
ITEM 4.
MINE SAFETY DISCLOSURES
5441
  
PART II
5441
   
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
5441
   
ITEM 6.
SELECTED FINANCIAL DATA
41
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
42
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
55
   
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
57
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
72
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
7459
   
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
74107
   
ITEM 9A.
CONTROLS AND PROCEDURES
74107
   
ITEM 9B.
OTHER INFORMATION
77111
  
PART III
77111
   
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
77111
   
ITEM 11.
EXECUTIVE COMPENSATION
77111
   
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
77111
   
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
77111
   
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
77111
  
PART IV
78112
   
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
78112
  
ITEM 16.
FORM 10-K SUMMARY
82117
  
Signatures
S-0
  
Index to Consolidated Financial Statements
F-1




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FORWARD-LOOKING STATEMENTS
Our disclosure and analysis in thisThis 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,(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), the effect of our remediation plan for a material weakness, 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

All forward-looking statements, as a result of new information, future eventsexpressed or otherwise, except as requiredimplied, included in this Annual Report are expressly qualified in their entirety by law. Thesethis cautionary statements qualify allstatement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements attributable to usthat we or persons acting on our behalf.behalf may issue.


Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.

Investors should note that we announce financial information in SEC filings, press releases and public conference calls. We may use the Investors section of our website (www.gulfportenergy.com) to communicate with investors. It is possible that the financial and other information posted there could be deemed to be material information. The information on our website is not part of this Annual Report on Form 10-K.

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Index to Financial Statements


PART I
ITEM 1.BUSINESS
GeneralOur Business
WeA Delaware corporation formed in 1997, we are an independent oil and natural gasgas-weighted exploration and production company focused on the exploration, exploitation,development, acquisition and production of natural gas, crude oil and natural gas liquids or NGLs,("NGL") in the United States.States with primary focus in the Appalachia and Mid-Continent basins. Our corporate strategy is focused on the economic development of our asset base in an effort 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,generate sustainable free cash flow. We also seek to opportunistically expand our inventory of economic drilling locations in the basins in which 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.operate. Our principal properties are located in Eastern Ohio, where we target development in the Utica Shale primarilyformation (the “Utica”) and Central Oklahoma where we target development in Eastern Ohio and the SCOOP Woodford and SCOOP Springer plays in Oklahoma.formations (the "SCOOP"). We seek to achieve reserve growth and increase our cash flow through our annual drilling programs. 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,("Grizzly"), and an approximate 21.9%21.8% equity interest in Mammoth Energy Services, Inc. ("Mammoth Energy"), or Mammoth Energy, aan energy services 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,, both 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 onare non-core to our Utica Shale acreage in 2018.business strategy.
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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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, 2018,2019, we had 4.74.5 trillion cubic feet of natural gas equivalent or Tcfe,("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$1.7 billion excluding reserves attributable to our interests in Grizzly and Tatex II.a present net value of estimated future net revenues, discounted at 10% ("PV-10"), of approximately $1.7 billion. See Item 2. "Properties-Proved Oil, and Natural Gas and NGL Reserves”" below 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 OilInformation About Us
Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and Natural Gas Propertiesall 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. From time to time, we also post announcements, updates, events, investor information and presentations on our website in addition to copies of our recent news releases. 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.
The following table presents certain information asBusiness Strategy
Gulfport aims to create shareholder value through the development of December 31, 2018 reflecting our net interestsignificant resource plays. Our substantial inventory of hydrocarbon resources, including unproved acreage positions in each of our key basins, provides a strong foundation to create future value.  Concentrated blocks of unproved acreage provide us the opportunity to apply best in class techniques including optimum well spacing, leading completion practices and lateral length optimization to maximize overall capital efficiency. We have improved our capital and operating efficiency metrics over the last several years and today have a low cost structure in both our Utica and SCOOP operating areas. We believe our low cost structure provides a significant competitive advantage in the current commodity price environment and it is our strategy to continue to seek capital and operating efficiencies to grow this advantage.
We continue to focus on reducing our leverage profile, increasing cash flow from operations, improving margins through financial discipline and operating efficiencies while at the same time maintaining strong environmental and safety performance. To accomplish these goals, we intend to allocate capital expenditures to projects we believe offer the highest rate of return, to deploy leading drilling and completion techniques and technologies in our principal producing oildevelopment efforts, and natural gas properties into take advantage of merger, acquisition and divestiture opportunities to strengthen our cost structure, deepen our inventory and improve our asset portfolio.
We believe that our dedication to financial discipline, the Utica Shale primarily in Eastern Ohio, the SCOOP in Oklahoma,along the Louisiana Gulf Coast, in the Niobrara Formation in Northwestern Coloradoflexibility and in the Bakken Formation in Western North Dakotaefficiency of our capital program, our low cost structure and Eastern Montana.our continued focus on safety and environmental stewardship provides opportunities for sustainable value creation.

               
Proved Reserves  
Field
 
Average NRI/WI (1) 
 
Productive
Wells  
 
Non-Productive
Wells  
 
Developed
Acreage (2)  
 
Gas  
 
Oil  
 NGLs 
Total  
Percentages  
 
Gross 
 
Net  
 
Gross  
 
Net  
 
Gross  
 
Net 
 MMcf 
MBbls  
 MBbls MMcfe
Utica Shale (3)44.26/54.44 567
 308
 5
 4.23
 92,594
 72,693
 3,123,629
 5,289
 32,500
 3,350,363
SCOOP (4)24.34/30.20 576
 173.27
 33
 27.83
 48,658
 34,532
 1,009,971
 12,937
 48,020
 1,375,713
West Cote Blanche Bay Field (5)80.108/100 69
 69
 146
 146
 5,668
 5,668
 18
 1,834
 —
 11,022
E. Hackberry Field (6)82.33/100 14
 14
 130
 130
 2,910
 2,910
 35
 276
 —
 1,692
W. Hackberry Field87.50/100 2
 2
 7
 7
 727
 727
 —
 391
 —
 2,346
Niobrara Formation34.52/48.61 3
 1.46
 —
 —
 1,998
 999
 —
 128
 —
 768
Bakken Formation1.51/1.83 18
 0.3
 —
 —
 386
 77
 227
 195
 —
 1,398
Overrides/Royalty Non-operatedVarious 673
 0.9
 —
 —
 —
 —
 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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Our 2020 capital expenditure program is expected to be $285 million to $310 million. We expect to fund these expenditures with our operating cash flow and borrowings under our revolving credit agreement. We expect this drilling program to result in 1,100 to 1,150 MMcfeper day of production in 2020.
(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 fromWe plan to run on average approximately one operated rig in our Utica area and 1.5 rigs in our SCOOP area in 2020. In the Utica, we intend to spud 16 gross operated horizontal wells that have been drilled or(14.8 net), and commence sales on 18 gross and net horizontal wells in which2020. In the SCOOP, we have electedintend to participate. Includes 392spud 10 gross (30.02operated horizontal wells (7.8 net), and commence sales on four gross horizontal wells drilled by other operators on(3.8 net) in 2020.
Operating Areas
We focus our acreage.development, production and acquisition efforts in the geographic operating areas described below.
(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 a hydrocarbon bearing rock formation 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 LimestoneWe have approximately 205,000 net reservoir acres located primarily in Belmont, Harrison, Jefferson 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,Monroe Counties in Eastern 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,where 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 During the fourth quarter 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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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,produced 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 1,115.91,090 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 leaseholdnet to our interests in approximately 66,000 gross (50,000 net) surface acres in the this area.
SCOOP and approximately 92,000 net reservoir acres, which includes 50,000 net Woodford acres and 42,000 net Springer acres.
Area History
(Oklahoma) - The SCOOP, or South Central Oklahoma Oil Province, is a loosely defined provincearea 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 fromOklahoma within 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.basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Shale.Sycamore and Springer formations. We have approximately 76,000 net reservoir acres (comprised of approximately 41,500 in the Woodford formation and approximately 34,500 in the Springer formation) located primarily in Garvin, Grady and Stephens Counties. The Woodford Shale is a silica and highly organic rich black shale that was deposited about 320 million to 370 million years ago. Acrossacross 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 equivalentconsists of hydrocarbon-bearing interbedded shales and siliceous limestones ranging in thickness from 150 to the Meramec and Osage being developed in the STACK, or Sooner Trend Anadarko Basin Canadian and Kingfisher Counties, playover 450 feet and is located betweenoverlain by the organic-rich Woodford and Caney Shales.Shale. The SycamoreSpringer formation is approximately 250 feet thick across our acreage position presentingis comprised of a significant development target.
Facilities
There are standard land oilseries of lenticular sand 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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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
shale units. 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 PUDprimary targets are up-dip offsetsa series of porous, low clay and organic-rich packages within the Goddard Shale member ranging in thickness from 50 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
Inover 250 feet. During the fourth quarter of 2018, our net production at WCBB was2019, we produced approximately 837 MMcfe, or an average of 9.1255 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 beneficialnet to our 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.this area.
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 of1.2 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 of827.1 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 including the Bakken formation in Louisiana, TexasNorth Dakota and Oklahoma as describedMontana, the Niobrara formation in Colorado and other formations in Texas. We previously held interests located in the West Cote Blanche Bay ("WCBB") and Hackberry fields of Louisiana. However, we sold these non-core interests in July 2019.
Drilling Activity
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, regardless of whether they produce a reasonable rate of return.

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 2019 2018 2017
 Gross Net Gross Net Gross Net
Recompletions:           
Productive—
 —
 47
 47
 81
 81
Dry—
 —
 —
 —
 —
 —
Total—
 —
 47
 47
 81
 81
Development:           
      Productive25
 22.4
 34
 30
 124
 115.4
      Dry—
 —
 —
 —
 2
 2
Total25
 22.4
 34
 30
 126
 117.4
Exploratory:           
Productive1
 0.8
 2
 1.5
 —
 —
Dry—
 —
 —
 —
 —
 —
Total1
 0.8
 2
 1.5
 —
 —
The following table presents activity by operating area for the year ended December 31, 2019:
 Operated Non-Operated
FieldDrilled Turned to Sales Drilled Turned to Sales
Gross Net Gross Net Gross Net Gross Net
Utica Shale (1)
16
 14.6
 47
 41.6
 5
 0.9
 14
 3.3
SCOOP (2)
10
 8.6
 14
 12.6
 42
 1.6
 39
 1.2
Niobrara Formation—
 —
 —
 —
 —
 —
 —
 —
Bakken Formation—
 —
 —
 —
 —
 —
 —
 —
Total26
 23.2
 61
 54.2
 47
 2.5
 53
 4.5
_____________________
(1)Of the 16 gross wells we drilled in 2019, six were completed as producing wells and 10 were in various stages of completion as of December 31, 2019.
(2)Of the 10 gross wells we drilled in 2019, five were completed as producing wells, four were in various stages of completion and one was being drilled as of December 31, 2019.
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, 2018:2019.

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 Average NRI/WI (1) 
Productive
Oil Wells
 
Productive
Gas Wells
 
Non-Productive
Oil Wells
 
Non-Productive
Gas Wells
 
Developed
Acreage
 
Undeveloped
Acreage
FieldPercentages Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net
Utica Shale45.93/56.32 126
 40.36
 503
 313.41
 —
 —
 2
 1.58
 107,076
 85,381
 130,734
 119,428
SCOOP26.21/32.64 118
 24.28
 480
 153.16
 13
 3.69
 56
 36.58
 50,721
 35,602
 7,373
 5,999
Niobrara Formation24.41/29.18 5
 1.46
 —
 —
 —
 —
 —
 —
 1,998
 999
 1,292
 646
Bakken Formation1.11/1.97 18
 0.35
 —
 —
 —
 —
 —
 —
 386
 77
 3,505
 701
Overrides/Royalty Non-operatedVarious 401
 0.02
 5
 0.02
 2
 —
 —
 —
 —
 —
 —
 —
Total  668
 66.47
 988
 466.59
 15
 3.69
 58
 38.16
 160,181
 122,059
 142,904
 126,774
_____________________
(1)Net Revenue Interest (NRI)/Working Interest (WI).

Most of our leases have a three- to five-year primary term, many of which include options to extend the primary term. We manage lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling our operations and drilling to establish production in paying quantities in order to hold leases prior to the expiration dates, paying the prescribed lease extension payments, planning non-core divestitures or strategic acreage trades with other operators to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans. The following table sets forth the potential expiration periods of gross and net undeveloped leasehold acres as of December 31, 2019
Field 
State 
 
Parish/County  
 
Average Working
Interest 
 
Overriding Royalty
Interests  
 
Producing
Wells 
 
Non-Producing
Wells 
Deer Island Louisiana Terrebonne 3.13% —
 —
 1
Napoleonville Louisiana Assumption —
 2.5% 3
 —
Crest Texas Ochiltree 2.00% —
 1
 —
Eagle City South Oklahoma Dewey 1.04% —
 1
 —
Fay South Oklahoma Blaine 0.30% —
 1
 —
Fay East Oklahoma Blaine 0.15% —
 1
 —
Squaw Cheek Oklahoma Blaine 0.13% —
 1
 —
Watonga Chickasha Trend Oklahoma Canadian 0.05% —
 1
 —
Green River Basin Colorado Moffat 0.07% —
 2
 —
 Undeveloped Acres
 Gross Acres Net Acres
Years Ending December 31:   
202016,572
 14,803
202113,773
 12,685
202217,960
 16,039
After 202220,088
 18,975
Held by production or operations74,511
 64,272
Total142,904
 126,774

Oil, Natural Gas and NGL Reserves
The tables below set forth information as of December 31, 2019, with respect to our estimated proved reserves, the associated estimated future net revenue, the PV-10 and the standardized measure of discounted future net cash flows (“standardized measure”). None of the estimated future net revenue, PV-10 nor the standardized measure are intended to represent the current market value of the estimated oil, natural gas and NGL reserves we own. All of our estimated reserves are located within the United States.
 December 31, 2019
 Oil
(MMbbl)		 
Natural
Gas
(Bcf)
 NGL (MMbbl) Total (Bcfe)
Proved developed8
 1,757
 30
 1,984
Proved undeveloped10
 2,291
 32
 2,544
Total proved(1)
18
 4,048
 62
 4,528

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 Proved Developed Proved Undeveloped Total Proved
 ($ in millions)
Estimated future net revenue(2)
$2,086
 $1,461
 $3,547
Present value of estimated future net revenue (PV-10)(2)
$1,383
 $320
 $1,704
Standardized measure(2)
    $1,704
_____________________
(1)Utica and SCOOP accounted for approximately 71% and 29%, respectively, of our estimated proved reserves by volume as of December 31, 2019.
(2)Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2019, and assuming commodity prices as set forth below. For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2019. The prices used in our PV-10 measure were $55.85 per barrel and $2.58 per MMBtu, before basis differential adjustments. These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2019. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization. The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense. There was no effect of estimated future income tax expense as of December 31, 2019, primarily as a result of significant net operating loss carryforwards that can be used to offset income taxes on future taxable income.
Management uses PV-10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consistent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP.
A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented above. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves.
 _____________________
Grizzly had no proved reserves as of December 31, 2019. For further discussion of our interest in Grizzly, see “Our Equity Investments” below.
Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A. “Risk Factors” contained elsewhere in this Form 10-K. We have not filed any estimates of total, proved net oil or gas reserves with any federal authority or agency other than the SEC since the beginning of our last fiscal year.
Changes in Proved Reserves during 2019.
The following table summarizes the changes in our estimated proved reserves during 2019 (in Bcfe):

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Proved Reserves, December 31, 20184,743
   Sales of oil and natural gas reserves in place(77)
   Extensions and discoveries1,097
   Revisions of prior reserve estimates(734)
   Current production(502)
Proved Reserves, December 31, 20194,528
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 2019, we sold approximately 76.8 Bcfe of proved oil and natural gas reserves through various sales of our Southern Louisiana assets, non-operated interests in our Utica assets and overriding royalty interests in North Dakota.
Extensions and discoveries. These are additions to our proved reserves that result from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery. Extensions of approximately 1.1 Tcfe of proved reserves were primarily attributable to the continued development of our Utica Shale and SCOOP acreage. We added 72 drilling locations in our Utica acreage for 793.5 Bcfe and 37 drilling locations in our SCOOP acreage for 302.9 Bcfe. 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 total downward revisions of 733.8 Bcfe in estimated proved reserves, of which 347.2 Bcfe was a result of the exclusion of nine PUD locations in our Utica field and 22 PUD locations in our SCOOP field when changes in our schedule moved development of these PUD locations beyond five years of initial booking. The development plan change reflects our commitment to capital discipline and funding future activities within cash flow.
An additional 296.4 Bcfe in downward revisions was the result of commodity price changes. Commodity prices experienced volatility throughout 2019 and the 12-month average price for natural gas decreased from $3.10 per MMBtu for 2018 to $2.58 per MMBtu for 2019, the 12-month average price for NGL decreased from $32.02 per barrel for 2018 to $21.25 per barrel for 2019, and the 12-month average price for crude oil decreased from $65.56 per barrel for 2018 to $55.85 per barrel for 2019.
We also experienced downward revisions of 90.2 Bcfe from a combination of working interest changes, optimization of our well design in the current commodity price environment and well performance.
Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2019, 2018 and 2017 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 of the notes to our consolidated financial statements included in this report.
Proved Undeveloped Reserves (PUDs)
As of December 31, 2019, our proved undeveloped reserves totaled 10 MMbbl of oil, 2,291 Bcf of natural gas and 32 MMbbl of NGL, for a total of 2,544 Bcfe. Approximately 70% and 30% of our PUD reserves at year-end 2019 were located in Utica and SCOOP, 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.

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The following table summarizes the changes in our estimated proved undeveloped reserves during 2019 (in Bcfe):
Proved Undeveloped Reserves, December 31, 20182,628
   Sales of oil and natural gas reserves in place(69)
   Extensions and discoveries1,078
   Conversion to proved developed reserves(654)
   Revisions of prior reserve estimates(439)
Proved Undeveloped Reserves, December 31, 20192,544
Sales of oil and natural gas reserves in place. During 2019, we sold approximately 68.8 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 of approximately 1.1 Tcfe were primarily attributed to the addition of 72 PUD drilling locations in the Utica field and 37 PUD drilling 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. Our 2019 development activities resulted in the conversion of approximately 654.0 Bcfe into proved developed producing reserves, attributable to 49 PUD locations in the Utica field and 12 PUD locations in the SCOOP field. These 61 PUDs represent a conversion rate of 20% for 2019.
Revision of prior reserve estimates. We experienced proved undeveloped downward revisions of 347.2 Bcfe from the exclusion of 9 PUD locations in our Utica field and 22 PUD locations in our SCOOP field due to the SEC five-year development rule. The development plan change, as approved by our senior management and Board of Directors, reflects our commitment to capital discipline and funding future activities within cash flow. We also experienced 146.8 Bcfe of downward revisions as a result of commodity price changes. These downward revisions were partially offset by positive revisions of 54.8 Bcfe in estimated proved reserves from a combination of well performance, changes in ownership interest and development well design changes.
Costs incurred relating to the development of PUDs were approximately $353.1 million in 2019.
All PUD drilling locations included in our 2019 reserve report are scheduled to be drilled within five years of initial booking.
As of December 31, 2019, 1% of our total proved reserves were classified as proved developed non-producing.
Reserves Estimation
Reserve estimates at December 31, 2019 and December 31, 2018 were prepared by Netherland, Sewell & Associates, Inc. ("NSAI") for all of our operating areas. 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. 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.
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,

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commodity prices, operating and development costs and other considerations, including availability and costs of infrastructure and status of permits. 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 approximately 100 years combined industry experience and our reservoir staff has approximately 40 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, operating, marketing and capital 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.
PV-10 Sensitivities.
As noted above, our December 31, 2019 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 2019 of $55.85 per barrel and $2.58 per MMBtu. Holding production and development costs constant, if SEC pricing were $61.44 per barrel and $2.84 per MMBtu, or a 10% increase, this would have resulted in an increase of 69.6 Bcfe of our total proved reserves and a $0.7 billion increase in PV-10 value at December 31, 2019. Holding production and development costs constant, if SEC pricing were $50.27 per barrel and $2.32 per MMBtu, or a 10% decrease, this would have resulted in a decrease of 106.5 Bcfe of our total proved reserves and a $0.7 billion decrease in PV-10 value at December 31, 2019.
Production, Prices and Production Costs
The following table presents our production volumes in our core operating areas during the periods indicated:

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 Year Ended December 31,
Field2019
Net Production
Natural Gas (MMcf) Oil and Condensate (Mbbls) NGL (MGal) Natural gas equivalents (MMcfe) MMcfe per Day
Utica Shale387,473
 247
 76,112
 399,828
 1,095
SCOOP70,669
 1,610
 136,948
 99,891
 274
Niobrara Formation—
 14
 —
 86
 —
Bakken Formation35
 41
 67
 292
 1
Louisiana and Other1
 274
 2
 1,645
 5
Total458,178
 2,186
 213,129
 501,742
 1,375

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The following table presents our production volumes, average prices received and average production costs during the periods indicated:
 2019 2018 2017
 ($ In thousands)
Natural gas sales     
Natural gas production volumes (MMcf)458,178
 443,742
 350,061
      
Total natural gas sales$918,263
 $1,121,815
 $845,999
      
Natural gas sales without the impact of derivatives ($/Mcf)$2.00
 $2.53
 $2.42
Impact from settled derivatives ($/Mcf)$0.23
 $(0.04) $0.07
Average natural gas sales price, including settled derivatives
($/Mcf)
$2.23
 $2.49
 $2.49
      
Oil and condensate sales     
Oil and condensate production volumes (Mbbls)2,186
 2,801
 2,579
      
Total oil and condensate sales$117,937
 $177,793
 $124,568
      
Oil and condensate sales without the impact of derivatives ($/Bbl)$53.95
 $63.48
 $48.29
Impact from settled derivatives ($/Bbl)$1.86
 $(9.51) $1.59
Average oil and condensate sales price, including settled derivatives ($/Bbl)$55.81
 $53.97
 $49.88
      
NGL sales     
NGL production volumes (MGal)213,129
 251,720
 224,038
      
Total NGL sales$101,448
 $178,915
 $136,057
      
NGL sales without the impact of derivatives ($/Gal)$0.48
 $0.71
 $0.61
Impact from settled derivatives ($/Gal)$0.06
 $(0.05) $(0.03)
Average NGL sales price, including settled derivatives ($/Gal)$0.54
 $0.66
 $0.58
      
Natural gas, oil and condensate and NGL sales     
Natural gas equivalents (MMcfe)501,742
 496,505
 397,543
      
Total natural gas, oil and condensate and NGL sales$1,137,648
 $1,478,523
 $1,106,624
      
Natural gas, oil and condensate and NGL sales without the impact of derivatives ($/Mcfe)$2.27
 $2.98
 $2.78
Impact from settled derivatives ($/Mcfe)$0.24
 $(0.12) $0.07
Average natural gas, oil and condensate and NGL sales price, including settled derivatives ($/Mcfe)$2.51
 $2.86
 $2.85
      
Production Costs:     
Average production costs ($/Mcfe)$0.17
 $0.18
 $0.20
Average production taxes ($/Mcfe)$0.06
 $0.07
 $0.05
Average midstream gathering and processing ($/Mcfe)$0.58
 $0.58
 $0.63
Total production costs, midstream costs and production taxes ($/Mcfe)$0.81
  $0.83
  $0.88

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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, 2019:
 Year Ended December 31,
 2019 2018 2017
Utica Shale     
Net Production     
Natural gas (MMcf)387,473
 379,417
 309,450
Oil (Mbbls)247
 299
 473
NGL (Mgal)76,112
 113,379
 139,634
Total (MMcfe)399,828
 397,406
 332,238
Average Sales Price Without the Impact of Derivatives:     
Natural gas ($/Mcf)$1.99
 $2.50
 $2.38
Oil ($/Bbl)$51.11
 $60.22
 $44.26
NGL ($/Gal)$0.47
 $0.67
 $0.60
Average Production Costs ($/Mcfe)$0.14
 $0.14
 $0.15
 Year Ended December 31,
 2019 2018 2017 (1)
SCOOP     
Net Production     
Natural gas (MMcf)70,669
 64,258
 40,501
Oil (Mbbls)1,610
 1,710
 1,083
NGL (Mgal)136,948
 138,261
 84,283
Total (MMcfe)99,891
 94,268
 59,038
Average Sales Price Without the Impact of Derivatives:     
Natural gas ($/Mcf)$2.08
 $2.67
 $2.68
Oil ($/Bbl)$53.32
 $62.36
 $48.70
NGL ($/Gal)$0.48
 $0.75
 $0.62
Average Production Costs ($/Mcfe)$0.18
 $0.20
 $0.19
_____________________
(1)
We acquired our SCOOP assets through an acquisition completed on February 17, 2017. See Note 2 in the notes to our consolidated financial statements for additional discussion of this acquisition.
Our Equity Investments
Grizzly Oil Sands. We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. As of December 31, 2018,2019, 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,("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, inIn 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 startupfuture plans for the facility. Grizzly also owns the May River property comprising approximately 47,000 acres.acres prospective for oil sands development. 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 awaitingreceived final approval.approval in December 2019. If pursued, this project could begin production as early as 2023. 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,("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

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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,("LPG") into the oil sands area for use in Thermal applications by SAGD producers. We elected to cease funding capital calls in 2019, and we have no obligation to fund any of the projects Grizzly is pursuing. Failure to fund capital calls may lead to dilution of our equity ownership interest.
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 InvestmentsMammoth Energy. In connection with Mammoth Energy's initial public offering or IPO,("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, 2018,2019, we owned 9,829,548 shares, or approximately 21.9%21.8%, 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 saleSee Note 4 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 4notes to our consolidated financial statements included elsewhere in this report for additional information regarding these and our other equity investments.
Marketing
The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including securing and negotiating of commodity transactions, gathering, hauling, processing and transportation services, contract administration and nomination services for Gulfport’s interest and other interest owners in Gulfport-operated wells. In addition, there are a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including risk mitigation and satisfaction of our pipeline delivery commitments. These marketing activities often enhance the value of our production by aggregating volumes and allowing improved flexibility in relation to deal structure, size and counterparty exposure whether through intermediary markets or direct end markets.

Generally, natural gas and NGL production is sold to purchasers under both spot and term transactions. Oil production is sold under both spot and term transactions with the majority being shorter term in nature. We have entered into long-term gathering, processing and transportation contracts with various parties that require us to deliver fixed, determinable quantities of production over specified periods of time. Some contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. See Note 16 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our commitments.

Major Customers
For the year ended December 31, 2019, sales to Morgan Stanley Capital accounted for approximately 14% of our total natural gas, oil and NGL revenues, before the effects of hedging. For the year ended December 31, 2018, sales to BP Energy Company ("BP") and ECO-Energy accounted for approximately 17% and 10%, respectively, of our total natural gas, oil and NGL revenues, before the effects of hedging. For the year ended December 31, 2017, sales to BP accounted for approximately 40% of our total natural gas, oil and NGL revenues, before the effects of hedging.
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 onhave midstream and refiningfurther downstream operations and market petroleum and othera variety of hydrocarbon 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,renewable sources such as wind or solar energy in addition to 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 limitedTitle 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 ProductionProperties
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 affectingIt is customary in the oil and natural gas industry is under constantto make only a preliminary review for amendment or expansion. Some of these requirements carry substantial penalties for failuretitle to comply. The regulatory burden on theundeveloped 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 increasespractice. Certain of our cost of doing business and, consequently, affects our profitability.
We own interests in producing oil and natural gas properties locatedmay be subject to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in management's opinion, will 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 whichaggregate materially restrict 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.operations.
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 oilRegulation - Environment, Health and gas waste. It has until March 2019 to determine whether any revisions are necessary. Any such changes in the lawsSafety
Exploration and regulations could have a material adverse effect on our capital expendituresProduction, Environmental, Health 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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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 ActOccupational Laws and Regulations
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, tribal, state, and local level.laws and regulations. These typeslaws and regulations relate to matters that include, but are not limited to, the following:

reporting of regulation include requiringworkplace injuries and illnesses;
industrial hygiene monitoring;
worker protection and workplace safety;
approval or permits for theto drill and to conduct operations;
provision of financial assurances (such as bonds) covering drilling and well operations;
calculation and disbursement of wells,royalty payments and production taxes;
seismic operations and data;
location, drilling, bondscementing and reports concerning operations. The states and some counties and municipalities in which we operate also regulate one or more of the following:
the locationcasing of wells;
the well design and construction of pad and equipment;
construction and operations activities in sensitive areas, such as wetlands, coastal regions or areas that contain endangered or threatened species, their habitats, or sites of cultural significance;
method of drillingcompleting wells;
hydraulic fracturing;
water withdrawal;
well production and casing wells;operations, including processing and gathering systems;
the timingemergency response, contingency plans and spill prevention plans;
air emissions and fluid discharges;
climate change;
use, transportation, storage and disposal of construction or drilling activities, including seasonal wildlife closures;fluids and materials incidental to oil and gas operations;
the rates of production or “allowables”;
the surface useusage, maintenance, monitoring and the restoration of properties upon which wells are drilled;associated with well pads, pipelines, impoundments and access roads;
the plugging and abandoning of wells; and
noticetransportation of production.

Failure to comply with these laws and consultationregulations can lead to the imposition of remedial liabilities, fines, or criminal penalties or to injunctions limiting our operations in affected areas. Moreover, multiple environmental laws provide for citizen suits which allow environmental organizations to act in the place of the government and sue operators for alleged violations of environmental law. We consider the costs of environmental protection and of safety and health compliance to be necessary, manageable parts of our business. We have been able to plan for and comply with surface ownersenvironmental, safety and other third parties.health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. See the Risk Factors described in Item 1A of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters.
State laws regulate
Our operations are also subject to conservation regulations, including the regulation of the size and shape of drilling and spacing units or proration units, governing the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and natural gas properties. SomeIn the United States, some states allow the forced pooling or integration of tracts to facilitate exploration while otherexploration. Other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitizationleases which may be implemented by third partiesmake it more difficult to develop oil and may reduce our interest in the unitizedgas properties. In addition, federal and state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibitlimit the venting or flaring of natural

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gas, and state conservation laws impose certain requirements regarding the ratabilityratable purchase of production. These laws and regulations may limit the amountamounts of oil and natural gas we can produce

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from our wells or limitand the number of wells or the locations at which we can drill. Moreover, each

Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state generally imposes a production agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or severance tax with respectlocal legislation and regulation. Further restrictions of hydraulic fracturing could reduce the amount of natural gas, oil and NGL that we are ultimately able to the production and saleproduce in commercial quantities from our properties.

Certain of oil,our U.S. natural gas and natural gas liquids within its jurisdiction. States do notoil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, wellhead pricesamong other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or engagetribal members. The federal government has been particularly active in other similar direct regulation, but we cannot assure you that they will not do sorecent years in the future. The effect of such futureevaluating and, in some cases, promulgating new rules and regulations may be to limit the amounts ofregarding competitive lease bidding, venting and flaring, oil and natural gas that may be produced from our wells, negatively affect the economics ofmeasurement and royalty payment obligations for 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, variouslands. In addition, permitting activities on 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 rateslands are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation,frequent delays.

Delays in obtaining permits or an inability to obtain new permits or permit renewals could inhibit our ability to execute our drilling and production plans. Failure to comply with applicable regulations or permit requirements could result in revocation of our permits, inability to obtain new permits and the degreeimposition of regulatory oversightfines 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.penalties.
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.
OperationalOperating Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow outs,blow-outs, pipe failuresfailure, abnormally pressured formations and in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks, and the dischargeruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amountssuffer substantial losses due to injury or loss of life, severe damage to or destruction toof property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.

We maintain a control of well insurance policy with a $25 million single well limit and a $35 million multiple wells limit that insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $101 million comprehensive general liability umbrella insurance policy. In accordance with whataddition, we maintain a $10 million pollution liability insurance policy providing coverage for gradual pollution related risks and in excess of the general liability policy for sudden and accidental pollution risks. We provide workers' compensation insurance coverage to employees in all states in which we operate. While we believe to bethese policies are customary in the industry, practice, we maintain insurancethey do not provide complete coverage 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 damagepolicy limits scale to our oil and natural gas properties, operational control ofworking interest percentage in 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,situations. In addition, our insurance is subject to exclusions and limitations, and there is no assurancedoes not cover penalties or fines that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could causemay be assessed by a significant disruption to our business.governmental authority. 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 Our 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 ablesufficient to secure additional insurancecover every claim made against us or bonding that mightmay not 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.commercially available for purchase in the future.
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 each of 2019 and 2018 and 2017 were approximately $0.6 million and $0.2 million.immaterial. 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 coordinateWe pay these companies a retainer plus additional amounts when they provide us 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 Rightclean up services.



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Index 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.Financial Statements
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, 2018,2019, we had 350298 employees.
Availability of Company ReportsExecutive Officers
Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-KDavid M. Wood, Chief Executive Officer, President and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d)Director
David M. Wood, 62,has served as the Chief Executive Officer and President of the Exchange Act are made available freeCompany, and as a member of chargeour board of directors, since December 2018. Prior to joining the Company, Mr. Wood served as the Chief Executive Officer and Chairman of the Board of Directors of Arsenal Resources LLC, which we refer to as Arsenal, a West Virginia focused natural gas producer and portfolio company of First Reserve Corporation ("First Reserve"), an energy-focused private equity firm, where he most recently served as Chairman of its board of directors and previously held the role of the Chief Executive Officer. Prior to his tenure at Arsenal, Mr. Wood served as a Senior Advisor to First Reserve from 2013 to 2016, serving on several of its portfolio company boards. Prior to his position at First Reserve, Mr. Wood spent more than 17 years at Murphy Oil Corporation (NYSE: MUR) ("Murphy Oil"), a global oil and natural gas exploration and production company, where he served as Chief Executive Officer, President and a member of the board of directors from 2009 to 2012. From 1980 to 1994, Mr. Wood held various senior positions with Ashland Exploration and Production, an oil and natural gas exploration and production company. Mr. Wood began his career as a well-site geologist in Saudi Arabia. Mr. Wood has served on the board of directors of Lilis Energy, Inc. (NYSE: LLEX), an exploration and development company operating in the Delaware Basin since June 2018. Mr. Wood also served on the board of directors of the general partner of Crestwood Equity Partners LP (NYSE: CEQP) and its wholly-owned subsidiary, Crestwood Midstream Partners LP, an owner and operator of crude oil and natural gas midstream assets. Mr. Wood also served on the board of directors of several private oil and natural gas companies, including Deep Gulf Energy LP (prior to its acquisition by Kosmos Energy Ltd.) and Berkana Energy Corp. (when it was majority owned by Murphy Oil). Mr. Wood previously served on the board of directors and as an executive committee member of the American Petroleum Institute. He was also a member of the National Petroleum Council and is a member of the Society of Exploration Geophysicists. Mr. Wood holds a B.S. in Geology from the University of Nottingham in England and completed Harvard University’s Advanced Management Program.
Quentin R. Hicks, Executive Vice President and Chief Financial Officer
Quentin R. Hicks, 45,has served as the Executive Vice President and Chief Financial Officer of the Company since August 2019. Prior to joining the Company, Mr. Hicks served as the Executive Vice President and Chief Financial Officer of Halcón Resources Corporation (“Halcón”), a position he held since March 2019, having previously served as Executive Vice President, Finance, Capital Markets and Investor Relations page of Halcón since January 2018. Prior to that, Mr. Hicks held various roles at Halcón focused primarily on finance and investor relations. Prior to Halcón, Mr. Hicks worked for GeoResources Inc., where he served as Director of Acquisitions and Financial Planning from 2011 to 2012. From 2004 to 2011, he worked in investment banking with Bear Stearns, Sanders Morris Harris and Madison Williams, where he was a Director in their energy investment banking practice. Prior to that, Mr. Hicks worked as Manager of Financial Reporting for Continental Airlines. Mr. Hicks began his career in 1998 working as an auditor for Ernst and Young LLP. Mr. Hicks graduated from Texas A&M University with a Bachelor of Business Administration and a Master of Science degree in Accounting. In addition, Mr. Hicks holds a Master of Business Administration degree in Finance from Vanderbilt University and also holds a Certified Public Accountant license from the State of Texas.
Donnie G. Moore, Executive Vice President and Chief Operating Officer
Donnie G. Moore, 55, has served as Executive Vice President and Chief Operating Officer of the Company since January 2018. He also served as Interim Chief Executive Officer of the Company from October 29, 2018, the date our websiteformer Chief Executive Officer and President left the Company, to December 18, 2018, the date of the appointment of Mr. Wood as our new Chief Executive Officer and President. From 2007 until December 2017, Mr. Moore worked at www.gulfportenergy.comNoble Energy, Inc. ("Noble"), where he most recently served as soonVice President of Noble’s Texas operations for its Eagle Ford and Delaware Basin assets. Prior to that, Mr. Moore held various leadership roles at Noble including Vice President of the Marcellus Business Unit, Manager for Operations of the Wattenberg/DJ Business Unit, Manager of Operations for the Gunflint discovery in the Deepwater Gulf of Mexico and Development Manager for Noble’s Mid-Continent and Gulf Coast positions. From 1989 until 2007, Mr. Moore served in a variety of roles with ARCO Oil and Gas Company, Vastar Resources, Inc. and BP America. Mr. Moore holds a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University.


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Patrick K. Craine, Executive Vice President, General Counsel and Corporate Secretary
Patrick K. Craine, 47, has served as reasonably practicable after such material is electronically filedExecutive Vice President, General Counsel and Corporate Secretary of the Company since May 2019. Mr. Craine has over 20 years of extensive senior-level experience handling a broad range of securities, corporate, regulatory, governance, compliance and litigation matters, with or furnishedparticular expertise in the energy industry.  He joined Gulfport from Chesapeake Energy Corporation (NYSE: CHK) ("Chesapeake"), where he served as Deputy General Counsel – Chief Risk and Compliance Officer from 2013 until 2019.  Prior to the SEC. Information containedjoining Chesapeake, Mr. Craine was a partner with Bracewell LLP, a global law firm, where his practice focused 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-Ksecurities and should not be considered part of this report or any other filing that we makecorporate regulatory matters and investigations.  Before Mr. Craine entered private practice, he served as a lawyer with the SEC.U.S. Securities and Exchange Commission and the Financial Industry Regulatory Authority where he held leadership positions in their Oil and Gas Task Forces.
Michael J. Sluiter, Senior Vice President of Reservoir Engineering
Michael J. Sluiter, 47, has served as Senior Vice President of Reservoir Engineering of the Company since December 2018. Mr. Sluiter joined the Company from Noble Energy, Inc., where he held various engineering and leadership positions from March 2007 to November 2018, including, most recently, the Permian Basin Business Unit Manager.  Prior to, Noble Mr. Sluiter worked for Santos Australia and Santos USA from February 2000 to March 2007, and started his career as a wireline field services engineer for Schlumberger in Thailand. He has over 18 years combined of experience in unconventional resource development, reservoir engineering, subsurface development, business development and acquisitions.  Mr. Sluiter holds a Bachelor of Science degree in Chemical Engineering from the University of Sydney, Australia.
ITEM 1A.RISK FACTORS
Risks RelatedThere are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future results to differ materially from those currently expected. The risks described below are not the only risks facing our Businesscompany. Additional risks and Industryuncertainties not presently known to us or that we currently deem immaterial may also affect our business operations. If any of these risks actually occur, our business, financial position, operating results, cash flows, reserves or our ability to pay our debts and other liabilities could suffer, the trading price and liquidity of our securities could decline and you may lose all or part of your investment in our securities. 
Market conditions for
Natural gas, oil and natural gas,NGL prices fluctuate widely, and volatility inlower prices for oil and natural gas,an extended period of time are likely to have in the past adversely affected, and may continue in the future to adversely affect,a material adverse effect on our revenue, cash flows, profitability, growth, production and the present value of our estimated reserves.business.
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 NGL. We incur substantial expenditures to replace reserves, sustain production and fund our business plans. Low oil, natural gas and NGL prices can negatively affect the amount of cash available for capital expenditures, debt service and debt repayment and our ability to borrow money or raise additional capital and, as a result, could have a material adverse effect on our financial condition, results of operations, cash flows and reserves. In addition, periods of low natural gas, oil and NGL prices may result in ceiling test write-downs of our oil and natural gas pricesproperties.
Historically, the markets for natural gas, oil and NGL have been volatile, and they are subjectlikely to continue to be volatile. For example, during 2018, West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or 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. During 2019, WTI prices ranged from $46.31 to $66.24 per barrel and the Henry Hub spot market price of natural gas ranged from $1.75 to $4.25 per MMBtu. As of February 14, 2020, the WTI price was $52.03 per barrel and the Henry Hub spot market price of natural gas was $1.93 per MMBtu.
Wide fluctuations in response to changes in supplynatural gas, oil and demand, market uncertainty and a variety of additionalNGL prices may result from factors that are beyond our control, including:
domestic and worldwide supplies of oil, natural gas and domestic suppliesNGL, including U.S. inventories of oil and natural gas;

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gas reserves;
the level of prices, and expectations about future prices, of oil and natural gas;
changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns, such as the recent coronavirus;

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the cost of exploring for, developing, producing and delivering oil and natural gas;
the expected rates of declining current production;
changes in the level of consumer and industrial demand;
the price and availability of alternative fuels;
technicaltechnological advances affecting energy consumption;
risks associated with operating drilling rigs;
the effectiveness of worldwide conservation measures;
the availability, proximity and capacity of pipeline capacity andpipelines, other transportation facilities and processing facilities;
the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
U.S. exports of oil, natural gas, liquefied natural gas and NGL;
the price and level of foreign imports;
the nature and extent of 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 weather conditions;
acts of terrorism; and
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.conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and natural gasNGL 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 barrelAs of February 27, 2020, including January and the Henry Hub spot market priceFebruary derivative contracts that have settled, approximately 50% of our forecasted 2020 natural gas, ranged from $2.44 to $3.71 per MMBtu. During 2018, WTI prices ranged from $44.48 to $77.41 per barreloil and the Henry Hub spot market priceNGL production revenue was hedged, including 52% and 80% of our forecasted 2020 natural gas ranged from $2.49 to $6.24 per MMBtu. If theand oil production, at average prices of $2.86 per Mcf and $59.82 per Bbl, respectively. Even with natural gas, oil and natural gas decline, our operations, financial condition and level of expenditures for the developmentNGL derivatives currently in place to mitigate price risks associated with a portion of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and2020 cash flows, we have substantial exposure to natural gas prices, mayand to a lesser extent, oil and NGL prices, in 2021 and beyond. In addition, a prolonged extension of lower prices could reduce the amountquantities of oil and natural gasreserves that we can produce economically.may economically produce. 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
We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects.
As of December 31, 2019, we had approximately $2.0 billion in principal amount of debt outstanding, primarily attributable to our senior notes. We also had $120.0 million in borrowings outstanding under our revolving credit facility and our borrowing base availability was $636.4 million after giving effect to an aggregate of $243.6 million of letters of credit.
Our outstanding indebtedness could have important consequences to you, including the following:
our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations under any of our debt instruments, including their restrictive covenants,

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could result in a default under our revolving credit facility or the indentures governing our senior notes;
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 reservesbusiness 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 revolving credit facility are at variable interest rates.
Any of the foregoing could also negatively impact thehave a material adverse effect on our business, financial condition, results of operations and prospects.
Our ability to pay our expenses and fund our working capital needs and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as commodity prices, other economic conditions and governmental regulation. If our borrowing base under our revolving credit facility which could limitdecreases as a result of lower prices of natural gas, oil or NGL, operating difficulties, declines in reserves or for any other reason, our liquidity and ability to conduct additional exploration and development activities.
Strategic determinations,activities may be limited. To the extent that the value of the collateral pledged under our revolving credit facility declines as a result of lower oil and natural gas prices, asset dispositions or otherwise, we may be required to pledge additional collateral to maintain the current availability of the commitments thereunder, and we cannot assure you that we will be able to maintain a sufficiently high valuation to maintain the current borrowing base. 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 allocationinstruments governing our indebtedness, we could be in default under the terms of capitalthe 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 other resourcespayable, together with accrued and unpaid interest. More specifically, the lenders under our revolving credit facility could elect to strategic opportunities, are challenging,terminate their commitments, cease making further loans and institute foreclosure proceedings against our failure to appropriately allocate capitalassets, and resources among our strategic opportunities maywe could be forced into bankruptcy or litigation. Any of the above risks could materially adversely affect our business, financial condition, cash flows and reduce our future growth rate.results of operations.
Our future growth prospects are dependent uponWe have significant capital needs, and our ability to identify optimal strategies for our business. In developing our 2019 business plan, we considered allocatingaccess the capital and other resourcescredit markets to various aspects ofraise capital on favorable terms is limited by our businesses, including well development, reserve acquisitions, midstream infrastructuredebt level and other activities. We also considered our likely sources of capital. Notwithstanding the determinations madeindustry conditions.
Disruptions in the development of our 2019 plan, business opportunities not previously identified periodically comecapital and credit markets, in particular with respect 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

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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 mayenergy sector, could limit our ability to achieveaccess these markets or may significantly increase our objectives.
We periodically engage in acquisitions, dispositionscost to borrow. Low commodity prices have caused and other strategic transactions, including equity investmentsmay continue to cause lenders to increase the interest rates under our revolving credit facility, enact tighter lending standards, refuse to refinance existing debt around maturity on favorable terms or at all and joint ventures such asreduce or cease to provide funding to borrowers. If we are unable to access the capital and credit markets on favorable terms, it could have a material adverse effect on 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 timingbusiness, financial condition, results of operations, cash flows and conditions that may be imposed on us by regulatorsliquidity and our ability to achieve benefits anticipatedrepay or refinance our debt. Additionally, challenges in the economy have led and could further lead to reductions in the demand for natural gas, oil and NGL, or further reductions in the prices of natural gas, oil and NGL, which could have a negative impact on our financial position, results of operations and cash flows.
If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to refinance our indebtedness or fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.

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Our earnings and cash flow could vary significantly from year to year due to the volatility of hydrocarbon commodity prices. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments or to make necessary capital expenditures. A range of economic, competitive, business and industry factors will affect our future financial performance and, as a result, our ability to generate cash flow from operations and service our debt. Factors that may cause us to generate cash flow that is insufficient to meet our debt obligations include the transactions.events and risks related to our business, many of which are beyond our control. Any cash flow insufficiency would have a material adverse impact on our business, financial condition, results of operations, cash flows and liquidity and our ability to repay or refinance our debt.
If we do not generate sufficient cash flow from operations to service our outstanding indebtedness, or if future borrowings are not available to us in an amount sufficient to enable us to pay or refinance our indebtedness, we may be required to undertake various alternative financing plans, which may include:
•refinancing or restructuring all or a portion of our debt;
•seeking alternative financing or additional capital investment;
•selling strategic assets;
•reducing or delaying capital investments; or
•revising or delaying our strategic plans.
We cannot assure you that we would be able to implement any alternative financing plans, if necessary, on commercially reasonable terms or at all,or that any such alternative financing plans would allow us to meet our debt obligations. If we are unable to generate sufficient cash flow to satisfy our debt obligations or to obtain necessary and sufficient alternative financing, our business, financial condition, results of operations, cash flows and liquidity could be materially and adversely affected. Any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could significantly harm our ability to incur additional indebtedness on acceptable terms. Further, if for any reason we are unable to meet our equity investmentsdebt service and joint venture arrangements mayrepayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our revolving credit facility could terminate their commitments to extend credit, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. In addition, our revolving credit facility and the indentures governing our senior notes restrict our operational and corporate flexibility and subject usability to risks and uncertainties, such as committing us to fund operating and/or capital expenditures,use the timing and amount of which weproceeds from asset sales. We may not be able to control. Further,consummate those asset sales to raise capital or sell assets at prices that we believe are fair. If the counterpartiesamounts outstanding under our revolving credit facility or any of our other significant indebtedness were to these transactionsbe accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to the lenders or to our other debt holders. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.
Restrictive covenants in our revolving credit facility and the indentures governing our senior notes could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.
Our revolving credit facility and the indentures governing our senior notes impose operating and financial restrictions on us. These restrictions limit our ability and that of our restricted subsidiaries to, among other things
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;

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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. The restrictions contained in the covenants could:
limit our ability to plan for, or react to, market conditions, to meet capital needs or otherwise to restrict our activities or business plan;
adversely affect our ability to finance our operations, enter into acquisitions or divestitures to engage in other business activities that would be in our interest; or
withstand a continuing future downturn in our business.
Also, our revolving credit facility requires us to maintain compliance with specified financial ratios and satisfy theircertain financial condition tests. Specifically, our revolving credit facility requires us to maintain a ratio of net funded debt to EBITDAX at the end of each fiscal quarter for a twelve-month period of not greater than 4.00 to 1.00, and a ratio of EBITDAX to interest expense at the end of each fiscal quarter for a twelve-month period of not less than 3.00 to 1.00. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control and, as a result, we may be unable to meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a continued downturn in our business or a downturn in the economy in general or otherwise conduct necessary corporate activities. Further declines in natural gas, oil and NGL prices, or a prolonged period of low natural gas, oil and NGL prices could eventually result in our failing to meet one or more of the financial covenants under our revolving credit facility, which could require us to refinance or amend such obligations resulting in the payment of consent fees or higher interest rates, or require us to raise additional capital at an inopportune time or on terms not favorable to us.
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 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.
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.
Any significant reduction in our borrowing base under our revolving credit facility as a result of periodic borrowing base

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redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.
Availability under our revolving credit facility is currently subject to a borrowing base of $1.2 billion, with an elected commitment of $1.0 billion. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on our oil and natural gas reserves and other factors. As of December 31, 2019, we had $120.0 million in borrowings and $243.6 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 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 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, 2019, our borrowing base under our revolving credit facility was set at $1.2 billion, with an elected commitment of $1.0 billion, and we had $120.0 million in borrowings under this facility. Total funds available for borrowing under our revolving credit facility as of December 31, 2019, after giving effect to $243.6 million of outstanding letters of credit, were $636.4 million. In addition, the indentures governing our 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. If new debt or other liabilities are added to our current debt levels, the related risks that we now face could intensify.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase.
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 such, our interest expense is sensitive to fluctuations in the joint venture. Our inability to complete a transaction or to achieveLondon Interbank Offered Rate. At December 31, 2019, amounts borrowed under our strategic or financial goalsrevolving credit facility bore interest at the weighted average rate of 3.30%. A 1% increase in any transaction couldthe average interest rate would have significant adverse effectsincreased our interest expense by approximately $1.2 million based on outstanding borrowings under our earnings, cash flows and financial position.
Concerns over general economic, business or industry conditionsrevolving credit facility throughout the year ended December 31, 2019. 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 liquidity and financial condition. As of December 31, 2019, we did not hedge our interest rate risk.
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 hostilitiesChanges in the Middle East andmethod of determining the occurrenceLondon Interbank Offered Rate, or threatthe replacement of terrorist attacksthe London Interbank Offered Rate with an alternative reference rate, may adversely affect interest expense related to outstanding debt.
Amounts drawn under our revolving credit facility may bear interest at rates based on the London Interbank Offered Rate (“LIBOR”). On July 27, 2017, the Financial Conduct Authority in the United StatesKingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. Our revolving credit facility provides for a mechanism to amend the facility to reflect the establishment of an alternative rate of interest upon the occurrence of certain events related to the phase-out of LIBOR. However, we have not yet pursued any technical amendment or other countriescontractual alternative to address this matter and are currently evaluating the impact of the potential replacement of the LIBOR interest rate. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could adversely affect the global economy. These factors, combined with volatilityhave a material adverse effect on our financial condition, results of operations and cash flows.

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Under our method of accounting for oil and natural gas properties, declines in commodity prices businessmay result in impairment of asset value.
We use the full cost method of accounting for oil and consumer confidencenatural gas operations. Accordingly, all costs, including nonproductive costs and unemployment rates, havecertain 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 proved 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 unweighted arithmetic average of the closing prices on the first day of each month for the 12-month period ending at the balance sheet date, 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 past precipitated,cost being amortized, less income tax effects related to differences between the book and maytax 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 the future precipitate, an economic slowdown. Concerns about global economic growth could have a significant adverse impact on global financial marketsloss 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.prices, we recorded a ceiling test impairment of $2.0 billion for the year ended December 31, 2019. If prices of natural gas, oil and natural gas liquids continue to decrease, we will be required to further write down 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 abilityvalue of our vendors, suppliersoil and customers to continue operations and ultimately adversely impactnatural gas properties. Future non-cash asset impairments could negatively affect our results of operations, liquidity and financial condition.operations.
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 explorationdrilling and productioncompletions capital expenditures for 20192020 to be in the range of $525.0$265 million to $550.0$285 million and an additional $40.0$20 million to $50.0$25 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 otherrevolving credit facilities.facility. 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 20192020 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we


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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.
If we are not able to replace reserves, we may not be able to sustain production.
Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. Thus, our future oil and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.
The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
The estimates of our proved reserves and the estimated future net revenues from our proved reserves included in this report are based upon various assumptions, including assumptions required by the SEC relating to natural gas, oil and NGL prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating natural gas, oil and NGL reserves is complex and involves significant decisions and assumptions associated with geological, geophysical, engineering and economic data for each well. Therefore, these estimates are subject to future revisions.
Actual future production, natural gas, oil and NGL prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas, oil and NGL reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities and present value of our proved reserves. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
As of December 31, 2019, approximately 56.2% of our total estimated proved reserves were proved undeveloped reserves ("PUDs") and may not be ultimately developed or produced. Recovery of PUDs 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.  You should be aware that the estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not 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. If we choose not to develop our PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove them from our reported proved reserves. In addition, under the SEC's reserve reporting rules, because PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, we may be required to remove any PUDs that are not developed within this five-year time frame.
You should not assume that the present values included in this report represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of our present values are based on prices and costs as of the date of the estimates. The price on the date of estimate is calculated as the average natural gas and oil price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. The December 31, 2019 present value is based on a $2.58 per MMBtu of gas price and a $55.85 per Bbl of oil price, before considering basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
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;

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•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 the production and the expenses from the development and production of oil and natural gas properties will affect both the timing of future net cash flows from our proved reserves and their present value. Any changes in demand for oil and natural gas, governmental regulations or taxation will also affect the future net cash flows from our production. In addition, the 10% discount factor that is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. 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 acquire significant amounts of unproven properties 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 initial investments. Additionally, there can be no assurance that undeveloped properties acquired 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 undeveloped properties 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 and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, and a decline in commodity prices, among others. The profitability of wells, particularly in certain of the areas in which we operate, will be reduced or eliminated if commodity prices decline. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and future market prices for natural gas, oil and NGL, costs associated with producing natural gas, oil and NGL 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. All costs of development and exploratory drilling activities are capitalized under the full cost method, even if the activities do not result in commercially productive discoveries, which may result in a future impairment of our oil and natural gas properties if commodity prices decrease.
We rely to a significant extent on seismic data and other technologies in evaluating undeveloped properties and in conducting our exploration activities. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of undeveloped properties, or drilling a well, whether oil or natural gas is present or may be produced economically. If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.
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.

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As of December 31, 2019, we had entered into firm transportation contracts to deliver approximately 1,205,000 MMBtu to 1,505,000 MMBtu per day for 2020 and 2021. 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.
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 development activities we employ, such as offset drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of offset drilling, adjacent 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, such as our SCOOP play in Oklahoma. The area was historically developed by vertical wells drilled through multiple stacked reservoirs and recent development has focused on the Woodford formation; however, development in the Sycamore and Springer formations has been limited. As emerging formations, our drilling results in this area are more uncertain than drilling results in areas that are more developed and have been producing for a longer period of time. Since limited production history from horizontal wells in the SCOOP Sycamore and Springer formations exists over our acreage position, it is difficult to predict our future drilling results.
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, 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.
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

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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.
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.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established. 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. Approximately 20% of our Utica Shale undeveloped acreage that is subject to expiration will be subject to expiration in 2020, with 17% of such acreage expiring in 2021, 22% in 2022 and 41% thereafter, although our Utica Shale leases generally grant us the right to extend these leases for an additional five-year period. Although 97% of our SCOOP acreage is held by existing production from both vertical and horizontal wells, the remaining acreage is subject to expiration. Of the remaining 3% of our SCOOP acreage not held by production, 59% will be be subject to expiration in 2020, 17% in 2021, 7% in 2022 and 17% thereafter. During the year ended December 31, 2019, leases representing 66% of our total Niobrara Formation undeveloped acreage as of December 31, 2018 expired due to failure to establish production. Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties. 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.
Our commodity price risk management activities may limit the benefit we would receive from increases in commodity prices, may require us to provide collateral for derivative liabilities and involve risk that our counterparties may be unable to satisfy their obligations to us.
To manage our exposure to price volatility, we enter into natural gas, oil and NGL price derivative contracts. Our natural gas, oil and NGL derivative arrangements may limit the benefit we would receive from increases in commodity prices. The fair value of our natural gas, oil and NGL derivative instruments can fluctuate significantly between periods. Our decision to mitigate cash flow volatility through derivative arrangements, if any, is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to enter into derivatives if the pricing environment for certain time periods is not deemed to be favorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program.
Natural gas, oil and NGL derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, the value of our commodity derivative asset positions increase, which increases our counterparty exposure. Although the counterparties to our hedging arrangements are required to secure their obligations to us under certain scenarios, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have an adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future cash flows being exposed to commodity price changes.
The ultimate outcome of pending legal and governmental proceedings is uncertain, and there are significant costs associated with these matters.
We are defending against claims by royalty owners alleging, among other things, that we underpaid royalty owners. The resolution of disputes regarding past payments could cause our future obligations to royalty owners to increase and would negatively impact our future results of operations.
In addition, there is an ongoing SEC investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former management and the Company of the Sarbanes-Oxley Act of 2002. The outcome of any pending or future litigation or governmental regulatory matter is uncertain and may

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adversely affect our results of operations. In addition, we have incurred substantial legal expenses in the past three years, and such expenses may continue to be significant in the future. Further, attention to these matters by members of our senior management has been required, reducing the time they have available to devote to managing our business.
Oil and natural gas operations are uncertain and involve substantial costs and risks. Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.
Our oil and natural gas operating activities are subject to numerous costs and risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. Drilling for oil, natural gas and NGL can be unprofitable, not only from dry holes, but from productive wells that do not return a profit because of insufficient revenue from production or high costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are common risks that can make a particular project uneconomic or less economic than forecasted. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. For the 16% of our daily production volumes from properties which we did not serve as operator as of December 31, 2019, we are dependent on the operator for operational and regulatory compliance. In addition, our oil and gas properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to:
unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;
loss of drilling fluid circulation;
equipment failures or accidents;
fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals;
risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives;
adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures;
issues with title or in receiving governmental permits or approvals;
restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets;
environmental hazards or liabilities, including liabilities for environmental damage caused by previous owners of properties purchased by us;
restrictions in access to, or disposal of, water used or produced in drilling and completion operations;
shortages or delays in the availability of services or delivery of equipment; and
unexpected or unforeseen changes in regulatory policy, and political or public opinions.
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities.
While we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. For certain risks, such as political risk, business interruption, war, terrorism and piracy, we have limited or no insurance coverage. Also, in the future we may not be able to obtain insurance at premium levels that 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

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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.
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;
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.
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 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 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 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.
We are subject to extensive governmental regulation and ongoing regulatory changes, which could adversely impact our business.
Our operations are subject to extensive federal, state, tribal, local and other laws, rules and regulations, including with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and transportation of oil, gas and NGL, conservation policies, reporting obligations, royalty payments, unclaimed property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling, completion and well operations. If permits are not issued, or if unfavorable restrictions or conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. In addition, we may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or

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orders.
In addition, changes in public policy have affected, and in the future could further affect, our operations. Regulatory changes could, among other things, restrict production levels, impose price controls, alter environmental protection requirements and increase taxes, royalties and other amounts payable to the government. Our operating and compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. We do not expect that any of these laws and regulations will affect our operations materially differently than they would affect other companies with similar operations, size and financial strength. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity. As is discussed below this is particularly true of changes related to pipeline safety, seismic activity, hydraulic fracturing, climate change and endangered species designations.
Pipeline Safety. The pipeline assets owned by our midstream service providers are subject to stringent and complex regulations related to pipeline safety and integrity management. The Pipeline and Hazardous Materials Safety Administration (PHMSA) has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Additional action by PHMSA with respect to pipeline integrity management requirements may occur in the future. In July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. PHMSA has not yet issued the final rule. In October 2019, three final rules making up the “Gas Mega Rule” - one establishing procedures to implement the expanded emergency order enforcement authority; the second, concerning gas transmission, extending the requirement to conduct integrity assessments beyond HCAs to pipelines in Moderate Consequence Areas (“MCAs”); and the third, concerning hazardous liquids, extending the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines and updating reporting and inspection requirements - were finalized. The cost of these requirements or other potential new or amended regulations could be significant, and any such costs incurred by our midstream service providers could result in increased midstream gathering and processing expenses for us. Moreover, violations of pipeline safety regulations by our midstream service providers could result in the imposition of significant penalties which may impact the cost or availability of pipeline capacity necessary for our operations.
Seismic Activity. Earthquakes in some of our operating areas and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. For example, the Oklahoma Corporation Commission (OCC) issued guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing or water disposal activities. Legislative and regulatory initiatives intended to address these concerns may result in additional levels of regulation or other requirements that could lead to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In addition, we could be subject to third-party lawsuits seeking damages or other remedies as a result of alleged induced seismic activity in our areas of operation.
Hydraulic Fracturing. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations. Three states (New York, Maryland and Vermont) have banned the use of high-volume hydraulic fracturing. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. There have also been certain governmental reviews that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. Governments may continue to study hydraulic fracturing. We cannot predict the outcome of future studies, but based on the results of these studies to date, federal and state legislatures and agencies may seek to further regulate or even ban hydraulic fracturing activities. In addition, if existing laws and regulations with regard to hydraulic fracturing are revised or reinterpreted or if new laws and regulations become applicable to our operations through judicial or administrative actions, our business, financial condition, results of operations and cash flows could be adversely affected. A decision is pending.
We cannot predict whether additional federal, state or local laws or regulations applicable to hydraulic fracturing will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed on hydraulic fracturing operations, our business and operations could be subject to delays, increased operating and compliance costs and potential bans. Additional regulation could also lead to greater opposition to hydraulic fracturing, including litigation.
Climate Change. Continuing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers at both the U.S.

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federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases through inventories, limitations or taxes on greenhouse gas emissions. Several states where we operate have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of cap and trade or carbon tax programs. Cap and trade programs offer greenhouse gas emission allowances that are gradually reduced over time. A cap and trade program could impose direct costs on us through the purchase of allowances and could impose indirect costs by incentivizing consumers to shift away from fossil fuels. A carbon tax could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.
In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities.
These various legislative, regulatory and other activities addressing greenhouse gas emissions could adversely affect our business, including by imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations, which could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Limitations on greenhouse gas emissions could also adversely affect demand for oil and gas, which could lower the value of our reserves and have a material adverse effect on our profitability, financial condition and liquidity. Furthermore, increasing attention to climate change risks has resulted in increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business.
Endangered Species. The Endangered Species Act (ESA) prohibits the taking of endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, the designation of previously unidentified endangered or threatened species in areas where we intend to conduct construction activity or the imposition of seasonal restrictions on our construction or operational activities could materially limit or delay our plans.
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.
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 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, Oklahoma regulations allow for the storage of produced water in permitted lined impoundments.  These storage impoundments allowed us to recycle approximately 75% of our produced water in 2019 from all of our producing wells.  All of our wells completed in 2019 in our SCOOP asset were completed with recycled produced water from these impoundments with minimal use of local freshwater sources.  These recycling facilities allowed us to dramatically reduce the amount of produced water that had to be injected into state regulated commercial disposal wells, and decreased our reliance of local freshwater sources required for our completions operations.
Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Our ability to produce natural gas, oil and NGL economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.

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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. For water sourcing, we first seek to use non-potable water supplies for our operational needs. In certain areas, there may be insufficient local aquifer capacity to provide a source of water for drilling activities. Water must then be obtained from other sources and transported to the drilling site. An inability to secure sufficient amounts of water or to dispose of or recycle the water used in our operations could adversely impact our operations in certain areas. The imposition of new environmental regulations could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of things such as produced water and drilling fluids
Future U.S. and state tax legislation may adversely affect our business, results of operations, financial condition and cash flow.
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, legislative proposals have been introduced in the U.S. Congress in the past that, if enacted, would (i) eliminate the immediate deduction for intangible drilling and development costs, (ii) repeal the percentage depletion allowance for oil and natural gas properties, and (iii) extend the amortization period for certain geological and geophysical expenditures. 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. In addition, at the state level, legislative changes imposing increased taxes on oil and gas production have periodically been considered in Ohio and Oklahoma. These proposed changes in the U.S. federal and state 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.
Substantially all of our producing properties are located in Eastern Ohio and Oklahoma, making us vulnerable to risks associated with operating in these regions.
Our largest fields by production are located in Eastern Ohio and Oklahoma. 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, tornados 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.
The oil and gas exploration and production industry is very competitive, and some of our competitors have greater financial and other resources than we do.
We face competition in every aspect of our business, including, but not limited to, buying and selling reserves and leases, obtaining goods and services needed to operate our business and marketing natural gas, oil or NGL. Competitors include multinational oil companies, independent production companies and individual producers and operators. Some of our competitors have greater financial and other resources than we do and, due to our debt levels and other factors, may have greater access to the capital and credit markets. 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. As a result, these competitors may be able to address these competitive factors more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.
Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively may be diminished. We also compete for the equipment required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield equipment and services, which could adversely affect our ability to execute our development plans on a timely basis and within budget.

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The loss of one or more of the purchasers of our production could adversely affect our business, results of operations, financial condition and cash flows.
The largest purchaser of our oil and natural gas during the year ended December 31, 2019 accounted for approximately 14% of our total natural gas, oil and NGL revenues. If this purchaser or one or more other significant purchasers, are unable to satisfy its contractual obligations, we may be unable to sell such production to other customers on terms we consider acceptable. Further, the inability of one or more of our customers to pay amounts owed to us could adversely affect our business, financial condition, results of operations and cash flows.
Risks related to potential acquisitions or dispositions may adversely affect our business. 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 forFrom time to time, we evaluate acquisitions and dispositions of assets, businesses and other investments, including equity investments and joint ventures. 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 or capital expenditures, the timing and amount of which we may not be able to control. These transactions may not result in the anticipated benefits or efficiencies. 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. In addition, acquisitions may be financed by borrowings, requiring us to incur more debt, or by the issuance of our common stock. Any such acquisition opportunitiesor disposition involves risks and we cannot assure you that:
any acquisition would be successfully integrated into our operations and internal controls;
the due diligence conducted prior to an acquisition would uncover situations that could result in financial or legal exposure, such as title defects and potential environmental and other liabilities;
post-closing purchase price adjustments will be realized in our industry. Thefavor;
any investment, acquisition, disposition or integration would not divert management resources from the operation of our business; and
any investment, acquisition, or disposition or integration would not have a material adverse effect on our financial condition, results of operations, cash flows or reserves.
If any of these risks materialize, the benefits of such acquisition or disposition may not be fully realized, if at all, and our financial condition, results of operations, cash flows and reserves could be negatively impacted.
Further, 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
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In addition, 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.

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Properties we acquire may not produce as projected, and weWe 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 oildispose of nonstrategic assets on attractive terms 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 assumeretain liabilities for certain matters.
We regularly review our property base for the riskpurpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect our ability to dispose of nonstrategic assets or complete announced dispositions, including the availability of purchasers willing to purchase the nonstrategic assets at prices acceptable to us and restrictions under our revolving credit facility. Sellers typically retain liabilities for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the physical conditiontransaction and ultimately may be material. Also, third parties are often unwilling to release us from guarantees or other credit support provided prior to the sale of the properties in additiondivested assets. As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the riskextent that the properties may notbuyer of the assets fails to perform these obligations.
A deterioration 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 leasesgeneral economic, business 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 ofindustry conditions would have a material title deficiency can render a lease worthless and can adversely affectadverse effect on our results of operations, liquidity and financial condition.
PriorConcerns 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 the drilling of an oil or natural gas well, however, it is the normal practice in our industryeconomic volatility and diminished expectations for the person or company acting asglobal economy. Historically, concerns about global economic growth have had a significant impact on global financial markets and commodity prices. If 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 defectseconomic climate in the marketabilityUnited 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 the title,our vendors, suppliers and such curative work entails expense. Our failurecustomers to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which maycontinue operations and materially adversely impact our abilityresults of operations, liquidity and financial condition.
Terrorist activities could materially and adversely affect our business and results of operations.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. 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 in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices, or the possibility that the infrastructure on which we rely could be a direct target or an indirect casualty of an act of terrorism, and, in turn, could materially and adversely affect our business and results of operations. 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 to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defectsprecipitate, an economic slowdown.
Negative public perception regarding us 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 whichindustry could have an adverse effect on our resultsoperations.

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Negative public perception regarding us or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, waste disposal, oil spills, seismic activity, climate change, explosions of natural gas transmission lines and the development and operation of pipelines and other midstream facilities may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. Additionally, environmental groups, landowners, local groups and other advocates may oppose our operations through organized protests, attempts to block or sabotage our operations or those of our midstream transportation providers, intervene in regulatory or administrative proceedings involving our assets or those of our midstream transportation providers, or file lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and financial condition.
Ifbusiness or those of our midstream transportation providers. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we are unablerequire to complete capital projects in a timely manner,conduct our business, financial condition, results of operations and cash flows couldto 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 affectwithheld, delayed or burdened by requirements that restrict our ability to achieve forecasted internal ratesprofitably conduct our business.
Recently, activists concerned about the potential effects of returnclimate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and operating results. Delays in making required changesother sources of capital restricting 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;

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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 oureliminating their investment in Grizzlyenergy-related activities. Ultimately, this could make it more difficult to secure funding for impairment, resulting in an aggregate other than temporary impairment write down of $23.1 million for the year ended December 31, 2016. As ofexploration 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.production activities.
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.
OilOur operations may be adversely affected by pipeline, trucking and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the abilitygathering system capacity constraints and may be subject 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,interruptions that could adversely impactaffect 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

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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.flow.
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. In certain resource plays, the capacity of gathering and transportation systems is insufficient to accommodate potential production from existing and new wells. 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 Capital constraints could limit the construction of new pipelines and gathering systems and the providing or expansion of trucking services by third parties in the Utica Shale or SCOOP acreage decreases due to decreased developmental activities, production related difficulties or otherwise,and the other areas in which we operate. Until this new capacity is available, we may fail to meetexperience delays in producing and selling 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.

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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, pipeNGL. In such event, we might have to shut in our wells awaiting a pipeline connection or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such ascapacity or sell natural gas, oil spills, gas leaks, ruptures or discharges of toxic gases. In addition,NGL production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect 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.operations.
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 anyA portion of our investment in such unproved property or wells.
Drilling fornatural gas, 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 operationsNGL production in any region may be curtailed, delayedinterrupted, or canceled asshut in, from time to time for numerous reasons, including weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If 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.
Partsubstantial amount of our strategy involves drilling in existing or emerging shale plays usingproduction is interrupted at 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 maysame time, it could materially 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.cash flow.
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 advancescomplete capital projects 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 ontimely manner, 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 maycould be less predictable, whichmaterially 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 plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatilityachieve forecasted internal rates 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 declinereturn and operating expensesresults. Delays in making required changes or upgrades to increase.
Section 1(b) of the Natural Gas Act of 1938, or the NGA, exempts natural gas gatheringour 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,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 could haveare beyond our control, including:
denial of or delay in receiving requisite regulatory approvals or permits;
unplanned increases in the cost of construction materials or labor;
disruptions in transportation of components or construction materials;
adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
market-related increases in a material adverse effect on our business, financial conditionproject's debt or results of operations.equity financing costs; and
We face extensive competition in our industry.nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.
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 ofAny 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 an approximate 24.9% interest in Grizzly. As of December 31, 2019, Grizzly had approximately 830,000 net acres under lease in the purchasersAthabasca, Peace River and Cold Lake oil sands regions of ourAlberta, Canada. Grizzly has high-graded three oil sands projects to various stages of development. Grizzly commenced commercial production could adversely affect our business, results of operations, financial condition and cash flows.
The two largest purchasers of ourfrom its Algar Lake Phase 1 SAGD oil and natural gassand project during the year endedsecond 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. At December 31, 2018 accounted2019, we reviewed our investment in Grizzly for approximately 17% and 10%, respectively, of our total oil, natural gas and NGL revenues. If these purchasers or one or moreimpairment, resulting in an aggregate 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 inthan temporary 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$32.4 million for the year ended December 31, 2016. If prices2019. 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 oil, natural gasthese projects are completed that they will be successful or that we realize a return on our investment. We elected to cease funding capital calls in 2019, and natural gas liquids continuewe have no obligation to decrease, wefund any of the projects Grizzly is pursuing. Failure to fund capital calls may be requiredlead to further write down the valuedilution of our oilequity ownership interest.
Cyber-attacks targeting systems 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 madeinfrastructure used 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 pastindustry and related regulations may adversely impact our operations and, if we are unable to (i) eliminate the immediate deductionobtain and maintain adequate protection 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 affectdata, 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.harmed.
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 and production and processing activities. For example, weWe depend on digital technologiestechnology to interpret seismic data, manage drilling rigs, production equipmentestimate quantities of oil, natural gas and gathering systems, conduct reservoir modeling andNGL reserves, estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased.data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners. 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 itsour 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,access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations, which may include drilling, completion, production and corporate functions. A cyber-attack involving our information systems and related

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infrastructure, or that of our business associates, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, non-compliance leading to regulatory fines or penalties, loss or destructiondisclosure of, proprietaryor damage to, our or any of our customer’s, supplier’s or royalty owners’ data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other information, or other disruption of its business operations. remedial steps.
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 incidentscyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilityvulnerabilities to cyber incidents.
Risks Relating to Our Indebtedness
Our substantial levelcyber-attacks. In addition, new laws and regulations governing data privacy and the unauthorized disclosure of indebtedness could adversely affect our business, financial condition, results of operationsconfidential information pose increasingly complex compliance challenges 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,potentially elevate costs, and any failure to comply with the obligations under any of our debt instruments, including restrictive covenants,these laws and regulations could result in a default undersignificant penalties and legal liability.
Our business is subject to complex and evolving laws and regulations regarding privacy and data protection.
The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate our secured revolving credit facilitycosts. For example, the California Consumer Privacy Act (“CCPA”) was signed into law on June 28, 2018 and largely took effect on January 1, 2020. The CCPA, among other things, contains new disclosure obligations for businesses that collect personal information about California residents and enhanced consumer protections for those individuals, and provides for statutory fines for data security breaches or other CCPA violations. Meanwhile, over fifteen other states have considered privacy laws like the senior note indentures;
CCPA. We will continue to monitor and assess the restrictions imposed on the operationimpact of these state laws, which may impose substantial penalties for violations, impose significant costs for investigations and compliance, require us to change 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 financingpractices, allow private class-action litigation and carry significant potential liability 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 whichshould 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 any such applicable laws.
Any failure, or perceived failure, by us to comply with applicable data protection laws could result in heightened risk of litigation, including private rights of action, and proceedings or actions against us by governmental entities or others, subject us to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the various covenants, including financialcosts and operating covenants,complexity of compliance, and adversely affect our business. As noted above, we are also subject to the possibility of cyber incidents or attacks, which themselves may result in the instruments governing our indebtedness,a violation of these laws. Additionally, if we could beacquire a company that has violated or is not 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, togethercompliance 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, andapplicable data protection laws, we may incur significant liabilities and penalties as a result.
If our investments in entities are 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 onsuccessful 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 operationsdecrease in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow,market value, we may be required to adopt onewrite off or more alternatives, such as reducinglose the value of a portion 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,investments, 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 materialmaterially adverse effect on our results of operations.
Through our wholly owned subsidiaries, we have directly or indirectly made investments in certain entities that are accounted for by the equity method of accounting. We have recorded impairment charges to reflect the other than temporary decreases in the fair value of such entities, including an impairment loss of $160.8 million with respect to our investment in Mammoth Energy and an impairment loss of $32.4 million with respect to our investment in Grizzly recorded during the year ended December 31, 2019. If the financial position of any such entity declines, we could be required to write down all or part of our investment in that entity, which could have a materially adverse effect on our results of operations.
An interruption in operations at our headquarters could adversely affect our business.
Our headquarters are located in Oklahoma City, Oklahoma, an area that experiences severe weather events, including tornadoes and earthquakes. Our information systems and administrative and management processes are primarily provided to our various drilling projects and producing wells throughout the United States from this location, which could be disrupted if a catastrophic event, such as a tornado, power outage or act of terror, destroyed or severely damaged our headquarters. Any such catastrophic event could harm our ability to conduct normal operations and could adversely affect our business.
We have identified a material weakness in internal controls. If we fail to remediate this material weakness or otherwise fail to develop, implement and maintain effective internal controls in future periods, our ability to report our financial condition. Ascondition and results of operations accurately and on a timely basis could be adversely affected.
We have identified a material weakness in our internal controls over the completeness and accuracy of the accounting of transfers of unevaluated capitalized costs into the amortization base. Accordingly, based on our management’s assessment, we believe that, as of December 31, 2018,2019, our disclosure controls and procedures were not effective. We also determined that this

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material weakness existed as of September 30, 2019. The material weakness and our remediation plans are described in Item 9A, Controls and Procedures.
A "material weakness" is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements would not be prevented or detected on a timely basis. We cannot assure you that we didwill adequately remediate the material weakness or that additional material weaknesses in our internal controls will not hedgebe identified in the future. Any failure to maintain or implement required new or improved controls, or any difficulties we encounter in the implementation, could result in additional material weaknesses, or could result in material misstatements in our interest rate risk.financial statements. These misstatements could result in restatements of our financial statements, cause us to fail to meet our reporting obligations or cause investors to lose confidence in our reported financial information.
We are in the process of remediating the identified material weakness in our internal controls, but we are unable at this time to estimate when the remediation will be completed. If we experience liquidity concerns, wefail to remediate this material weakness, there will continue to be an increased risk that our future financial statements could face a downgradecontain errors that will be undetected. Further and continued determinations that there are material weaknesses in the effectiveness of our debt ratings whichinternal controls could restrictreduce our access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financings and trade credit andfinancing or could increase the termscost of any financings or trade credit are, in part, dependent on the credit ratings assignedfinancing we obtain and require additional expenditures of resources 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.comply with applicable requirements.
We do not currently payanticipate paying dividends on our common stock and do not anticipate doing so in the near 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 currently intend to retain any earnings for the future operation and development of our business, including exploration, development and acquisition activities or to fund our operations.retire outstanding debt. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Any future dividend payments will require approval by the board of directors. 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 existenceFuture sales of some provisionsour 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 14, 2020, there were 159,710,955 shares of our common stock issued and outstanding, excluding 5,871,991 shares of unvested restricted stock awarded under our 2019 Amended and Restated Stock Incentive Plan.  
A change of control could limit our use of net operating losses to reduce future taxable income.
As of December 31, 2019, we had a net operating loss, or NOL, carryforward of approximately $1.3 billion for federal income tax purposes. If we were to experience an “ownership change,” as determined under Section 382 of the Internal

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Revenue Code of 1986, as amended (or 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 for the month in which such ownership change occurs. In general, an ownership change will occur if there is a cumulative increase in our organizational documentsownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period.
Our business could delaybe disrupted as a result of actions of certain stockholders.
During 2019, stockholders made public statements critical of our performance and advocated that we make certain changes regarding our strategic plan, capital allocation, executive compensation and corporate governance, including the addition of a stockholder representative to our board of directors. They have also suggested that they could pursue the nomination of director candidates for election to our board of directors at our 2020 Annual Meeting of Stockholders.
If any of our stockholders commence a proxy contest, further advocate for change or preventengage in other similar activities, then our business could be adversely affected. Responding to proxy contests and other actions by activist stockholders can be costly and time-consuming, disrupt our operations and divert the attention of our board of directors and senior management from the pursuit of business strategies, which could adversely affect our results of operations and financial condition. Additionally, perceived uncertainties as to our future direction as a result of stockholder activism or changes to the composition of the board of directors may lead to the perception of a change in controlthe direction of the business, instability or lack of continuity, and, if individuals are elected to our board of directors with a specific agenda, the execution of our company, even if that change wouldstrategic plan may be beneficialdisrupted or a new strategic plan altogether may be implemented. This may be exploited by our competitors, cause concern to our stockholders. Our certificatecurrent or potential customers, and make it more difficult to attract and retain qualified personnel.
We cannot predict, and no assurances can be given, as to the outcome or timing of incorporationany matters relating to the foregoing actions by stockholders or the ultimate impact on our business, financial condition or results of operations. Further, any of these matters or any further actions by this or other stockholders may impact and bylaws contain provisions that may make acquiring controlresult in volatility of the price of our company difficult.common stock, including if this stockholder were to exit its investment in our common stock.
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.
ITEM 2.PROPERTIES
Additional informationInformation regarding our properties is included in Item 1. "Business" above1 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 2017 2016
 
Oil
(MBbls)
 
Natural
Gas
(MMcf)
 Natural Gas Liquids (MBbls) 
Oil
(MBbls)
 
Natural
Gas
(MMcf)
 Natural Gas Liquids (MBbls) 
Oil
(MBbls)
 
Natural
Gas
(MMcf)
 Natural Gas Liquids (MBbls)
Proved developed9,570
 1,813,184
 40,810
 10,245
 1,616,930
 36,247
 4,882
 744,797
 14,299
Proved undeveloped11,480
 2,320,705
 39,710
 8,912
 3,208,380
 39,519
 664
 1,422,271
 5,828
Total (1)21,050
 4,133,889
 80,520
 19,157
 4,825,310
 75,766
 5,546
 2,167,068
 20,127
 Year Ended December 31,
 2018 2017 2016
Total net proved oil and natural gas reserves (MMcfe) (1)4,743,311
 5,394,851
 2,321,108
PV-10 value (in millions) (2)$3,407.3
 $2,883.0
 $696.0
Standardized measure (in millions) (3)$2,982.7
 $2,643.6
 $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:
 December 31,
 2018 2017 2016
 (In thousands)
Standardized measure of discounted future net cash flows$2,982,725
 $2,643,564
 $688,040
Add: Present value of future income tax discounted at 10%424,596
 239,468
 7,927
PV-10 value$3,407,321
 $2,883,032
 $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:
 SEC Pricing 2018 2-month Average 2019
Henry Hub Natural Gas (per MMBtu)$3.10
 $3.90
WTI Crude Oil (per Bbl)$65.56
 $48.17
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, 20175,395
   Sales of oil and gas reserves in place(45)
   Extensions and discoveries711
   Revisions of prior reserve estimates(821)
   Current production(497)
Proved Reserves, December 31, 20184,743
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 of the notes 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, 20173,499
   Sales of oil and natural gas reserves in place(45)
   Extensions and discoveries649
   Conversion to proved developed reserves(576)
   Revisions of prior reserve estimates(899)
Proved Undeveloped Reserves, December 31, 20182,628
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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 2018 2017 2016
 ($ In thousands)
Natural gas sales     
Natural gas production volumes (MMcf)443,742
 350,061
 227,594
      
Total natural gas sales$1,121,815
 $845,999
 $420,128
      
Natural gas sales without the impact of derivatives ($/Mcf)$2.53
 $2.42
 $1.85
Impact from settled derivatives ($/Mcf)$(0.04) $0.07
 $0.60
Average natural gas sales price, including settled derivatives
($/Mcf)
$2.49
 $2.49
 $2.45
      
Oil and condensate sales     
Oil and condensate production volumes (MBbls)2,801
 2,579
 2,126
      
Total oil and condensate sales$177,793
 $124,568
 $81,173
      
Oil and condensate sales without the impact of derivatives ($/Bbl)$63.48
 $48.29
 $38.18
Impact from settled derivatives ($/Bbl)$(9.51) $1.59
 $5.11
Average oil and condensate sales price, including settled derivatives ($/Bbl)$53.97
 $49.88
 $43.29
      
Natural gas liquids sales     
Natural gas liquids production volumes (MGal)251,720
 224,038
 161,562
      
Total natural gas liquids sales$178,915
 $136,057
 $59,115
      
Natural gas liquids sales without the impact of derivatives ($/Gal)$0.71
 $0.61
 $0.37
Impact from settled derivatives ($/Gal)$(0.05) $(0.03) $(0.01)
Average natural gas liquids sales price, including settled derivatives ($/Gal)$0.66
 $0.58
 $0.36
      
Natural gas, oil and condensate and natural gas liquids sales     
Natural gas equivalents (MMcfe)496,505
 397,543
 263,430
      
Total natural gas, oil and condensate and natural gas liquids sales$1,478,523
 $1,106,624
 $560,416
      
Natural gas, oil and condensate and natural gas liquids sales without the impact of derivatives ($/Mcfe)$2.98
 $2.78
 $2.13
Impact from settled derivatives ($/Mcfe)$(0.12) $0.07
 $0.56
Average natural gas, oil and condensate and natural gas liquids sales price, including settled derivatives ($/Mcfe)$2.86
 $2.85
 $2.69
      
Production Costs:     
Average production costs ($/Mcfe)$0.18
 $0.20
 $0.26
Average production taxes ($/Mcfe)$0.07
 $0.05
 $0.05
Average midstream gathering and processing ($/Mcfe)$0.58
 $0.63
 $0.63
Total production costs, midstream costs and production taxes ($/Mcfe)$0.83
  $0.88
  $0.94

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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:
 Year Ended December 31,
 2018 2017 2016
Utica Shale     
Net Production     
Oil (MBbls)299
 473
 870
Natural gas (MMcf)379,417
 309,450
 227,447
NGL (Mgal)113,379
 139,634
 161,494
Total (MMcfe)397,406
 332,238
 255,740
Average Sales Price Without the Impact of Derivatives:     
Oil ($/Bbl)$60.22
 $44.26
 $34.59
Natural gas ($/Mcf)$2.50
 $2.38
 $1.85
NGL ($/Gal)$0.67
 $0.60
 $0.37
Average Production Costs ($/Mcfe)$0.14
 $0.15
 $0.18
 Year Ended December 31,
 2018 2017 (1)
SCOOP   
Net Production   
Oil (MBbls)1,710
 1,083
Natural gas (MMcf)64,258
 40,501
NGL (Mgal)138,261
 84,283
Total (MMcfe)94,268
 59,038
Average Sales Price Without the Impact of Derivatives:   
Oil ($/Bbl)$62.36
 $48.70
Natural gas ($/Mcf)$2.67
 $2.68
NGL ($/Gal)$0.75
 $0.62
Average Production Costs ($/Mcfe)$0.20
 $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 NRI/WI (1) 
Productive
Oil Wells
 
Productive
Gas Wells
 
Non-Productive
Oil Wells
 
Non-Productive
Gas Wells
 
Developed
Acreage (2)
 
Undeveloped
Acreage
FieldPercentages Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net
Utica Shale (3)44.26/54.44 74
 36.14
 493
 271.86
 3
 2.66
 2
 1.57
 92,594
 72,693
 148,417
 136,839
SCOOP (4)24.34/30.20 110
 18.58
 466
 154.69
 3
 2.59
 30
 25.24
 48,658
 34,532
 17,625
 15,517
West Cote Blanche Bay Field (5)80.108/100 69
 69
 —
 —
 146
 146
 —
 —
 5,668
 5,668
 —
 —
E. Hackberry Field (6)82.33/100 14
 14
 —
 —
 130
 130
 —
 —
 2,910
 2,910
 1,206
 1,206
W. Hackberry Field87.50/100 2
 2
 —
 —
 7
 7
 —
 —
 727
 727
 306
 306
Niobrara Formation (7)34.52/48.61 3
 1.46
 —
 —
 —
 —
 —
 —
 1,998
 999
 3,816
 1,908
Bakken Formation (8)1.51/1.83 18
 0.3
 —
 —
 —
 —
 —
 —
 386
 77
 3,505
 701
Overrides/Royalty Non-operatedVarious 673
 0.9
 —
 —
 —
 —
 —
 —
 —
 —
 —
 —
Total  963
 142.38
 959
 426.55
 289
 288.25
 32
 26.81
 152,941
 117,606
 174,875
 156,477
(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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 2018 2017 2016
 Gross Net Gross Net Gross Net
Recompletions:           
Productive47
 47
 81
 81
 77
 77
Dry—
 —
 —
 —
 —
 —
Total47
 47
 81
 81
 77
 77
Development:           
      Productive34
 30
 124
 115.4
 49
 42.5
      Dry—
 —
 2
 2
 1
 1.0
Total34
 30
 126
 117.4
 50
 43.5
Exploratory:           
Productive2
 1.5
 —
 —
 —
 —
Dry—
 —
 —
 —
 —
 —
Total2
 1.5
 —
 —
 —
 —
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
InLitigation and Regulatory Proceedings
We are involved in a number of litigation and regulatory proceedings that may result in material liabilities, including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. Our total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different.
We, along with a number of other oil and gas companies, have been named as a defendant 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(together, the Cameron Parish complaint and among more than 40 oil and gas companies in the Vermilion Parish complaint, or the Complaints."Complaints"). The Complaints were filed underallege that certain of the defendants’ operations violated the State and Local Coastal Resources Management Act of

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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(the "CZM Laws") by causing 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.Parish. 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-judgmentinterest. The United States District Court for the Western District of Louisiana issued orders remanding the cases to their respective state court, and post judgment interest.the defendants have appealed the remand orders to the 5th Circuit Court of Appeals.
We were servedIn July 2019, Pigeon Land Company, Inc., a successor in interest to certain of our legacy Louisiana properties, filed an action against us and a number of other oil and gas companies in the 16th Judicial District Court for the Parish of Iberia in Louisiana. The suit alleges negligence, strict liability and various violations of Louisiana statutes relating to property damage in connection with the Cameron complaint in early May 2016historic development of our Louisiana properties and withseeks unspecified damages (including punitive damages), an injunction to return the Vermilion complaint in early September 2016. The Louisiana Attorney Generalaffected property to its original condition, and the Louisiana Departmentpayment of Natural Resources intervenedreasonable attorney fees and legal expenses and interest.
In September 2019, a stockholder of Mammoth Energy filed a derivative action on behalf of Mammoth Energy against members of Mammoth Energy’s board of directors, including a director designated by us, and its significant stockholders, including us, 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.Oklahoma. In both cases,January 2020, plaintiffs consolidated actions against the plaintiffssame defendants in the United States District Court for the District of Delaware.  The consolidated and amended complaint alleges, among other things, that we breached our fiduciary duties and misappropriated information as a controlling shareholder of Mammoth Energy in connection with Mammoth Energy’s activities in Puerto Rico following Hurricane Maria and our secondary offering of Mammoth Energy common stock in June 2018. The complaint seeks unspecified damages, the payment of reasonable attorney fees and legal expenses and interest and to force Mammoth Energy and its board of directors to make specified corporate governance reforms.
In October 2019, Saydee Resources, LLC, on behalf of itself and a class of similarly situated royalty holders, filed motionsan action against us in the District Court of Grady County Oklahoma. The suit alleges that we underpaid royalty holders and seeks unspecified damages for breach of contract, tortious breach of contract, fraud and unjust enrichment.
In October 2019, Kelsie Wagner, in her capacity as trustee of various trusts and on behalf of the trusts and other similarly situated royalty owners, filed an action against us in the District Court of Grady County, Oklahoma.  The suit alleges that we underpaid royalty owners and seeks unspecified damages for violations of the Oklahoma Production Revenue Standards Act and fraud.

SEC Investigation
The SEC has commenced an investigation with respect to remandcertain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former management and the Company of the Sarbanes-Oxley Act of 2002 in connection with such actions. We have fully cooperated and intend to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liability with respect to this matter, we believe that the outcome of this matter will not have a material effect on our business, financial condition or results of operations.

Business Operations
We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions.
Environmental Contingencies
The nature of the oil and gas business carries with it certain environmental risks for us and our subsidiaries. We have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. We conduct periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, we may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property.

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lawsuits to state court, which were ultimately granted by the district courts. However, on May 23, 2018, a groupWe received several Finding 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 withViolation (“FOVs”) from 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 postureEnvironmental Protection Agency ("USEPA") alleging violations of the lawsuits,Clean Air Act in Ohio. The first FOV for one site was dated December 11, 2013.  Two subsequent FOVs incorporated and expanded the casesscope on January 4, 2017 and April 15, 2019.  We entered into a settlement with the Department of Justice and USEPA agreeing to pay $1.7 million and invest in improvements at 17 well pads. The settlement was filed with the U.S. District Court for the Southern District of Ohio in January 2020, and is pending approval. 
Other Matters
Based on management’s current assessment, we 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,opinion that may result.
In addition, due to the nature of our business, we are, from time to time, involved in routine litigationno pending or subject to disputesthreatened lawsuit or claims relateddispute relating 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, willoperations are likely to have a material adverse effect on our future consolidated financial condition, cash flows orposition, results of operations.operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
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 quotedtrades on the Nasdaq Global Select MarketExchange under the symbol “GPOR.” The following table sets forth"GPOR".
Shareholders
At the highclose of business on February 14, 2020, there were approximately 313 stockholders and low sale prices15,722 beneficial owners of our common stock for the periods presented:
 
Price Range of
Common Stock
 High Low
2017   
First Quarter$22.35
 $15.66
Second Quarter17.82
 12.47
Third Quarter15.09
 10.90
Fourth Quarter15.08
 11.73
2018   
First Quarter$13.74
 $8.11
Second Quarter12.70
 8.60
Third Quarter13.41
 10.07
Fourth Quarter11.67
 6.18
stock.
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 
Total number of shares purchased(2)
 Average price paid per share 
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)
October 2018 —
 $—
 —
 $90,003,000
November 2018 28,584
 $8.81
 —
 $90,003,000
December 2018 10,212,483
 $8.81
 10,212,483
 $—
Total 10,241,067
 $8.81
 10,212,483
  
(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 a 24 month period. During the next 24 months. Our boardyear ended December 31, 2019, we repurchased approximately 3.8 million shares of director’s determinationour outstanding common stock pursuant to the plan for total consideration of approximately $30.0 million. In the fourth quarter of 2019, the program was suspended but may be reactivated in the future depending on our projected leverage profile, commodity price outlook and market conditions. The Company did not repurchase any shares of our common stock during the quarter ended December 31, 2019 and has $370.0 million of shares that may yet be repurchased 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.its announced program.
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 PolicyDividends
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 theThe following table sets forth selected consolidated financial data of Gulfport as of and for the years ended December 31, 2019, 2018, 2017, 2016 and 2015. The data are derived from our audited consolidated financial statements. The table below should be read in conjunctionconnection with Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations”Operations and theour consolidated financial statements and the related notes appearing elsewhere in Items 7 and 8, respectively, of 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
 Fiscal Year Ended December 31,
 2019 2018 2017 2016 2015
 (In thousands, except share data)
Selected Consolidated Statements of Operations Data:         
Revenues$1,346,008
 $1,355,044
 $1,320,303
 $385,910
 $708,990
Costs and expenses:         
Lease operating expenses82,998
 91,640
 80,246
 68,877
 69,475
Production taxes28,571
 33,480
 21,126
 13,276
 14,740
Midstream gathering and processing expenses291,725
 290,188
 248,995
 165,972
 138,590
Depreciation, depletion and amortization550,108
 486,664
 364,629
 245,974
 337,694
Impairment of oil and natural gas properties

2,039,770
 —
 —
 715,495
 1,440,418
General and administrative expenses47,979
 49,994
 45,523
 37,681
 38,086
Restructuring costs4,611
 —
 —
 —
 —
Accretion expense3,939
 4,119
 1,611
 1,057
 820
Acquisition expense—
 —
 2,392
 —
 —
 3,049,701
 956,085
 764,522
 1,248,332
 2,039,823
(Loss) Income from Operations(1,703,693) 398,959
 555,781
 (862,422) (1,330,833)
Other Expense (Income):         
Interest expense141,786
 141,912
 115,613
 69,258
 55,102
Interest income(801) (314) (1,009) (1,230) (643)
(Gain) loss on debt extinguishment(48,630) —
 —
 23,776
 —
Gain on sale of equity method investments—
 (124,768) (12,523) (3,391) —
Loss (income) from equity method investments, net210,148
 (49,904) 17,780
 37,376
 106,093
Other expense (income)3,725
 1,542
 (1,041) (5,589) (10,500)
 306,228
 (31,532) 118,820
 120,200
 150,052
(Loss) Income from Continuing Operations before Income Taxes(2,009,921) 430,491
 436,961
 (982,622) (1,480,885)
        Income Tax (Benefit) Expense(7,563) (69) 1,809
 (2,913) (256,001)
(Loss) Income from Continuing Operations(2,002,358) 430,560
 435,152
 (979,709) (1,224,884)
Net (Loss) Income Available to Common Stockholders$(2,002,358) $430,560
 $435,152
 $(979,709) $(1,224,884)
Net (Loss) Income Per Common Share—Basic:$(12.49) $2.46
 $2.42
 $(7.97) $(12.27)
Net (Loss) Income Per Common Share—Diluted:$(12.49) $2.45
 $2.41
 $(7.97) $(12.27)

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 Fiscal Year Ended December 31,
 2018 2017 2016 2015 2014
 (In thousands, except share data)
Selected Consolidated Statements of Operations Data:         
Revenues$1,355,044
 $1,320,303
 $385,910
 $708,990
 $670,762
Costs and expenses:         
Lease operating expenses91,640
 80,246
 68,877
 69,475
 52,191
Production taxes33,480
 21,126
 13,276
 14,740
 24,006
Midstream gathering and processing290,188
 248,995
 165,972
 138,590
 64,467
Depreciation, depletion and amortization486,664
 364,629
 245,974
 337,694
 265,431
Impairment of oil and natural gas properties

—
 —
 715,495
 1,440,418
 —
General and administrative56,633
 52,938
 43,409
 41,967
 38,290
Accretion expense4,119
 1,611
 1,057
 820
 761
Acquisition expense—
 2,392
 —
 —
 —
       Gain on sale of assets—
 —
 —
 —
 (11)
 962,724
 771,937
 1,254,060
 2,043,704
 445,135
Income (Loss) from Operations392,320
 548,366
 (868,150) (1,334,714) 225,627
Other (Income) Expense:         
Interest expense135,273
 108,198
 63,530
 51,221
 23,986
Interest income(314) (1,009) (1,230) (643) (195)
Litigation settlement1,075
 —
 —
 —
 25,500
Insurance proceeds(231) —
 (5,718) (10,015) —
Loss on debt extinguishment—
 —
 23,776
 —
 —
Gain on contribution of investments—
 —
 —
 —
 (84,470)
Gain on sale of equity method investments(124,768) (12,523) (3,391) —
 —
(Income) loss from equity method investments(49,904) 17,780
 37,376
 106,093
 (139,434)
Other expense (income)698
 (1,041) 129
 (485) (504)
 (38,171) 111,405
 114,472
 146,171
 (175,117)
Income (Loss) from Continuing Operations before Income Taxes430,491
 436,961
 (982,622) (1,480,885) 400,744
        Income Tax (Benefit) Expense(69) 1,809
 (2,913) (256,001) 153,341
Income (Loss) from Continuing Operations430,560
 435,152
 (979,709) (1,224,884) 247,403
Net Income (Loss) Available to Common Stockholders$430,560
 $435,152
 $(979,709) $(1,224,884) $247,403
Net Income (Loss) Per Common Share—Basic:$2.46
 $2.42
 $(7.97) $(12.27) $2.90
Net Income (Loss) Per Common Share—Diluted:$2.45
 $2.41
 $(7.97) $(12.27) $2.88

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At December 31,At December 31,
2018 2017 2016 2015 20142019 2018 2017 2016 2015
(In thousands)(In thousands)
Selected Consolidated Balance Sheet Data:                  
Total assets$6,051,036
 $5,807,752
 $4,223,145
 $3,334,734
 $3,619,473
$3,882,819
 $6,051,036
 $5,807,752
 $4,223,145
 $3,334,734
Total debt, including current maturities$2,087,416
 $2,038,943
 $1,593,875
 $946,263
 $703,564
$1,978,651
 $2,087,416
 $2,038,943
 $1,593,875
 $946,263
Total liabilities$2,723,268
 $2,706,138
 $2,039,253
 $1,295,897
 $1,323,177
$2,568,227
 $2,723,268
 $2,706,138
 $2,039,253
 $1,295,897
Stockholders’ equity$3,327,768
 $3,101,614
 $2,183,892
 $2,038,837
 $2,296,296
$1,314,592
 $3,327,768
 $3,101,614
 $2,183,892
 $2,038,837
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with the consolidated financial statements“Item 8. Financial Statements and related notesSupplementary Data” of this report. The following discussion and analysis generally discusses 2019 and 2018 items and year-to-year comparisons between 2019 and 2018. Discussions of 2017 items and year-to-year comparisons between 2018 and 2017 that are not included elsewhere in this Form 10-K can be found in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of our 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 and10-K for 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.year ended December 31, 2018.
Overview
We are an independent oil and natural gasgas-weighted exploration and production company focused on the exploration, exploitation, acquisition and production of natural gas, crude oil and natural gas liquids and crude oil("NGL") in the United States.States with primary focus in the Appalachia and Mid-Continent basins. Our principal properties are located in Eastern Ohio targeting the Utica Shale primarilyformation and in Eastern Ohio andcentral Oklahoma targeting the SCOOP Woodford and SCOOP Springer plansformations.
2019 Highlights
During the year ended December 31, 2019, we entered into several agreements to divest of certain non-core assets as part of our strategic initiatives to focus development in Oklahoma. In addition, among otherour core operating areas. These non-core divestitures consisted of the following:
◦We sold our non-core assets located in the West Cote Blanche Bay ("WCBB") and Hackberry fields of Louisiana for a purchase price of approximately $19.7 million, subject to customary closing terms and adjustments. We received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, we could also receive contingent payments based on commodity prices exceeding specified thresholds over the two years following the closing date. The buyer assumed all plugging and abandonment liabilities associated with these assets, which totaled approximately $30.0 million at the divestiture date. The sale closed on July 3, 2019.
◦We sold certain non-operated interests in the Utica Shale for cash proceeds of $29.0 million subject to customary closing terms and adjustments. The sale closed on December 30, 2019.
◦We sold certain overriding royalty interests associated with assets we held in the Bakken for cash proceeds of approximately $7.0 million subject to customary closing terms and adjustments. The sale closed on December 11, 2019.
◦In December 2019, we entered into an agreement to divest our water infrastructure assets across our SCOOP position to a third-party water service provider. This transaction closed on January 2, 2020. We received $50.0 million in cash upon closing and have an opportunity to earn potential additional incentive payments over the next 15 years, subject to our ability to meet certain thresholds which will be driven by, among other things, our future development program and future water production levels. The agreement contains no

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minimum volume commitments. The assets related to this transaction are included in our amortization base of the full cost pool and we hold an acreage position alongdo not expect to recognize a gain or loss in our statement of operations.
During the Louisiana Gulf Coastyear ended December 31, 2019, we used borrowings under our revolving credit facility to repurchase in the West Cote Blanche Bay, or WCBB,open market approximately $190.1 million aggregate principal amount of our outstanding 6.625% Senior Notes due 2023 ("2023 Notes"), 6.000% Senior Notes due 2024 ("2024 Notes"), 6.375% Senior Notes due 2025 ("2025 Notes"), and Hackberry fields, an acreage position in6.375% Senior Notes due 2026 ("2026 Notes") (collectively 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."Notes"), or Mammoth Energy, an oil field services company listedfor $138.8 million. We recognized a $48.6 million gain 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 varietydebt extinguishment, which included retirement 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 wellunamortized issuance 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 resultsfees associated 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 Highlightsrepurchased debt.
Production increased 25%1% to approximately 501,742 MMcfe for the year ended December 31, 2019 from approximately 496,505 MMcfe for the year ended December 31, 2018 from approximately 397,543 MMcfe for the year ended December 31, 2017.2018.
During 2018,2019, we spud 3626 gross (31.6(23.2 net) wells, turned to sales 5061 gross (47.8(54.1 net) operated wells, participated in an additional 6847 gross (7.5(2.5 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.acreage. Of our 3626 new wells spud during 2018, seven2019, 11 were completed as producing wells and, at year end, 2914 were in various stages of completion.
Oilcompletion 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.one was being drilled.
During the year ended December 31, 2018,2019, we reduced our unit lease operating expense by 10% to $0.18$0.17 per Mcfe from $0.20$0.18 per Mcfe during the year ended December 31, 2017.

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2018.
During the year ended December 31, 2018,2019, we reduced our unit general and administrative expense by 15%4% to $0.11 per Mcfe$48.0 million from $0.13 per Mcfe$50.0 million during the year ended December 31, 2017.2018.
Liquidity and Capital Resources
Overview. Historically, our primary sources of capital funding and liquidity have been our operating cash flow, borrowings under our revolving credit facility and issuances of equity and debt securities. Our ability to access these sources of funds can be significantly impacted by changes in capital markets, decreases in commodity prices and decreases in our production levels.
Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facility, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months.
As of December 31, 2019, we had a cash balance of $6.1 million compared to $52.3 million as of December 31, 2018, and a net working capital deficit of $145.3 million as of December 31, 2019, compared to a net working capital deficit of $223.1 million as of December 31, 2018. As of December 31, 2019, our working capital deficit includes $0.6 million of debt due in the next 12 months. Our total principal debt as of December 31, 2019 was $2.0 billion compared to $2.1 billion as of December 31, 2018. As of December 31, 2019, we had $636.4 million of borrowing capacity available under the revolving credit facility, with outstanding borrowings of $120.0 million and $243.6 million utilized for various letters of credit.  See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our debt obligations, including principal and carrying amounts of our notes.
Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive.
As of December 31, 2019, we had the following open natural gas, oil and NGL derivative instruments:

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Natural Gas Derivatives
Year Type of Derivative Instrument Index Daily Volume (MMBtu/day) 
Weighted
Average Price
2020 Swaps NYMEX Henry Hub 548,000
 $2.88
2020 Basis Swaps Various 70,000
 $(0.12)
2022 Sold Call Options NYMEX Henry Hub 628,000
 $2.90
2023 Sold Call Options NYMEX Henry Hub 628,000
 $2.90
Oil Derivatives
Year Type of Derivative Instrument Index Daily Volume (Bbls/day) 
Weighted
Average Price
2020 Swaps NYMEX WTI 6,000
 $59.82
NGL Derivatives
Year Type of Derivative Instrument Index Daily Volume (Bbls/day) 
Weighted
Average Price
2020 Swaps Mont Belvieu C3 500
 $21.63
See Note 12 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of derivatives and hedging activities.
Credit Facility. We have entered into a senior secured revolving credit facility agreement, 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, 2019, we had a borrowing base of $1.2 billion, with an elected commitment of $1.0 billion, and $120.0 million in borrowings outstanding under our revolving credit facility. Total funds available for borrowing, after giving effect to an aggregate of $243.6 million of letters of credit as of December 31, 2019, were $636.4 million. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries, excluding Grizzly Holdings Inc. ("Grizzly Holdings"), Mule Sky LLC ("Mule Sky") and GRUS, LLC ("GRUS"), guarantee our obligations under our revolving credit facility. Our next borrowing base redetermination is scheduled for the second quarter of 2020.
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 the administrative 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 administrative agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of December 31, 2019, amounts borrowed under our revolving credit facility bore interest at the weighted average rate of 3.30%.
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; agree to payment restrictions affecting our restricted subsidiaries; make investments; undertake fundamental changes including selling all or substantially all of our assets; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; enter into transactions with their affiliates; and engage in certain transactions with restricted subsidiaries. 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 (as defined under the revolving credit agreement) may not be greater than 4.00 to 1.00 for the twelve-month period of the end of each fiscal quarter; and (2) the ratio of EBITDAX to interest expense for the twelve-month period at the end of each fiscal quarter may not be less than 3.00 to 1.00. We were in compliance with these financial covenants at December 31, 2019.

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Senior Notes. In April 2015, we issued an aggregate of $350.0 million in principal amount of our 2023 Notes. Interest on these senior 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. As of December 31, 2019, after giving effect to 2019 open market repurchases of these 2023 Notes, $329.5 million principal amount remained outstanding. 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 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. As of December 31, 2019, after giving effect to 2019 open market repurchases of these 2024 Notes, $603.4 million principal amount remained outstanding. 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 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. As of December 31, 2019, after giving effect to 2019 open market repurchases of these 2025 Notes, $529.5 million principal amount remained outstanding. 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. As of December 31, 2019, after giving effect to 2019 open market repurchases of these 2026 Notes, $397.5 million principal amount remained outstanding. The 2026 Notes will mature on January 15, 2026.
During the year ended December 31, 2019, we used borrowings under our revolving credit facility to repurchase in the open market approximately $190.1 million aggregate principal amount of our outstanding Notes for $138.8 million. This included approximately $20.5 million principal amount of the 2023 Notes, $46.6 million principal amount of the 2024 Notes, $70.5 million principal amount of the 2025 Notes, and $52.5 million principal amount of the 2026 Notes. We recognized a $48.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt.
We may use a combination of cash and borrowing under our revolving credit facility to retire our outstanding debt, through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.
All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings, Mule Sky or GRUS, and will not be guaranteed by any of our future unrestricted subsidiaries. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The 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 Notes.
If we experience a change of control (as defined in the senior note indentures relating to the Notes), we will be required to make an offer to repurchase the 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 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 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 Notes, certain of these covenants are subject to termination upon the occurrence of certain events, including in the event the Notes are ranked as "investment grade."
Construction Loan. On June 4, 2015, we entered into a construction loan agreement (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

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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, 2019, the total borrowings under the construction loan were approximately $22.5 million.
Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2019:
 Payment due by period
Contractual ObligationsTotal Less than 1 year 1-3 years 3-5 years 
More than 5
years
 (In thousands)
Long-term debt(1):
         
Principal$2,002,402
 $631
 $121,357
 $934,380
 $946,034
Interest613,260
 118,428
 236,198
 203,330
 55,304
Firm transportation contracts(2)
3,560,504
 274,813
 573,252
 548,513
 2,163,926
Operating lease liabilities(3)
57,438
 35,045
 22,275
 118
 —
Other15,000
 7,500
 7,500
 —
 —
Total contractual cash obligations(4)
$6,248,604
 $436,417
 $960,582
 $1,686,341
 $3,165,264
_____________________ 
(1)
See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our long-term debt.
(2)
See Note 16 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our firm transportation contracts.
(3)
See Note 9 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease liabilities.
(4)
This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 12 and 3 of the notes to our consolidated financial statements included in Item 8 of this report, respectively.
Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2019, our material off-balance sheet arrangements and transactions include $243.6 million in letters of credit outstanding against our revolving credit facility and $105.1 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance on certain firm transportation agreements. Management believes these items will expire without being funded. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 17 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.
Capital Expenditures. Our capital commitments have been primarily for the execution of our drilling programs, share repurchases, and discounted repurchases of our senior notes. Our capital investment strategy is focused on prudently developing our existing properties in an effort to generate sustainable cash flow considering current and forecasted commodity prices while also selectively pursuing mergers or acquisitions in our current operating regions in an effort to gain scale and deepen our drilling inventory.
Our capital expenditures for 2020 are currently estimated to be in the range of $265.0 million to $285.0 million for drilling and completion expenditures. In addition, we currently expect to spend $20.0 million to $25.0 million in 2020 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale. The midpoint of the 2020 range of capital expenditures is 51% lower than the $602.5 million spent in 2019, primarily due to our decision to reduce capital activity in response to lower commodity prices, specifically natural gas prices, and our desire to fund our capital development program primarily with cash flow from operations. As a result of our decreased capital spending program for 2020 and the impact of our 2019 property divestitures, we expect our volumes in 2020 to be approximately 18% lower than 2019. Coupled with forecasted lower commodity prices, we expect 2020 revenues, operating cash flows and EBITDA to be lower in 2020 as compared to 2019.

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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 have the ability to react quickly to changing commodity prices and accelerate or decelerate our activity within our operating areas as market conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels or our capital or other costs increase we may be required to obtain additional funds which we would seek to do through borrowings, offerings of debt or equity securities or other means, including the sale of assets. We regularly evaluate merger, acquisition and divestiture opportunities. Capital may not be available to us on acceptable terms or at all in the future. 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 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. During 2019, WTI prices ranged from $46.31 to $66.24 per barrel and the Henry Hub spot market price of natural gas ranged from $1.75 to $4.25 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 reducedcan produce economically. This may result in our unit midstream gatheringhaving 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 processing expensenatural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities.
See Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" for information regarding our open fixed price swaps at December 31, 2019.
Cash Flow from Operating Activities. Net cash flow provided by 8% to $0.58 per Mcfe from $0.63 per Mcfe duringoperating activities was $724.0 million for the year ended December 31, 2017.2019 as compared to $786.3 million for 2018. This decrease was primarily the result of a decrease in cash receipts from our oil and natural gas purchasers due to a 23% decrease in net revenues after giving effect to settled derivative instruments, partially offset by a decrease in our operating expenses.
In January 2018,Divestitures. During 2019, we divested certain non-core assets and interests in operated and non-operated oil and natural gas properties for approximately $48.5 million. Proceeds from these transactions were primarily used to repay debt and fund our boarddevelopment program. See Note 2 of directors approved a stock repurchase programthe notes to acquire up to $100.0 millionour consolidated financial statements included in Item 8 of this report for further discussion.
Uses of Funds. The following table presents the uses of our outstanding common stock,cash and cash equivalents for the years ended December 31, 2019 and 2018:

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 Years Ended December 31,
 2019 2018
 (In thousands)
Oil and Natural Gas Property Expenditures:   
Drilling and completion costs654,407
 713,031
Leasehold acquisitions39,664
 125,585
Other25,986
 60,467
Total oil and natural gas property expenditures720,057
 899,083
Other Uses of Cash and Cash Equivalents   
Cash paid to repurchase senior notes138,786
 —
Cash paid to repurchase common stock30,688
 200,251
Additions to other property and equipment5,021
 7,870
Contributions to equity method investments432
 2,319
Other288
 831
Total other uses of cash and cash equivalents$175,215
 $211,271
Total uses of cash and cash equivalents$895,272
 $1,110,354
Drilling and Completion Costs. During 2019, we spud 16 gross (14.6 net) and commenced sales from 47 gross (41.6 net) wells in May 2018 expanded this program to acquire up to an additional $100.0 million of our common stock during 2018the Utica Shale for a total cost of upapproximately $318.3 million. In addition, five gross (0.9 net) wells were spud and 14 gross (3.3 net) wells were turned to $200.0 million, which we believe underscores the confidence we have insales by other operators on our business model, financial performance and asset base. During 2018, we purchased 20.7 million shares of our outstanding common stockUtica Shale acreage during 2019 for a total cost to us of approximately $200.0$44.2 million.
During 2019, we spud 10 gross (8.6 net) and commenced sales from 14 gross (12.6 net) wells in the SCOOP for a total cost of approximately $124.8 million. In addition, 42 gross (1.6 net) wells were spud and 39 gross (1.2 net) wells were turned to sales by other operators on our SCOOP acreage during 2019 for a total cost to us of approximately $14.6 million.
On May 1,
Results of Operations
The markets for oil and natural gas have historically been, and will likely continue to be, volatile. Prices for oil and natural gas may fluctuate in response to relatively minor changes in supply and demand, market uncertainty and a variety of factors beyond our control.

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The following table presents our production volumes, average prices received and average production costs during the periods indicated:
 Years Ended December 31,
 2019 2018
 (In thousands, unless otherwise stated)
Natural gas sales   
Natural gas production volumes (MMcf)458,178
 443,742
    
Total natural gas sales$918,263
 $1,121,815
    
Natural gas sales without the impact of derivatives ($/Mcf)$2.00
 $2.53
Impact from settled derivatives ($/Mcf)$0.23
 $(0.04)
Average natural gas sales price, including settled derivatives ($/Mcf)$2.23
 $2.49
    
Oil and condensate sales   
Oil and condensate production volumes (Mbbls)2,186
 2,801
    
Total oil and condensate sales$117,937
 $177,793
    
Oil and condensate sales without the impact of derivatives ($/Bbl)$53.95
 $63.48
Impact from settled derivatives ($/Bbl)$1.86
 $(9.51)
Average oil and condensate sales price, including settled derivatives ($/Bbl)$55.81
 $53.97
    
NGL sales   
NGL production volumes (MGal)213,129
 251,720
    
Total NGL sales$101,448
 $178,915
    
NGL sales without the impact of derivatives ($/Gal)$0.48
 $0.71
Impact from settled derivatives ($/Gal)$0.06
 $(0.05)
Average NGL price, including settled derivatives ($/Gal)$0.54
 $0.66
    
Natural gas, oil and condensate and NGL sales   
Natural gas equivalents (MMcfe)501,742
 496,505
    
Total natural gas, oil and condensate and NGL sales$1,137,648
 $1,478,523
    
Natural gas, oil and condensate and NGL sales without the impact of derivatives ($/Mcfe)$2.27
 $2.98
Impact from settled derivatives ($/Mcfe)$0.24
 $(0.12)
Average natural gas, oil and condensate and NGL sales price, including settled derivatives ($/Mcfe)$2.51
 $2.86
    
Production Costs:   
Average production costs ($/Mcfe)$0.17
 $0.18
Average production taxes ($/Mcfe)$0.06
 $0.07
Average midstream gathering and processing ($/Mcfe)$0.58
 $0.58
Total production costs, midstream costs and production taxes ($/Mcfe)$0.81
 $0.83

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The total natural gas, oil and NGL volumes hedged for 2019 and 2018 represented approximately 96% and 78%, respectively, of our total sales volumes for the applicable year.
From 2018 to 2019, our net equivalent gas production increased 1% from 1,360 MMcfe per day to 1,375 MMcfe per day primarily as a result of our continued development of our Utica Shale and SCOOP acreage. We currently estimate that our 2020 production will be between 1,100 and 1,150 MMcfe per day. 2020 production levels are expected to be lower than 2019 levels as we soldhave decided to reduce our 25%2020 capital spending as compared to 2019 levels given relatively low natural gas prices. 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, 2019 and December 31, 2018
We reported net loss of $2.0 billion for the year ended December 31, 2019 as compared to net income of $430.6 million for the year ended December 31, 2018. This decrease in period-to-period net income was due primarily to a $2.0 billion oil and natural gas properties impairment charge related primarily to the decline in commodity prices, a $260.1 million decrease in income from equity method investments, a $124.8 million decrease in gain on sale of equity method investments, a $63.4 million increase in depreciation, depletion and amortization expense, and a $9.0 million decrease in natural gas, oil and NGL revenues, partially offset by a $48.6 million increase in gain on debt extinguishment, an $8.6 million decrease in lease operating expenses, a $4.9 million decrease in production taxes, and a $2.0 million decrease in general and administrative expenses for the year ended December 31, 2019, as compared to the year ended December 31, 2018.
Natural Gas, Oil and NGL Sales
 Years Ended December 31,
 2019 2018 change
 ($ In thousands)
Natural gas918,263
 1,121,815
 (18)%
Oil and condensate117,937
 177,793
 (34)%
NGL101,448
 178,915
 (43)%
Natural gas, oil and NGL revenues$1,137,648
 $1,478,523
 (23)%
The decrease in natural gas sales without the impact of derivatives was primarily due to a 21% decrease in natural gas market prices, partially offset by a 3%increase in natural gas sales volumes.
The decrease in oil and condensate sales without the impact of derivatives was due to a 22% decrease in oil and condensate sales volumes and a 15% decrease in oil and condensate market prices.
The decrease in NGL sales without the impact of derivatives was due to a 33% decrease in NGL market prices and a 15% decrease in NGL sales volumes.
Natural Gas, Oil and NGL Derivatives

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 Years Ended December 31,
 2019 2018
 ($ In thousands)
Natural gas derivatives - fair value (gains) losses$(89,576) $98,130
Natural gas derivatives - settlement (gains) losses(104,874) 18,000
Total (gains) losses on natural gas derivatives(194,450) 116,130
    
Oil and condensate derivatives - fair value (gains) losses(2,952) (13,546)
Oil and condensate derivatives - settlement (gains) losses(4,083) 26,630
Total (gains) losses on oil and condensate derivatives(7,035) 13,084
    
NGL derivatives - fair value (gains) losses7,541
 (19,533)
NGL derivatives - settlement (gains) losses(14,173) 13,798
Total (gains) losses on NGL derivatives(6,632) (5,735)
    
Contingent consideration arrangement - fair value gains(243) —
Total (gains) losses on natural gas, oil and NGL derivatives$(208,360) $123,479
See Note 12 to our consolidated financial statements for further discussion of our derivative activity.
Lease Operating Expenses
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Lease operating expenses     
Utica$55,839
 $54,347
 3 %
SCOOP18,239
 18,385
 (1)%
WCBB6,941
 14,178
 (51)%
Hackberry1,679
 4,435
 (62)%
Other(1)
300
 295
 2 %
Total lease operating expenses$82,998
 $91,640
 (9)%
      
Lease operating expenses per Mcfe     
Utica$0.14
 $0.14
 2 %
SCOOP0.18
 0.20
 (6)%
WCBB4.87
 3.87
 26 %
Hackberry7.65
 6.57
 16 %
Other(1)
0.79
 0.60
 32 %
Total lease operating expenses per Mcfe$0.17
 $0.18
 (10)%
 _____________________
(1)Includes Niobrara and Bakken
The decrease in total and per unit lease operating expenses ("LOE"), not including production taxes, in 2019 was mainly the result of our divesting of our Louisiana properties which have higher operating costs than our Utica and SCOOP areas.
Production Taxes

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 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Production taxes$28,571
 $33,480
 (15)%
Production taxes per Mcfe$0.06
 $0.07
 (16)%
The decrease in production taxes was primarily related to a decrease in realized prices in 2019 as compared to 2018.
Midstream Gathering and Processing Expenses
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Midstream gathering and processing expenses$291,725
 $290,188
 1 %
Midstream gathering and processing expenses per Mcfe$0.58
 $0.58
 (1)%
Midstream gathering and processing expenses were relatively consistent in 2019 as compared to 2018 on both a total expense basis and a per unit basis.
Depreciation, Depletion and Amortization
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Depreciation, depletion and amortization$550,108
 $486,664
 13%
Depreciation, depletion and amortization per Mcfe$1.10
 $0.98
 12%
Depreciation, depletion and amortization ("DD&A") expense consisted of $538.9 million in depletion of oil and natural gas properties and $11.2 million in depreciation of other property and equipment in 2019, compared to $476.4 million in depletion of oil and natural gas properties and $10.3 million in depreciation of other property and equipment in 2018. The increase in DD&A was due to an increase in our amount of oil and gas properties subject to amortization and a decrease in our total proved reserves volume used to calculate our total DD&A expense.
Impairment of Oil and Gas Properties. During the year ended December 31, 2019, we had a $2.0 billion oil and natural gas properties impairment charge related primarily to the decline in commodity prices, compared to no impairment charge of oil and gas properties in 2018. If prices of natural gas, oil and NGL continue to decline, the Company may be required to further write down the value of its oil and natural gas properties, which could negatively affect its results of operations.
Equity Investments
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Gain on sale of equity method investments$—
 $(124,768) (100)%
Loss (income) from equity method investments, net$210,148
 $(49,904) (521)%
Gain on sale of equity method investments during the year ended December 31, 2018 consisted of $96.4 million from the sale of our interest in Strike Force Midstream LLC, or Strike Force, to EQT Midstream Partners, LP for $175.0and $28.3 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,from the sale of our Mammoth Energy common stockstock. The decrease in an underwritten public offeringincome from equity method investments is primarily related to a $160.8 million impairment loss related to our investment in

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Mammoth Energy and a $32.4 million impairment loss related partial exerciseto our investment in Grizzly for the year ended December 31, 2019. See Note 4 to our consolidated financial statements for further discussion on our equity investments.
General and Administrative Expenses
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
General and administrative expenses, gross$89,291
 $97,526
 (8)%
Reimbursed from third parties(11,173) (9,820) 14 %
Capitalized general and administrative expenses(30,139) (37,712) (20)%
General and administrative expenses, net$47,979
 $49,994
 (4)%
      
General and administrative expenses, net per Mcfe$0.10
 $0.10
 (5)%
The decrease in total general and administrative expenses, net was due primarily to lower compensation and benefits and cost-focused initiatives.
Restructuring Costs. In the fourth quarter of 2019, we announced and completed a workforce reduction representing approximately 13% of our headcount. In connection with the underwriters' option to purchase additional shares for an aggregate net proceeds to usreduction, we incurred a total charge of approximately $51.5 million. Following$4.6 million, primarily consisting of one-time employee-related termination benefits, with a remaining liability of $0.2 million at December 31, 2019.
Accretion Expense. Accretion expense decreased to $3.9 million for the year ended December 31, 2019 from $4.1 million for the year ended December 31, 2018, primarily as a result of a decrease in our asset retirement obligation due to the sale of these shares, we owned 9,829,548 shares, or 21.9% atour Louisiana properties.
Interest Expense
 Years Ended December 31,
 2019 2018
 ($ In thousands, except per unit)
Interest expense on senior notes125,687
 129,125
Interest expense on revolving credit agreement12,088
 9,601
Interest expense on construction loan and other1,055
 1,535
Capitalized interest(3,372) (4,470)
Amortization of loan costs6,328
 6,121
Total interest expense$141,786
 $141,912
    
Interest expense per Mcfe$0.28
 $0.29
    
Weighted average debt outstanding under revolving credit facility$161,416
 $83,589
Interest expense was relatively consistent in 2019 as compared to 2018 on both a total expense basis and a per unit basis. Total weighted debt outstanding under our revolving credit facility was $161.4 million for the year ended December 31, 2019 as compared to $83.6 million outstanding under such facility for 2018; however, this increase was largely offset by decreases in interest on our senior notes outstanding for 2019 as compared to 2018 due to senior notes repurchases.
Income Taxes. We recognized an income tax benefit of Mammoth Energy’s outstanding common stock.$7.6 million million in 2019 compared to an income tax benefit of $69 thousand in 2018. The income tax benefit for 2019 consists mainly of a partial release of valuation allowance that was
During 2019 (through February 15, 2019), we spud seven gross (5.3 net) wells. As
53
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Index to Financial Statements

maintained against our Oklahoma deferred tax asset, as the Company believes that it can utilize a portion of its Oklahoma state NOL through carrybacks and four were still being drilled.carryforwards to offset Oklahoma sourced income from the sale of assets.
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 EstimatesResults of Operations
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 accountingmarkets for oil and natural gas operations. Accordingly, all costs, including non-productive costshave historically been, and certain general and administrative costs directly associated with acquisition, exploration and development ofwill likely continue to be, volatile. Prices for oil and natural gas properties, are capitalized. Companies that use the full cost methodmay fluctuate in response to relatively minor changes in supply and demand, market uncertainty and a variety 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 hedgefactors beyond 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 andcontrol.


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totaled $2.9 billion at bothThe following table presents our production volumes, average prices received and average production costs during the periods indicated:
 Years Ended December 31,
 2019 2018
 (In thousands, unless otherwise stated)
Natural gas sales   
Natural gas production volumes (MMcf)458,178
 443,742
    
Total natural gas sales$918,263
 $1,121,815
    
Natural gas sales without the impact of derivatives ($/Mcf)$2.00
 $2.53
Impact from settled derivatives ($/Mcf)$0.23
 $(0.04)
Average natural gas sales price, including settled derivatives ($/Mcf)$2.23
 $2.49
    
Oil and condensate sales   
Oil and condensate production volumes (Mbbls)2,186
 2,801
    
Total oil and condensate sales$117,937
 $177,793
    
Oil and condensate sales without the impact of derivatives ($/Bbl)$53.95
 $63.48
Impact from settled derivatives ($/Bbl)$1.86
 $(9.51)
Average oil and condensate sales price, including settled derivatives ($/Bbl)$55.81
 $53.97
    
NGL sales   
NGL production volumes (MGal)213,129
 251,720
    
Total NGL sales$101,448
 $178,915
    
NGL sales without the impact of derivatives ($/Gal)$0.48
 $0.71
Impact from settled derivatives ($/Gal)$0.06
 $(0.05)
Average NGL price, including settled derivatives ($/Gal)$0.54
 $0.66
    
Natural gas, oil and condensate and NGL sales   
Natural gas equivalents (MMcfe)501,742
 496,505
    
Total natural gas, oil and condensate and NGL sales$1,137,648
 $1,478,523
    
Natural gas, oil and condensate and NGL sales without the impact of derivatives ($/Mcfe)$2.27
 $2.98
Impact from settled derivatives ($/Mcfe)$0.24
 $(0.12)
Average natural gas, oil and condensate and NGL sales price, including settled derivatives ($/Mcfe)$2.51
 $2.86
    
Production Costs:   
Average production costs ($/Mcfe)$0.17
 $0.18
Average production taxes ($/Mcfe)$0.06
 $0.07
Average midstream gathering and processing ($/Mcfe)$0.58
 $0.58
Total production costs, midstream costs and production taxes ($/Mcfe)$0.81
 $0.83

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The total natural gas, oil and NGL volumes hedged for 2019 and 2018 represented approximately 96% and 78%, respectively, of our total sales volumes for the applicable year.
From 2018 to 2019, our net equivalent gas production increased 1% from 1,360 MMcfe per day to 1,375 MMcfe per day primarily as a result of our continued development of our Utica Shale and SCOOP acreage. We currently estimate that our 2020 production will be between 1,100 and 1,150 MMcfe per day. 2020 production levels are expected to be lower than 2019 levels as we have decided to reduce our 2020 capital spending as compared to 2019 levels given relatively low natural gas prices. 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, 2019 and December 31, 2018 and
We reported net loss of $2.0 billion for the year ended December 31, 2017. These costs are reviewed quarterly by management for impairment, with the impairment provision included in the cost2019 as compared to net income 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$430.6 million for the year ended December 31, 2016. No ceiling test2018. This decrease in period-to-period net income was due primarily to a $2.0 billion oil and natural gas properties impairment was recognizedcharge related primarily to the decline in commodity prices, a $260.1 million decrease in income from equity method investments, a $124.8 million decrease in gain on sale of equity method investments, a $63.4 million increase in depreciation, depletion and amortization expense, and a $9.0 million decrease in natural gas, oil and NGL revenues, partially offset by usa $48.6 million increase in gain on debt extinguishment, an $8.6 million decrease in lease operating expenses, a $4.9 million decrease in production taxes, and a $2.0 million decrease in general and administrative expenses for the yearsyear ended December 31, 2019, as compared to the year ended December 31, 2018.
Natural Gas, Oil and NGL Sales
 Years Ended December 31,
 2019 2018 change
 ($ In thousands)
Natural gas918,263
 1,121,815
 (18)%
Oil and condensate117,937
 177,793
 (34)%
NGL101,448
 178,915
 (43)%
Natural gas, oil and NGL revenues$1,137,648
 $1,478,523
 (23)%
The decrease in natural gas sales without the impact of derivatives was primarily due to a 21% decrease in natural gas market prices, partially offset by a 3%increase in natural gas sales volumes.
The decrease in oil and condensate sales without the impact of derivatives was due to a 22% decrease in oil and condensate sales volumes and a 15% decrease in oil and condensate market prices.
The decrease in NGL sales without the impact of derivatives was due to a 33% decrease in NGL market prices and a 15% decrease in NGL sales volumes.
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 Years Ended December 31,
 2019 2018
 ($ In thousands)
Natural gas derivatives - fair value (gains) losses$(89,576) $98,130
Natural gas derivatives - settlement (gains) losses(104,874) 18,000
Total (gains) losses on natural gas derivatives(194,450) 116,130
    
Oil and condensate derivatives - fair value (gains) losses(2,952) (13,546)
Oil and condensate derivatives - settlement (gains) losses(4,083) 26,630
Total (gains) losses on oil and condensate derivatives(7,035) 13,084
    
NGL derivatives - fair value (gains) losses7,541
 (19,533)
NGL derivatives - settlement (gains) losses(14,173) 13,798
Total (gains) losses on NGL derivatives(6,632) (5,735)
    
Contingent consideration arrangement - fair value gains(243) —
Total (gains) losses on natural gas, oil and NGL derivatives$(208,360) $123,479
See Note 12 to our consolidated financial statements for further discussion of our derivative activity.
Lease Operating Expenses
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Lease operating expenses     
Utica$55,839
 $54,347
 3 %
SCOOP18,239
 18,385
 (1)%
WCBB6,941
 14,178
 (51)%
Hackberry1,679
 4,435
 (62)%
Other(1)
300
 295
 2 %
Total lease operating expenses$82,998
 $91,640
 (9)%
      
Lease operating expenses per Mcfe     
Utica$0.14
 $0.14
 2 %
SCOOP0.18
 0.20
 (6)%
WCBB4.87
 3.87
 26 %
Hackberry7.65
 6.57
 16 %
Other(1)
0.79
 0.60
 32 %
Total lease operating expenses per Mcfe$0.17
 $0.18
 (10)%
 _____________________
(1)Includes Niobrara and Bakken
The decrease in total and per unit lease operating expenses ("LOE"), not including production taxes, in 2019 was mainly the result of our divesting of our Louisiana properties which have higher operating costs than our Utica and SCOOP areas.
Production Taxes

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 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Production taxes$28,571
 $33,480
 (15)%
Production taxes per Mcfe$0.06
 $0.07
 (16)%
The decrease in production taxes was primarily related to a decrease in realized prices in 2019 as compared to 2018.
Midstream Gathering and Processing Expenses
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Midstream gathering and processing expenses$291,725
 $290,188
 1 %
Midstream gathering and processing expenses per Mcfe$0.58
 $0.58
 (1)%
Midstream gathering and processing expenses were relatively consistent in 2019 as compared to 2018 on both a total expense basis and 2017.a per unit basis.
Depreciation, Depletion and Amortization
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Depreciation, depletion and amortization$550,108
 $486,664
 13%
Depreciation, depletion and amortization per Mcfe$1.10
 $0.98
 12%
Depreciation, depletion and amortization ("DD&A") expense consisted of $538.9 million in depletion of oil and natural gas properties and $11.2 million in depreciation of other property and equipment in 2019, compared to $476.4 million in depletion of oil and natural gas properties and $10.3 million in depreciation of other property and equipment in 2018. The increase in DD&A was due to an increase in our amount of oil and gas properties subject to amortization and a decrease in our total proved reserves volume used to calculate our total DD&A expense.
Impairment of Oil and Gas Properties. During the year ended December 31, 2019, we had a $2.0 billion oil and natural gas properties impairment charge related primarily to the decline in commodity prices, compared to no impairment charge of oil and gas properties in 2018. If prices of oil, natural gas, oil and natural gas liquidsNGL continue to decline, in the future, weCompany may be required to further write down the value of ourits oil and natural gas properties, which could negatively affect ourits results of operations.
Asset Retirement Obligations. We have obligations to remove equipment and restore land at the end of oil and gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities.Equity Investments
We record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon settlement of the liability or the
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Gain on sale of equity method investments$—
 $(124,768) (100)%
Loss (income) from equity method investments, net$210,148
 $(49,904) (521)%
Gain on sale of equity method investments during 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 year ended 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 consisted 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$96.4 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 gasour interest in Strike Force and natural gas liquids produced$28.3 million from our oil and natural gas properties. Revenue is recordedthe sale of Mammoth Energy common stock. The decrease in the month the product is delivered to the purchaser. We receive payment on substantially all of these salesincome 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 investments is primarily related to a $160.8 million impairment loss related to our shareinvestment in

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Table of investees’ earnings or loss is recognized in the statement of operations.Contents
We review our investmentsIndex to determine ifFinancial Statements

Mammoth Energy and 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$32.4 million impairment loss related to our investment in Grizzly for the year ended December 31, 2019. See Note 4 to our consolidated financial statements for further discussion on our equity investments.
General and Administrative Expenses
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
General and administrative expenses, gross$89,291
 $97,526
 (8)%
Reimbursed from third parties(11,173) (9,820) 14 %
Capitalized general and administrative expenses(30,139) (37,712) (20)%
General and administrative expenses, net$47,979
 $49,994
 (4)%
      
General and administrative expenses, net per Mcfe$0.10
 $0.10
 (5)%
The decrease in total general and administrative expenses, net was due primarily to lower compensation and benefits and cost-focused initiatives.
Restructuring Costs. In the fourth quarter of 2019, we announced and completed a workforce reduction representing approximately 13% of our headcount. In connection with the reduction, we incurred a total charge of approximately $23.1 million.$4.6 million, primarily consisting of one-time employee-related termination benefits, with a remaining liability of $0.2 million at December 31, 2019.
CommitmentsAccretion Expense. Accretion expense decreased to $3.9 million for the year ended December 31, 2019 from $4.1 million for the year ended December 31, 2018, primarily as a result of a decrease in our asset retirement obligation due to the sale of our Louisiana properties.
Interest Expense
 Years Ended December 31,
 2019 2018
 ($ In thousands, except per unit)
Interest expense on senior notes125,687
 129,125
Interest expense on revolving credit agreement12,088
 9,601
Interest expense on construction loan and other1,055
 1,535
Capitalized interest(3,372) (4,470)
Amortization of loan costs6,328
 6,121
Total interest expense$141,786
 $141,912
    
Interest expense per Mcfe$0.28
 $0.29
    
Weighted average debt outstanding under revolving credit facility$161,416
 $83,589
Interest expense was relatively consistent in 2019 as compared to 2018 on both a total expense basis and Contingencies. Liabilitiesa per unit basis. Total weighted debt outstanding under our revolving credit facility was $161.4 million 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 involvedyear ended December 31, 2019 as compared to $83.6 million outstanding under such facility for 2018; however, this increase was largely offset by decreases in certain litigationinterest on our senior notes outstanding for which the outcome is uncertain. Changes in the certainty and the ability2019 as compared to reasonably estimate a loss amount, if any, may result in the recognition and subsequent payment of legal liabilities.2018 due to senior notes repurchases.
Derivative InstrumentsIncome Taxes. We seekrecognized an income tax benefit of $7.6 million million in 2019 compared to reduce our exposure to unfavorable changesan income tax benefit of $69 thousand 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 prices2018. The income tax benefit for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures.
The accounting for changes in the fair value2019 consists mainly of a derivative depends onpartial release of valuation allowance that was

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maintained against our Oklahoma deferred tax asset, as the intended useCompany believes that it can utilize a portion of its Oklahoma state NOL through carrybacks and carryforwards to offset Oklahoma sourced income from 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 statementssale 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.assets.
RESULTS OF OPERATIONS
ResultsLiquidity and Capital Resources
Overview. Historically, our primary sources of Operationscapital funding and liquidity have been our operating cash flow, borrowings under our revolving credit facility and issuances of equity and debt securities. Our ability to access these sources of funds can be significantly impacted by changes in capital markets, decreases in commodity prices and decreases in our production levels.
Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facility, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months.
As of December 31, 2019, we had a cash balance of $6.1 million compared to $52.3 million as of December 31, 2018, and a net working capital deficit of $145.3 million as of December 31, 2019, compared to a net working capital deficit of $223.1 million as of December 31, 2018. As of December 31, 2019, our working capital deficit includes $0.6 million of debt due in the next 12 months. Our total principal debt as of December 31, 2019 was $2.0 billion compared to $2.1 billion as of December 31, 2018. As of December 31, 2019, we had $636.4 million of borrowing capacity available under the revolving credit facility, with outstanding borrowings of $120.0 million and $243.6 million utilized for various letters of credit.  See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our debt obligations, including principal and carrying amounts of our notes.
Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive.
As of December 31, 2019, we had the following open natural gas, oil and NGL derivative instruments:

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Natural Gas Derivatives
Year Type of Derivative Instrument Index Daily Volume (MMBtu/day) 
Weighted
Average Price
2020 Swaps NYMEX Henry Hub 548,000
 $2.88
2020 Basis Swaps Various 70,000
 $(0.12)
2022 Sold Call Options NYMEX Henry Hub 628,000
 $2.90
2023 Sold Call Options NYMEX Henry Hub 628,000
 $2.90
Oil Derivatives
Year Type of Derivative Instrument Index Daily Volume (Bbls/day) 
Weighted
Average Price
2020 Swaps NYMEX WTI 6,000
 $59.82
NGL Derivatives
Year Type of Derivative Instrument Index Daily Volume (Bbls/day) 
Weighted
Average Price
2020 Swaps Mont Belvieu C3 500
 $21.63
See Note 12 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of derivatives and hedging activities.
Credit Facility. We have entered into a senior secured revolving credit facility agreement, 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, 2019, we had a borrowing base of $1.2 billion, with an elected commitment of $1.0 billion, and $120.0 million in borrowings outstanding under our revolving credit facility. Total funds available for borrowing, after giving effect to an aggregate of $243.6 million of letters of credit as of December 31, 2019, were $636.4 million. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries, excluding Grizzly Holdings Inc. ("Grizzly Holdings"), Mule Sky LLC ("Mule Sky") and GRUS, LLC ("GRUS"), guarantee our obligations under our revolving credit facility. Our next borrowing base redetermination is scheduled for the second quarter of 2020.
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 the administrative 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 administrative agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of December 31, 2019, amounts borrowed under our revolving credit facility bore interest at the weighted average rate of 3.30%.
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; agree to payment restrictions affecting our restricted subsidiaries; make investments; undertake fundamental changes including selling all or substantially all of our assets; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; enter into transactions with their affiliates; and engage in certain transactions with restricted subsidiaries. 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 (as defined under the revolving credit agreement) may not be greater than 4.00 to 1.00 for the twelve-month period of the end of each fiscal quarter; and (2) the ratio of EBITDAX to interest expense for the twelve-month period at the end of each fiscal quarter may not be less than 3.00 to 1.00. We were in compliance with these financial covenants at December 31, 2019.

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Senior Notes. In April 2015, we issued an aggregate of $350.0 million in principal amount of our 2023 Notes. Interest on these senior 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. As of December 31, 2019, after giving effect to 2019 open market repurchases of these 2023 Notes, $329.5 million principal amount remained outstanding. 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 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. As of December 31, 2019, after giving effect to 2019 open market repurchases of these 2024 Notes, $603.4 million principal amount remained outstanding. 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 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. As of December 31, 2019, after giving effect to 2019 open market repurchases of these 2025 Notes, $529.5 million principal amount remained outstanding. 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. As of December 31, 2019, after giving effect to 2019 open market repurchases of these 2026 Notes, $397.5 million principal amount remained outstanding. The 2026 Notes will mature on January 15, 2026.
During the year ended December 31, 2019, we used borrowings under our revolving credit facility to repurchase in the open market approximately $190.1 million aggregate principal amount of our outstanding Notes for $138.8 million. This included approximately $20.5 million principal amount of the 2023 Notes, $46.6 million principal amount of the 2024 Notes, $70.5 million principal amount of the 2025 Notes, and $52.5 million principal amount of the 2026 Notes. We recognized a $48.6 million gain on debt extinguishment, which included retirement of unamortized issuance costs and fees associated with the repurchased debt.
We may use a combination of cash and borrowing under our revolving credit facility to retire our outstanding debt, through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.
All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings, Mule Sky or GRUS, and will not be guaranteed by any of our future unrestricted subsidiaries. The guarantees rank equally in the right of payment with all of the senior indebtedness of the subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The 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 Notes.
If we experience a change of control (as defined in the senior note indentures relating to the Notes), we will be required to make an offer to repurchase the 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 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 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 Notes, certain of these covenants are subject to termination upon the occurrence of certain events, including in the event the Notes are ranked as "investment grade."
Construction Loan. On June 4, 2015, we entered into a construction loan agreement (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

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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, 2019, the total borrowings under the construction loan were approximately $22.5 million.
Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2019:
 Payment due by period
Contractual ObligationsTotal Less than 1 year 1-3 years 3-5 years 
More than 5
years
 (In thousands)
Long-term debt(1):
         
Principal$2,002,402
 $631
 $121,357
 $934,380
 $946,034
Interest613,260
 118,428
 236,198
 203,330
 55,304
Firm transportation contracts(2)
3,560,504
 274,813
 573,252
 548,513
 2,163,926
Operating lease liabilities(3)
57,438
 35,045
 22,275
 118
 —
Other15,000
 7,500
 7,500
 —
 —
Total contractual cash obligations(4)
$6,248,604
 $436,417
 $960,582
 $1,686,341
 $3,165,264
_____________________ 
(1)
See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our long-term debt.
(2)
See Note 16 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our firm transportation contracts.
(3)
See Note 9 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease liabilities.
(4)
This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 12 and 3 of the notes to our consolidated financial statements included in Item 8 of this report, respectively.
Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2019, our material off-balance sheet arrangements and transactions include $243.6 million in letters of credit outstanding against our revolving credit facility and $105.1 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance on certain firm transportation agreements. Management believes these items will expire without being funded. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 17 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.
Capital Expenditures. Our capital commitments have been primarily for the execution of our drilling programs, share repurchases, and discounted repurchases of our senior notes. Our capital investment strategy is focused on prudently developing our existing properties in an effort to generate sustainable cash flow considering current and forecasted commodity prices while also selectively pursuing mergers or acquisitions in our current operating regions in an effort to gain scale and deepen our drilling inventory.
Our capital expenditures for 2020 are currently estimated to be in the range of $265.0 million to $285.0 million for drilling and completion expenditures. In addition, we currently expect to spend $20.0 million to $25.0 million in 2020 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale. The midpoint of the 2020 range of capital expenditures is 51% lower than the $602.5 million spent in 2019, primarily due to our decision to reduce capital activity in response to lower commodity prices, specifically natural gas prices, and our desire to fund our capital development program primarily with cash flow from operations. As a result of our decreased capital spending program for 2020 and the impact of our 2019 property divestitures, we expect our volumes in 2020 to be approximately 18% lower than 2019. Coupled with forecasted lower commodity prices, we expect 2020 revenues, operating cash flows and EBITDA to be lower in 2020 as compared to 2019.

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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 have the ability to react quickly to changing commodity prices and accelerate or decelerate our activity within our operating areas as market conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels or our capital or other costs increase we may be required to obtain additional funds which we would seek to do through borrowings, offerings of debt or equity securities or other means, including the sale of assets. We regularly evaluate merger, acquisition and divestiture opportunities. Capital may not be available to us on acceptable terms or at all in the future. 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 formakes it extremely difficult to predict future oil and natural gas have historically been,price movements with any certainty. During 2018, WTI prices ranged from $44.48 to $77.41 per barrel and will continuethe Henry Hub spot market price of natural gas ranged from $2.49 to be, volatile. Prices for$6.24 per MMBtu. During 2019, WTI prices ranged from $46.31 to $66.24 per barrel and the Henry Hub spot market price of natural gas ranged from $1.75 to $4.25 per MMBtu. If the prices of oil and natural gas may fluctuate in response to relatively minor changes in supplydecline further, our operations, financial condition and demand, market uncertainty and a varietylevel of factors beyond our control.

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The following table presents our production volumes, average prices received and average production costs during the periods indicated:
 2018 2017 2016
 ($ In thousands)
Natural gas sales     
Natural gas production volumes (MMcf)443,742
 350,061
 227,594
      
Total natural gas sales$1,121,815
 $845,999
 $420,128
      
Natural gas sales without the impact of derivatives ($/Mcf)$2.53
 $2.42
 $1.85
Impact from settled derivatives ($/Mcf)$(0.04) $0.07
 $0.60
Average natural gas sales price, including settled derivatives ($/Mcf)$2.49
 $2.49
 $2.45
      
Oil and condensate sales     
Oil and condensate production volumes (MBbls)2,801
 2,579
 2,126
      
Total oil and condensate sales$177,793
 $124,568
 $81,173
      
Oil and condensate sales without the impact of derivatives ($/Bbl)$63.48
 $48.29
 $38.18
Impact from settled derivatives ($/Bbl)$(9.51) $1.59
 $5.11
Average oil and condensate sales price, including settled derivatives ($/Bbl)$53.97
 $49.88
 $43.29
      
Natural gas liquids sales     
Natural gas liquids production volumes (MGal)251,720
 224,038
 161,562
      
Total natural gas liquids sales$178,915
 $136,057
 $59,115
      
Natural gas liquids sales without the impact of derivatives ($/Gal)$0.71
 $0.61
 $0.37
Impact from settled derivatives ($/Gal)$(0.05) $(0.03) $(0.01)
Average natural gas liquids sales price, including settled derivatives ($/Gal)$0.66
 $0.58
 $0.36
      
Natural gas, oil and condensate and natural gas liquids sales     
Natural gas equivalents (MMcfe)496,505
 397,543
 263,430
      
Total natural gas, oil and condensate and natural gas liquids sales$1,478,523
 $1,106,624
 $560,416
      
Natural gas, oil and condensate and natural gas liquids sales without the impact of derivatives ($/Mcfe)$2.98
 $2.78
 $2.13
Impact from settled derivatives ($/Mcfe)$(0.12) $0.07
 $0.56
Average natural gas, oil and condensate and natural gas liquids sales price, including settled derivatives ($/Mcfe)$2.86
 $2.85
 $2.69
      
Production Costs:     
Average production costs ($/Mcfe)$0.18
 $0.20
 $0.26
Average production taxes ($/Mcfe)$0.07
 $0.05
 $0.05
Average midstream gathering and processing ($/Mcfe)$0.58
 $0.63
 $0.63
Total production costs, midstream costs and production taxes ($/Mcfe)$0.83
 $0.88
 $0.94

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The total volume hedged for 2018, 2017 and 2016 represented approximately 78%, 68% and 77%, respectively, of our total sales volumesexpenditures 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 Shaleoil and SCOOP acreage. From 2016natural 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 2017,make substantial downward adjustments to our net equivalent gasestimated proved reserves. If this occurs or if our production increased 51% from 263,430 MMcfeestimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to 397,543 MMcfe primarilywrite down, as a result ofnon-cash charge to earnings, the continued developmentcarrying value of our Utica Shale acreageoil and natural gas properties. Reductions in commodity prices and/or our reserves could also negatively impact the acquisition ofborrowing base under our SCOOP acreage. We currently estimate thatrevolving credit facility, which could limit our 2019 production will be between 496,400liquidity and 511,000 MMcfe. However, our actual production may be different dueability to changes in our currently anticipated drilling and recompletion activities, changing economic climate, adverse weather conditions or other unforeseen events. fund development activities.
See Item 1A. "Risk Factors."
Comparison of the Years Ended7A. "Quantitative and Qualitative Disclosures about Market Risk" for information regarding our open fixed price swaps at December 31, 2018 and December 31, 20172019.
We reported net income of $430.6Cash Flow from Operating Activities. Net cash flow provided by operating activities was $724.0 million for the year ended December 31, 20182019 as compared to net income of $435.2$786.3 million for the year ended December 31, 2017.2018. 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 volumesa decrease in the Utica Shale and SCOOP resultingcash receipts 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

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million for 2017. This increase waspurchasers due to an increase in our production and our full cost pool and a 23% decrease in our total proved reserves volume usednet revenues after giving effect 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,settled derivative instruments, partially offset by a decrease in consulting fees. However, duringour operating expenses.
Divestitures. During 2019, we divested certain non-core assets and interests in operated and non-operated oil and natural gas properties for approximately $48.5 million. Proceeds from these transactions were primarily used to repay debt and fund our development program. See Note 2 of the year ended December 31, 2018, we decreasednotes to our per unit generalconsolidated financial statements included in Item 8 of this report for further discussion.
Uses of Funds. The following table presents the uses of our cash 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 millioncash equivalents 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 2017.2019 and 2018:
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
 Years Ended December 31,
 2019 2018
 (In thousands)
Oil and Natural Gas Property Expenditures:   
Drilling and completion costs654,407
 713,031
Leasehold acquisitions39,664
 125,585
Other25,986
 60,467
Total oil and natural gas property expenditures720,057
 899,083
Other Uses of Cash and Cash Equivalents   
Cash paid to repurchase senior notes138,786
 —
Cash paid to repurchase common stock30,688
 200,251
Additions to other property and equipment5,021
 7,870
Contributions to equity method investments432
 2,319
Other288
 831
Total other uses of cash and cash equivalents$175,215
 $211,271
Total uses of cash and cash equivalents$895,272
 $1,110,354
Drilling and Completion Costs. Lease operating expenses, or LOE, not including production taxes increased to $80.2 million for the year ended December 31, 2017During 2019, we spud 16 gross (14.6 net) and commenced sales 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 volumes47 gross (41.6 net) wells in the Utica Shale resultingfor a total cost of approximately $318.3 million. In addition, five gross (0.9 net) wells were spud and 14 gross (3.3 net) wells were turned to sales by other operators on our Utica Shale acreage during 2019 for a total cost to us of approximately $44.2 million.
During 2019, we spud 10 gross (8.6 net) and commenced sales from our 201714 gross (12.6 net) wells in the SCOOP for a total cost of approximately $124.8 million. In addition, 42 gross (1.6 net) wells were spud and 2016 drilling activities, as well as production volumes resulting from39 gross (1.2 net) wells were turned to sales by other operators on our SCOOP acquisition in February 2017.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization, or DD&A, expense increasedacreage during 2019 for a total cost 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 forwardus 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.$14.6 million.
Liquidity and Capital Resources
Overview. Historically, our primary sources of fundscapital funding and liquidity have been our operating cash flow, from our producing oil and natural gas properties, borrowings under our revolving credit facility and issuances of equity and debt securities. Our ability to access any of these sources of funds can be significantly impacted by changes in capital markets, decreases in commodity prices and decreases in our production levels.
Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facility, we expect to be able to fund our planned capital expenditures, meet our debt service requirements and fund our other commitments and obligations for the next 12 months.
As of December 31, 2019, we had a cash balance of $6.1 million compared to $52.3 million as of December 31, 2018, and a net working capital deficit of $145.3 million as of December 31, 2019, compared to a net working capital deficit of $223.1 million as of December 31, 2018. As of December 31, 2019, our working capital deficit includes $0.6 million of debt due in the next 12 months. Our total principal debt as of December 31, 2019 was $2.0 billion compared to $2.1 billion as of December 31, 2018. As of December 31, 2019, we had $636.4 million of borrowing capacity available under the revolving credit facility, with outstanding borrowings of $120.0 million and $243.6 million utilized for various letters of credit.  See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our debt obligations, including principal and carrying amounts of our notes.
Derivatives and Hedging Activities. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, prices or oil and NGL derivative activities, when combined with our sales of natural gas, production.oil and NGL, allow us to predict with greater certainty the total revenue we will receive.

As of December 31, 2019, we had the following open natural gas, oil and NGL derivative instruments:

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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.
Natural Gas Derivatives
Year Type of Derivative Instrument Index Daily Volume (MMBtu/day) 
Weighted
Average Price
2020 Swaps NYMEX Henry Hub 548,000
 $2.88
2020 Basis Swaps Various 70,000
 $(0.12)
2022 Sold Call Options NYMEX Henry Hub 628,000
 $2.90
2023 Sold Call Options NYMEX Henry Hub 628,000
 $2.90
Oil Derivatives
Year Type of Derivative Instrument Index Daily Volume (Bbls/day) 
Weighted
Average Price
2020 Swaps NYMEX WTI 6,000
 $59.82
NGL Derivatives
Year Type of Derivative Instrument Index Daily Volume (Bbls/day) 
Weighted
Average Price
2020 Swaps Mont Belvieu C3 500
 $21.63
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 portionSee Note 12 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 (priornotes to our saleconsolidated financial statements included in Item 8 of our equity interest in Strike Force in May 2018), netthis report for further discussion 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 operationsderivatives and proceeds from our 2016 equity and debt offerings and our 2017 debt offering for our investinghedging 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 agreement, 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, 2018,2019, we had a borrowing base of $1.4$1.2 billion, with an elected commitment of $1.0 billion, and $45.0$120.0 million in borrowings outstanding under our revolving credit facility. Total funds available for borrowing, after giving effect to an aggregate of $316.6$243.6 million of letters of credit as of December 31, 2019, were $638.4$636.4 million. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries, excluding Grizzly Holdings Inc. ("Grizzly Holdings"), Mule Sky LLC ("Mule Sky") and GRUS, LLC ("GRUS"), guarantee our obligations under our revolving credit facility.

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2020.
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 the administrative 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 administrative agent shall inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. As of December 31, 2018,2019, amounts borrowed under our revolving credit facility bore interest at the weighted average rate of 4.23%3.30%.
Our revolving credit facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries'subsidiaries’ ability to: incur indebtedness; grant liens; pay dividends and make other restricted payments; agree to payment restrictions affecting our restricted subsidiaries; make investments; makeundertake fundamental changes;changes including selling all or substantially all of our assets; enter into swap contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates.affiliates; and engage in certain transactions with restricted subsidiaries. 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(as defined under 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 periodrevolving credit agreement) may not be greater than 4.00 to 1.00;1.00 for the twelve-month period of the end of each fiscal quarter; and (2) the ratio of EBITDAX to interest expense for athe twelve-month period at the end of each fiscal quarter may not be less than 3.00 to 1.00. We were in compliance with these financial covenants at December 31, 2018.2019.

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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 Notesthese senior 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.year. As of December 31, 2019, after giving effect to 2019 open market repurchases of these 2023 Notes, $329.5 million principal amount remained outstanding. 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.year. As of December 31, 2019, after giving effect to 2019 open market repurchases of these 2024 Notes, $603.4 million principal amount remained outstanding. 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.year. As of December 31, 2019, after giving effect to 2019 open market repurchases of these 2025 Notes, $529.5 million principal amount remained outstanding. 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.year. As of December 31, 2019, after giving effect to 2019 open market repurchases of these 2026 Notes, $397.5 million principal amount remained outstanding. The 2026 Notes will mature on January 15, 2026. We received
During the year ended December 31, 2019, we used borrowings under our revolving credit facility to repurchase in the open market approximately $444.1$190.1 million in net proceeds fromaggregate principal amount of our outstanding Notes for $138.8 million. This included approximately $20.5 million principal amount of the offering2023 Notes, $46.6 million principal amount of the 2024 Notes, $70.5 million principal amount of the 2025 Notes, and $52.5 million principal amount of the 2026 Notes,Notes. We recognized a portion$48.6 million gain on debt extinguishment, which included retirement of which was used to repay allunamortized issuance costs and fees associated with the repurchased debt.
We may use a combination of our outstanding borrowingscash and borrowing under our secured revolving credit facility on October 11, 2017 and the balance was used to fund the remaining outspend relatedretire our outstanding debt, through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to our 2017 capital development plans.do so.
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.Mule Sky or GRUS, 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 toto: incur or guarantee additional indebtedness,indebtedness; make certain investments,investments; declare or pay dividends or make distributions on capital stock,stock; prepay subordinated indebtedness,indebtedness; sell assets, including capital stock of restricted subsidiaries,subsidiaries; agree to payment restrictions affecting our restricted subsidiaries,subsidiaries; consolidate, merge, sell or otherwise dispose of all or substantially all of our assets,assets; enter into transactions with affiliates,affiliates; incur liens,liens; engage in business other than the oil and gas businessbusiness; 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.grade."
Construction Loan. On June 4, 2015, we entered into a construction loan agreement or the construction loan,(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

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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, 2018,2019, the total borrowings under the construction loan were approximately $23.1$22.5 million.
Contractual and Commercial Obligations. The following table sets forth our contractual and commercial obligations at December 31, 2019:
 Payment due by period
Contractual ObligationsTotal Less than 1 year 1-3 years 3-5 years 
More than 5
years
 (In thousands)
Long-term debt(1):
         
Principal$2,002,402
 $631
 $121,357
 $934,380
 $946,034
Interest613,260
 118,428
 236,198
 203,330
 55,304
Firm transportation contracts(2)
3,560,504
 274,813
 573,252
 548,513
 2,163,926
Operating lease liabilities(3)
57,438
 35,045
 22,275
 118
 —
Other15,000
 7,500
 7,500
 —
 —
Total contractual cash obligations(4)
$6,248,604
 $436,417
 $960,582
 $1,686,341
 $3,165,264
_____________________ 
(1)
See Note 5 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our long-term debt.
(2)
See Note 16 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our firm transportation contracts.
(3)
See Note 9 of the notes to our consolidated financial statements included in Item 8 of this report for a description of our operating lease liabilities.
(4)
This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 12 and 3 of the notes to our consolidated financial statements included in Item 8 of this report, respectively.
Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2019, our material off-balance sheet arrangements and transactions include $243.6 million in letters of credit outstanding against our revolving credit facility and $105.1 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance on certain firm transportation agreements. Management believes these items will expire without being funded. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 17 to our consolidated financial statements for further discussion of the various financial guarantees we have issued.
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 2017share repurchases, and for investments in entities that may provide services to facilitate the developmentdiscounted repurchases of our acreage.senior notes. Our capital investment strategy is to continue to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploitfocused on prudently developing 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 ofgenerate sustainable cash flow considering current and forecasted commodity prices while also selectively pursuing mergers or acquisitions in 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 stockcurrent operating regions in an underwritten public offeringeffort to gain scale 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, throughdeepen 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.drilling inventory.
Our total capital expenditures for 20192020 are currently estimated to be in the range of $525.0$265.0 million to $550.0$285.0 million for drilling and completion expenditures. In addition, we currently expect to spend $40.0$20.0 million to $50.0$25.0 million in 20192020 for non-drilling and completion expenditures, which includes acreage expenses, primarily lease extensions in the Utica Shale. The 2019midpoint of the 2020 range of capital expenditures is 51% lower than the $814.7$602.5 million spent in 2018,2019, primarily due to the decreaseour decision to reduce capital activity in currentresponse to lower 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 opportunisticallyprimarily with available funds primarily from cash flow from operationsoperations. As a result of our decreased capital spending program for 2020 and salethe impact of non-core assets while maintaining sufficient liquidityour 2019 property divestitures, we expect our volumes in 2020 to fund our capital development programs.be approximately 18% lower than 2019. Coupled with forecasted lower commodity prices, we expect 2020 revenues, operating cash flows and EBITDA to be lower in 2020 as compared to 2019.

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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 wellhave the ability to react quickly to changing commodity prices and accelerate or decelerate our activity within the Utica Basin and the SCOOPour operating areas as the market conditions warrant. Notwithstanding the foregoing, in the event commodity prices decline from current levels or 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 newmerger, acquisition and divestiture opportunities. Needed capitalCapital may not be available to us on acceptable terms or at all.all in the future. 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
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. During 2019, WTI prices ranged from $46.31 to $66.24 per barrel and the Henry Hub spot market price of natural gas ranged from $1.75 to $4.25 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 commodity prices and/or 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 andfund development activities.
See Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" for information regarding our open fixed price swaps at December 31, 2018.2019.
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 yearCash Flow from Operating Activities. Net cash flow provided by operating activities was $724.0 million 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, 2018,2019 as compared to $786.3 million for 2018. This decrease was primarily the result of a decrease in cash receipts from our oil and repurchased 20.7 million sharesnatural gas purchasers due to a 23% decrease in net revenues after giving effect to settled derivative instruments, partially offset by a decrease in our operating expenses.
Divestitures. During 2019, we divested certain non-core assets and interests in operated and non-operated oil and natural gas properties for approximately $48.5 million. Proceeds from these transactions were primarily used to repay debt and fund our development program. See Note 2 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion.
Uses of Funds. The following table presents the uses of our cash and cash equivalents for the years ended December 31, 2019 and 2018:

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 Years Ended December 31,
 2019 2018
 (In thousands)
Oil and Natural Gas Property Expenditures:   
Drilling and completion costs654,407
 713,031
Leasehold acquisitions39,664
 125,585
Other25,986
 60,467
Total oil and natural gas property expenditures720,057
 899,083
Other Uses of Cash and Cash Equivalents   
Cash paid to repurchase senior notes138,786
 —
Cash paid to repurchase common stock30,688
 200,251
Additions to other property and equipment5,021
 7,870
Contributions to equity method investments432
 2,319
Other288
 831
Total other uses of cash and cash equivalents$175,215
 $211,271
Total uses of cash and cash equivalents$895,272
 $1,110,354
Drilling and Completion Costs. During 2019, we spud 16 gross (14.6 net) and commenced sales from 47 gross (41.6 net) wells in the Utica Shale for a total cost of approximately $200.0$318.3 million. In Januaryaddition, five gross (0.9 net) wells were spud and 14 gross (3.3 net) wells were turned to sales by other operators on our Utica Shale acreage during 2019 for a total cost to us of approximately $44.2 million.
During 2019, we spud 10 gross (8.6 net) and commenced sales from 14 gross (12.6 net) wells in the SCOOP for a total cost of approximately $124.8 million. In addition, 42 gross (1.6 net) wells were spud and 39 gross (1.2 net) wells were turned to sales by other operators on our boardSCOOP acreage during 2019 for a total cost to us of directors approved a stock repurchase program to acquire up to $400.0 millionapproximately $14.6 million.
Results 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,Operations
The markets for oil and natural gas have historically been, and will likely continue to be, subjectvolatile. Prices for oil and natural gas may fluctuate in response to relatively minor changes in supply and demand, market conditions, applicable legal requirements, contractual obligationsuncertainty and other factors. The repurchase program does not require the Company to acquire any specifica variety of factors beyond our control.


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numberThe following table presents our production volumes, average prices received and average production costs during the periods indicated:
 Years Ended December 31,
 2019 2018
 (In thousands, unless otherwise stated)
Natural gas sales   
Natural gas production volumes (MMcf)458,178
 443,742
    
Total natural gas sales$918,263
 $1,121,815
    
Natural gas sales without the impact of derivatives ($/Mcf)$2.00
 $2.53
Impact from settled derivatives ($/Mcf)$0.23
 $(0.04)
Average natural gas sales price, including settled derivatives ($/Mcf)$2.23
 $2.49
    
Oil and condensate sales   
Oil and condensate production volumes (Mbbls)2,186
 2,801
    
Total oil and condensate sales$117,937
 $177,793
    
Oil and condensate sales without the impact of derivatives ($/Bbl)$53.95
 $63.48
Impact from settled derivatives ($/Bbl)$1.86
 $(9.51)
Average oil and condensate sales price, including settled derivatives ($/Bbl)$55.81
 $53.97
    
NGL sales   
NGL production volumes (MGal)213,129
 251,720
    
Total NGL sales$101,448
 $178,915
    
NGL sales without the impact of derivatives ($/Gal)$0.48
 $0.71
Impact from settled derivatives ($/Gal)$0.06
 $(0.05)
Average NGL price, including settled derivatives ($/Gal)$0.54
 $0.66
    
Natural gas, oil and condensate and NGL sales   
Natural gas equivalents (MMcfe)501,742
 496,505
    
Total natural gas, oil and condensate and NGL sales$1,137,648
 $1,478,523
    
Natural gas, oil and condensate and NGL sales without the impact of derivatives ($/Mcfe)$2.27
 $2.98
Impact from settled derivatives ($/Mcfe)$0.24
 $(0.12)
Average natural gas, oil and condensate and NGL sales price, including settled derivatives ($/Mcfe)$2.51
 $2.86
    
Production Costs:   
Average production costs ($/Mcfe)$0.17
 $0.18
Average production taxes ($/Mcfe)$0.06
 $0.07
Average midstream gathering and processing ($/Mcfe)$0.58
 $0.58
Total production costs, midstream costs and production taxes ($/Mcfe)$0.81
 $0.83

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The Company intendstotal natural gas, oil and NGL volumes hedged for 2019 and 2018 represented approximately 96% and 78%, respectively, of our total sales volumes for the applicable year.
From 2018 to purchase shares under2019, our net equivalent gas production increased 1% from 1,360 MMcfe per day to 1,375 MMcfe per day primarily as a result of our continued development of our Utica Shale and SCOOP acreage. We currently estimate that our 2020 production will be between 1,100 and 1,150 MMcfe per day. 2020 production levels are expected to be lower than 2019 levels as we have decided to reduce our 2020 capital spending as compared to 2019 levels given relatively low natural gas prices. 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 repurchase program opportunistically with available funds while maintaining sufficient liquidity to fund its 2019 capital development program. This repurchase program is authorized to extend throughYears Ended December 31, 20202019 and may be suspended from time to time, modified, extended or discontinued by the boardDecember 31, 2018
We reported net loss of directors of the Company at any time. We did not make any purchases of our common stock during$2.0 billion for 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 at2019 as compared to net income of $430.6 million for the year ended December 31, 2018:2018. This decrease in period-to-period net income was due primarily to a $2.0 billion oil and natural gas properties impairment charge related primarily to the decline in commodity prices, a $260.1 million decrease in income from equity method investments, a $124.8 million decrease in gain on sale of equity method investments, a $63.4 million increase in depreciation, depletion and amortization expense, and a $9.0 million decrease in natural gas, oil and NGL revenues, partially offset by a $48.6 million increase in gain on debt extinguishment, an $8.6 million decrease in lease operating expenses, a $4.9 million decrease in production taxes, and a $2.0 million decrease in general and administrative expenses for the year ended December 31, 2019, as compared to the year ended December 31, 2018.
Natural Gas, Oil and NGL Sales
 Payment due by period
Contractual ObligationsTotal Less than 1 year 1-3 years 3-5 years 
More than 5
years
 (In thousands)
Revolving credit agreement (1)$45,000
 $—
 $45,000
 $—
 $—
6.625% senior unsecured notes due 2023 (2)454,344
 23,188
 46,375
 384,781
 —
6.000% senior unsecured notes due 2024 (3)884,101
 39,000
 78,000
 78,000
 689,101
6.375% senior unsecured notes due 2025 (4)848,748
 38,250
 76,500
 76,500
 657,498
6.375% senior unsecured notes due 2026 (5)665,156
 28,687
 57,375
 57,375
 521,719
Asset retirement obligations (6)79,952
 —
 —
 —
 79,952
Building loan (7)23,149
 651
 1,290
 1,416
 19,792
Firm transportation contracts3,504,318
 251,644
 494,201
 490,972
 2,267,501
Drilling and purchase obligations (8)204,969
 89,022
 115,947
 —
 —
Operating leases271
 144
 127
 —
 —
Total$6,710,008
 $470,586
 $914,815
 $1,089,044
 $4,235,563
 Years Ended December 31,
 2019 2018 change
 ($ In thousands)
Natural gas918,263
 1,121,815
 (18)%
Oil and condensate117,937
 177,793
 (34)%
NGL101,448
 178,915
 (43)%
Natural gas, oil and NGL revenues$1,137,648
 $1,478,523
 (23)%
_____________________ The decrease in natural gas sales without the impact of derivatives was primarily due to a 21% decrease in natural gas market prices, partially offset by a 3%increase in natural gas sales volumes.

The decrease in oil and condensate sales without the impact of derivatives was due to a 22% decrease in oil and condensate sales volumes and a 15% decrease in oil and condensate market prices.
(1) Does not include future loan advances, repayments, commitment fees or other fees on our revolving credit facility as we cannot determine with accuracyThe decrease in NGL sales without the timingimpact of such items. Additionally, this table does not include interest expense as it isderivatives was due to a floating rate instrument33% decrease in NGL market prices and we cannot determine with accuracy the future interest rates to be charge.a 15% decrease in NGL sales volumes.
(2) Includes estimated interest of $23.2 million due in less than one year; $46.4 million due in 1-3 yearsNatural Gas, Oil and $34.8 million due in 3-5 years.NGL Derivatives
(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.
 Years Ended December 31,
 2019 2018
 ($ In thousands)
Natural gas derivatives - fair value (gains) losses$(89,576) $98,130
Natural gas derivatives - settlement (gains) losses(104,874) 18,000
Total (gains) losses on natural gas derivatives(194,450) 116,130
    
Oil and condensate derivatives - fair value (gains) losses(2,952) (13,546)
Oil and condensate derivatives - settlement (gains) losses(4,083) 26,630
Total (gains) losses on oil and condensate derivatives(7,035) 13,084
    
NGL derivatives - fair value (gains) losses7,541
 (19,533)
NGL derivatives - settlement (gains) losses(14,173) 13,798
Total (gains) losses on NGL derivatives(6,632) (5,735)
    
Contingent consideration arrangement - fair value gains(243) —
Total (gains) losses on natural gas, oil and NGL derivatives$(208,360) $123,479
See Note 1012 to our consolidated financial statements for further discussion of our derivative activity.
Lease Operating Expenses
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Lease operating expenses     
Utica$55,839
 $54,347
 3 %
SCOOP18,239
 18,385
 (1)%
WCBB6,941
 14,178
 (51)%
Hackberry1,679
 4,435
 (62)%
Other(1)
300
 295
 2 %
Total lease operating expenses$82,998
 $91,640
 (9)%
      
Lease operating expenses per Mcfe     
Utica$0.14
 $0.14
 2 %
SCOOP0.18
 0.20
 (6)%
WCBB4.87
 3.87
 26 %
Hackberry7.65
 6.57
 16 %
Other(1)
0.79
 0.60
 32 %
Total lease operating expenses per Mcfe$0.17
 $0.18
 (10)%
 _____________________
(1)Includes Niobrara and Bakken
The decrease in total and per unit lease operating expenses ("LOE"), not including production taxes, in 2019 was mainly the revenue standard.result of our divesting of our Louisiana properties which have higher operating costs than our Utica and SCOOP areas.
In February 2016,Production Taxes

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 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Production taxes$28,571
 $33,480
 (15)%
Production taxes per Mcfe$0.06
 $0.07
 (16)%
The decrease in production taxes was primarily related to a decrease in realized prices in 2019 as compared to 2018.
Midstream Gathering and Processing Expenses
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Midstream gathering and processing expenses$291,725
 $290,188
 1 %
Midstream gathering and processing expenses per Mcfe$0.58
 $0.58
 (1)%
Midstream gathering and processing expenses were relatively consistent in 2019 as compared to 2018 on both a total expense basis and a per unit basis.
Depreciation, Depletion and Amortization
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Depreciation, depletion and amortization$550,108
 $486,664
 13%
Depreciation, depletion and amortization per Mcfe$1.10
 $0.98
 12%
Depreciation, depletion and amortization ("DD&A") expense consisted of $538.9 million in depletion of oil and natural gas properties and $11.2 million in depreciation of other property and equipment in 2019, compared to $476.4 million in depletion of oil and natural gas properties and $10.3 million in depreciation of other property and equipment in 2018. The increase in DD&A was due to an increase in our amount of oil and gas properties subject to amortization and a decrease in our total proved reserves volume used to calculate our total DD&A expense.
Impairment of Oil and Gas Properties. During the FASB issued ASU No. 2016-02, Leases (Topic 842). The standard supersedes the previous lease guidance by requiring lessees to recognizeyear ended December 31, 2019, we had a right-to-use asset$2.0 billion oil and lease liability on the balance sheet for all leases with lease terms of greater than one year while maintaining substantially similar classifications for financing and operating leases. The guidance is effective for periods after December 15, 2018, and we will adopt beginning January 1, 2018 using the transition method permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, issued in August 2018, which permits an entity to recognize a cumulative-effect adjustmentnatural gas properties impairment charge related primarily to the opening balancedecline in commodity prices, compared to no impairment charge of retained earningsoil and gas properties in 2018. If prices of natural gas, oil and NGL continue to decline, the periodCompany may be required to further write down the value of adoption with no adjustment made toits oil and natural gas properties, which could negatively affect its results of operations.
Equity Investments
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
Gain on sale of equity method investments$—
 $(124,768) (100)%
Loss (income) from equity method investments, net$210,148
 $(49,904) (521)%
Gain on sale of equity method investments during 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 componentsyear ended December 31, 2018 consisted of $96.4 million from the associated lease componentsale of our interest in Strike Force and instead,$28.3 million from the sale of Mammoth Energy common stock. The decrease in income from equity method investments is primarily related to accounta $160.8 million impairment loss related to our investment in

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Mammoth Energy and a $32.4 million impairment loss related to our investment in Grizzly for those components as a single component if the non-lease components would be accounted for under ASC 606 and other conditions are met.
We have identified our portfolio of leased assets under the new standard and has evaluated the impact of this guidance onyear ended December 31, 2019. See Note 4 to our consolidated financial statements for further discussion on our equity investments.
General and related disclosures. Offsetting right-of-use assetsAdministrative Expenses
 Years Ended December 31,
 2019 2018 change
 ($ In thousands, except per unit)
General and administrative expenses, gross$89,291
 $97,526
 (8)%
Reimbursed from third parties(11,173) (9,820) 14 %
Capitalized general and administrative expenses(30,139) (37,712) (20)%
General and administrative expenses, net$47,979
 $49,994
 (4)%
      
General and administrative expenses, net per Mcfe$0.10
 $0.10
 (5)%
The decrease in total general and corresponding lease liabilitiesadministrative expenses, net was due primarily to lower compensation and benefits and cost-focused initiatives.
Restructuring Costs. In the fourth quarter of 2019, we announced and completed a workforce reduction representing approximately 13% of our headcount. In connection with the reduction, we incurred a total charge of approximately $4.6 million, primarily consisting of one-time employee-related termination benefits, with a remaining liability of $0.2 million at December 31, 2019.
Accretion Expense. Accretion expense decreased to $3.9 million for the year ended December 31, 2019 from $4.1 million for the year ended December 31, 2018, primarily as a result of a decrease in our asset retirement obligation due to the sale of our Louisiana properties.
Interest Expense
 Years Ended December 31,
 2019 2018
 ($ In thousands, except per unit)
Interest expense on senior notes125,687
 129,125
Interest expense on revolving credit agreement12,088
 9,601
Interest expense on construction loan and other1,055
 1,535
Capitalized interest(3,372) (4,470)
Amortization of loan costs6,328
 6,121
Total interest expense$141,786
 $141,912
    
Interest expense per Mcfe$0.28
 $0.29
    
Weighted average debt outstanding under revolving credit facility$161,416
 $83,589
Interest expense was relatively consistent in 2019 as compared to 2018 on both a total expense basis and a per unit basis. Total weighted debt outstanding under our revolving credit facility was $161.4 million for the year ended December 31, 2019 as compared to $83.6 million outstanding under such facility for 2018; however, this increase was largely offset by decreases in interest on our senior notes outstanding for 2019 as compared to 2018 due to senior notes repurchases.
Income Taxes. We recognized an income tax benefit of $7.6 million million in 2019 compared to an income tax benefit of $69 thousand in 2018. The income tax benefit for 2019 consists mainly of a partial release of valuation allowance that was

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maintained against our Oklahoma deferred tax asset, as the Company believes that it can utilize a portion of its Oklahoma state NOL through carrybacks and carryforwards to offset Oklahoma sourced income from the sale of assets.
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors.
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.
Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.
We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by usthe SEC on a quarterly basis. This quarterly review is referred to as a ceiling test.
Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the adoption date totaled approximately $110 million, representing minimum payment obligations associated with identified leases with contractual durations longer than one year. Adoptionfirst day of each month within the new standard will not result in12-month period ended December 31, 2019. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices can have a material impact toon the consolidated statementpresent value of operations. We have implemented processes and controls needed to comply with the requirementsestimated future net revenues. Any excess of the new standard, which includesnet book value, less deferred income taxes, is generally written off as an expense. During the implementationyear ended December 31, 2019 we recorded impairments of a lease accounting software solution to support lease portfolio managementour oil 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 presentednatural gas properties in the statementamount 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$2.0 billion. No such impairments were required for the year ended December 31, 2018. As a resultSee Oil and Natural Gas Properties in Note 1 of the adoption, $185.0 millionnotes to our consolidated financial statements included in restricted cash was removedItem 8 of this report for further information on the full cost method of accounting.
Oil, Natural Gas and NGL Reserves. Estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from net cash usedour estimates. See Note 19 included in investing resulting in an increaseItem 8 of this report for further information.
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 ending cash balancefuture 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, 2019, a valuation allowance of $647.6 million had been established for the year ended December 31, 2016. The adoption also resultednet deferred tax asset.
Revenue Recognition. We derive almost all of our revenue from the sale of natural gas, crude oil and NGL produced from our oil and natural gas properties. Revenue is recorded in an addition of $185.0 million in restricted cashthe month the product is delivered to the net cash usedpurchaser. 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 received have not significantly deviated from our accruals.

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Investments—Equity Method. Investments in investing activitiesentities 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 currently account for our investments in Mammoth Energy Services, Inc. ("Mammoth Energy") and Grizzly Oil Sands ULC ("Grizzly") using the equity method.
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 charge.
Derivative Instruments. We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL 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 year ended December 31, 2017. This additionunderlying 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 decrease to ending cash was offset by the increase to beginning cash balance of $185.0 million due todesignation. Our current commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, the changes at December 31, 2016. Therefore, there was no net impactin fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on the statementderivatives are included in cash flows from operating activities.
See Item 7A. "Natural Gas, Oil and NGL Derivatives" for a summary of cash flowsour derivative instruments in place as of December 31, 2017.2019.
In January 2017, the FASB issued ASU No. 2017-01, Clarifying the DefinitionDisclosures About Effects of a Business. Under the current business combination guidance, thereTransactions with Related parties
Our equity method investees are three elements of a business: inputs, processesconsidered related parties. See Notes 4, 9 and outputs. The revised guidance adds an initial screen test to determine if substantially all15 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 necessarynotes 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 Requirementsincluded in Item 8 of this report 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 impactfurther discussion of the ASU ontransactions with 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.method investees.
ITEM 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Natural Gas, Oil and Natural Gas Liquids Derivative Instruments. Our revenues, operating results profitability, future rate of growthoperations and the carrying valuecash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.
Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse natural gas, oil and NGL price changes is to hedge into strengthening natural gas, oil and NGL futures markets when prices reach levels that management believes are unsustainable for the long term, have material downside risk in the short term or provide reasonable rates of return on our invested capital. Information we consider in forming an opinion about future prices includes general economic conditions, industrial output levels and expectations, producer breakeven cost structures, liquefied natural gas trends, oil and natural gas properties depend primarily upon the prevailing pricesstorage inventory levels, industry decline rates for oilbase production and natural gas. Historically, oil and natural gas prices have been

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volatile and are subject to fluctuationsweather trends. Executive management is involved 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;all risk management activities and the overall economic environment.Board of Directors reviews our derivative program at its quarterly board meetings. We believe we have sufficient internal controls to prevent unauthorized trading.
These factorsWe use derivative instruments to achieve our risk management objectives, including swaps and the volatilityoptions. All of these are described in more detail below. We typically use swaps for a large portion of the energy markets make it extremely difficult to predict future oil and natural gas price movementsrisk we hedge. We have also sold calls, taking advantage of premiums associated with any certainty. During 2017, WTI prices rangedmarket price volatility.
We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from $42.48extensive examination of existing producing reserve estimates and estimates of likely production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to $60.46 per barrelactual results and activity levels. We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions would be reversed. The actual fixed price on our derivative instruments is derived from the reference NYMEX price, as reflected in current NYMEX trading. The pricing dates of our derivative contracts follow

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NYMEX futures. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the Henry Hub spotfloating-price, resulting in a net amount due to or from the counterparty.
We review our derivative positions continuously and if future market priceconditions change and prices are at levels we believe could jeopardize the effectiveness of natural gas ranged from $2.44a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering into a new trade that effectively reverses the current position. The factors we consider in closing or restructuring a position before the settlement date are identical to $3.71 per MMBtu. During 2018, WTI prices ranged from $44.48those we review when deciding to $77.41 per barrel andenter into the Henry Hub spot market price of natural gas ranged from $2.49original derivative position. Gains or losses related to $6.24 per MMBtu. Ifclosed positions will be recognized in the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures formonth specified in the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduceoriginal contract.
We have determined 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 carryingfair value of our derivative instruments utilizing established index prices, volatility curves and discount factors. These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. Future risk related to counterparties not being able to meet their obligations has been partially mitigated under our commodity hedging arrangements that require counterparties to post collateral if their obligations to us are in excess of defined thresholds. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 12 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of the fair value measurements associated with our derivatives.
As of December 31, 2019, our natural gas, oil and natural gas properties. Reductions in our reserves could also negatively impactNGL derivative instruments consistent of the borrowing base under our revolving credit facility, which could further limit our liquidity and abilityfollowing types of instruments:
•
Swaps: We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we may sell call options.
•
Basis Swaps: These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. We receive the fixed price differential and pay the floating market price differential to the counterparty for the hedged commodity.
•
Options: We sell, and occasionally buy, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.

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To mitigate the effects
As of commodity price fluctuations on our oil and natural gas production,December 31, 2019, we had the following open fixed price swap positions as of December 31, 2018.
 LocationDaily Volume (MMBtu/day) 
Weighted
Average Price
2019NYMEX Henry Hub1,254,000
 $2.83
2020NYMEX Henry Hub204,000
 $2.77
 LocationDaily Volume (Bbls/day) 
Weighted
Average Price
2019Mont Belvieu C21,000

$18.48
2019Mont Belvieu C34,000
 $28.87
2019Mont Belvieu C5500
 $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.derivative instruments:
    Weighted Average Price Fair Value
  Volume Fixed Call Differential Asset (Liability)
  MMBtu/day $/MMBtu (in thousands)
Natural Gas:          
Swaps:          
Short-term 548,000
 $2.88
 $—
 $—
 $121,934
Call Options (sold)(1):
          
Long-term 628,000
 $—
 $2.90
 $—
 $(53,135)
Basis Swaps:          
Short-term 70,000
 $—
 $—
 $(0.12) $(267)
Total Natural Gas         $68,532
  Bbls/day $/Bbl  
Oil:          
Swaps:          
Short-term 6,000
 $59.82
 $—
 $—
 $2,952
Total Oil         $2,952
  Bbls/day $/Bbl 
NGL:          
Swaps:          
Short-term 500
 $21.63
 $—
 $—
 $461
Total NGL         $461
Total Commodities         $71,945
Contingent Consideration:          
Louisiana Divestiture(2):
          
Short-term         $818
Long-term         $563
Total         $1,381
Total Derivative Asset       $73,326
We_____________________
(1)In the third quarter of 2019, we sold call options in exchange for a premium, and used the associated premiums received to enhance the fixed price for a portion of the fixed price natural gas swaps primarily for 2020 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.
(2)The purchase and sale agreement for the sale of our non-core assets located in the WCBB and Hackberry fields of Louisiana included a contingent consideration arrangement that entitles us to receive bonus payments if commodity prices exceed specified thresholds. The calculated fair value of this contingent payment arrangement was approximately $1.1 million as of the closing date of the divestiture.
In January and February 2020, we early terminated certain fixed price swaps for natural gas scheduled to settle in August through November of 2020 covering an average of approximately 294,000 MMBtu of natural gas per day over this four month period. The value received from these early terminations was used to enhance the fixed price for a portion of the fixed pricenew natural gas swaps listed above. Each short call option hasfor April and May of 2020 covering 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.
 LocationDaily Volume (MMBtu/day) 
Weighted
Average Price
January 2019 - March 2019NYMEX Henry Hub50,000
 $3.13
April 2019 - December 2019NYMEX Henry Hub30,000
 $3.10

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For a portionapproximately 472,000 MMBtu 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 over this two month period 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.
 LocationDaily Volume (MMBtu/day) Hedged Differential
2019Transco Zone 460,000
 $(0.05)
2020Transco Zone 460,000
 $(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$2.85 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,
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At February 27, 2020, we have hedged approximately 94%49% to 97%52% of our expected 2019 production.2020 production under our 2020 contracts. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oilcommodities prices increase. At December 31, 2018,2019, we had a net asset derivative position of $73.3 million as compared to 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, 2017,2018, 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$99.8 million,, while a 10% decrease in underlying commodity prices would have increased the fair value of these instruments by approximately $154.6$85.5 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.
Interest Rate Risk. 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.United States or, if the eurodollar rates are elected, the eurodollar rates. At December 31, 2018,2019, we had $45.0$120.0 million in borrowings outstanding under our credit facility which bore interest at the weighted average rate of 4.23%3.30%. A 1% increase in the average interest rate would have increased interest expense by approximately $0.8$1.2 million based on outstanding borrowings under our revolving credit facility throughout the year endedat December 31, 2018.2019. As of December 31, 2018,2019, we did not have any interest rate swaps to hedge our interest risks.

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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.
INDEX TO FINANCIAL STATEMENTS
ITEM 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSUREPage
Report of Independent Registered Public Accounting Firm
60
Consolidated Balance Sheets, December 31, 2019 and December 31, 2018

63
Consolidated Statements of Operations, Years Ended December 31, 2019, 2018, and 2017
64
Consolidated Statements of Comprehensive Income (Loss), Years Ended December 31, 2019, 2018, and 2017
65
Consolidated Statements of Stockholders' Equity, Years Ended December 31, 2019, 2018, and 2017
66
Consolidated Statements of Cash Flows, Year Ended December 31, 2019, 2018, and 2017
67
Notes to Consolidated Financial Statements
69
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/s/ Keri Crowell
Name:David M. WoodName:Keri Crowell
Title:Chief Executive Officer and PresidentTitle:Chief Financial Officer


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Report of Independent Registered Public Accounting Firm

BoardReport of Directors and Stockholders
Gulfport Energy Corporation

Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Gulfport Energy Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 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 theIndependent Registered 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.Firm
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.
PART III
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
For information concerning Item 10-Directors, Executive Officers and Corporate Governance, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).
ITEM 11.EXECUTIVE COMPENSATION
For information concerning Item 11-Executive Compensation, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).
ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
For information concerning Item 12-Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission within 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).
ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
For information concerning Item 13-Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).
ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES
For information concerning Item 14-Principal Accounting Fees and Services, see our definitive proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).

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PART IV
ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following documents are filed as part of this report or incorporated by reference herein:
(1)Financial Statements
Reference is made to the Index to Financial Statements appearing on Page F-1.

(2)Financial Statement Schedules
All financial statement schedules have been omitted because they are not applicable or the required disclosure is presented in the financial statements or notes thereto.

(3)Exhibits
Exhibit
Number
Description
2.1##
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).
3.1
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).
3.2
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).
3.3
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).
3.4
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).
3.5
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).
3.6
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).
4.1
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).
4.2
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).
4.3
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).
4.4
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).
4.5
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).
4.6
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).

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4.7
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)
10.1+
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).
10.2+
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).
10.3+
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).
10.4+
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).
10.5+
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).
10.6+
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).

10.7
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).
10.8
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).
10.9
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).
10.10
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).
10.11
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).
10.12
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).
10.13
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).
10.14
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).

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10.15
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).
10.16
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).
10.17
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).
10.18
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).
10.19
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).
10.20
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).
10.21#
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).
10.22#
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).
10.23
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).
10.24#
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).
10.25#
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.
10.26#
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).
10.27+
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).
10.28+
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).
10.29+
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).

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10.30+
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).
10.31+
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*
Consent of Grant Thornton LLP.
23.2*
Consent of Netherland, Sewell & Associates, Inc.
31.1*
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1**
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.
32.2**
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.


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ITEM 16.FORM 10-K SUMMARY
None.
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 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.

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Date:February 28, 2019By:/s/    DAVID M. WOOD
David M. Wood
Chief Executive Officer and President, Director
(Principal Executive Officer)
Date:February 28, 2019By:/s/    DAVID L. HOUSTON
David L. Houston
Chairman of the Board and Director
Date:February 28, 2019By:/s/    KERI CROWELL
Keri Crowell
Chief Financial Officer
(Principal Accounting and Financial Officer)
Date:February 28, 2019By:/s/    DEBORAH G. ADAMS
Deborah G. Adams
Director
Date:February 28, 2019By:/s/    CRAIG GROESCHEL
Craig Groeschel
Director
Date:February 28, 2019By:/s/    C. DOUG JOHNSON
C. Doug Johnson
Director
Date:February 28, 2019By:/s/    BEN T. MORRIS
Ben T. Morris
Director
Date:February 28, 2019By:/s/    SCOTT E. STRELLER
Scott E. Streller
Director
Date:February 28, 2019By:/s/    PAUL WESTERMAN
Paul Westerman
Director


S-1
Table of Contents
Index to Financial Statements

ITEM 8.FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
Page
Report of Independent Registered Public Accounting Firm
F-2
Consolidated Balance Sheets, December 31, 2018 and December 31, 2017

F-3
Consolidated Statements of Operations, Years Ended December 31, 2018, 2017, and 2016
F-4
Consolidated Statements of Comprehensive Income (Loss), Years Ended December 31, 2018, 2017, and 2016
F-5
Consolidated Statements of Stockholders' Equity, Years Ended December 31, 2018, 2017, and 2016
F-6
Consolidated Statements of Cash Flows, Year Ended December 31, 2018, 2017, and 2016
F-7
Notes to Consolidated Financial Statements
F-9


F-1
Table of Contents
Index to Financial Statements

Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Gulfport Energy Corporation
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Gulfport Energy Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 20182019 and 2017, and2018, 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, 2018,2019, and the related notes (collectively referred to as the "financial statements"“financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20182019 and 2017,2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018,2019, 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, 2018,2019, 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, 201927, 2020 expressed an unqualifiedadverse opinion.

Basis for Opinionopinion
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.


Change in accounting principle
As discussed in Note 9 to the consolidated financial statements, the Company has adopted new accounting guidance as of January 1, 2019, related to the adoption of Accounting Standards Codification Topic 842, Leases. Our opinion is not modified with respect to this matter.
Critical audit matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Depletion expense and impairment of oil and gas properties impacted by the Company’s estimation of proved reserves
As described further in Note 1 to the financial statements, the Company uses the full cost method of accounting for oil and gas operations. This accounting method requires management to make estimates of proved reserves and related future net cash flows to compute and record depletion, depreciation and amortization, as well as to assess potential impairment of oil and gas properties (the full cost ceiling test). To estimate the volume of proved oil and gas reserve quantities, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with those proved reserves to determine if wells are expected to be economical under the appropriate pricing assumptions that are required in the estimation of depletion, depreciation and amortization expense and potential ceiling test impairment assessments. We identified the estimation of proved reserves as it relates to the recognition of depletion, depreciation and amortization expense and the assessment of potential impairment as a critical audit matter.

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The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that relatively minor changes in certain inputs and assumptions that are necessary to estimate the volume and future cash flows of the Company’s proved reserves could have a significant impact on the measurement of depletion, depreciation and amortization expense and/or impairment expense. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
Our audit procedures related to the estimation of proved reserves included the following, among others.
We tested the design and operating effectiveness of internal controls relating to management’s estimation of proved reserves for the purpose of estimating depletion, depreciation and amortization expense and assessing the Company’s oil and gas properties for potential ceiling test impairment.
We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve specialists, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes and read the report prepared by the Company’s reserve specialists.
We evaluated sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions that are derived from the Company’s accounting records, such as historical pricing differentials, operating costs, estimated capital costs, and ownership interests. We tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis where applicable. Specifically, our audit procedures involved testing management’s assumptions as follows:
◦Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for pricing differentials, where applicable;
◦Tested the model used to estimate the operating costs at year end and compared to historical operating costs;
◦Tested the model used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells, where applicable;
◦Tested the working and net revenue interests used in the reserve report by inspecting land and division order records;
◦Evaluated the Company’s evidence supporting the proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and
◦Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year’s reserve report.

Valuation Allowance of Deferred Tax Assessment
As described further in Note 1 and 10 to the financial statements, the Company records a valuation allowance to reduce total net deferred tax assets when a judgment is made that is considered more likely than not that a tax benefit will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences will become deductible. The Company assesses the need for a valuation allowance by evaluating both positive and negative evidence that may exist. We identified the realizability of deferred tax assets as a critical audit matter.
The principal considerations for our determination that the realizability of deferred tax assets is a critical audit matter are that (a) the forecast of future taxable income is an accounting estimate subject to a high level of estimation and (b) the determination of any limitations on the utilization of net operating loss carryforwards involves complex calculations and judgment. There is inherent uncertainty and subjectivity related to management’s judgments and assumptions regarding the Company’s future taxable income, which are complex in nature and require significant auditor judgment.
Our audit procedures related to the valuation of deferred taxes included the following, among others.
We tested the effectiveness of controls over management’s estimates of the realization of the deferred tax assets, including those over management’s corporate model which was the basis for the forecast of future taxable income, management’s tax planning strategies and the determination of whether it is more likely than not that the deferred tax assets will be realized prior to expiration.

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With the assistance of our income tax specialists, we evaluated the forecast of future taxable income considering whether the estimated future sources of taxable income were of the appropriate character to utilize the net operating loss carryforwards and other temporary differences giving rise to the deferred tax assets under current tax law.
With the assistance of our income tax specialists, we evaluated management’s Internal Revenue Code Section 382 ownership change calculations.
We tested the reasonableness of management’s corporate model used to estimate future taxable income by comparing the estimates to the following:
◦Historical taxable income.
◦Internal communications with the board of directors.
◦Evidence obtained in other areas of the audit.
◦Management’s history of carrying out its stated plans and its ability to carry out its plans considering contractual commitments, available financing, or debt covenants.


/s/ GRANT THORNTON LLP
We have served as the Company's auditor since 2005.
Oklahoma City, Oklahoma
February 28, 201927, 2020




F-262
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Index to Financial Statements


GULFPORT ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31, 2018 December 31, 2017December 31, 2019 December 31, 2018
(In thousands, except share data)(In thousands, except share data)
Assets      
Current assets:      
Cash and cash equivalents$52,297
 $99,557
$6,060
 $52,297
Accounts receivable—oil and natural gas sales210,200
 146,773
121,210
 210,200
Accounts receivable—joint interest and other22,497
 35,440
47,975
 22,497
Prepaid expenses and other current assets10,607
 4,912
4,431
 10,017
Short-term derivative instruments21,352
 78,847
126,201
 21,352
Total current assets316,953
 365,529
305,877
 316,363
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, respectively10,026,836
 9,169,156
Oil and natural gas properties, full-cost accounting, $1,686,666 and $2,873,037 excluded from amortization in 2019 and 2018, respectively10,595,735
 10,026,836
Other property and equipment92,667
 86,754
96,719
 92,667
Accumulated depletion, depreciation, amortization and impairment(4,640,098) (4,153,733)(7,228,660) (4,640,098)
Property and equipment, net5,479,405
 5,102,177
3,463,794
 5,479,405
Other assets:      
Equity investments236,121
 302,112
32,044
 236,121
Long-term derivative instruments—
 8,685
563
 —
Deferred tax asset—
 1,208
7,563
 —
Inventories4,754
 8,227
5,182
 5,344
Operating lease assets14,168
 —
Operating lease assets - related parties43,270
 —
Other assets13,803
 19,814
10,358
 13,803
Total other assets254,678
 340,046
113,148
 255,268
Total assets$6,051,036
 $5,807,752
$3,882,819
 $6,051,036
Liabilities and stockholders’ equity      
Current liabilities:      
Accounts payable and accrued liabilities$518,380
 $553,609
$415,218
 $518,380
Asset retirement obligation—current—
 120
Short-term derivative instruments20,401
 32,534
303
 20,401
Current portion of operating lease liabilities13,826
 —
Current portion of operating lease liabilities - related parties21,220
 —
Current maturities of long-term debt651
 622
631
 651
Total current liabilities539,432
 586,885
451,198
 539,432
Long-term derivative instruments13,992
 2,989
53,135
 13,992
Asset retirement obligation—long-term79,952
 74,980
60,355
 79,952
Deferred tax liability3,127
 —
Other non-current liabilities—
 2,963
Uncertain tax position liability3,127
 3,127
Non-current operating lease liabilities342
 —
Non-current operating lease liabilities - related parties22,050
 —
Long-term debt, net of current maturities2,086,765
 2,038,321
1,978,020
 2,086,765
Total liabilities2,723,268
 2,706,138
2,568,227
 2,723,268
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—
 —
Preferred stock, $.01 par value; 5,000,000 authorized (30,000 authorized as redeemable 12% cumulative preferred stock, Series A), and none 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 20171,630
 1,831
Common stock - $.01 par value, 200,000,000 shares authorized, 159,710,955 issued and outstanding in 2019 and 162,986,045 in 20181,597
 1,630
Paid-in capital4,227,532
 4,416,250
4,207,554
 4,227,532
Accumulated other comprehensive loss(56,026) (40,539)(46,833) (56,026)
Accumulated deficit(845,368) (1,275,928)(2,847,726) (845,368)
Total stockholders’ equity3,327,768
 3,101,614
1,314,592
 3,327,768
Total liabilities and stockholders’ equity$6,051,036
 $5,807,752
$3,882,819
 $6,051,036
See accompanying notes to consolidated financial statements.


F-363
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Index to Financial Statements


GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Year Ended December 31,For the Year Ended December 31,
2018 2017 20162019 2018 2017
(In thousands, except share data)(In thousands, except share data)
Revenues:          
Natural gas sales$1,121,815
 $845,999
 $420,128
$918,263
 $1,121,815
 $845,999
Oil and condensate sales177,793
 124,568
 81,173
117,937
 177,793
 124,568
Natural gas liquid sales178,915
 136,057
 59,115
101,448
 178,915
 136,057
Net (loss) gain on natural gas, oil, and NGL derivatives(123,479) 213,679
 (174,506)
Net gain (loss) on natural gas, oil, and NGL derivatives208,360
 (123,479) 213,679
1,355,044
 1,320,303
 385,910
1,346,008
 1,355,044
 1,320,303
Costs and expenses:
    
    
Lease operating expenses91,640
 80,246
 68,877
82,998
 91,640
 80,246
Production taxes33,480
 21,126
 13,276
28,571
 33,480
 21,126
Midstream gathering and processing expenses290,188
 248,995
 165,972
291,725
 290,188
 248,995
Depreciation, depletion and amortization486,664
 364,629
 245,974
550,108
 486,664
 364,629
Impairment of oil and natural gas properties—
 —
 715,495
2,039,770
 —
 —
General and administrative expenses56,633
 52,938
 43,409
47,979
 49,994
 45,523
Restructuring costs4,611
 —
 —
Accretion expense4,119
 1,611
 1,057
3,939
 4,119
 1,611
Acquisition expense—
 2,392
 —
—
 —
 2,392
962,724
 771,937
 1,254,060
3,049,701
 956,085
 764,522
INCOME (LOSS) FROM OPERATIONS392,320
 548,366
 (868,150)
OTHER (INCOME) EXPENSE:
    
(LOSS) INCOME FROM OPERATIONS(1,703,693) 398,959
 555,781
OTHER EXPENSE (INCOME):
    
Interest expense135,273
 108,198
 63,530
141,786
 141,912
 115,613
Interest income(314) (1,009) (1,230)(801) (314) (1,009)
Litigation settlement1,075
 —
 —
Insurance proceeds(231) —
 (5,718)
Loss on debt extinguishment—
 —
 23,776
Gain on debt extinguishment(48,630) —
 —
Gain on sale of equity method investments(124,768) (12,523) (3,391)—
 (124,768) (12,523)
(Income) loss from equity method investments, net(49,904) 17,780
 37,376
Loss (income) from equity method investments, net210,148
 (49,904) 17,780
Other expense (income), net698
 (1,041) 129
3,725
 1,542
 (1,041)
(38,171) 111,405
 114,472
306,228
 (31,532) 118,820
INCOME (LOSS) BEFORE INCOME TAXES430,491
 436,961
 (982,622)
(LOSS) INCOME BEFORE INCOME TAXES(2,009,921) 430,491
 436,961
INCOME TAX (BENEFIT) EXPENSE(69) 1,809
 (2,913)(7,563) (69) 1,809
NET INCOME (LOSS)$430,560
 $435,152
 $(979,709)
NET INCOME (LOSS) PER COMMON SHARE:     
NET (LOSS) INCOME$(2,002,358) $430,560
 $435,152
NET (LOSS) INCOME PER COMMON SHARE:     
Basic$2.46
 $2.42
 $(7.97)$(12.49) $2.46
 $2.42
Diluted$2.45
 $2.41
 $(7.97)$(12.49) $2.45
 $2.41
Weighted average common shares outstanding—Basic174,675,840
 179,834,146
 122,952,866
160,341,125
 174,675,840
 179,834,146
Weighted average common shares outstanding—Diluted175,398,706
 180,253,024
 122,952,866
160,341,125
 175,398,706
 180,253,024


See accompanying notes to consolidated financial statements.


F-464
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Index to Financial Statements


GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME (LOSS)


 For the Year Ended December 31,
 2019 2018 2017
 (In thousands)
Net (loss) income$(2,002,358) $430,560
 $435,152
Foreign currency translation adjustment (1)
9,193
 (15,487) 12,519
Other comprehensive income (loss)9,193
 (15,487) 12,519
Comprehensive (loss) income$(1,993,165) $415,073
 $447,671
_____________________
(1)NaN taxes were recorded for the years ended December 31, 2019, 2018 and 2017.
 For the Year Ended December 31,
 2018 2017 2016
 (In thousands)
Net income (loss)$430,560
 $435,152
 $(979,709)
Foreign currency translation adjustment (1)(15,487) 12,519
 2,119
Other comprehensive (loss) income(15,487) 12,519
 2,119
Comprehensive income (loss)$415,073
 $447,671
 $(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-565
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Index to Financial Statements



GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY


    

Paid-in
Capital
 
Accumulated
Other
Comprehensive
Loss
 Accumulated Deficit 
Total
Stockholders’
Equity
    

Paid-in
Capital
 
Accumulated
Other
Comprehensive
Loss
 Accumulated Deficit 
Total
Stockholders’
Equity
Common Stock Common Stock 
Shares Amount Shares Amount 
(In thousands, except share data)(In thousands, except share data)
Balance at January 1, 2016108,322,250
 $1,082
 $2,824,303
 $(55,177) $(731,371) $2,038,837
Net Loss—
 —
 —
 —
 (979,709) (979,709)
Other Comprehensive Income—
 —
 —
 2,119
 —
 2,119
Stock-based Compensation—
 —
 12,251
 —
 —
 12,251
Issuance of Common Stock in public offerings, net of related expenses50,255,000
 503
 1,109,891
 —
 —
 1,110,394
Issuance of Restricted Stock252,566
 3
 (3) —
 —
 —
Balance at December 31, 2016158,829,816
 1,588
 3,946,442
 (53,058) (1,711,080) 2,183,892
Balance at January 1, 2017158,829,816
 1,588
 3,946,442
 (53,058) (1,711,080) 2,183,892
Net Income—
 —
 —
 —
 435,152
 435,152
—
 —
 —
 —
 435,152
 435,152
Other Comprehensive Income—
 —
 —
 12,519
 —
 12,519
—
 —
 —
 12,519
 —
 12,519
Stock-based Compensation—
 —
 10,615
 —
 —
 10,615
—
 —
 10,615
 —
 —
 10,615
Issuance of Common Stock for the Vitruvian Acquisition, net of related expenses23,852,117
 239
 459,197
 —
 —
 459,436
23,852,117
 239
 459,197
 —
 —
 459,436
Issuance of Restricted Stock423,977
 4
 (4) 

 

 —
423,977
 4
 (4) —
 —
 —
Balance at December 31, 2017183,105,910
 1,831
 4,416,250
 (40,539) (1,275,928) 3,101,614
183,105,910
 1,831
 4,416,250
 (40,539) (1,275,928) 3,101,614
Net Income—
 —
 —
 —
 430,560
 430,560
—
 —
 —
 —
 430,560
 430,560
Other Comprehensive Loss—
 —
 —
 (15,487) —
 (15,487)—
 —
 —
 (15,487) —
 (15,487)
Stock-based Compensation—
 —
 11,332
 —
 —
 11,332
—
 —
 11,332
 —
 —
 11,332
Shares Repurchased(20,746,536) (207) (200,044) —
 —
 (200,251)(20,746,536) (207) (200,044) —
 ���
 (200,251)
Issuance of Restricted Stock626,671
 6
 (6) —
 —
 —
626,671
 6
 (6) —
 —
 —
Balance at December 31, 2018162,986,045
 $1,630
 $4,227,532
 $(56,026) $(845,368) $3,327,768
162,986,045
 1,630
 4,227,532
 (56,026) (845,368) 3,327,768
Net Loss—
 —
 —
 —
 (2,002,358) (2,002,358)
Other Comprehensive Income—
 —
 —
 9,193
 —
 9,193
Stock-based Compensation—
 —
 10,677
 —
 —
 10,677
Shares Repurchased(3,951,198) (40) (30,648) —
 —
 (30,688)
Issuance of Restricted Stock676,108
 7
 (7) —
 —
 —
Balance at December 31, 2019159,710,955
 $1,597
 $4,207,554
 $(46,833) $(2,847,726) $1,314,592
See accompanying notes to consolidated financial statements.


F-666
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Index to Financial Statements


GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31,Year Ended December 31,
2018 2017 20162019 2018 2017
(In thousands)(In thousands)
Cash flows from operating activities:          
Net income (loss)$430,560
 $435,152
 $(979,709)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:     
Net (loss) income$(2,002,358) $430,560
 $435,152
Adjustments to reconcile net (loss) income to net cash provided by operating activities:     
Accretion expense4,119
 1,611
 1,057
3,939
 4,119
 1,611
Depletion, depreciation and amortization486,664
 364,629
 245,974
550,108
 486,664
 364,629
Impairment of oil and gas properties—
 —
 715,495
Impairment of oil and natural gas properties2,039,770
 —
 —
Stock-based compensation expense6,799
 6,369
 7,351
4,911
 6,799
 6,369
(Income) loss from equity investments(49,625) 18,513
 37,788
Loss (income) from equity investments, net210,289
 (49,625) 18,513
Gain on debt extinguishment—
 —
 (1,108)(48,630) —
 —
Change in fair value of derivative instruments65,051
 (188,802) 323,303
(85,230) 65,051
 (188,802)
Deferred income tax expense1,208
 1,690
 18,188
Deferred income tax (benefit) expense(7,563) 1,208
 1,690
Amortization of loan costs6,121
 5,011
 3,660
6,328
 6,121
 5,011
Amortization of note discount and premium—
 —
 (1,716)
Gain on sale of equity method investments(124,768) (12,523) (3,391)
Gain on sale of equity method investments and other assets(220) (124,768) (12,523)
Distributions from equity method investments3,206
 —
 —
2,457
 3,206
 —
Changes in operating assets and liabilities:          
Increase in accounts receivable—oil and natural gas sales(63,427) (35,879) (76,269)
Decrease (increase) in accounts receivable—joint interest and other12,943
 (9,573) 11,380
Decrease (increase) in accounts receivable—oil and natural gas sales88,990
 (63,427) (35,879)
(Increase) decrease in accounts receivable—joint interest and other(25,478) 12,943
 (9,573)
Decrease in accounts receivable—related parties—
 16
 —
—
 —
 16
Increase in prepaid expenses and other current assets(5,695) (1,777) (3,734)
Decrease (increase) in prepaid expenses and other current assets5,586
 (5,695) (1,777)
Decrease (increase) in other assets4,066
 (7,866) —
915
 4,066
 (7,866)
(Decrease) increase in accounts payable, accrued liabilities and other(24,015) 106,375
 43,763
(19,548) 9,768
 106,375
Settlement of asset retirement obligation(719) (3,057) (4,189)(273) (719) (3,057)
Net cash provided by operating activities752,488
 679,889
 337,843
723,993
 786,271
 679,889
Cash flows from investing activities:          
Deductions to cash held in escrow—
 8
 8
—
 —
 8
Additions to other property and equipment(7,870) (19,372) (33,152)(5,021) (7,870) (19,372)
Acquisitions of oil and natural gas properties—
 (1,348,657) —
—
 —
 (1,348,657)
Additions to oil and natural gas properties(865,300) (1,064,678) (724,925)(720,057) (899,083) (1,064,678)
Proceeds from sale of oil and gas properties5,114
 4,866
 45,812
48,527
 5,114
 4,866
Proceeds from sale of other property and equipment351
 1,569
 —
267
 351
 1,569
Proceeds from sale of equity method investments226,487
 —
 —
—
 226,487
 —
Contributions to equity method investments(2,319) (55,280) (26,472)(432) (2,319) (55,280)
Distributions from equity method investments446
 7,376
 18,147
1,945
 446
 7,376
Net cash used in investing activities(643,091) (2,474,168) (720,582)(674,771)��(676,874) (2,474,168)
Cash flows from financing activities:          
Principal payments on borrowings(220,575) (365,276) (87,685)(877,697) (220,575) (365,276)
Borrowings on line of credit265,000
 365,000
 86,000
952,000
 265,000
 365,000
Proceeds from bond issuance—
 450,000
 1,250,000
—
 —
 450,000
Repayment of bonds—
 —
 (624,561)
Repurchase of senior notes(138,786) —
 —
Borrowings on term loan—
 2,951
 21,049
—
 —
 2,951
Debt issuance costs and loan commitment fees(831) (14,350) (24,718)(288) (831) (14,350)
Payments on repurchase of stock(200,251) —
 —
(30,688) (200,251) —
Proceeds from issuance of common stock, net of offering costs and exercise of stock options—
 (5,364) 1,110,555
—
 —
 (5,364)
Net cash (used in) provided by financing activities(156,657) 432,961
 1,730,640
(95,459) (156,657) 432,961
Net (decrease) increase in cash, cash equivalents and restricted cash(47,260) (1,361,318) 1,347,901
Net decrease in cash, cash equivalents and restricted cash(46,237) (47,260) (1,361,318)
Cash, cash equivalents and restricted cash at beginning of period99,557
 1,460,875
 112,974
52,297
 99,557
 1,460,875
Cash, cash equivalents and restricted cash at end of period$52,297
 $99,557
 $1,460,875
$6,060
 $52,297
 $99,557
(Continued on next page)















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GULFPORT ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
Supplemental disclosure of cash flow information:          
Interest payments$126,342
 $101,958
 $68,966
$142,664
 $132,995
 $107,548
Income tax receipts$—
 $(1,105) $(19,770)$(1,794) $—
 $(1,105)
Supplemental disclosure of non-cash transactions:          
Capitalized stock-based compensation$4,533
 $4,246
 $4,900
$5,766
 $4,533
 $4,246
Asset retirement obligation capitalized$1,452
 $42,270
 $10,971
$6,883
 $1,452
 $42,270
Asset retirement obligation removed due to divestiture$(30,146) $—
 $—
Interest capitalized$4,470
 $9,470
 $9,148
$3,372
 $4,470
 $9,470
Foreign currency translation (loss) gain on equity method investments$(15,487) $12,519
 $3,468
Fair value of contingent consideration asset on date of divestiture$(1,137) $—
 $—
Foreign currency translation gain (loss) on equity method investments$9,193
 $(15,487) $12,519
See accompanying notes to consolidated financial statements.


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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”"Company"), a Delaware corporation formed in 1997, is an independent oil and gasnatural gas-weighted exploration development and production company with itsfocused on the exploration, acquisition and production of natural gas, crude oil and natural gas liquids ("NGL") in the United States. The Company's principal properties are located in the Utica Shale primarily in Eastern Ohio targeting the Utica formation and in central Oklahoma targeting 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.formations.
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.consolidated financial statements.
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, Mule Sky LLC and GRUS, 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. NoNaN allowance was deemed necessary at December 31, 20182019 and December 31, 2017.2018.
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. Additionally, interest is capitalized on the cost of unproved oil and natural gas properties that are excluded from amortization for which exploration and development activities are in process or expected within the next 12 months.
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 proved 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 (only to the extent that the derivative instruments are treated as cash flow hedges for accounting purposes), and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of unproved 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

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would be reduced. A decline in oil and gas prices may result in an impairment of oil and gas properties. TheAs a result of the decline in commodity prices at December 31, 2019, the Company did not recognizerecognized a ceiling test impairment of $2.0 billion for the year ended December 31, 2018.2019.
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 six6 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 provenproved oil and gas reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled approximately $1.7 billion and $2.9 billion at bothDecember 31, 2019 and December 31, 2018, and December 31, 2017.respectively. These costs are reviewed quarterly by management for impairment. If impairment has occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production, and available funds for exploration and development.
The Company accounts for its abandonment and restoration liabilities 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.
 (In thousands)
December 31, 2016$(51,709)
December 31, 2017$(39,190)
December 31, 2018$(54,677)
December 31, 2019$(45,484)
 (In thousands)
December 31, 2015$(55,175)
December 31, 2016$(51,709)
December 31, 2017$(39,190)
December 31, 2018$(54,677)

Net Income per Common Share
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 12.11.

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Income Taxes

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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 20042005 – 20172018 U.S. federal and 19981999 - 20172018 state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2018,2019, the Company has no0 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.NGL. Sales of natural gas, oil and condensate and NGLsNGL 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 108 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 statementconsolidated statements 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. TheDuring the year ended December 31, 2019, the Company recognizedrecorded an impairment charge of $23.1$160.8 million related to its investment in Mammoth Energy Services, Inc. ("Mammoth Energy") and an impairment of $32.4 million related to its investment in Grizzly Oil Sands ULC for the year ended December 31, 2016.("Grizzly"). There were no0 impairment charges recorded for the years ended December 31, 2017 and December 31, 2018. See Note 4 for further discussion of Mammoth Energy and Grizzly impairments.


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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 liquidNGL production. All derivative instruments are recognized as assets or liabilities in the consolidated balance sheet,sheets, 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 (loss) income (loss) or total operating cash flows.
Statements of Cash Flows
During the third quarter of 2019, the Company identified that certain activities were misclassified between cash flows from operating activities and cash flows from investing activities. These activities had been included in accounts payable, accrued liabilities and other and presented as cash flows from operating activities while they should have been presented as additions to oil and natural gas properties in cash flows from investing activities.  The Company corrected the previously presented statements of cash flows for these additions and in doing so, for the year ended December 31, 2018, the consolidated statements of cash flows and the condensed consolidating statements of cash flows were adjusted to increase net cash flows provided by operating activities by $33.8 million with a corresponding increase in net cash flows used in investing activities. The Company has evaluated the effect of the incorrect presentation, both qualitatively and quantitatively, and concluded that it did not have a material impact on any previously filed annual or quarterly consolidated financial statements.
Recent Accounting Pronouncements
In May 2014,January 2019, the Financial Accounting Standards Board ("FASB") issuedCompany adopted 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, 20182016-02, Leases (Topic 842) on a prospective basis using the modified retrospectivesimplified 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.permitted by ASU 2018-11, Leases (Topic 842): Targeted Improvements. See Note 109 for further discussion of the revenuelease 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

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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. Subsequent to ASU 2016-13, the FASB issued several related ASU’s to clarify the application of the credit loss standard.

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The guidance is effective for periods after December 15, 2019, with early adoption permitted. The Company is currently evaluatingadopted 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 20181, 2020 with no significantmaterial effect on its financial statements or related disclosures.

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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.disclosures.
In August 2018,July 2019, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes2019-07, Codification Updates 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 incurredSEC Sections, Amendments 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") issuedSEC Paragraphs Pursuant to SEC Final Rule ReleaseReleases No. 33-10532, Disclosure Update and Simplification,, which and Nos. 33-10231 and 33-10442, Investment Company Reporting Modernization, and Miscellaneous Updates. This ASU amends various SEC sections within the FASB Codification to align with the updated requirements of certain disclosure requirements that were redundant, duplicative, overlapping or superseded. Under these amendments,SEC final rules and includes miscellaneous updates to agree the annual disclosure requirements onlanguage in the analysisCodification to the electronic Code 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 ruleFederal Regulations. ASU No. 2019-07 is effective November 5, 2018,upon issuance, and the Company will begin presenting this analysis beginninghas adopted the changes 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.no material impacts.
2.ACQUISITIONS AND DIVESTITURES
Sale of Southern Louisiana Assets
In December 2018, the Company entered into an agreement to sell its non-core assets located in the West Cote Blanche Bay ("WCBB") and Hackberry fields of Louisiana to an undisclosed third party for a purchase price of approximately $19.7 million. The sale closed on July 3, 2019, subject to customary post-closing terms and conditions, with an effective date of August 15, 2018. The Company received approximately $9.2 million in cash and retained contingent overriding royalty interests. In addition, the Company could also receive contingent payments based on commodity prices exceeding specified thresholds over the two years following the closing date. See Note 12 for further discussion of the contingent consideration arrangement, which was determined to be an embedded derivative. The buyer assumed all plugging and abandonment liabilities associated with these assets which totaled approximately $30.0 million at the divestiture date.
Sale of Non-operated Utica Interests
In December 2019, the Company entered into an agreement to divest certain non-operated interests in the Utica Shale for approximately $29.0 million in cash subject to customary closing terms and adjustments. This sale closed on December 30, 2019.
Sale of Bakken Overriding Royalty Interests
During 2019, the Company announced the sale of certain overriding royalty interests associated with assets the Company held in the Bakken. The sale closed on December 11, 2019 and, net of purchase price adjustments, the Company received approximately $7.0 million of total proceeds.
Vitruvian Acquisition
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 costsexpenses of $2.42.4 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.

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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.
  (In thousands)
Consideration:  
     Cash, net of purchase price adjustments $1,354,093
     Fair value of Gulfport’s common stock issued 464,639
Total Consideration $1,818,732
   
Estimated Fair value of identifiable assets acquired and liabilities assumed:  
     Oil and natural gas properties  
       Proved properties $362,264
       Unproved properties 1,462,957
     Asset retirement obligations (6,489)
Total fair value of net identifiable assets acquired $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

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Company integrating the acquired assets into its overall operations using the full cost method of accounting.
  Period from
  February 17, 2017
  to
  December 31, 2017
  (In thousands)
Revenue $213,368
Pro Forma Information (Unaudited)

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.
  December 31, 2017
  (In thousands, except share data)
Pro forma revenue $1,356,202
Pro forma net income $448,398
Pro forma earnings per share (basic) $2.49
Pro forma earnings per share (diluted) $2.49

  December 31,
  2017 2016
  (In thousands, except share data)
Pro forma revenue $1,356,202
 $523,097
Pro forma net income (loss) $448,398
 $(1,190,481)
Pro forma earnings (loss) per share (basic) $2.49
 $(8.11)
Pro forma earnings (loss) per share (diluted) $2.49
 $(8.11)

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3.PROPERTY AND EQUIPMENT
The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of December 31, 20182019 and 20172018 are as follows:
December 31,December 31,
2018 20172019 2018
(In thousands)(In thousands)
Oil and natural gas properties$10,026,836
 $9,169,156
$10,595,735
 $10,026,836
Office furniture and fixtures42,581
 37,369
Buildings44,565
 44,565
Other depreciable property and equipment91,198
 87,146
Land5,521
 4,820
5,521
 5,521
Total property and equipment10,119,503
 9,255,910
10,692,454
 10,119,503
Accumulated depletion, depreciation, amortization and impairment(4,640,098) (4,153,733)(7,228,660) (4,640,098)
Property and equipment, net$5,479,405
 $5,102,177
$3,463,794
 $5,479,405

NoUnder the full cost method of accounting, capitalized costs of oil and natural gas properties are subject to a quarterly full cost ceiling test, which is discussed in Note 1. During the year ended December 31, 2019, the Company incurred $2.0 billion of impairments as a result of its oil and natural gas properties exceeding its calculated ceiling. The lower ceiling values resulted primarily from significant decreases in the 12-month average trailing prices for natural gas, oil and NGL, which significantly reduced proved reserves values and, to a lesser degree, proved reserves. NaN 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 $30.1 million, $37.7 million $35.7 million and $29.3$35.7 million for the years ended December 31, 2019, 2018 2017 and 2016,2017, 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 $1.08, $0.96 $0.90 and $0.92$0.90 per Mcfe for the years ended December 31, 2019, 2018 2017 and 2016,2017, respectively.

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The following is a summary of Gulfport’s oil and natural gas properties not subject to amortization as of December 31, 2018:
 Costs Incurred in
 2018 2017 2016 Prior to 2016 Total
 (In thousands)
Acquisition costs$128,415
 $1,469,820
 $122,399
 $1,128,975
 $2,849,609
Exploration costs9,027
 —
 —
 —
 9,027
Development costs548
 869
 4,536
 5,789
 11,742
Capitalized interest2,120
 2,915
 (657) (1,719) 2,659
Total oil and natural gas properties not subject to amortization$140,110
 $1,473,604
 $126,278
 $1,133,045
 $2,873,037

2019:
F-16
 Costs Incurred in
 2019 2018 2017 Prior to 2017 Total
 (In thousands)
Acquisition costs$9,089
 $98,870
 $756,963
 $806,982
 $1,671,904
Exploration costs259
 —
 —
 —
 259
Development costs1,213
 548
 869
 10,325
 12,955
Capitalized interest888
 413
 247
 —
 1,548
Total oil and natural gas properties not subject to amortization$11,449
 $99,831
 $758,079
 $817,307
 $1,686,666
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The following table summarizes the Company’s non-producing properties excluded from amortization by area as of December 31, 2018:
2019:
 December 31, 2018
 (In thousands)
Utica$1,483,194
MidContinent1,388,706
Niobrara451
Southern Louisiana586
Bakken100
 $2,873,037
 December 31, 2019
 (In thousands)
Utica$976,593
MidContinent709,739
Other334
 $1,686,666

As of December 31, 2017,2018, 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, 20182019 and 20172018 is as follows:
 December 31,
 2018 2017
 (In thousands)
Asset retirement obligation, beginning of period$75,100
 $34,276
Liabilities incurred1,827
 16,300
Liabilities settled(719) (3,057)
Accretion expense4,119
 1,611
Revisions in estimated cash flows(375) 25,970
Asset retirement obligation as of end of period79,952
 75,100
Less current portion—
 120
Asset retirement obligation, long-term$79,952
 $74,980

F-17
 December 31,
 2019 2018
 (In thousands)
Asset retirement obligation, beginning of period$79,952
 $75,100
Liabilities incurred5,935
 1,827
Liabilities settled(273) (719)
Liabilities removed due to divestitures(30,146) —
Accretion expense3,939
 4,119
Revisions in estimated cash flows948
 (375)
Asset retirement obligation as of end of period$60,355
 $79,952


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4.EQUITY INVESTMENTS
Investments accounted for by the equity method consist of the following as of December 31, 20182019 and 2017:2018:
  Carrying Value (Income) loss from equity method investments  Carrying Value Loss (income) from equity method investments
Approximate Ownership % December 31, For the Year Ended December 31,Approximate Ownership % December 31, For the Year Ended December 31,
 2018 2017 2018 2017 2016 2019 2018 2019 2018 2017
  (In thousands)  (In thousands)
Investment in Tatex Thailand II, LLC23.5% $—
 $—
 $(241) $(549) $(412)23.5% $—
 $—
 $(2,086) $(241) $(549)
Investment in Tatex Thailand III, LLC(1)—% —
 —
 —
 (183) —
—% —
 —
 —
 —
 (183)
Investment in Grizzly Oil Sands ULC24.9999% 44,259
 57,641
 510
 2,189
 25,150
24.9999% 21,000
 44,259
 32,710
 510
 2,189
Investment in Timber Wolf Terminals LLC(3)(2)
—% —
 983
 536
 8
 8
—% —
 —
 —
 536
 8
Investment in Windsor Midstream LLC22.5% 39
 30
 (9) 25,233
 (13,618)22.5% 39
 39
 —
 (9) 25,233
Investment in Stingray Cementing LLC(1)(3)
—% —
 —
 —
 205
 263
—% —
 —
 —
 —
 205
Investment in Blackhawk Midstream LLC(4)
—% —
 —
 (38) —
 —
—% —
 —
 —
 (38) —
Investment in Stingray Energy Services LLC(1)(3)
—% —
 —
 —
 282
 1,044
—% —
 —
 —
 —
 282
Investment in Sturgeon Acquisitions LLC(1)(3)
—% —
 —
 

 (71) 993
—% —
 —
 —
 


 (71)
Investment in Mammoth Energy Services, Inc.(1)(3)
21.9% 191,823
 165,715
 (49,969) (11,288) 24,037
21.8% 11,005
 191,823
 179,524
 (49,969) (11,288)
Investment in Strike Force Midstream LLC(2)(5)
—% —
 77,743
 (693) 1,954
 (89)—% —
 —
 —
 (693) 1,954
  $236,121
 $302,112
 $(49,904) $17,780
 $37,376
  $32,044
 $236,121
 $210,148
 $(49,904) $17,780
_____________________
(1)In December 2017, the Company received its final distribution from Tatex Thailand III, LLC ("Tatex III"), which was dissolved in 2017.
(1)(2)
On June 5, 2018, the Company received its final distribution from Timber Wolf Terminals LLC ("Timber Wolf"), which was dissolved in 2018.
(3)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, which was dissolved in 2018.
(5)On May 1, 2018, the Company sold its 25% interest in Strike Force Midstream LLC ("Strike Force") to EQT Midstream Partners, LP for information regarding this distribution.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.
The tables below summarize financial information for the Company's equity investments, as of December 31, 20182019 and 2017.2018.
Summarized balance sheet information:
 December 31,
 2018 2017
 (In thousands)
Current assets$471,733
 $415,032
Noncurrent assets$1,302,488
 $1,542,090
Current liabilities$239,975
 $261,086
Noncurrent liabilities$94,575
 $148,839

F-18
 December 31,
 2019 2018
 (In thousands)
Current assets$421,326
 $471,733
Noncurrent assets$1,260,075
 $1,302,488
Current liabilities$132,569
 $239,975
Noncurrent liabilities$163,241
 $94,575

Summarized results of operations:

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Summarized results of operations:    
 December 31,
 2019 2018 2017
 (In thousands)
Gross revenue$625,012
 $1,729,778
 $755,374
Net (loss) income$(76,523) $253,451
 $(37,102)
 December 31,
 2018 2017 2016
 (In thousands)
Gross revenue$1,729,778
 $755,374
 $287,733
Net income (loss)$253,451
 $(37,102) $(65,070)

Tatex Thailand II, LLC
The Company has an indirect ownership interest in Tatex Thailand II, LLC (“Tatex”). and received $2.1 million in distributions from Tatex holds an 8.5%during the year ended December 31, 2019, of which $1.9 million related to proceeds from the sale of its interest in APICO LLC (“APICO”), an international oil and gas exploration company. The Company received $0.2 million in distributions from Tatex during the year ended December 31, 2018. Tatex previously held an 8.5% interest in APICO before selling its interest in June 2019. 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 ana 24.9999% 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, 2018,2019, 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 ofat December 31, 20162019 for impairment due tobased on certain qualitative factors and as such,quantitative factors. The Company 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, resultingindicated. This resulted in recording an aggregate impairment loss of $23.1$32.4 million for the year ended December 31, 2016,2019, which is included in (income) loss from equity method investments, net in the accompanying consolidated statements of operations. As of and during the periods endedThe Company reviewed its investment in Grizzly for impairment at December 31, 2018 and 2017 commodity prices had increased as compared to 2016. and determined no impairment was required.
The Company engaged an independent third partypaid $0.4 million in cash calls during 2019 prior to perform a sensitivity analysis based on updated pricing as of December 31, 2018, and concluded that there were no impairment indicators that requiredits election to cease funding further evaluation for impairment. If commodity prices decline in the future however, further impairment of the investment in Grizzly may be necessary. Gulfportcapital calls. The Company paid $2.3 million in cash calls during each of the yearsyear ended December 31, 2018 and December 31, 2017.2018. Grizzly’s functional currency is the Canadian dollar. The Company's investment in Grizzly was increased by a $9.0 million foreign currency translation gain, 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, 2019, 2018 and 2017, respectively. The Company had $44.8 million and 2016, respectively.
Effective October 5, 2012,$53.8 million in accumulated other comprehensive loss in its accompanying consolidated balance sheets related to 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 terminalat December 31, 2019 and a sand transloading facility in Ohio. During the years ended December 31, 2018, and 2017,respectively, that will be included in the

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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.sale or abandonment.
Windsor Midstream LLC
At December 31, 2018,2019, 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 no0 distributions from Midstream during the yearyears ended December 31, 20182019 and $0.5 million in distributions during the same period in 2017.2018.
Stingray Cementing LLC
During 2012,The Company has determined that Midstream is a variable interest entity ("VIE") but that the Company investedis not the primary beneficiary because it does not have a controlling financial interest in Stingray Cementing LLC ("Stingray Cementing"). Stingray Cementing provides well cementing services.Midstream. This entity is considered a VIE because the limited partners lack substantive kick-out or participating rights over the general partner. The (income) loss fromgeneral partner has power to direct the activities that most significantly impact Midstream's economic performance. The Company accounts for its investment in VIEs following the equity method of accounting. The carrying amounts of the Company’s equity investments presentedare 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 table above reflects any intercompany profit eliminations. consolidated statements of operations.
Mammoth Energy Services, Inc.

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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 four3 entities to Mammoth Energy Partners LP ("Mammoth")in exchange 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 9,150,000approximately 2.0 million shares of Mammoth Energy common stock in returnstock. The Company accounted for its contribution. Following thethis contribution Mammoth Energy completed its initial public offering (the "IPO")as a sale 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 Energyfinancial assets 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$12.5 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").

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Following the June 2017 transactions, the Company held approximately 25.1% of Mammoth Energy’s outstanding common stock. The Company accountedoperations 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,year ended December 31, 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.
At December 31, 2019, the Company owned 9,829,548 shares, or 21.8%, of the outstanding common stock of Mammoth Energy. The Company reviewed its investment in Mammoth Energy during 2019 for impairment based on certain qualitative and quantitative factors. As a result of the calculated fair values and other qualitative factors, the Company concluded that an other than temporary impairment was indicated. This resulted in recording an impairment loss of $160.8 million for the year ended December 31, 2019, which is included in loss (income) from equity method investments, net in the accompanying consolidated statements of operations. If Mammoth Energy's common stock continues to trade below the Company's carrying value for a prolonged period of time, further impairment of the Company's investment in Mammoth Energy may be necessary. The Company's investment in Mammoth Energy was increased by a $0.2 million foreign currency gain, 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, 2019, 2018 and 2017, respectively. During the year ended December 31, 2019, Gulfport received distributions of $2.5 million from Mammoth Energy as a result of $0.125 per share dividends in February 2019 and May 2019. 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 approximate fair value of the Company's investment in Mammoth Energy's common stock at December 31, 2019 was $21.6 million based on the quoted market price of Mammoth Energy's common stock. The loss (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

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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:
 2019 2018
 (In thousands)
Revolving credit agreement(1) 
$120,000
 $45,000
6.625% senior unsecured notes due 2023329,467
 350,000
6.000% senior unsecured notes due 2024603,428
 650,000
6.375% senior unsecured notes due 2025529,525
 600,000
6.375% senior unsecured notes due 2026397,529
 450,000
Net unamortized debt issuance costs(2) 
(23,751) (30,733)
Construction loan22,453
 23,149
Less: current maturities of long term debt(631) (651)
Debt reflected as long term$1,978,020
 $2,086,765


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 2018 2017
 (In thousands)
Revolving credit agreement (1)$45,000
 $—
6.625% senior unsecured notes due 2023 (2)350,000
 350,000
6.000% senior unsecured notes due 2024 (3)650,000
 650,000
6.375% senior unsecured notes due 2025 (4)600,000
 600,000
6.375% senior unsecured notes due 2026 (5)450,000
 450,000
Net unamortized debt issuance costs (6)(30,733) (34,781)
Construction loan (7)23,149
 23,724
Less: current maturities of long term debt(651) (622)
Debt reflected as long term$2,086,765
 $2,038,321

Maturities of long-term debt (excluding unamortized debt issuance costs) as of December 31, 20182019 are as follows:
 (In thousands)
2020$631
2021120,663
2022694
2023330,194
2024604,186
Thereafter946,034
Total$2,002,402
 (In thousands)
2019$651
2020629
202145,661
2022692
2023350,724
Thereafter1,719,792
Total$2,118,149

(1) The Company has entered into a senior secured revolving credit facility, as amended (the "revolving credit facility"), with theThe Bank of Nova Scotia, as the lead arranger and administrative agent and certain lenders from time to time party thereto.other lenders. The revolving credit agreement provides for a maximum facility amount of $1.5 billion and matures on December 31,13, 2021. On March 29, 2017,June 3, 2019, the Company further amended its revolving credit facility to, among other things, amendallow the definition of the term EBITDAXCompany 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 anydesignate certain of its subsidiaries in excess of $50.0 million.as unrestricted subsidiaries and to include LIBOR replacement provisions. The borrowing base was reaffirmed at $1.4 billion, and the Company's elected commitment amount remained at $1.0 billion. On May 4, 2017,November 25, 2019, the borrowing base under the Company's revolving credit facility was further amendedreduced 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

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borrowing base was set at $1.2 billion, with anand the Company's 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 ofremained at $1.0 billion.
As of December 31, 2018, $45.02019, $120.0 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$243.6 million of letters of credit, was $638.4$636.4 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, 2018,2019, amounts borrowed under the credit facility bore interest at a weighted average rate of 4.23%3.30%.
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

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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 related to its outstanding indebtedness at December 31, 2018.2019.
(2) On April 21, 2015,Loan issuance costs related to 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”"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”"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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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"“Notes”) have been presented as a reduction to the principal amount of the Notes. At December 31, 2018,2019, total unamortized debt issuance costs were $4.4$3.3 million for the 2023 Notes, $8.7$6.9 million for the 2024 Notes, $12.5$9.6 million for the 2025 Notes and $5.0$3.9 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, 2018.2019.
(7) On June 4, 2015,Debt Repurchases
In July of 2019, the Company's Board of Directors authorized $100 million of cash to be used to repurchase its senior notes in the open market at discounted values to par. In December 2019, the Company's Board of Directors increased the authorized size of its senior note repurchase program to $200 million in total. During the year ended December 31, 2019, the Company entered into a construction loan agreement (the "Construction Loan") with InterBankused borrowings under its revolving credit facility to repurchase in the open market approximately $190.1 million aggregate principal amount of its outstanding Notes for the construction of a new corporate headquarters$138.8 million in Oklahoma City, which was substantially completed in December 2016. The Construction Loan allows for maximumcash. This included approximately $20.5 million principal borrowings of $24.5 million and required the Company to fund 30%amount of the cost2023 Notes, $46.6 million principal amount of the construction before any funds could be drawn, which occurred in January 2016. Interest accrues daily on the outstanding2024 Notes, $70.5 million principal balance at a fixed rate of 4.50% per annum and was payable on the last dayamount of the month through May 31, 2017. Starting June 30, 2017,2025 Notes, and $52.5 million principal amount of the 2026 Notes. The Company began making monthly paymentsrecognized a $48.6 million gain on debt extinguishment, which included retirement of principalunamortized issuance costs and interest,fees associated with the final payment due June 4, 2025. At December 31, 2018,repurchased debt. This gain is included in gain on debt extinguishment in the total borrowings under the Construction loan were approximately $23.1 million.accompanying consolidated statements of operations.
Interest Expense
The following schedule shows the components of interest expense for the year ended December 31:

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 2018 2017 2016
 (In thousands)
Cash paid for interest$126,342
 $101,958
 $68,966
Change in accrued interest7,280
 10,699
 1,768
Capitalized interest(4,470) (9,470) (9,148)
Amortization of loan costs6,121
 5,011
 3,660
Amortization of note discount and premium—
 —
 (1,716)
Total interest expense$135,273
 $108,198
 $63,530

 2019 2018 2017
 (In thousands)
Cash paid for interest$142,664
 $132,995
 $107,548
Change in accrued interest(3,834) 7,266
 12,524
Capitalized interest(3,372) (4,470) (9,470)
Amortization of loan costs6,328
 6,121
 5,011
Total interest expense$141,786
 $141,912
 $115,613

The Company capitalized approximately $4.5$3.4 million and $9.5$4.5 million in interest expense to undeveloped oil and natural gas properties during the years ended December 31, 2019 and 2018, and 2017, respectively.
Fair Value of Debt
At December 31, 2019, the carrying value of the outstanding debt represented by the Notes was approximately $1.8 billion. Based on the quoted market prices (Level 1), the fair value of the Notes was determined to be approximately $1.3 billion at December 31, 2019.
7.6.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

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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 doesdid not require the Company to acquire any specific number of shares. This repurchase program was authorized to extend through December 31, 2018 and the Company repurchased 20.7 million shares of common stock in 2018 for $200.0 million in aggregate consideration.
In January 2019, the board of directors of the Company approved a new stock repurchase program to acquire a portion of the Company's outstanding common stock within a 24 month period. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and are 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. This repurchase program is authorized to extend through December 31, 2020. The program was fully executed. suspended in the fourth quarter of 2019, but may be reactivated in the future depending on our projected leverage profile, commodity price outlook and market conditions.
For the year ended December 31, 2018,2019, the Company repurchased 20.73.8 million shares for a cost of approximately $200.0$30.0 million under this repurchase program. Additionally, for the year ended December 31, 2018,2019, the Company repurchased approximately 29,0000.1 million shares for a cost of approximately $0.3$0.7 million to satisfy tax withholding requirements incurred upon the vesting of restricted stock. All repurchased shares have been canceled.canceled and returned to the status of authorized but unissued shares.
8.7.STOCK-BASED COMPENSATION
The Company adopted the 2005 Stock Incentive Plan ("2005 Plan") in January 2005. The 2005 Plan was amended and restated in April 2013 with the 2013 Restated Stock Incentive Plan ("2013 Plan"). During 2019, the Company further amended and restated the 2013 Plan with the 2019 Amended and Restated Stock Incentive Plan ("2019 Plan"). The 2019 Plan provides for grants of options, stock appreciation rights, restricted awards (restricted stock and restricted stock units) and performance awards to employees, consultants and directors of the Company that, in aggregate, do not exceed 12,500,000 shares. The 2019 Plan is administered by the Compensation Committee of the Company's board of directors (the "Committee"). Among other responsibilities, the Committee selects individuals to receive awards and establishes the terms of awards. As of December 31, 2019, the Company has awarded 8,673,254 restricted stock units and 2,009,144 performance vesting restricted stock units under the 2019 Plan.
During the years ended December 31, 2019, 2018 2017 and 20162017 the Company’s stock-based compensation cost was $10.7 million, $11.3 million $10.6 million and $12.3$10.6 million, respectively, of which the Company capitalized $5.8 million, $4.5 million $4.2 million and $4.9 $4.2

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million, respectively, relating to its exploration and development efforts. Stock compensation costs, net of the amounts capitalized, are included in general and administrative expenses in the accompanying consolidated statements of operations.
The following table summarizes restricted stock unit and performance vesting restricted stock unit activity for the twelve months ended December 31, 2019, 2018 2017 and 2016:

2017:
F-26
 
Number of
Unvested
Restricted Stock Units
 
Weighted
Average
Grant Date
Fair Value
 
Number of
Unvested
Performance Vesting Restricted Stock Units
 
Weighted
Average
Grant Date
Fair Value
Unvested shares as of January 1, 2017613,056
 $32.90
 $—
 $—
Granted876,846
 15.14
 —
 —
Vested(423,977) 29.90
 —
 —
Forfeited(89,898) 27.91
 —
 —
Unvested shares as of December 31, 2017976,027
 $18.71
 $—
 $—
Granted1,579,911
 $9.90
 $—
 $—
Vested(626,671) 18.05
 —
 —
Forfeited(393,456) 12.23
 —
 —
Unvested shares as of December 31, 20181,535,811
 $11.57
 $—
 $—
Granted4,011,073
 3.74
 2,009,144
 2.85
Vested(676,108) 12.89
 —
 —
Forfeited(772,458) 6.05
 (225,484) 1.98
Unvested shares as of December 31, 20194,098,318
 $4.73
 1,783,660
 $2.96

Restricted Stock Units
TableRestricted stock units awarded under the 2019 Plan generally vest over a period of Contents
Index to Financial Statements

 
Number of
Unvested
Restricted Shares
 
Weighted
Average
Grant Date
Fair Value
Unvested shares as of January 1, 2016484,239
 $43.51
Granted451,241
 27.78
Vested(252,566) 43.94
Forfeited(69,858) 33.43
Unvested shares as of December 31, 2016613,056
 $32.90
Granted876,846
 $15.14
Vested(423,977) 29.90
Forfeited(89,898) 27.91
Unvested shares as of December 31, 2017976,027
 $18.71
Granted1,579,911
 9.90
Vested(626,671) 18.05
Forfeited(393,456) 12.23
Unvested shares as of December 31, 20181,535,811
 $11.57
one year in the case of directors and three years in the case of employees and vesting is dependent upon the recipient meeting applicable service requirements. Stock-based compensation costs are recorded ratably over the service period. The grant date fair value of restricted stock units represents the closing market price of the Company's common stock on the date of grant. Unrecognized compensation expense as of December 31, 20182019 related to outstanding restricted stock options and restricted sharesunits was $13.9 million.$14.6 million. The expense is expected to be recognized over a weighted average period of 1.602.10 years.
Performance Vesting Restricted Stock Units
During the year ended December 31, 2019, the Company awarded performance vesting restricted stock units to certain of its executive officers under the 2019 Plan. The number of shares of common stock issued pursuant to the award will be based on relative total shareholder return ("RTSR"). RTSR is an incentive measure whereby participants will earn from 0% to 200% of the target award based on the Company’s RTSR ranking compared to the RTSR of the companies in the Company’s designated peer group at the end of the performance period. Awards will be earned and vested over a performance period measured from January 1, 2019 to December 31, 2021, subject to earlier termination of the performance period in the event of a change in control. The grant date fair value was determined using the Monte Carlo simulation method and is being recorded ratably over the performance period. Expected volatilities utilized in the Monte Carlo model were estimated using a historical period consistent with the remaining performance period of approximately two years. The risk-free interest rates were based on the U.S. Treasury rate for a term commensurate with the expected life of the grant. The Company assumed a range of risk-free interest rates of 1.56% to 2.42% and a range of expected volatilities of 29.1% to 85.1% to estimate the fair value of performance vesting units granted during the year ended December 31, 2019. Unrecognized compensation expense as of December 31, 2019 related to performance vesting restricted stock units was $4.2 million. The expense is expected to be recognized over a weighted average period of 2.38 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.
10.8.REVENUE FROM CONTRACTS WITH CUSTOMERS
On January 1, 2018,Revenue Recognition
The Company’s revenues are primarily derived from the Company adopted ASC 606 using the modified retrospective transition appliedsale of natural gas, oil and condensate and NGL. Sales of natural

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gas, oil and condensate and NGL are recognized in the Company’s accountingperiod that the performance obligations are satisfied. The Company generally considers the delivery of each unit (MMBtu or haveBbl) to be separately identifiable and represents a material effectdistinct performance obligation that is satisfied at the time control of the product is transferred to the customer. 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 Company’s financial position, including measurementapplicable market pricing, which will be known upon transfer of revenue, the timinggoods to the customer. The payment date is usually within 30 days of revenue recognition and the recognitionend of contract assets, liabilities and related costs. For periods through December 31, 2017, the Company accounted for its revenue using ASC 605, Revenue Recognition.calendar month in which the commodity is delivered.
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

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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$121.2 million and $146.8$210.2 million as of December 31, 20182019 and December 31, 2017,2018, respectively, and are reported in accounts receivable - oil and natural gas sales onin the accompanying consolidated balance sheet.sheets. 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, 2018,2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.
11.9.LEASES
Effective January 1, 2019, the Company adopted ASU No. 2016-02, Leases (Topic 842). The new standard supersedes the previous lease guidance by requiring lessees to recognize a right-of-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 Company adopted the new standard on a prospective basis using the simplified transition method permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. 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 exceeding one year. NaN cumulative-effect adjustment to retained earnings was required upon adoption of the new standard. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. The Company elected the package of practical expedients permitted under the new standard, which among other things, allows for lease and non-lease components in a contract to be accounted for as a single lease component for all asset classes and the carry forward of historical lease classifications.
Nature of Leases
The Company has operating leases associated with drilling rig commitments, pressure pumping services, field offices and other equipment with remaining lease terms with contractual durations in excess of one year. Short-term leases that have an initial term of one year or less are not capitalized.
The Company has entered into contracts for drilling rigs with third parties to ensure rig availability in its key operating areas. The Company has concluded its drilling rig contracts are operating leases as the assets are identifiable and the evaluation that the Company has the right to control the identified assets. The Company's drilling rig commitments are typically structured with an initial term of less than one year to two years and expire at various dates through 2020. These agreements typically include renewal options at the end of the initial term. Due to the nature of the Company's drilling schedules and potential volatility in commodity prices, the Company is unable to determine at commencement with reasonable certainty if the renewal options will be exercised; therefore, renewal options are not considered in the lease term for drilling contracts. The operating lease liabilities associated with these rig commitments are based on the minimum contractual obligations, primarily standby rates, and do not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of these costs are borne by other interest owners.
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 and a related party. 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 through 2021 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. The Company has determined that the agreement with Stingray Pressure is an operating lease due to the implicit identification of assets and the evaluation that the Company has the right to control the identified assets. The operating lease liability associated with this agreement is based on the minimum contractual obligations, which is the monthly service fee for one crew, and does not include variable amounts based on actual activity in a given period. Pursuant to the full cost method of accounting, these costs are capitalized as part of oil and natural gas properties on the accompanying consolidated balance sheets. A portion of these costs are borne by other interest owners. On December 18, 2019, the Company filed a lawsuit against Stingray Pressure to terminate this agreement. As the outcome of this lawsuit is unknown, the related right of use asset and operating lease liability are still recognized as of December 31, 2019 in the accompanying consolidated balance sheets.
The Company rents office space for its field locations and certain other equipment from third parties, which expire at various dates through 2024. These agreements are typically structured with non-cancelable terms of one to five years. The Company has determined these agreements represent operating leases with a lease term that equals the primary non-cancelable contract term. The Company has included any renewal options that it has determined are reasonably certain of exercise in the determination of the lease terms.
Discount Rate
As most of the Company's leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The Company's incremental borrowing rate reflects the estimated rate of interest that it would pay to borrow on a collateralized basis over a similar term an amount equal to the lease payments in a similar economic environment.
Maturities of operating lease liabilities as of December 31, 2019 were as follows:

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  (In thousands)
2020 $36,415
2021 22,569
2022 115
2023 90
2024 30
Total lease payments $59,219
Less: Imputed interest (1,781)
Total $57,438

Lease cost for the year ended December 31, 2019 consisted of the following:
 (In thousands)
Operating lease cost $24,960
Operating lease cost - related party 22,440
Variable lease cost 2,172
Variable lease cost - related party 66,924
Short-term lease cost 834
Total lease cost(1)
 $117,330
_____________________
(1)The majority of the Company's total lease cost was capitalized to the full cost pool, and the remainder was included in general and administrative expenses in the accompanying consolidated statements of operations.
Supplemental cash flow information for the year ended December 31, 2019 related to leases was as follows:
Cash paid for amounts included in the measurement of lease liabilities(In thousands)
     Operating cash flows from operating leases182
     Investing cash flow from operating leases24,263
     Investing cash flow from operating leases - related party84,750

The weighted-average remaining lease term as of December 31, 2019 was 1.75 years. The weighted-average discount rate used to determine the operating lease liability as of December 31, 2019 was 3.52%.
10.INCOME TAXES
The income tax provision consists of the following:
 2019 2018 2017
 (In thousands)
Current:     
State$—
 $(1,530) $2,167
Federal(7) 253
 3,362
Deferred:     
State(7,556) 1,530
 (118)
Federal—
 (322) (3,602)
Total income tax (benefit) expense provision$(7,563) $(69) $1,809


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 2018 2017 2016
 (In thousands)
Current:     
State$(1,530) $2,167
 $(1,330)
Federal253
 3,362
 (19,771)
Deferred:     
State1,530
 (118) (386)
Federal(322) (3,602) 18,574
Total income tax (benefit) expense provision$(69) $1,809
 $(2,913)

A reconciliation of the statutory federal income tax amount to the recorded expense follows:

 2019 2018 2017
 (In thousands)
Income (loss) before federal income taxes$(2,009,921) $430,491
 $436,961
Expected income tax at statutory rate(422,083) 90,403
 152,936
State income taxes(28,316) (511) 2,299
Other differences3,372
 1,078
 5,731
Remeasurement due to Tax Cut and Jobs Act—
 —
 190,034
Change in valuation allowance due to current year activity439,464
 (91,039) (158,704)
Change in valuation allowance due to Tax Cuts and Jobs Act—
 —
 (190,487)
Income tax (benefit) expense recorded$(7,563) $(69) $1,809

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 2018 2017 2016
 (In thousands)
Income (loss) before federal income taxes$430,491
 $436,961
 $(982,622)
Expected income tax at statutory rate90,403
 152,936
 (343,918)
State income taxes(511) 2,299
 (5,883)
Other differences1,078
 5,731
 4,293
Intraperiod tax allocation—
 —
 (1,349)
Remeasurement due to Tax Cut and Jobs Act—
 190,034
 —
Change in valuation allowance due to current year activity(91,039) (158,704) 343,944
Change in valuation allowance due to Tax Cuts and Jobs Act—
 (190,487) —
Income tax (benefit) expense recorded$(69) $1,809
 $(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, 2019, 2018 2017 and 20162017 are estimated as follows:
 2019 2018 2017
 (In thousands)
Deferred tax assets:     
Net operating loss carryforward$269,851
 $164,363
 $120,626
Oil and gas property basis difference289,850
 3,595
 151,260
Investment in pass through entities58,951
 8,620
 12,343
Stock-based compensation expense1,440
 616
 813
Business energy investment tax credit370
 369
 369
Charitable contributions carryover297
 269
 255
Change in fair value of derivative instruments11,219
 2,761
 —
Foreign tax credit carryforwards943
 2,009
 2,074
Accrued liabilities669
 834
 285
ARO liability12,744
 16,923
 15,897
Non-oil and gas property basis difference—
 104
 171
Lease liability12,128
 —
 —
State net operating loss carryover13,258
 11,526
 6,954
Interest expense carryforward23,818
 —
 —
Total deferred tax assets695,538
 211,989
 311,047
Valuation allowance for deferred tax assets(647,575) (211,987) (298,830)
Deferred tax assets, net of valuation allowance47,963
 2
 12,217
Deferred tax liabilities:     
Non-oil and gas property basis difference1,859
 —
 —
Change in fair value of derivative instruments26,410
 2
 11,009
Right of use asset12,128
 —
 —
Other3
 —
 —
Total deferred tax liabilities40,400
 2
 11,009
Net deferred tax asset$7,563
 $—
 $1,208

The company recognized an income tax benefit of $7.6 million in 2019 and an income tax benefit of $69.0 thousand in 2018. The income tax benefit for 2019 consists mainly of a partial release of valuation allowance that was maintained against

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 2018 2017 2016
 (In thousands)
Deferred tax assets:     
Net operating loss carryforward$164,363
 $120,626
 $162,073
Oil and gas property basis difference3,595
 151,260
 386,302
Investment in pass through entities8,620
 12,343
 27,469
Stock-based compensation expense616
 813
 2,084
Business energy investment tax credit369
 369
 369
AMT credit—
 —
 3,842
Charitable contributions carryover269
 255
 303
Change in fair value of derivative instruments2,761
 —
 48,317
Foreign tax credit carryforwards2,009
 2,074
 2,074
Accrued liabilities834
 285
 397
ARO liability16,923
 15,897
 12,107
Non-oil and gas property basis difference104
 171
 —
State net operating loss carryover11,526
 6,954
 5,351
Total deferred tax assets211,989
 311,047
 650,688
Valuation allowance for deferred tax assets(211,987) (298,830) (645,841)
Deferred tax assets, net of valuation allowance2
 12,217
 4,847
Deferred tax liabilities:     
Non-oil and gas property basis difference—
 —
 155
Change in fair value of derivative instruments2
 11,009
 —
Total deferred tax liabilities2
 11,009
 155
Net deferred tax asset$—
 $1,208
 $4,692


our Oklahoma deferred tax asset, as the Company believes that it can utilize a portion of its Oklahoma state NOL through carrybacks and carryforwards to offset Oklahoma sourced income from the sale of assets.
The Company has an available federal tax net operating loss carryforward estimated at approximately $1.3 billion as of December 31, 2019. This carryforward will begin to expire in the year 2023. The Company also has state net operating loss carryovers of $244.5 million that began to expire in 2019 and federal foreign tax credit carryovers of $0.9 million which began to expire in 2019.
At each reporting period, the Company weighs all available positive and negative evidence to determine whether its deferred tax assets are more likely than not to be realized. As a result of this analysis at December 31, 2019, the Company determined a valuation allowance was necessary with respect to its deferred tax assets, except for its Oklahoma state NOL. The more significant evidential matter relates to the Company’s recent cumulative losses resulting primarily from impairments to the full cost pool during 2019 and the decline in commodity prices. At December 31, 2019, the Company has recorded a total valuation allowance of $647.6 million related to the federal and state net deferred tax assets for which it believes do not meet the more likely than not threshold.
There was an increase of $439.5 million, a decrease of $86.8 million and a decrease of $347.0 million to the valuation allowance of $86.8 million and $347.0 million during 2019, 2018 and 2017, respectively, and anrespectively. The increase toin the valuation allowance of $342.6 million during 2016.in 2019 was primarily due to increases in net deferred tax assets from pre-tax losses resulting from impairments in the Company's oil and natural gas properties. The decrease in the valuation allowance in 2018 was primarily due to decreases in net deferred tax assets due to pretaxpre-tax income. The decrease in the valuation allowance in 2017 was primarily due to decreases in net deferred tax assets due to pretaxpre-tax 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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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”382") and its related tax regulations. The utilization of these attributes may be limited if certain ownership changes by 5% stockholdersshareholders (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. Thethe Company. As of December 31, 2019, the Company is currently conductinghas completed a Section 382 analysis, to determine if an ownership change has occurred. If it is determinedwhich reflects that anno ownership change has occurred under these rules, the Company would generally be subject to an annual limitation onfurther limit the use of pre-ownership change NOL carryforwards and certainor 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 transactionstax attributes. There are conditions that exist that are beyond the Company’s control which could cause an ownership change in the future and thereforecreate a potentialsignificant limitation on the annual utilization of their deferredCompany's ability to utilize those 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.attributes.
As of December 31, 2018,2019, the amount of unrecognized tax benefits related to federal and state tax liabilitiesCompany has recorded a liability associated with uncertain tax positions was immaterial.of $3.1 million.




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12.11.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,
 2019 2018 2017
 Loss Shares 
Per
Share
 Income Shares 
Per
Share
 Income Shares Per Share
 (In thousands, except share data)
Basic:                 
Net (loss) income$(2,002,358) 160,341,125
 $(12.49) $430,560
 174,675,840
 $2.46
 $435,152
 179,834,146
 $2.42
Effect of dilutive securities:
 
 
 
 
 
      
Stock options and awards—
 —
 
 —
 722,866
 
 —
 418,878
  
Diluted:
 
 
 
 
 
      
Net (loss) income$(2,002,358) 160,341,125
 $(12.49) $430,560
 175,398,706
 $2.45
 $435,152
 180,253,024
 $2.41
 For the Year Ended December 31,
 2018 2017 2016
 Income Shares 
Per
Share
 Loss Shares 
Per
Share
 Loss Shares Per Share
 (In thousands, except share data)
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—
 722,866
 
 —
 418,878
 
 —
 —
  
Diluted:
 
 
 
 
 
      
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 no3,867,084 shares of common stock that were considered anti-dilutive for the year ended December 31, 2019. There were 0 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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13.12.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 NGLsNGL 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, oil and NGLsNGL 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.
 LocationDaily Volume (MMBtu/day) 
Weighted
Average Price
2019NYMEX Henry Hub1,254,000
 $2.83
2020NYMEX Henry Hub204,000
 $2.77
2019.
 LocationDaily Volume (Bbls/day) 
Weighted
Average Price
2019Mont Belvieu C21,000
 $18.48
2019Mont Belvieu C34,000
 $28.87
2019Mont Belvieu C5500
 $54.08
 IndexDaily Volume (MMBtu/day) 
Weighted
Average Price
2020NYMEX Henry Hub548,000
 $2.88
During
 IndexDaily Volume
(Bbls/day)		 Weighted
Average Price
2020NYMEX WTI6,000
 59.82
 IndexDaily Volume (Bbls/day) 
Weighted
Average Price
2020Mont Belvieu C3500
 $21.63

In the fourththird quarter of 2018,2019, 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 in exchange for a premium, and used the associated premiums received to enhance the fixed price for a portion of the fixed price natural gas swaps primarily for 2020 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.
 LocationDaily Volume (MMBtu/day) 
Weighted
Average Price
January 2019 - March 2019NYMEX Henry Hub50,000
 $3.13
April 2019 - December 2019NYMEX Henry Hub30,000
 $3.10
 IndexDaily Volume (MMBtu/day) 
Weighted
Average Price
2022NYMEX Henry Hub628,000
 $2.90
2023NYMEX Henry Hub628,000
 $2.90

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.positions. As of December 31, 2018,2019, the Company had the following natural gas basis swap positions for Transco Zone 4.open:
 Gulfport PaysGulfport ReceivesDaily Volume (MMBtu/day) Weighted Average Fixed Spread
2020Transco Zone 4NYMEX Plus Fixed Spread60,000

$(0.05)
2020Fixed SpreadONEOK Minus NYMEX10,000

$(0.54)



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Contingent Consideration Arrangement
The purchase and sale agreement for the sale of the Company's non-core assets located in the WCBB and Hackberry fields of Louisiana included a contingent consideration arrangement that entitles the Company to receive bonus payments if commodity prices exceed specified thresholds. The calculated fair value of this contingent payment arrangement was approximately $1.1 million as of the closing date of the divestiture. See below for threshold and potential payment amounts.
Period
Threshold(1)
Payment to be received(2)
July 2020 - June 2021Greater than or equal to $60.65$150,000
 Between $52.62 - $60.65
Calculated Value(3)

 Less than or equal to $52.62$—
_____________________
 LocationDaily Volume (MMBtu/day) Hedged Differential
2019Transco Zone 460,000
 $(0.05)
2020Transco Zone 460,000
 $(0.05)
(1)Based on the "WTI NYMEX + Argus LLS Differential," as published by Argus Media.
(2)Payment will be assessed monthly from July 2020 through June 2021. If threshold is met, payment shall be received within five business days after the end of each calendar month.
(3)If average daily price, as defined in (1), is greater than $52.62 but less than $60.65, payment received will be $150,000 multiplied by a fraction, the numerator of which is the amount determined by subtracting $52.62 from such average daily price, and the denominator of which is $8.03.
Balance sheet presentation
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, 20182019 and 2017:2018:
 December 31,
 2018 2017
 (In thousands)
Short-term derivative instruments - asset$21,352
 $78,847
Long-term derivative instruments - asset$—
 $8,685
Short-term derivative instruments - liability$20,401
 $32,534
Long-term derivative instruments - liability$13,992
 $2,989
 December 31,
 2019 2018
 (In thousands)
Commodity derivative instruments125,383
 21,352
Contingent consideration arrangement818
 —
Total short-term derivative instruments – asset126,201
 21,352
    
Commodity derivative instruments—
 —
Contingent consideration arrangement563
 —
Total long-term derivative instruments – asset563
 —
    
Total short-term derivative instruments – liability303
 $20,401
    
Total long-term derivative instruments – liability53,135
 $13,992
Gains and losses
The following table presents the gain and loss recognized in net gain (loss) gain on natural gas, oil and NGL derivatives in the accompanying consolidated statements of operations for the years ended December 31, 2019, 2018, 2017, and 2016.2017.

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 Net (loss) gain on derivative instruments
 For the Year Ended December 31,
 2018 2017 2016
 (In thousands)
Natural gas derivatives$(116,130) $232,143
 $(165,933)
Oil derivatives(13,084) (3,350) (5,387)
Natural gas liquids derivatives5,735
 (15,114) (3,186)
Total$(123,479) $213,679
 $(174,506)

The Company delivered approximately 78% of its 2018 production under fixed price swaps.
 Net gain (loss) on derivative instruments
 For the Year Ended December 31,
 2019 2018 2017
 (In thousands)
Natural gas derivatives$194,450
 $(116,130) $232,143
Oil derivatives7,035
 (13,084) (3,350)
NGL derivatives6,632
 5,735
 (15,114)
Contingent consideration arrangement243
 —
 —
Total$208,360
 $(123,479) $213,679

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.
As of December 31, 2018As of December 31, 2019
Derivative instruments, gross Netting adjustments Derivative instruments, netDerivative instruments, gross Netting adjustments Derivative instruments, net
(In thousands)(In thousands)
Derivative assets$21,352
 $(19,289) $2,063
$126,764
 $(53,438) $73,326
Derivative liabilities$(34,393) $19,289
 $(15,104)$(53,438) $53,438
 $—
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 As of December 31, 2018
 Derivative instruments, gross Netting adjustments Derivative instruments, net
 (In thousands)
Derivative assets$21,352
 $(19,289) $2,063
Derivative liabilities$(34,393) $19,289
 $(15,104)
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 As of December 31, 2017
 Derivative instruments, gross Netting adjustments Derivative instruments, net
 (In thousands)
Derivative assets$87,532
 $(22,199) $65,333
Derivative liabilities$(35,523) $22,199
 $(13,324)

Concentration of Credit Risk
By using derivative instruments that are not traded on an exchange, the Company is exposed to the credit risk of its counterparties. Credit risk is the risk of loss from counterparties not performing under the terms of the derivative instrument. When the fair value of a derivative instrument is positive, the counterparty is expected to owe the Company, which creates credit risk. To minimize the credit risk in derivative instruments, it is the Company's policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The Company's derivative contracts are with multiple counterparties to lessen its exposure to any individual counterparty. Additionally, the Company uses master netting agreements to minimize credit risk exposure. The creditworthiness of the Company's counterparties is subject to periodic review. None of the Company's derivative instrument contracts contain credit-risk related contingent features. Other than as provided by the Company's revolving credit facility, the Company is not required to provide credit support or collateral to any of its counterparties under its derivative instruments, nor are the counterparties required to provide credit support to the Company.
13.RESTRUCTURING COSTS
In the fourth quarter of 2019, the Company announced and completed a workforce reduction representing approximately 13% of its headcount. In connection with the reduction, the Company incurred a total charge of approximately $4.6 million, primarily consisting of one-time employee-related termination benefits, with a remaining liability of $0.2 million at December 31, 2019.
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, 20182019 and 2017:2018:
 December 31, 2018
 Level 1 Level 2 Level 3
 (In thousands)
Assets:     
Derivative Instruments

$—
 $21,352
 $—
Liabilities:     
Derivative Instruments

$—
 $34,393
 $—

December 31, 2019
Level 1Level 2Level 3
(In thousands)
Assets:
Derivative Instruments

$—
126,764
$—
Liabilities:
Derivative Instruments

$—
53,438
$—
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 December 31, 2018
 Level 1 Level 2 Level 3
 (In thousands)
Assets:     
Derivative Instruments$—
 $21,352
 $—
Liabilities:     
Derivative Instruments
$—
 $34,393
 $—
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 December 31, 2017
 Level 1 Level 2 Level 3
 (In thousands)
Assets:     
Derivative Instruments$—
 $87,532
 $—
Liabilities:     
Derivative Instruments
$—
 $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.

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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 downwardupward revisions recognized during the year ended December 31, 20182019 were approximately $1.8$5.9 million and $0.4$0.9 million, respectively.
Due to the unobservable nature of the inputs, the fair value of the Company's investment in Grizzly as of December 31, 2019 was estimated using assumptions that represent Level 3 inputs.
The fair value of the common stock received fromCompany's investment in Mammoth Energy in connection with the Company’s contributionas of all of its membership interests in Sturgeon, Stingray Energy and Stingray CementingDecember 31, 2019 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.
DueFair 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 unobservable nature ofCompany's construction loan is carried at cost, which approximates market value based on the inputs,borrowing rates currently available to the Company with similar terms and maturities. See Note 5 for 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.long-term debt.
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, 2018,2019, the Company held approximately 21.9%21.8% of Mammoth Energy's outstanding common stock as discussed above in Note 4.4. Approximately $0.6 million, $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, 2019, 2018 and 2017, respectively. Approximately $139.7$109.9 million and $196.5$139.7 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

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December 31, 20182019 and 2017,2018, respectively. At December 31, 20182019 and 2017,2018, the Company owed Mammoth Energy approximately $10.9$8.4 million and $32.0$10.9 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.4. 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 December 31, 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 amade bi-weekly contributioncontributions 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, 2019, 2018 2017 and 2016,2017, Gulfport incurred $2.9 million, $2.6 million, $3.0 million, and $1.7$3.0 million, respectively, in contributions expense related to this plan.
Employmentand 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.Future Sales Commitments
The Company has also entered into employment agreementsvarious firm sales contracts to deliver and sell natural gas. The Company expects to fulfill its delivery commitments primarily with certain membersproduction from proved developed reserves. The Company's proved reserves have generally been sufficient to satisfy its delivery commitments during the three most recent years, and it expects such reserves will continue to be the primary means 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 unlessfulfilling its future commitments. However, where the Company orCompany's proved reserves are not sufficient to satisfy its delivery commitments, it can and may use spot market purchases to satisfy 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.commitments.


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Firm Transportation and Sales Commitments

The Company had approximately 2,300,000 MMBtu per dayA summary of firm sales contracted with third parties. The table below presents these commitments at December 31, 2018 as follows:2019 are set forth in the table below:
 (MMBtu per day)
2020326,000
2021192,000
202270,000
202317,000
2024—
Thereafter—
Total605,000

 (MMBtu per day)
2019663,000
2020526,000
2021372,000
2022272,000
2023255,000
Thereafter212,000
Total2,300,000
Future Firm Transportation Commitments
The Company also had approximately $3.5 billionhas contractual commitments with pipeline carriers for future transportation of natural gas from the Company's production areas to downstream markets. Commitments related to future firm transportation contracted with third parties. The table below presentsagreements are not recorded as obligations in the accompanying consolidated balance sheets; however, they are reflected in the Company's estimates of proved reserves.
A summary of these commitments at December 31, 2018 as follows:2019 are set forth in the table below:
 Total MMBtu (In thousands)
2020505,080,000
 $274,813
2021531,075,000
 286,626
2022531,075,000
 286,626
2023515,867,000
 282,945
2024489,525,000
 265,568
Thereafter3,778,217,000
 2,163,926
Total6,350,839,000
 $3,560,504
 (In thousands)
2019$251,644
2020247,581
2021246,620
2022246,620
2023244,352
Thereafter2,267,501
Total$3,504,318
Operating Leases
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:
 (In thousands)
2019$144
202090
202137
Total$271
Presented below is rent expense for the years ended December 31, 2018, 2017 and 2016, respectively.
 For the years ended December 31,
 2018 2017 2016
 (In thousands)
Rent expense$196

$343

$840

Other Commitments
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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Energy and a related party. Pursuant to this agreement, as amended effective August 3, 2018, 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.expenses through 2021. 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 $3.5 million and $2.2 million related to non-utilization fees during the yearyears 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 Amended2019 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.2018.
Future minimum commitments under these agreements at December 31, 20182019 are as follows:
 (In thousands)
2020$7,500
20217,500
Total$15,000
 (In thousands)
2019$89,022
202067,203
202148,744
Total$204,969


17.CONTINGENCIES
InLitigation and Regulatory Proceedings
The Company is involved in a number of litigation and regulatory proceedings that may result in material liabilities, including those described below. Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. The Company's total accrued liabilities in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, its experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. Significant judgment is required in making these estimates and their final liabilities may ultimately be materially different.
The Company, along with a number of other oil and gas companies, has been named as a defendant 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 (together, 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."Complaints"). The Complaints were filed underallege that certain of the defendants’ operations violated 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(the "CZM Laws") by causing 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.Parish. 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-judgmentinterest. The United States District Court for the Western District of Louisiana issued orders remanding the cases to their respective state court, and post judgment interest.the defendants have appealed the remand orders to the 5th Circuit Court of Appeals.
In July 2019, Pigeon Land Company, Inc., a successor in interest to certain of the Company's legacy Louisiana properties, filed an action against the Company and a number of other oil and gas companies in the 16th Judicial District Court for the Parish of Iberia in Louisiana. The Company was servedsuit alleges negligence, strict liability and various violations of Louisiana statutes relating to property damage in connection with the Cameron complaint in early May 2016historic development of the Company's Louisiana properties and withseeks unspecified damages (including punitive damages), an injunction to return the Vermilion complaint in early September 2016. The Louisiana Attorney Generalaffected property to its original condition, and the Louisiana Departmentpayment of Natural Resources intervenedreasonable attorney fees and legal expenses and interest.
In September 2019, a stockholder of Mammoth Energy filed a derivative action on behalf of Mammoth Energy against members of Mammoth Energy’s board of directors, including a director designated by the Company, and its significant stockholders, including the Company, in both the

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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.Oklahoma. In both cases,January 2020, plaintiffs consolidated actions against 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 ofsame 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”) requestingDistrict Court for the District of Delaware.  The consolidated and amended complaint alleges, among other things, that the Cameron ParishCompany breached its fiduciary duties and Vermilion Parish lawsuits be consolidatedmisappropriated information as a controlling shareholder of Mammoth Energy in connection with 40 similar lawsuits so that pre-trial proceedingsMammoth Energy’s activities in Puerto Rico following Hurricane Maria and the Company's secondary offering of Mammoth Energy common stock in June 2018. The complaint seeks unspecified damages, the payment of reasonable attorney fees and legal expenses and interest and to force Mammoth Energy and its board of directors to make specified corporate governance reforms.
In October 2019, Saydee Resources, LLC, on behalf of itself and a class of similarly situated royalty holders, filed an action against the Company in the cases could be coordinated.District Court of Grady County Oklahoma. The MDL Panel deniedsuit alleges that the motion to consolidate the lawsuits. Due to the procedural postureCompany underpaid royalty holders and seeks unspecified damages for breach of contract, tortious breach of contract, fraud and unjust enrichment.
In October 2019, Kelsie Wagner, in her capacity as trustee of various trusts and on behalf of the lawsuits,trusts and other similarly situated royalty owners, filed an action against us in the cases are still in their early stagesDistrict Court of Grady County, Oklahoma.  The suit alleges that the Company underpaid royalty owners and seeks unspecified damages for violations of the Oklahoma Production Revenue Standards Act and fraud.

SEC Investigation
The SEC has commenced an investigation with respect to certain actions by former Company management, including alleged improper personal use of Company assets, and potential violations by former management and the partiesCompany of the Sarbanes-Oxley Act of 2002 in connection with such actions. We have conducted very little discovery. As a result,fully cooperated and intend to continue to cooperate fully with the SEC’s investigation. Although it is not possible to predict the ultimate resolution or financial liability with respect to this matter, the Company hasbelieves that the outcome of this matter will not had the opportunity to evaluate the applicability of the allegations made in plaintiffs' complaints tohave a material effect on the Company's business, financial condition or results of operations.
Business Operations

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The Company is involved in various lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and management cannot determine the amount of loss, if any, that may result.contract actions.
In addition, due to theEnvironmental Contingencies
The nature of the Company'soil and gas business carries with it certain environmental risks for Gulfport and its subsidiaries. They have implemented various policies, programs, procedures, training and audits to reduce and mitigate such environmental risks. They conduct periodic reviews, on a company-wide basis, to assess changes in their environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. The Company manages its exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, they may, among other things, exclude a property from the transaction, require the seller to remediate the property to their satisfaction in an acquisition or agree to assume liability for the remediation of the property.
The Company received several Finding of Violation (“FOVs”) from the United States Environmental Protection Agency ("USEPA") alleging violations of the Clean Air Act in Ohio. The first FOV for 1 site was dated December 11, 2013.  NaN subsequent FOVs incorporated and expanded the scope on January 4, 2017 and April 15, 2019.  The Company entered into a settlement with the Department of Justice and USEPA agreeing to pay $1.7 million and invest in improvements at 17 well pads. The settlement was filed with the U.S. District Court for the Southern District of Ohio in January 2020, and is from time to time, involved in routine litigationpending approval. 
Other Matters
Based on management’s current assessment, they are of the opinion that no pending or subject to disputesthreatened lawsuit or claims relateddispute relating 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, willoperations is likely to have a material adverse effect on itstheir future consolidated financial condition, cash flows orposition, results of operations.operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
Insurance Proceeds
For the years ended December 31, 20182019 and 20162018 the Company was reimbursed $0.2$0.1 million and $5.7$0.2 million, respectively, net of related legal fees by its insurance provider, which is included in insurance proceedsother expense (income) in the accompanying consolidated statements of operations. There were no0 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 LouisianaOklahoma 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, 2018,2019, Gulfport held cash in excess of insured limits in these banks totaling $50.3$5.6 million.
During the year ended December 31, 2019, one customer accounted for approximately 14% of the Company's total sales. 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, oil and condensate 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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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"Mule Sky LLC ("Mule Sky") or GRUS, LLC ("GRUS")

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(the “Non-Guarantors”). The Guarantors are 100% owned by Gulfport (the "Parent"“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. Effective June 1, 2019, the Parent contributed interests in certain oil and gas assets and related liabilities to certain of the Guarantors.
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-GuarantorNon-Guarantors 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'sParent’s ownership of the Guarantors and the Non-Guarantor.Non-Guarantors.


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CONDENSED CONSOLIDATING BALANCE SHEETS
(Amounts in thousands)
 December 31, 2019
 Parent Guarantors Non-Guarantor Eliminations Consolidated
Assets         
Current assets:         
Cash and cash equivalents$2,768
 $3,097
 $195
 $—
 $6,060
Accounts receivable - oil and natural gas sales859
 120,351
 —
 —
 121,210
Accounts receivable - joint interest and other5,279
 42,696
 —
 —
 47,975
Accounts receivable - intercompany1,065,593
 843,223
 —
 (1,908,816) —
Prepaid expenses and other current assets4,047
 308
 76
 —
 4,431
Short-term derivative instruments126,201
 —
 —
 —
 126,201
Total current assets1,204,747
 1,009,675
 271
 (1,908,816) 305,877
Property and equipment:         
Oil and natural gas properties, full-cost accounting1,314,933
 9,273,681
 7,850
 (729) 10,595,735
Other property and equipment92,650
 50
 4,019
 —
 96,719
Accumulated depletion, depreciation, amortization and impairment(1,418,888) (5,808,254) (1,518) —
 (7,228,660)
Property and equipment, net(11,305) 3,465,477
 10,351
 (729) 3,463,794
Other assets:         
Equity investments and investments in subsidiaries3,064,503
 6,332
 21,000
 (3,059,791) 32,044
Long-term derivative instruments563
 —
 —
 —
 563
Deferred tax asset7,563
 —
 —
 —
 7,563
Inventories—
 5,182
 —
 —
 5,182
Operating lease assets14,168
 —
 —
 —
 14,168
Operating lease assets - related parties43,270
 —
 —
 —
 43,270
Other assets10,026
 332
 


 


 10,358
Total other assets3,140,093
 11,846
 21,000
 (3,059,791) 113,148
  Total assets$4,333,535
 $4,486,998
 $31,622
 $(4,969,336) $3,882,819
          
Liabilities and stockholders' equity         
Current liabilities:         
Accounts payable and accrued liabilities$48,006
 $367,088
 $124
 $—
 $415,218
Accounts payable - intercompany878,283
 1,026,249
 4,285
 (1,908,817) —
Short-term derivative instruments303
 —
 —
 —
 303
Current portion of operating lease liabilities13,826
 —
 —
 —
 13,826
Current portion of operating lease liabilities - related parties21,220
 —
 —
 —
 21,220
Current maturities of long-term debt631
 —
 —
 —
 631
Total current liabilities962,269
 1,393,337
 4,409
 (1,908,817) 451,198
Long-term derivative instruments53,135
 —
 —
 —
 53,135
Asset retirement obligation - long-term—
 58,322
 2,033
 —
 60,355
Uncertain tax position liability3,127
 —
 —
 —
 3,127
Non-current operating lease liabilities342
 —
 —
 —
 342
Non-current operating lease liabilities - related parties22,050
 —
 —
 —
 22,050
Long-term debt, net of current maturities1,978,020
 —
 —
 —
 1,978,020
Total liabilities3,018,943
 1,451,659
 6,442
 (1,908,817) 2,568,227
          
Stockholders' equity:         
Common stock1,597
 —
 —
 —
 1,597
Paid-in capital4,207,554
 4,171,408
 267,557
 (4,438,965) 4,207,554
Accumulated other comprehensive loss(46,833) —
 (44,763) 44,763
 (46,833)
Accumulated deficit(2,847,726) (1,136,069) (197,614) 1,333,683
 (2,847,726)
Total stockholders' equity1,314,592
 3,035,339
 25,180
 (3,060,519) 1,314,592
  Total liabilities and stockholders' equity$4,333,535
 $4,486,998
 $31,622
 $(4,969,336) $3,882,819

 December 31, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
Assets         
Current assets:         
Cash and cash equivalents$25,585
 $26,711
 $1
 $—
 $52,297
Accounts receivable - oil and natural gas sales146,075
 64,125
 —
 —
 210,200
Accounts receivable - joint interest and other16,212
 6,285
 —
 —
 22,497
Accounts receivable - intercompany671,633
 319,464
 —
 (991,097) —
Prepaid expenses and other current assets8,433
 2,174
 —
 —
 10,607
Short-term derivative instruments21,352
 —
 —
 —
 21,352
Total current assets889,290
 418,759
 1
 (991,097) 316,953
Property and equipment:         
Oil and natural gas properties, full-cost accounting7,044,550
 2,983,015
 —
 (729) 10,026,836
Other property and equipment91,916
 751
 —
 —
 92,667
Accumulated depletion, depreciation, amortization and impairment(4,640,059) (39) —
 —
 (4,640,098)
Property and equipment, net2,496,407
 2,983,727
 —
 (729) 5,479,405
Other assets:         
Equity investments and investments in subsidiaries2,856,988
 —
 44,259
 (2,665,126) 236,121
Inventories3,620
 1,134
 —
 —
 4,754
Other assets12,624
 1,178
 —
 1
 13,803
Total other assets2,873,232
 2,312
 44,259
 (2,665,125) 254,678
  Total assets$6,258,929
 $3,404,798
 $44,260
 $(3,656,951) $6,051,036
          
Liabilities and stockholders' equity         
Current liabilities:         
Accounts payable and accrued liabilities$419,107
 $99,273
 $—
 $—
 $518,380
Accounts payable - intercompany320,259
 670,708
 130
 (991,097) —
Short-term derivative instruments20,401
 —
 —
 —
 20,401
Current maturities of long-term debt651
 —
 —
 —
 651
Total current liabilities760,418
 769,981
 130
 (991,097) 539,432
Long-term derivative instruments13,992
 —
 —
 —
 13,992
Asset retirement obligation - long-term66,859
 13,093
 —
 —
 79,952
Deferred tax liability3,127
 —
 —
 —
 3,127
Long-term debt, net of current maturities2,086,765
 —
 —
 —
 2,086,765
Total liabilities2,931,161
 783,074
 130
 (991,097) 2,723,268
          
Stockholders' equity:         
Common stock1,630
 —
 —
 —
 1,630
Paid-in capital4,227,532
 1,915,598
 261,626
 (2,177,224) 4,227,532
Accumulated other comprehensive loss(56,026) —
 (53,783) 53,783
 (56,026)
(Accumulated deficit) retained earnings(845,368) 706,126
 (163,713) (542,413) (845,368)
Total stockholders' equity3,327,768
 2,621,724
 44,130
 (2,665,854) 3,327,768
  Total liabilities and stockholders' equity$6,258,929
 $3,404,798
 $44,260
 $(3,656,951) $6,051,036



F-4193
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CONDENSED CONSOLIDATING BALANCE SHEETS
(Amounts in thousands)
 December 31, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
Assets         
Current assets         
Cash and cash equivalents$25,585
 $26,711
 $1
 $—
 $52,297
Accounts receivable - oil and natural gas146,075
 64,125
 —
 —
 210,200
Accounts receivable - joint interest and other16,212
 6,285
 —
 —
 22,497
Accounts receivable - intercompany671,633
 319,464
 —
 (991,097) —
Prepaid expenses and other current assets7,843
 2,174
 —
 —
 10,017
Short-term derivative instruments21,352
 —
 —
 —
 21,352
Total current assets888,700
 418,759
 1
 (991,097) 316,363
Property and equipment:         
Oil and natural gas properties, full-cost accounting,7,044,550
 2,983,015
 —
 (729) 10,026,836
Other property and equipment91,916
 751
 —
 —
 92,667
Accumulated depletion, depreciation, amortization and impairment(4,640,059) (39) —
 —
 (4,640,098)
Property and equipment, net2,496,407
 2,983,727
 —
 (729) 5,479,405
Other assets:         
Equity investments and investments in subsidiaries2,856,988
 —
 44,259
 (2,665,126) 236,121
Inventories4,210
 1,134
 —
 —
 5,344
Other assets12,624
 1,178
 —
 1
 13,803
Total other assets2,873,822
 2,312
 44,259
 (2,665,125) 255,268
  Total assets$6,258,929
 $3,404,798
 $44,260
 $(3,656,951) $6,051,036
          
Liabilities and stockholders' equity         
Current liabilities:         
Accounts payable and accrued liabilities$419,107
 $99,273
 $—
 $—
 $518,380
Accounts payable - intercompany320,259
 670,708
 130
 (991,097) —
Short-term derivative instruments20,401
 —
 —
 —
 20,401
Current maturities of long-term debt651
 —
 —
 —
 651
Total current liabilities760,418
 769,981
 130
 (991,097) 539,432
Long-term derivative instruments13,992
 —
 —
 —
 13,992
Asset retirement obligation - long-term66,859
 13,093
 —
 —
 79,952
Uncertain tax position liability3,127
 —
 —
 —
 3,127
Long-term debt, net of current maturities2,086,765
 —
 —
 —
 2,086,765
Total liabilities2,931,161
 783,074
 130
 (991,097)
2,723,268
          
Stockholders' equity:         
Common stock1,630
 —
 —
 —
 1,630
Paid-in capital4,227,532
 1,915,598
 261,626
 (2,177,224) 4,227,532
Accumulated other comprehensive loss(56,026) —
 (53,783) 53,783
 (56,026)
(Accumulated deficit) retained earnings(845,368) 706,126
 (163,713) (542,413) (845,368)
Total stockholders' equity3,327,768
 2,621,724
 44,130
 (2,665,854) 3,327,768
  Total liabilities and stockholders' equity$6,258,929
 $3,404,798
 $44,260
 $(3,656,951) $6,051,036

 December 31, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
Assets         
Current assets         
Cash and cash equivalents$67,908
 $31,649
 $—
 $—
 $99,557
Accounts receivable - oil and natural gas112,686
 34,087
 —
 —
 146,773
Accounts receivable - joint interest and other15,435
 20,005
 —
 —
 35,440
Accounts receivable - intercompany554,439
 63,374
 —
 (617,813) —
Prepaid expenses and other current assets4,719
 193
 —
 —
 4,912
Short-term derivative instruments78,847
 —
 —
 —
 78,847
Total current assets834,034
 149,308
 —
 (617,813) 365,529
Property and equipment:         
Oil and natural gas properties, full-cost accounting,6,562,147
 2,607,738
 —
 (729) 9,169,156
Other property and equipment86,711
 43
 —
 —
 86,754
Accumulated depletion, depreciation, amortization and impairment(4,153,696) (37) —
 —
 (4,153,733)
Property and equipment, net2,495,162
 2,607,744
 —
 (729) 5,102,177
Other assets:         
Equity investments and investments in subsidiaries2,361,575
 77,744
 57,641
 (2,194,848) 302,112
Long-term derivative instruments8,685
 —
 —
 —
 8,685
Deferred tax asset1,208
 —
 —
 —
 1,208
Inventories5,816
 2,411
 —
 —
 8,227
Other assets12,483
 7,331
 —
 —
 19,814
Total other assets2,389,767
 87,486
 57,641
 (2,194,848) 340,046
  Total assets$5,718,963
 $2,844,538
 $57,641
 $(2,813,390) $5,807,752
          
Liabilities and stockholders' equity         
Current liabilities:         
Accounts payable and accrued liabilities$416,249
 $137,361
 $—
 $(1) $553,609
Accounts payable - intercompany63,373
 554,313
 127
 (617,813) —
Asset retirement obligation - current120
 —
 —
 —
 120
Short-term derivative instruments32,534
 —
 —
 —
 32,534
Current maturities of long-term debt622
 —
 —
 —
 622
Total current liabilities512,898
 691,674
 127
 (617,814) 586,885
Long-term derivative instruments2,989
 —
 —
 —
 2,989
Asset retirement obligation - long-term63,141
 11,839
 —
 —
 74,980
Other non-current liabilities—
 2,963
 —
 —
 2,963
Long-term debt, net of current maturities2,038,321
 —
 —
 —
 2,038,321
Total liabilities2,617,349
 706,476
 127
 (617,814)
2,706,138
          
Stockholders' equity:         
Common stock1,831
 —
 —
 —
 1,831
Paid-in capital4,416,250
 1,915,598
 259,307
 (2,174,905) 4,416,250
Accumulated other comprehensive loss(40,539) —
 (38,593) 38,593
 (40,539)
(Accumulated deficit) retained earnings(1,275,928) 222,464
 (163,200) (59,264) (1,275,928)
Total stockholders' equity3,101,614
 2,138,062
 57,514
 (2,195,576) 3,101,614
  Total liabilities and stockholders' equity$5,718,963
 $2,844,538
 $57,641
 $(2,813,390) $5,807,752




F-4294
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Index to Financial Statements


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)
 Year Ended December 31, 2019
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Total revenues$524,089
 $821,919
 $—
 $—
 $1,346,008
          
Costs and expenses:         
Lease operating expenses26,923
 56,075
 —
 —
 82,998
Production taxes6,117
 22,454
 —
 —
 28,571
Midstream gathering and processing expenses71,420
 220,305
 —
 —
 291,725
Depreciation, depletion and amortization203,921
 345,504
 683
 —
 550,108
Impairment of oil and gas properties—
 2,039,770
 —
 —
 2,039,770
General and administrative expenses71,219
 (23,748) 508
 —
 47,979
Restructuring costs4,611
 —
 —
 —
 4,611
Accretion expense1,390
 2,549
 —
 —
 3,939
 385,601
 2,662,909
 1,191
 —
 3,049,701
          
INCOME (LOSS) FROM OPERATIONS138,488
 (1,840,990) (1,191) —
 (1,703,693)
          
OTHER (INCOME) EXPENSE:         
Interest expense144,645
 (2,859) —
 —
 141,786
Interest income(501) (300) —
 —
 (801)
Gain on debt extinguishment(48,630) —
 —
 —
 (48,630)
Loss (income) from equity method investments and investments in subsidiaries2,053,533
 


 32,710
 (1,876,095) 210,148
Other (income) expense, net(638) 3,364
 —
 999
 3,725
 2,148,409
 205
 32,710
 (1,875,096) 306,228
          
(LOSS) INCOME BEFORE INCOME TAXES(2,009,921) (1,841,195) (33,901) 1,875,096
 (2,009,921)
INCOME TAX BENEFIT(7,563) —
 —
 —
 (7,563)
          
NET (LOSS) INCOME$(2,002,358) $(1,841,195) $(33,901) $1,875,096
 $(2,002,358)

 Year Ended December 31, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Total revenues$839,241
 $515,803
 $—
 $—
 $1,355,044
          
Costs and expenses:         
Lease operating expenses66,947
 24,693
 —
 —
 91,640
Production taxes17,140
 16,340
 —
 —
 33,480
Midstream gathering and processing expenses199,607
 90,581
 —
 —
 290,188
Depreciation, depletion and amortization486,661
 3
 —
 —
 486,664
General and administrative expenses59,303
 (2,673) 3
 —
 56,633
Accretion expense3,228
 891
 —
 —
 4,119
 832,886
 129,835
 3
 —
 962,724
          
INCOME (LOSS) FROM OPERATIONS6,355
 385,968
 (3) —
 392,320
          
OTHER (INCOME) EXPENSE:         
Interest expense137,894
 (2,621) —
 —
 135,273
Interest income(287) (27) —
 —
 (314)
Litigation settlement1,075
 —
 —
 —
 1,075
Insurance proceeds(231) —
 —
 —
 (231)
Gain on sale of equity method investments(28,349) (96,419) —
 —
 (124,768)
(Income) loss from equity method investments and investments in subsidiaries(532,869) (694) 510
 483,149
 (49,904)
Other (income) expense, net(1,369) (33) —
 2,100
 698
 (424,136) (99,794) 510
 485,249
 (38,171)
          
INCOME (LOSS) BEFORE INCOME TAXES430,491
 485,762
 (513) (485,249) 430,491
INCOME TAX BENEFIT(69) —
 —
 —
 (69)
          
NET INCOME (LOSS)$430,560
 $485,762
 $(513) $(485,249) $430,560




F-4395
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Index to Financial Statements


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)
 Year Ended December 31, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Total revenues$839,241
 $515,803
 $—
 $—
 $1,355,044
          
Costs and expenses:         
Lease operating expenses66,947
 24,693
 —
 —
 91,640
Production taxes17,140
 16,340
 —
 —
 33,480
Midstream gathering and processing expenses199,607
 90,581
 —
 —
 290,188
Depreciation, depletion and amortization486,661
 3
 —
 —
 486,664
General and administrative expenses52,664
 (2,673) 3
 —
 49,994
Accretion expense3,228
 891
 —
 —
 4,119
 826,247
 129,835
 3
 —
 956,085
          
INCOME (LOSS) FROM OPERATIONS12,994
 385,968
 (3) —
 398,959
          
OTHER (INCOME) EXPENSE:         
Interest expense144,533
 (2,621) —
 —
 141,912
Interest income(287) (27) —
 —
 (314)
Gain on sale of equity method investments(28,349) (96,419) —
 —
 (124,768)
(Income) loss from equity method investments and investments in subsidiaries(532,869) (694) 510
 483,149
 (49,904)
Other (income) expense, net(525) (33) —
 2,100
 1,542
 (417,497) (99,794) 510
 485,249
 (31,532)
          
INCOME (LOSS) BEFORE INCOME TAXES430,491
 485,762
 (513) (485,249) 430,491
INCOME TAX BENEFIT(69) —
 —
 —
 (69)
          
NET INCOME (LOSS)$430,560
 $485,762
 $(513) $(485,249) $430,560

 Year Ended December 31, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Total revenues$1,010,989
 $309,314
 $—
 $—
 $1,320,303
          
Costs and expenses:         
Lease operating expenses65,793
 14,453
 —
 —
 80,246
Production taxes15,100
 6,026
 —
 —
 21,126
Midstream gathering and processing expenses187,678
 61,317
 —
 —
 248,995
Depreciation, depletion and amortization364,625
 4
 —
 —
 364,629
General and administrative expenses55,589
 (2,654) 3
 —
 52,938
Accretion expense1,246
 365
 —
 —
 1,611
Acquisition expense—
 2,392
 —
 —
 2,392
 690,031
 81,903
 3
 —
 771,937
          
INCOME (LOSS) FROM OPERATIONS320,958
 227,411
 (3) —
 548,366
          
OTHER (INCOME) EXPENSE:         
Interest expense112,732
 (4,534) —
 —
 108,198
Interest income(988) (21) —
 —
 (1,009)
Gain on sale of equity method investments(12,523) —
 —
 —
 (12,523)
(Income) loss from equity method investments and investments in subsidiaries(213,607) 1,955
 2,189
 227,243
 17,780
Other (income) expense, net(1,617) (324) —
 900
 (1,041)
 (116,003) (2,924) 2,189
 228,143
 111,405
          
INCOME (LOSS) BEFORE INCOME TAXES436,961
 230,335
 (2,192) (228,143) 436,961
INCOME TAX EXPENSE1,809
 —
 —
 —
 1,809
          
NET INCOME (LOSS)$435,152
 $230,335
 $(2,192) $(228,143) $435,152




F-4496
Table of Contents
Index to Financial Statements


CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(Amounts in thousands)
 Year Ended December 31, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Total revenues$1,010,989
 $309,314
 $—
 $—
 $1,320,303
          
Costs and expenses:         
Lease operating expenses65,793
 14,453
 —
 —
 80,246
Production taxes15,100
 6,026
 —
 —
 21,126
Midstream gathering and processing expenses187,678
 61,317
 —
 —
 248,995
Depreciation, depletion and amortization364,625
 4
 —
 —
 364,629
Impairment of oil and natural gas properties—
 —
 —
 —
 —
General and administrative expenses48,174
 (2,654) 3
 —
 45,523
Accretion expense1,246
 365
 —
 —
 1,611
Acquisition expense—
 2,392
 —
 —
 2,392
 682,616
 81,903
 3
 —
 764,522
          
INCOME (LOSS) FROM OPERATIONS328,373
 227,411
 (3) —
 555,781
          
OTHER (INCOME) EXPENSE:         
Interest expense120,147
 (4,534) —
 —
 115,613
Interest income(988) (21) —
 —
 (1,009)
Gain on sale of equity method investments(12,523) —
 —
 —
 (12,523)
(Income) loss from equity method investments and investments in subsidiaries(213,607) 1,955
 2,189
 227,243
 17,780
Other (income) expense, net(1,617) (324) —
 900
 (1,041)
 (108,588) (2,924) 2,189
 228,143
 118,820
          
INCOME (LOSS) BEFORE INCOME TAXES436,961
 230,335
 (2,192) (228,143) 436,961
INCOME TAX EXPENSE1,809
 —
 —
 —
 1,809
          
NET INCOME (LOSS)$435,152

$230,335

$(2,192)
$(228,143)
$435,152

 Year Ended December 31, 2016
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Total revenues$381,931
 $3,979
 $—
 $—
 $385,910
          
Costs and expenses:         
Lease operating expenses68,034
 843
 —
 —
 68,877
Production taxes13,121
 155
 —
 —
 13,276
Midstream gathering and processing expenses165,400
 572
 —
 —
 165,972
Depreciation, depletion and amortization245,970
 4
 —
 —
 245,974
Impairment of oil and natural gas properties715,495
 —
 —
 —
 715,495
General and administrative expenses43,896
 (490) 3
 —
 43,409
Accretion expense1,057
 —
 —
 —
 1,057
 1,252,973
 1,084
 3
 —
 1,254,060
          
(LOSS) INCOME FROM OPERATIONS(871,042) 2,895
 (3) —
 (868,150)
          
OTHER (INCOME) EXPENSE:         
Interest expense63,529
 1
 —
 —
 63,530
Interest income(1,230) —
 —
 —
 (1,230)
Insurance proceeds(5,718) —
 —
 —
 (5,718)
Loss on debt extinguishment23,776
 —
 —
 —
 23,776
Gain on sale of equity method investments(3,391) —
 —
 —
 (3,391)
Loss (income) from equity method investments and investments in subsidiaries34,469
 (89) 25,150
 (22,154) 37,376
Other expense (income), net145
 (16) —
 —
 129
 111,580
 (104) 25,150
 (22,154) 114,472
          
(LOSS) INCOME BEFORE INCOME TAXES(982,622) 2,999
 (25,153) 22,154
 (982,622)
INCOME TAX BENEFIT(2,913) —
 —
 —
 (2,913)
          
NET (LOSS) INCOME$(979,709)
$2,999

$(25,153)
$22,154

$(979,709)




F-4597
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Index to Financial Statements


CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Amounts in thousands)
 Year Ended December 31, 2019
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net (loss) income$(2,002,358) $(1,841,195) $(33,901) $1,875,096
 $(2,002,358)
Foreign currency translation adjustment9,193
 173
 9,020
 (9,193) 9,193
Other comprehensive loss (income)9,193
 173
 9,020
 (9,193) 9,193
Comprehensive income (loss)$(1,993,165) $(1,841,022) $(24,881) $1,865,903
 $(1,993,165)

 Year Ended December 31, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net income (loss)$430,560
 $485,762
 $(513) $(485,249) $430,560
Foreign currency translation adjustment(15,487) (297) (15,190) 15,487
 (15,487)
Other comprehensive loss (income)(15,487) (297) (15,190) 15,487
 (15,487)
Comprehensive income (loss)$415,073
 $485,465
 $(15,703) $(469,762) $415,073




 Year Ended December 31, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
  
Net income (loss)$430,560
 $485,762
 $(513) $(485,249) $430,560
Foreign currency translation adjustment(15,487) (297) (15,190) 15,487
 (15,487)
Other comprehensive (loss) income(15,487) (297) (15,190) 15,487
 (15,487)
Comprehensive income (loss)$415,073
 $485,465
 $(15,703) $(469,762) $415,073

 Year Ended December 31, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
  
Net income (loss)$435,152
 $230,335
 $(2,192) $(228,143) $435,152
Foreign currency translation adjustment12,519
 182
 12,337
 (12,519) 12,519
Other comprehensive income (loss)12,519
 182
 12,337
 (12,519) 12,519
Comprehensive income (loss)$447,671
 $230,517
 $10,145
 $(240,662) $447,671




 Year Ended December 31, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
  
Net income (loss)$435,152
 $230,335
 $(2,192) $(228,143) $435,152
Foreign currency translation adjustment12,519
 182
 12,337
 (12,519) $12,519
Other comprehensive income (loss)12,519
 182
 12,337
 (12,519) 12,519
Comprehensive income (loss)$447,671
 $230,517
 $10,145
 $(240,662) $447,671

 Year Ended December 31, 2016
 Parent Guarantors Non-Guarantor Eliminations Consolidated
  
Net (loss) income$(979,709) $2,999
 $(25,153) $22,154
 $(979,709)
Foreign currency translation adjustment2,119
 778
 1,341
 (2,119) $2,119
Other comprehensive income (loss)2,119
 778
 1,341
 (2,119) 2,119
Comprehensive (loss) income$(977,590) $3,777
 $(23,812) $20,035
 $(977,590)




F-4698
Table of Contents
Index to Financial Statements


CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Amounts in thousands)
 Year Ended December 31, 2019
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net cash provided by operating activities$64,037
 $656,443
 $3,510
 $3
 $723,993
          
Net cash provided by (used in) investing activities8,605
 (680,057) (3,751) 432
 (674,771)
          
Net cash (used in) provided by financing activities(95,459) —
 435
 (435) (95,459)
          
Net (decrease) increase in cash and cash equivalents(22,817) (23,614) 194
 —
 (46,237)
          
Cash and cash equivalents at beginning of period25,585
 26,711
 1
 —
 52,297
          
Cash and cash equivalents at end of period$2,768
 $3,097
 $195
 $—
 $6,060

 Year Ended December 31, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
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) 1
 —
 (47,260)
          
Cash and cash equivalents at beginning of period67,908
 31,649
 —
 —
 99,557
          
Cash and cash equivalents at end of period$25,585
 $26,711
 $1
 $—
 $52,297




 Year Ended December 31, 2018
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net cash provided by operating activities$560,203
 $226,067
 $—
 $1
 $786,271
          
Net cash (used in) provided by investing activities(445,869) (231,005) (2,318) 2,318
 (676,874)
          
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) 1
 —
 (47,260)
          
Cash and cash equivalents at beginning of period67,908
 31,649
 —
 —
 99,557
          
Cash and cash equivalents at end of period$25,585
 $26,711
 $1
 $—
 $52,297

 Year Ended December 31, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net cash provided by operating activities$392,680
 $287,209
 $—
 $—
 $679,889
          
Net cash (used in) provided by investing activities(2,216,615) (1,674,690) (2,280) 1,419,417
 (2,474,168)
          
Net cash provided by (used in) financing activities432,961
 1,417,137
 2,280
 (1,419,417) 432,961
          
Net (decrease) increase in cash and cash equivalents(1,390,974) 29,656
 —
 —
 (1,361,318)
          
Cash and cash equivalents at beginning of period1,458,882
 1,993
 —
 —
 1,460,875
          
Cash and cash equivalents at end of period$67,908
 $31,649
 $—
 $—
 $99,557




 Year Ended December 31, 2017
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
Net cash provided by operating activities$392,680
 $287,209
 $—
 $—
 $679,889
          
Net cash (used in) provided by investing activities(2,216,615) (1,674,690) (2,280) 1,419,417
 (2,474,168)
          
Net cash provided by (used in)financing activities432,961
 1,417,137
 2,280
 (1,419,417) 432,961
          
Net (decrease) increase in cash and cash equivalents(1,390,974) 29,656
 —
 —
 (1,361,318)
          
Cash and cash equivalents at beginning of period1,458,882
 1,993
 —
 —
 1,460,875
          
Cash and cash equivalents at end of period$67,908
 $31,649
 $—
 $—
 $99,557

 Year Ended December 31, 2016
 Parent Guarantors Non-Guarantor Eliminations Consolidated
          
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 activities1,730,640
 33,500
 15,473
 (48,973) 1,730,640
          
Net increase (decrease) in cash and cash equivalents1,346,388
 1,514
 (1) —
 1,347,901
          
Cash and cash equivalents at beginning of period112,494
 479
 1
 —
 112,974
          
Cash and cash equivalents at end of period$1,458,882
 $1,993
 $—
 $—
 $1,460,875


F-4799
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
 2019 2018
 (In thousands)
Proved properties$8,909,069
 $7,153,799
Unproved properties1,686,666
 2,873,037
 10,595,735
 10,026,836
Accumulated depreciation, depletion, amortization and impairment(7,191,957) (4,613,293)
Net capitalized costs$3,403,778
 $5,413,543
    
Equity investment in Grizzly Oil Sands ULC   
Proved properties$64,476
 $67,475
Unproved properties85,395
 79,605
 149,871
 147,080
Accumulated depreciation, depletion, amortization and impairment(1,634) (1,553)
Net capitalized costs$148,237
 $145,527
 2018 2017
 (In thousands)
Proven properties$7,153,799
 $6,256,182
Unproven properties2,873,037
 2,912,974
 10,026,836
 9,169,156
Accumulated depreciation, depletion, amortization and impairment reserve(4,613,293) (4,136,777)
Net capitalized costs$5,413,543
 $5,032,379
    
Equity investment in Grizzly Oil Sands ULC   
Proven properties$67,475
 $73,818
Unproven properties79,605
 86,540
 147,080
 160,358
Accumulated depreciation, depletion, amortization and impairment reserve(1,553) (1,693)
Net capitalized costs$145,527
 $158,665

Costs Incurred in Oil and Gas Property Acquisition and Development Activities
 2019 2018 2017
 (In thousands)
Acquisition$37,598
 $119,444
 $1,946,416
Development594,673
 714,269
 1,138,951
Exploratory9,762
 22,081
 9,058
Total$642,033
 $855,794
 $3,094,425
      
Equity investment in Grizzly Oil Sands ULC     
Acquisition$—
 $238
 $503
Development—
 —
 —
Exploratory849
 —
 —
Total$849
 $238
 $503

 2018 2017 2016
 (In thousands)
Acquisition$124,558
 $1,951,281
 $152,887
Development603,676
 994,237
 423,998
Exploratory21,840
 —
 —
Recompletions7,915
 14,289
 16,386
Capitalized asset retirement obligation1,452
 42,270
 10,971
Total$759,441
 $3,002,077
 $604,242
      
Equity investment in Grizzly Oil Sands ULC     
Acquisition$238
 $503
 $357
Development—
 —
 —
Exploratory—
 —
 —
Capitalized asset retirement obligation(285) (524) 784
Total$(47) $(21) $1,141


Capitalized interest is included as part of the cost of oil and natural gas properties. The Company capitalized $3.4 million, $4.5 million and $9.5 million during 2019, 2018, and 2017, respectively, based on the Company's weighted average cost of borrowings used to finance expenditures.
In addition to capitalized interest, the Company capitalized internal costs totaling $30.1 million, $37.7 million and $35.7 million during 2019, 2018, and 2017, respectively, which were directly related to the acquisition, exploration and development of the Company's oil and natural gas properties.

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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 natural 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.
 2019 2018 2017
 (In thousands)
Revenues$1,137,648
 $1,478,523
 $1,106,624
Production costs(403,294) (415,308) (350,367)
Depletion(539,379) (476,517) (358,792)
Impairment(2,039,770) —
 —
Income tax benefit7,563
 68
 240
Results of operations from producing activities$(1,837,232) $586,766
 $397,705
Depletion per Mcf of gas equivalent (Mcfe)$1.08
 $0.96
 $0.90
      
Results of Operations from equity method investment in Grizzly Oil Sands ULC     
Revenues$—
 $—
 $—
Production costs—
 —
 —
Depletion—
 —
 —
Income tax expense—
 —
 —
Results of operations from producing activities$—
 $—
 $—
 2018 2017 2016
 (In thousands)
Revenues$1,355,044
 $1,320,303
 $385,910
Production costs(415,308) (350,367) (248,125)
Depletion(476,517) (358,792) (243,098)
Impairment—
 —
 (715,495)
 463,219
 611,144
 (820,808)
Income tax expense (benefit)     
Current254
 3,362
 —
Deferred(322) (3,602) —
 (68) (240) —
Results of operations from producing activities$463,287
 $611,384
 $(820,808)
Depletion per Mcf of gas equivalent (Mcfe)$0.96
 $0.90
 $0.92
      
Results of Operations from equity method investment in Grizzly Oil Sands ULC     
Revenues$—
 $—
 $—
Production costs—
 —
 (13)
Depletion—
 —
 —
 —
 —
 (13)
Income tax expense—
 —
 —
Results of operations from producing activities$—
 $—
 $(13)

Oil and Natural Gas Reserves
The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2019, 2018 2017 and 20162017 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, 2019, 2018 2017 and 2016,2017, in accordance with guidelines of the SEC applicable to reserves estimates. Volumes for oil are stated in thousands of barrels (MBbls)(Mbbls) and volumes for natural gas are stated in millions of cubic feet (MMcf). The prices used for the 20182019 reserve report are $65.56$55.85 per barrel of oil, $3.10$2.58 per MMbtu and $32.02$21.25 per barrel for NGLs,NGL, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 20172018 and 20162017 for reserve report purposes are $65.56 per barrel, $3.10 per MMbtu and $32.02 per barrel for NGL and $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,NGL, 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-49101
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Index to Financial Statements


 2019 2018 2017
 Oil Natural Gas NGL Oil Natural Gas NGL Oil Natural Gas NGL
 (Mbbls) (MMcf) (Mbbls) (Mbbls) (MMcf) (Mbbls) (Mbbls) (MMcf) (Mbbls)
Proved Reserves                 
Beginning of the period21,050
 4,133,889
 80,520
 19,157
 4,825,310
 75,766
 5,546
 2,167,068
 20,127
Purchases in oil and natural gas reserves in place—
 —
 —
 —
 —
 —
 15,132
 1,098,644
 53,617
Extensions and discoveries3,612
 997,014
 12,992
 5,205
 622,271
 9,631
 951
 1,594,734
 4,619
Sales of oil and natural gas reserves in place(2,369) (62,557) —
 (134) (43,444) (112) —
 —
 —
Revisions of prior reserve estimates(1,749) (561,890) (26,909) (377) (826,506) 1,228
 107
 314,925
 2,737
Current production(2,186) (458,178) (5,074) (2,801) (443,742) (5,993) (2,579) (350,061) (5,334)
End of period18,357
 4,048,279
 61,528
 21,050
 4,133,889
 80,520
 19,157
 4,825,310
 75,766
Proved developed reserves7,887
 1,757,303
 29,898
 9,570
 1,813,184
 40,810
 10,245
 1,616,930
 36,247
Proved undeveloped reserves10,470
 2,290,976
 31,630
 11,480
 2,320,705
 39,710
 8,912
 3,208,380
 39,519
                  
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—
 —
 —
 —
 —
 —
 —
 —
 —

In 2019, the Company experienced extensions of 1.1 Tcfe 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, 793.5 Bcfe was attributable to the addition of 72 PUD locations in the Utica field, 302.9 Bcfe was attributable to the addition of 37 PUD locations in the SCOOP field. The Company experienced total downward revisions of approximately 733.8 Bcfe in estimated proved reserves, of which 347.2 Bcfe was a result of the exclusion of 9 PUD locations in the Utica field and 22 PUD locations in the SCOOP field, which was a result of changes in the Company's schedule that moved development of these PUD locations beyond five years of initial booking. The development plan change reflects the Company's commitment capital discipline and funding future activities within cash flow. An additional 296.4 Bcfe in downward revisions was the result of commodity price changes. Commodity prices experienced volatility throughout 2019 and the 12-month average price for natural gas decreased from $3.10 per MMBtu for 2018 to $2.58 per MMBtu for 2019, the 12-month average price for NGL decreased from $32.02 per barrel for 2018 to $21.25 per barrel for 2019, and the 12-month average price for crude oil decreased from $65.56 per barrel for 2018 to $55.85 per barrel for 2019. The Company also experienced downward revisions of 90.2 Bcfe from a combination of working interest changes, optimization of well design in the current commodity price environment and well performance.
Subsequent to completion of estimates of proved reserves at December 31, 2019, management lowered its 2020 budgeted capital expenditures due to the expectation of continued depressed commodities pricing. All PUD locations in the

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 2018 2017 2016
 Oil Natural Gas Natural Gas Liquids Oil Natural Gas Natural Gas Liquids Oil Natural Gas Natural Gas Liquids
 (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls) (MBbls) (MMcf) (MBbls)
Proved Reserves                 
Beginning of the period19,157
 4,825,310
 75,766
 5,546
 2,167,068
 20,127
 6,458
 1,560,145
 17,736
Purchases in oil and natural gas reserves in place—
 —
 —
 15,132
 1,098,644
 53,617
 —
 —
 —
Extensions and discoveries5,205
 622,271
 9,631
 951
 1,594,734
 4,619
 1,217
 1,082,220
 7,677
Sales of oil and natural gas reserves in place(134) (43,444) (112) —
 —
 —
 —
 —
 —
Revisions of prior reserve estimates(377) (826,506) 1,228
 107
 314,925
 2,737
 (3) (247,703) (1,439)
Current production(2,801) (443,742) (5,993) (2,579) (350,061) (5,334) (2,126) (227,594) (3,847)
End of period21,050
 4,133,889
 80,520
 19,157
 4,825,310
 75,766
 5,546
 2,167,068
 20,127
Proved developed reserves9,570
 1,813,184
 40,810
 10,245
 1,616,930
 36,247
 4,882
 744,797
 14,299
Proved undeveloped reserves11,480
 2,320,705
 39,710
 8,912
 3,208,380
 39,519
 664
 1,422,271
 5,828
                  
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—
 —
 —
 —
 —
 —
 —
 —
 —

December 31, 2019 proved reserve estimates remained in the development plan and are scheduled to be drilled within five years from the time of initial booking. However, development of several PUD locations was delayed. Management analyzed the impact of the timing of development and determined total proved reserves was materially unchanged and the total PV-10 value of reserves decreased by approximately 0.5%. Management determined these changes were immaterial and did not adjust its estimates of proved reserves at December 31, 2019 for the impact of these timing changes.
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

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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 2.2. 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 arewere 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 ten10 PUD locations in the Company's Utica field, five5 of which arewere operated by the Company and five5 of which arewere 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 two2 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, 2019, 2018 2017 and 20162017 using an unweighted average first-of-the-month price for the period January through December 31, 2019, 2018 2017 and 2016.2017.

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
 Year ended December 31,
 2019 2018 2017
 (In thousands)
Future cash flows$10,451,179
 $14,483,197
 $11,202,692
Future development and abandonment costs(2,058,374) (2,437,853) (3,005,217)
Future production costs(4,512,940) (5,067,554) (2,152,821)
Future production taxes(332,525) (455,840) (289,944)
Future income taxes—
 (943,293) (573,965)
Future net cash flows3,547,340
 5,578,657
 5,180,745
10% discount to reflect timing of cash flows(1,843,753) (2,595,932) (2,537,181)
Standardized measure of discounted future net cash flows$1,703,587
 $2,982,725
 $2,643,564
      
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$—
 $—
 $—

 Year ended December 31,
 2018 2017 2016
 (In thousands)
Future cash flows$14,483,197
 $11,202,692
 $3,354,168
Future development and abandonment costs(2,437,853) (3,005,217) (1,165,025)
Future production costs(5,067,554) (2,152,821) (924,167)
Future production taxes(455,840) (289,944) (69,447)
Future income taxes(943,293) (573,965) (14,545)
Future net cash flows5,578,657
 5,180,745
 1,180,984
10% discount to reflect timing of cash flows(2,595,932) (2,537,181) (492,944)
Standardized measure of discounted future net cash flows$2,982,725
 $2,643,564
 $688,040
      
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$—
 $—
 $—


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Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
 Year ended December 31,
 2019 2018 2017
 (In thousands)
Sales and transfers of oil and gas produced, net of production costs$(734,354) $(1,063,215) $(756,257)
Net changes in prices, production costs, and development costs(1,372,443) 590,519
 913,714
Acquisition of oil and gas reserves in place—
 —
 703,866
Extensions and discoveries388,151
 519,137
 618,039
Previously estimated development costs incurred during the period405,979
 402,156
 390,673
Revisions of previous quantity estimates, less related production costs(321,397) (356,933) 155,200
Sales of oil and gas reserves in place(48,547) (25,882) —
Accretion of discount298,273
 264,356
 68,804
Net changes in income taxes424,628
 (185,157) (231,545)
Change in production rates and other(319,428) 194,180
 93,030
Total change in standardized measure of discounted future net cash flows$(1,279,138) $339,161
 $1,955,524
      
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$—
 $—
 $—
Net changes in prices, production costs, and development costs—
 —
 —
Acquisition of oil and gas reserves in place—
 —
 —
Extensions and discoveries—
 —
 —
Previously estimated development costs incurred during the period—
 —
 —
Revisions of previous quantity estimates, less related production costs—
 —
 —
Accretion of discount—
 —
 —
Net changes in income taxes—
 —
 —
Change in production rates and other—
 —
 —
Total change in standardized measure of discounted future net cash flows$—
 $—
 $—

 Year ended December 31,
 2018 2017 2016
 (In thousands)
Sales and transfers of oil and gas produced, net of production costs$(1,063,215) $(756,257) $(312,291)
Net changes in prices, production costs, and development costs590,519
 913,714
 (146,518)
Acquisition of oil and gas reserves in place—
 703,866
 —
Extensions and discoveries519,137
 618,039
 186,909
Previously estimated development costs incurred during the period402,156
 390,673
 176,218
Revisions of previous quantity estimates, less related production costs(356,933) 155,200
 (38,448)
Sales of oil and gas reserves in place(25,882) —
 —
Accretion of discount264,356
 68,804
 76,433
Net changes in income taxes(185,157) (231,545) (6,495)
Change in production rates and other194,180
 93,030
 (12,099)
Total change in standardized measure of discounted future net cash flows$339,161
 $1,955,524
 $(76,291)
      
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$—
 $—
 $—
Net changes in prices, production costs, and development costs—
 —
 —
Acquisition of oil and gas reserves in place—
 —
 —
Extensions and discoveries—
 —
 —
Previously estimated development costs incurred during the period—
 —
 —
Revisions of previous quantity estimates, less related production costs—
 —
 —
Accretion of discount—
 —
 —
Net changes in income taxes—
 —
 —
Change in production rates and other—
 —
 —
Total change in standardized measure of discounted future net cash flows$—
 $—
 $—



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20.SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
The following table summarizes quarterly financial data for the years ended December 31, 20182019 and 2017:2018:
 2019
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 (In thousands)
Revenues $320,578
 $458,994
 $285,175
 $281,261
Income (loss) from operations 93,011
 218,456
 (570,955) (1,444,205)
Income tax (benefit) expense —
 (179,331) (144,047) 315,815
Net income (loss) 62,242
 234,956
 (484,802) (1,814,754)
Income (loss) per share:        
Basic $0.38
 $1.47
 $(3.04) $(11.36)
Diluted $0.38
 $1.47
 $(3.04) $(11.36)
        
 2018 2018
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 (In thousands) (In thousands)
Revenues $325,392
 $252,740
 $360,962
 $415,950
 $325,392
 $252,740
 $360,962
 $415,950
Income from operations 110,318
 13,791
 113,576
 154,635
 111,990
 15,373
 115,116
 156,480
Income tax benefit (69) —
 —
 —
 (69) —
 —
 —
Net income 90,090
 111,319
 95,150
 134,001
 90,090
 111,319
 95,150
 134,001
Income per share:                
Basic $0.50
 $0.64
 $0.55
 $0.78
 $0.50
 $0.64
 $0.55
 $0.78
Diluted $0.50
 $0.64
 $0.55
 $0.78
 $0.50
 $0.64
 $0.55
 $0.78
        
 2017
 
First
Quarter
 
Second
Quarter
 
Third
Quarter
 
Fourth
Quarter
 (In thousands)
Revenues $333,004
 $323,953
 $265,498
 $397,848
Income from operations 181,683
 143,175
 50,483
 173,025
Income tax expense (benefit) —
 —
 2,763
 (954)
Net income 154,455
 105,936
 18,235
 156,526
Income per share:        
Basic $0.91
 $0.58
 $0.10
 $0.85
Diluted $0.91
 $0.58
 $0.10
 $0.85

21.SUBSEQUENT EVENTS
DerivativesSale of Water Infrastructure Assets
In FebruaryDecember 2019, the Company entered into an agreement to divest its water infrastructure assets across its SCOOP position to a third-party water service provider. This transaction closed on January 2, 2020. The Company received $50.0 million in cash upon closing and has an opportunity to earn potential additional incentive payments over the next 15 years, subject to the Company’s ability to meet certain thresholds which will be driven by, among other things, the Company’s future development program and future water production levels. The agreement contains no minimum volume commitments. The assets related to this transaction are included in the amortization base of the full cost pool and the Company does not expect to recognize a gain or loss in the statement of operations.
Derivatives
In January and February 2020, the Company early terminated some of its fixed price swaps for natural gas basis swap position forscheduled to settle in August through November of 2020 which settles on the pricing index to basis differentialcovering an average of Inside FERC to the NYMEX Henry Hub natural gas price, for approximately 10,000294,000 MMBtu of natural gas per day over this four month period. The value of these early terminations was used to enhance the fixed price for new natural gas swaps for April and May of 2020 covering an average of approximately 472,000 MMBtu of natural gas per day over this two month period at a differentialweighted average price of $0.54$2.85 per MMBtu.
Stock Repurchase ProgramDebt Repurchases
In January 2020, the Company used borrowings under its revolving credit facility to repurchase in the open market approximately $10.2 million aggregate principal amount of its 2024 Notes, 2025 Notes, and 2026 Notes for $6.9 million.



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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
We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of December 31, 2019 because of the boardmaterial weakness in our internal control over financial reporting described in Management’s Report on Internal Control Over Financial Reporting disclosed below.
Our Chief Executive Officer and Chief Financial Officer also determined that the material weakness existed at September 30, 2019 and also concluded that we did not maintain effective disclosure controls and procedures as of that date. Our Chief Executive Officer and Chief Financial Officer have concluded that the unaudited condensed consolidated financial statements included in the Form 10-Q filing for the reporting period ended September 30, 2019 were materially misstated as a result of the material weakness. The Company filed an amended Form 10-QA for the period ended September 30, 2019 with the restated amounts.
Remediation Plan for the Material Weakness
Our management is actively engaged in the planning for, and implementation of, remediation efforts to address the material weakness identified. Specifically, our management is currently evaluating our policies and procedures related to its process of accounting for unevaluated oil and gas properties. We plan to design and implement additional controls to ensure that we are properly and timely identifying and transferring leasehold costs associated with acreage expirations, lease transfers and proved reserve additions from the unevaluated capitalized cost pool to the evaluated amortization base. We will do that through continued focus on (i) redesigning controls over the completeness and reconciliation of acreage movements; (ii) identifying new resources to execute and monitor the redesigned controls; (iii) process enhancements and (iv) additional technical training of our accounting staff. Our management believes that these actions will remediate the material weakness in internal control over financial reporting described above. The material weakness will not be considered remediated until the controls operate for a sufficient period of time and management has concluded, through testing, that the controls are operating effectively.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended December 31, 2019, which materially affected, or were reasonably likely to materially affect, our internal control over financial reporting, other than the material weakness described above.
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.

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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.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company's annual or interim financial statements will not be prevented or detected on a timely basis.
Management determined it did not effectively design and maintain controls over the completeness and accuracy of the accounting of transfers of unevaluated capitalized costs into the amortization base for the three and nine month periods ended September 30, 2019 and the twelve month period ended December 31, 2019. Specifically, we did not have an adequate process for monitoring that our accounting policies for transferring unevaluated oil and gas properties were consistently being performed timely and reconciled with the general ledger. This material weakness resulted in a material error in the amount of impairment expense booked in relation to our oil and gas properties for the nine months ended September 30, 2019 and resulted in the Company restating its consolidated financial statements as of and for the three and nine months ended September 30, 2019.
As a result of the material weakness in internal control over financial reporting described above, management has concluded that we did not maintain effective internal control over financial reporting as of December 31, 2019.
Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2019 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2019, as stated in their accompanying report.
/s/ David M. Wood/s/ Quentin Hicks
Name:David M. WoodName:Quentin Hicks
Title:Chief Executive Officer and PresidentTitle:Chief Financial Officer


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Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
Gulfport Energy Corporation
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Gulfport Energy Corporation (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019, 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, because of the effect of the material weakness described in the following paragraphs on the achievement of the objectives of the control criteria, the Company has not maintained effective internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
A material weakness is a deficiency, or combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weakness has been identified and included in management’s assessment:
The Company did not have effective internal control in place over the completeness and accuracy of the information used in determining the accounting for transfers of unevaluated capitalized costs into the amortization base.
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, 2019. The material weakness identified above was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2019 consolidated financial statements, and this report does not affect our report dated February 27, 2020 which 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 approved a stock repurchase program to acquire up to $400.0 millioncompany; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's outstanding common stock withincompany’s assets that could have a material effect on the next 24 months. Purchases under the repurchase programfinancial statements.
Because of its inherent limitations, internal control over financial reporting may be made from timenot prevent or detect misstatements. Also, projections of any evaluation of effectiveness to time in open market or privately negotiated transactions, and will befuture periods are subject to marketthe risk that controls may become inadequate because of changes in conditions, applicable legal requirements, contractual obligationsor that the degree of compliance with the policies or procedures may deteriorate.


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/s/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
February 27, 2020



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ITEM 9B.OTHER INFORMATION
Not applicable.
PART III
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The names of executive officers and certain 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 directorssenior officers of the Company at any time. The Company has not made any such purchases of its common stock under this programand their ages, titles and biographies as of February 28, 2019.the date hereof are incorporated by reference from Item 1 of Part I of this report. The other information called for by this Item 10 is incorporated herein by reference to the definitive proxy statement to be filed by Gulfport pursuant to Regulation 14A of the General Rules and Regulations under the Securities Exchange Act of 1934 not later than April 30, 2020 (the 2020 Proxy Statement).


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ITEM 11.EXECUTIVE COMPENSATION

The information called for by this Item 11 is incorporated herein by reference to the 2020 Proxy Statement.

ITEM 12.SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information called for by this Item 12 is incorporated herein by reference to the 2020 Proxy Statement.

ITEM 13.CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information called for by this Item 13 is incorporated herein by reference to the 2020 Proxy Statement.

ITEM 14.PRINCIPAL ACCOUNTING FEES AND SERVICES

The information called for by this Item 14 is incorporated herein by reference to the 2020 Proxy Statement.


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PART IV
ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following financial statements, financial statement schedules and exhibits are filed as part of this report:
1.
Financial Statements. Gulfport's consolidated financial statements are included in Item 8 of Part II of this report. Reference is made to the accompanying Index to Financial Statements.
2.
Financial Statement Schedules. No financial statement schedules are applicable or required.
3.
Exhibits. The exhibits listed below in the Index of Exhibits are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.

INDEX OF EXHIBITS
    Incorporated by Reference  
Exhibit Number Description Form SEC File Number Exhibit Filing Date Filed or Furnished Herewith
3.1
 
Restated Certificate of Incorporation.
 8-K 000-19514 3.1 4/26/2006  
            
3.2
 
Certificate of Amendment No. 1 to Restated Certificate of Incorporation.
 10-Q 000-19514 3.2 11/6/2009  
            
3.3
 
Certificate of Amendment No. 2 to Restated Certificate of Incorporation.
 8-K 000-19514 3.1 7/23/2013  
            
3.4
 
Second Amended and Restated Bylaws of Gulfport Energy Corporation.
 8-K 000-19514 3.1 2/27/2020  
             
4.1
 
Form of Common Stock certificate.
 SB-2 333-115396 4.1 7/22/2004  
            
4.2
 
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).
 8-K 000-19514 4.1 4/21/2015  
             
4.3
 
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).
 8-K 000-19514 4.1 10/19/2016  
             
4.4
 
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).
 8-K 000-19514 4.1 12/21/2016  
             
4.5
 
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).
 8-K 000-19514 4.1 10/11/2017  

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4.6
 
Registration Rights Agreement, dated as of February 17, 2017, by and between Gulfport Energy Corporation and Vitruvian II Woodford, LLC.
 8-K 000-19514 4.1 2/24/2017  
             
4.7
 
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.
 8-K 000-19514 4.1 6/12/2015  
             
4.8
 
Description of Securities:Registered under Section 12(b) of the Exchange Act
         X
             
10.1+
 
2019 Amended and Restated Stock Incentive Plan
 DEF 14A 000-19514 Appendix A 4/30/19  
             
10.2+
 
2019 Amended and Restated Stock Incentive Plan Form of Performance Share Award Agreement.
 8-K 000-19514 10.3 8/12/19  
             
10.3+
 
2014 Executive Annual Incentive Compensation Plan.
 8-K 000-19514 10.1 4/7/2014  
             
10.4+
 
Form of Stock Option Agreement.
 8-K 000-19514 10.2 4/26/2006  
             
10.5+
 
Form of Restricted Stock Award Agreement.
 10-K 000-19514 10.3 2/28/2014  
             
10.6+
 
2013 Restated Stock Incentive Plan.
 S-4 333-189992 10.1 7/17/2013  
             
10.7
 
Employment Agreement, entered into and effective as of August 1, 2019, by and between Gulfport Energy Corporation and David M. Wood.
 10-Q 000-19514 10.3 8/2/2019  
             
10.8
 
Employment Agreement, entered into and effective as of August 1, 2019, by and between Gulfport Energy Corporation and Donnie Moore.
 10-Q 000-19514 10.4 8/2/2019  
             
10.9
 
Employment Agreement, entered into and effective as of August 1, 2019, by and between Gulfport Energy Corporation and Patrick K. Craine.
 10-Q 000-19514 10.5 8/2/2019  
             
10.10
 
Employment Agreement, effective as of August 26, 2019, by and between Gulfport Energy Corporation and Quentin Hicks.
 8-K 000-19514 10.1 8/12/19  
             
10.11
 
Separation and Release Agreement, effective August 9, 2019, by and between Gulfport Energy Corporation and Keri Crowell.
 8-K 000-19514 10.2 8/12/19  
             
10.12
 
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.
 8-K 000-19514 10.1 1/3/2014  
             

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10.13
 
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.
 8-K 000-19514 10.1 4/28/2014  
             
10.14
 
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.
 8-K 000-19514 10.1 12/3/2014  
             
10.15
 
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. 
 8-K 000-19514 10.1 4/15/2015  
             
10.16
 
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.
 10-Q 000-19514 10.2 8/7/2015  
             
10.17
 
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.
 8-K 000-19514 10.1 9/24/2015  
             
10.18
 
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.
 10-Q 000-19514 10.2 5/5/2016  
             
10.19
 
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.
 8-K 000-19514 10.1 12/15/2016  
             
10.20
 
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.
 8-K 000-19514 10.1 4/4/2017  
             
10.21
 
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.
 10-Q 000-19514 10.2 5/9/2017  
             

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10.22
 
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.
 8-K 000-19514 10.1 10/5/2017  
             
10.23
 
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.
 8-K 000-19514 10.1 11/28/2017  
             
10.24
 
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.
 8-K 000-19514 10.1 5/25/2018  
             
10.25
 
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.
 8-K 000-19514 10.1 12/4/2018  
             
10.26#
 
Sand Supply Agreement, effective as of October 1, 2014, by and between Muskie Proppant LLC and Gulfport Energy Corporation.
 10-Q 000-19514 10.1 11/7/2014  
             
10.27#
 
Amendment to Sand Supply Agreement, dated as of November 3, 2015, by and between Muskie Proppant LLC and Gulfport Energy Corporation.
 10-Q 000-19514 10.2 11/5/2015  
             
10.28
 
Second Amendment to Sand Supply Agreement, dated as of August 6, 2018, between Gulfport Energy Corporation and Muskie Proppant LLC.
 10-Q 000-19514 10.2 11/1/2018  
             
10.29#
 
Amended and Restated Master Services Agreement, effective as of October 1, 2014, by and between Gulfport Energy Corporation and Stingray Pressure Pumping LLC.
 10-Q 000-19514 10.2 11/7/2014  
             
10.30#
 
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.
 10-K 000-19514 10.19 2/19/2016  
             
10.31#
 
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.
 10-Q 000-19514 10.2 8/2/2018  
             
10.32+
 
Form of Indemnification Agreement.
 S-4 333-199905 10.1 11/6/2014  
             
14
 
Code of Ethics.
 8-K 000-19514 14 2/14/2006  
             

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21
Subsidiaries of the Registrant.
X
23.1
Consent of Grant Thornton LLP.
X
23.2
Consent of Netherland, Sewell & Associates, Inc.
X
31.1
Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
X
31.2
Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
X
32.1
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.
X
32.2
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.
X
99.1
Report of Netherland, Sewell & Associates, Inc.
X
101.INSInline XBRL Instance Document.X
11.SCH*Inline XBRL Taxonomy Extension Schema Document.X
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document.X
101.DEFInline XBRL Taxonomy Extension Definition Linkbase Document.X
101.LABInline XBRL Taxonomy Extension Labels Linkbase Document.X
101.PREInline XBRL Taxonomy Extension Presentation Linkbase Document.X
*Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant hereby undertakes to furnish supplemental copies of any of the omitted schedules upon request by the SEC.
**The Company agrees to furnish a copy of any of its unfiled long-term debt instruments to the Securities and Exchange Commission upon request.
+Management contract, compensatory plan or arrangement.
#
Confidential treatment has been requested for portions of this exhibit. These portions have been omitted and submitted separately to the Securities and Exchange Commission.




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ITEM 16.FORM 10-K SUMMARY
None.
SIGNATURES
In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: February 27, 2020
GULFPORT ENERGY CORPORATION
By:/s/    Quentin Hicks
Quentin Hicks
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.

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Date:February 27, 2020By:/s/    DAVID M. WOOD
David M. Wood
Chief Executive Officer and President, Director
(Principal Executive Officer)
Date:February 27, 2020By:/s/    DAVID L. HOUSTON
David L. Houston
Chairman of the Board and Director
Date:February 27, 2020By:/s/    QUENTIN HICKS
Quentin Hicks
Chief Financial Officer
(Principal Accounting and Financial Officer)
Date:February 27, 2020By:/s/    DEBORAH G. ADAMS
Deborah G. Adams
Director
Date:February 27, 2020By:/s/    ALVIN BLEDSOE
Alvin Bledsoe
Director
Date:February 27, 2020By:/s/    VALERIE JOCHEN
Valerie Jochen
Director
Date:February 27, 2020By:/s/    C. DOUG JOHNSON
C. Doug Johnson
Director
Date:February 27, 2020By:/s/    BEN T. MORRIS
Ben T. Morris
Director
Date:February 27, 2020By:/s/    PAUL WESTERMAN
Paul Westerman
Director


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