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Table of Contents
Index to Financial Statements
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2021
OR
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
For the transition period from                    to                   
Commission File Number 001-19514
Gulfport Energy Corporation
(Exact Name of Registrant As Specified in Its Charter)
Delaware86-3684669
(State or Other Jurisdiction of Incorporation or Organization)(IRS Employer Identification Number)
3001 Quail Springs Parkway
Oklahoma City,Oklahoma73134
(Address of Principal Executive Offices)(Zip Code)
(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, $0.0001 par value per shareGPORThe New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes      No  
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes      No  
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes      No  
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit such files).
    Yes      No  
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated filer       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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).     Yes      No  


Table of Contents
Index to Financial Statements
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by the court.  Yes      No  
The aggregate market value of our common stock held by non-affiliates on June 30, 2021 was approximately $703.9 million. As of February 25, 2022, there were 21,477,000 shares of our $0.0001 par value common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Gulfport Energy Corporation’s Proxy Statement for the 2022 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.


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GULFPORT ENERGY CORPORATION
TABLE OF CONTENTS 
  Page
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
ITEM 9C.
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
ITEM 15.




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DEFINITIONS
Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Gulfport,” the “Company” and “Registrant” refer to Gulfport Energy Corporation and its consolidated subsidiaries. All monetary values, other than per unit and per share amounts, are stated in thousands of U.S. dollars unless otherwise specified. In addition, the following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:
2019 Plan. 2019 Amended and Restated Stock Incentive Plan.
2020 Plan. 2020 Incentive Plan, which provides incentive awards for select employees of the Company that were tied to the achievement of one or more performance goals relating to certain financial and operational metrics over a period of time.
2023 Notes. 6.625% Senior Notes due 2023.
2024 Notes. 6.000% Senior Notes due 2024.
2025 Notes. 6.375% Senior Notes due 2025.
2026 Notes. 6.375% Senior Notes due 2026.
ASC. Accounting Standards Codification.
ASU. Accounting Standards Update.
Bankruptcy Code. Chapter 11 of Title 11 of the United States Code.
Bankruptcy Court. The United States Bankruptcy Court for the Southern District of Texas.
Bankruptcy Rules. The Federal Rules of Bankruptcy Procedure.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of natural gas.
Bcfe. One billion cubic feet of natural gas equivalent.
Btu. British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.
Building Loan. Loan agreement for our corporate headquarters scheduled to mature in June 2025.
Chapter 11 Cases. Voluntary petitions filed on November 13, 2020 by Gulfport Energy Corporation, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Grizzly Holdings, Inc., Gulfport Appalachia, LLC, Gulfport Midcon, LLC, Gulfport Midstream Holdings, LLC, Jaguar Resources LLC, Mule Sky LLC, Puma Resources, Inc. and Westhawk Minerals LLC.
CODI. Cancellation of indebtedness income.
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, oil and NGL.
Combined Period. Combined Successor Period and Predecessor Period.
DD&A. Depreciation, depletion and amortization.
Debtors. Collectively, Gulfport Energy Corporation, Gator Marine, Inc., Gator Marine Ivanhoe, Inc., Grizzly Holdings, Inc., Gulfport Appalachia, LLC, Gulfport Midcon, LLC, Gulfport Midstream Holdings, LLC, Jaguar Resources LLC, Mule Sky LLC, Puma Resources, Inc. and Westhawk Minerals LLC.
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Developed Acreage. The number of acres allocated or assignable to productive wells or wells capable of production.
Development Well. A well drilled within the proved area of a natural gas or crude oil reservoir to the depth of a stratigraphic horizon known to be productive.
DIP Credit Facility. Senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million.
Dry Hole. A well that does not produce crude oil and/or natural gas in economically producible quantities.
Exploratory Well. A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area.
Emergence Date. May 17, 2021.
Exit Credit Agreement. The Second Amended and Restated Credit Agreement with the Bank of Nova Scotia as lead administrative agent and various lender parties providing for the Exit Facility and the First-Out Term Loan.
Exit Credit Facility. Collectively, the First-Out Term Loan and the Exit Facility, with an initial borrowing base and elected commitment amount of up to $580 million.
Exit Facility. Senior secured reserve-based revolving credit facility with The Bank of Nova Scotia as the lead arranger and administrative agent and various lender parties.
First-Out Term Loan. Senior secured term loan in an aggregate maximum principal amount of $180 million.
GAAP. Accounting principles generally accepted in the United States of America.
Grizzly. Grizzly Oil Sands ULC.
Grizzly Holdings. Grizzly Holdings Inc.
Gross Acres or Gross Wells. Refers to the total acres or wells in which a working interest is owned.
Guarantors. All existing consolidated subsidiaries that guarantee the Company's revolving credit facility or certain other debt.
Held By Production. Refers to an oil and gas lease continued into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith.
Horizontal Drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.
Indentures. Collectively, the 1145 Indenture and the 4(a)(2) Indenture governing the Successor Senior Notes.
IRC. The Internal Revenue Code of 1986, as amended.
LIBOR. London Interbank Offered Rate.
LOE. Lease operating expenses.
MBbl. One thousand barrels of crude oil, condensate or natural gas liquids.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One thousand cubic feet of natural gas equivalent.
MMBbl. One million barrels of crude oil, condensate or natural gas liquids.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of natural gas.
MMcfe. One million cubic feet of natural gas equivalent.
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Natural Gas Liquids (NGL). Hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption or other methods in gas processing or cycling plants. Natural gas liquids primarily include ethane, propane, butane, isobutene, pentane, hexane and natural gasoline.
Net Acres or Net Wells. Refers to the sum of the fractional working interests owned in gross acres or gross wells.
Net Revenue Interest (NRI). An interest in an oil and natural gas property entitling the owner to a share of oil, natural gas or NGL production.
New Common Stock. $0.0001 par value common stock issued by the Successor on the Emergence Date.
New Credit Facility. The Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and various lender parties, providing for a new money senior secured reserve-based revolving credit facility effective as of October 14, 2021.
New Preferred Stock. $0.0001 par value preferred stock issued by the Successor on the Emergence Date.
NYMEX. New York Mercantile Exchange.
OCC. Oklahoma Corporation Commission.
Petition Date. November 13, 2020.
Plan. The Amended Joint Chapter 11 Plan of Reorganization of Gulfport Energy Corporation and Its Debtor Subsidiaries.
Predecessor Period. Period from January 1, 2021 through May 17, 2021.
Predecessor Senior Notes. Collectively, the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes.
Pre-Petition Revolving Credit Facility. Senior secured revolving credit facility, as amended, with The Bank of Nova Scotia as the lead arranger and administrative agent and certain lenders from time-to-time party thereto with a maximum facility amount of $580 million.
Productive Well. A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
Proved Developed Reserves (PDPs). Reserves expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves. Quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
Proved Undeveloped Reserves (PUDs). Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
PV-10. Present net value of estimated future net revenues, discounted at 10%.
Repurchase Program. A stock repurchase program to acquire up to $100 million of Gulfport's outstanding New Common Stock. It is authorized to extend through December 31, 2022, and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
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Royalty Interest. Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.
RSA. Restructuring Support Agreement.
SCOOP. Refers to the South Central Oklahoma Oil Province, a term used to describe a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations. Our acreage is primarily in Garvin, Grady and Stephens Counties.
SEC. The United States Securities and Exchange Commission.
Section 382. Internal Revenue Code Section 382.
Standardized Measure. Standardized measure of discounted future net cash flows.
Successor Period. Period from May 18, 2021 through December 31, 2021.
Successor Senior Notes. 8.000% Senior Notes due 2026.
Tcfe. One trillion cubic feet of natural gas equivalent.
Undeveloped Acreage. Lease or mineral acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
USEPA. United States Environmental Protection Agency.
Utica. Refers to the Utica Play that includes the hydrocarbon bearing rock formations commonly referred to as the Utica formation located in the Appalachian Basin of the United States and Canada. Our acreage is located primarily in Belmont, Harrison, Jefferson and Monroe Counties in Eastern Ohio.
Working Interest (WI). The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
WTI. Refers to West Texas Intermediate.
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FORWARD-LOOKING STATEMENTS
This Form 10-K may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), Section 21E of the Securities Exchange Act of 1934, as amended (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 the expected impact of the novel coronavirus disease (COVID-19) pandemic on our business, our industry and the global economy, estimated future production and net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), the impact of our emergence from bankruptcy, share repurchases, 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.
All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our 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. 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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SUMMARY RISK FACTORS
Financial, Liquidity and Commodity Price Risks
Natural gas, oil and NGL prices fluctuate widely, and lower prices for extended time periods are likely to have a material adverse effect on 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.
Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase.
Our debt and other financial commitments may limit our financial and operating flexibility.
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.
Under our method of accounting for oil and natural gas properties, declines in commodity prices may result in impairment of asset value.
A change of control could limit our use of net operating losses to reduce future taxable income.
Industry, Business and Operational Risks
The oil and gas development, exploration and production industry is very competitive, and some of our competitors have greater financial and other resources than we do.
If we are not able to replace reserves, we may not be able to sustain production.
The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
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 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 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.
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.
Multi-well pad drilling may result in volatility in our operating results and delay the conversion of our PUD reserves.
We are not the operator of all our oil and natural gas properties and therefore are not positioned to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.
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.
Substantially all of our producing properties are located in Eastern Ohio and Oklahoma, making us vulnerable to risks associated with operating in only these regions.
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 unavailability, high cost or shortages of rigs, equipment, raw materials, supplies, oilfield services or personnel may restrict our operations.
Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash flow.
We are required to pay fees to some of our midstream service providers based on minimum volumes regardless of actual volume throughput.
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The outbreak of the novel coronavirus, or COVID-19, has affected and may materially adversely affect, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our operations, financial performance and condition, operating results and cash flows.
A deterioration in general economic, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.
Terrorist activities could materially and adversely affect our business and results of operations.
Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.
We may engage in acquisition and divestiture activities that involve substantial risks.
Legal and Regulatory Risks
We are subject to extensive governmental regulation and ongoing regulatory changes, which could adversely impact our business.
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.
Future U.S. and state tax legislation may adversely affect our business, results of operations, financial condition and cash flow.
Our business is subject to complex and evolving laws and regulations regarding privacy and data protection.
Risks Associated with our Emergence from Bankruptcy
We recently emerged from bankruptcy, which may adversely affect our business and relationships.
Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information because of the implementation of the Plan and the transactions contemplated thereby.
Upon emergence from bankruptcy, the composition of our board of directors changed significantly.
Risks Associated with an Investment in Us
The market price of our securities is subject to volatility.
Future sales or the availability for sale of substantial amounts of our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and could impair our ability to raise capital through future sales of equity securities.
Certain of our stockholders own a significant portion of our outstanding debt and equity securities, and their interests may not always coincide with the interests of other holders of the New Common Stock.
There may be future dilution of our common stock, which could adversely affect the market price of our common stock.
Our amended and restated certificate of incorporation provides, subject to certain exceptions, that the Court of Chancery of the State of Delaware will be the sole and exclusive forum for certain stockholder litigation matters, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or stockholders.



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PART I
ITEM 1.BUSINESS
Our Business
Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal properties are located in Eastern Ohio, where we target development in what is commonly referred to as the Utica formation, and Central Oklahoma where we target development in the SCOOP Woodford and Springer formations. Gulfport's predecessor was incorporated in the State of Delaware in July 1997. Our corporate headquarters are located in Oklahoma City, Oklahoma and shares of Gulfport's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol "GPOR". Our corporate strategy is focused on the economic development of our asset base in an effort to generate sustainable free cash flow.
As of December 31, 2021, we had 3.9 Tcfe of proved reserves with a Standardized Measure of $4.1 billion and a PV-10 of $4.3 billion. See "Definitions" above for our definition of PV-10 (a non-GAAP financial measure) and "Oil, Natural Gas and NGL Reserves" below for a reconciliation of our standardized measure of discounted future net cash flows (the most directly comparable GAAP measure) to PV-10.
Information About Us
Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. 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.
Emergence From Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
On November 13, 2020, we and certain of our subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases were administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ). The Bankruptcy Court confirmed the Plan and entered the confirmation order on April 28, 2021, and the Debtors emerged from the Chapter 11 Cases on the Emergence Date. On May 18, 2021, we began trading on the NYSE under the symbol "GPOR".
Although we are no longer a debtor-in-possession, we operated as debtors-in-possession through the pendency of the Chapter 11 Cases. See Note 2 and Note 3 of our consolidated financial statements for a complete discussion of the Chapter 11 Cases.
We believe we have emerged from the Chapter 11 Cases as a fundamentally stronger company, built to generate sustainable free cash flow, with a strengthened balance sheet. As a result of the Chapter 11 Cases, we reduced our total indebtedness by $1.4 billion by issuing equity in a reorganized entity to the holders of our unsecured notes and allowed general unsecured claimants. In addition, Gulfport reassessed its organizational needs post emergence and significantly reduced its general and administrative expense to ensure its cost structure is competitive with industry peers. We continue to focus on optimizing development of our resource plays, reducing our operating costs, per well drilling costs, general and administrative costs, and managing our liquidity. We believe our plan to generate free cash flow on an annual basis will allow us to further strengthen our balance sheet and return capital to shareholders.
Business Strategy
Gulfport aims to create sustainable value through the economic development of our significant resource plays in the Utica and SCOOP operating areas. Our strategy is to develop our assets in an environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders. To accomplish these goals, we allocate capital expenditures to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts.
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2022 Outlook
Our 2022 capital expenditure program is expected to be in a range of $340 million to $380 million. We plan to operate on average approximately one operated rig in each of our Utica and SCOOP development areas. In the Utica, we intend to spud 15 gross (13.4 net) operated horizontal wells, complete drilling on 24 gross (21.7 net) operated horizontal wells and commence sales on 17 gross (15.6 net) horizontal wells. In the SCOOP, we intend to spud five gross (3.6 net) operated horizontal wells, complete drilling on 8 gross (5.5 net) operated horizontal wells and commence sales on 13 gross (10.3 net) operated horizontal wells. 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 approximately 975 to 1,025 MMcfe per day of production in 2022.
Additionally, in 2022, we expect to focus on our strategy of returning capital to our shareholders. In the fourth quarter of 2021, our board of directors authorized the repurchase of up to $100 million of our outstanding common stock and we paid our first cash dividend payment on our New Preferred Stock.
Operating Areas
Utica - The Utica covers hydrocarbon bearing rock formations located in the Appalachian Basin of the United States and Canada. We have approximately 187,000 net reservoir acres located primarily in Belmont, Harrison, Jefferson and Monroe Counties in Eastern Ohio where the Utica ranges in thickness from 600 to over 750 feet. During the Combined Period, we produced approximately 772 MMcfe per day net to our interests in this area and it accounts for approximately 77% of our total production.
SCOOP - The SCOOP is a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations. We have approximately 74,000 net reservoir acres (comprised of approximately 41,000 in the Woodford formation and approximately 33,000 in the Springer formation) located primarily in Garvin, Grady and Stephens Counties. The Woodford Shale across our position 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 consists of hydrocarbon-bearing interbedded shales and siliceous limestones ranging in thickness from 150 to over 450 feet and is overlain by the Caney Shale. The Springer formation across our position is comprised of a series of lenticular sand and shale units. The primary targets are a series of porous, low clay and organic-rich packages within the Goddard Shale member ranging in thickness from 50 to over 250 feet. During the Combined Period, we produced approximately 231 MMcfe per day net to our interests in this area and it accounts for approximately 23% of our total production.
Oil, Natural Gas and NGL Reserves
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 reserve 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.
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The tables below set forth information as of December 31, 2021, with respect to our estimated proved reserves, the associated estimated future net revenue, the PV-10 and the 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, 2021
 Oil
(MMBbl)
Natural
Gas
(Bcf)
NGL (MMBbl)Total (Bcfe)
Utica
Proved developed1,482 1,550 
Proved undeveloped1,073 1,123 
Total proved2,555 13 2,673 
SCOOP
Proved developed445 22 613 
Proved undeveloped477 18 610 
Total proved10 921 40 1,223 
Total
Proved developed(1)
1,928 31 2,165 
Proved undeveloped1,550 22 1,733 
Total proved16 3,478 54 3,898 
Totals may not sum or recalculate due to rounding.
(1)    Includes approximately 2 Bcfe of net reserves located in non-core operating districts.
 
Successor
 Proved DevelopedProved UndevelopedTotal Proved
($ in millions)
Estimated future net revenue(1)
$4,649 $3,585 $8,234 
Present value of estimated future net revenue (PV-10)(1)
$2,655 $1,660 $4,316 
Standardized measure(1)
$4,138 
Totals may not sum due to rounding.
(1)    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, 2021, 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, 2021. The prices used in our PV-10 measure were $66.55 per barrel and $3.60 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, 2021. 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 of $178 million as of December 31, 2021.
    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.
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Proved Reserves
Estimates of proved reserves and related information are presented in accordance with the requirements of the SEC's rules for the Modernization of Oil and Gas Reporting. These rules permit the use of reliable technologies to estimate and categorize reserves and require the use of the unweighted average of the first-of-the-month commodity prices, adjusted for location and quality differentials, for the prior 12 months (unless contractual arrangements designate the price) to calculate economic producibility of reserves and the discounted cash flows reported as the Standardized Measure of Future Net Cash Flows Relating to Proved Reserves. Refer to Note 20 of our consolidated financial statements for more information pertaining to our proved reserves and the preparation of such estimates.
The following table summarizes the changes in our estimated proved reserves during 2021 (in Bcfe):
Proved Reserves, December 31, 2020 (Predecessor)2,588 
   Sales of oil and natural gas reserves in place— 
   Extensions and discoveries695 
   Revisions of prior reserve estimates982 
   Current production(366)
Proved Reserves, December 31, 2021 (Successor)3,898 
Total may not sum due to rounding.
Sales of oil and natural gas reserves in place. These are reductions to proved reserves resulting from the divestiture of minerals in place during a period. During 2021, we sold approximately 0.2 Bcfe of proved oil and natural gas reserves through various sales of our non-operated interests in our other non-core assets.
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 694.6 Bcfe of proved reserves were primarily attributable to the continued development of our Utica and SCOOP acreage. We added 29 PUD locations in our Utica acreage for 352.2 Bcfe and 34 PUD locations in our SCOOP acreage for 342.2 Bcfe. The five-year development plan focused on generating sustainable cash flow limited our ability to add significant well locations.
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 upward revisions of 982.2 Bcfe in estimated proved reserves, of which 889.2 Bcfe was the result of commodity price changes. Commodity prices experienced volatility throughout 2021 and the 12-month average price for natural gas increased from $1.99 per MMBtu for 2020 to $3.60 per MMBtu for 2021, the 12-month average price for NGL increased from $15.40 per barrel for 2020 to $31.90 per barrel for 2021, and the 12-month average price for crude oil increased from $39.54 per barrel for 2020 to $66.55 per barrel for 2021.
Upward revisions of 157.6 Bcfe were a result of a combination of well performance, operating and development cost improvements and working interest changes. A small downward revision of 64.6 Bcfe was also experienced as a result of the exclusion of 4 PUD locations in our Utica 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 and ongoing optimization of our development plan.
Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2021, 2020 and 2019 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 20 of our consolidated financial statements.
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Proved Undeveloped Reserves (PUDs)
As of December 31, 2021, our proved undeveloped reserves totaled 1,550 Bcf of natural gas, 8 MMBbl of oil and 22 MMBbl of NGL, for a total of 1,733 Bcfe. Approximately 65% and 35% of our PUD reserves at year-end 2021 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.
The following table summarizes the changes in our estimated proved undeveloped reserves during 2021 (in Bcfe):
Proved Undeveloped Reserves, December 31, 2020 (Predecessor)1,061 
   Extensions and discoveries694 
   Conversion to proved developed reserves(362)
   Revisions of prior reserve estimates341 
Proved Undeveloped Reserves, December 31, 2021 (Successor)1,733 
Total may not sum due to rounding.
Extensions and discoveries. Our extensions of approximately 694.4 Bcfe were primarily attributed to the addition of 29 PUD drilling locations in the Utica field and 34 PUD drilling locations in the SCOOP field as a result of our current five-year development plan that is focused on generating sustainable cash flow.
Conversion to proved developed reserves. Our 2021 development activities resulted in the conversion of approximately 362.4 Bcfe into proved developed producing reserves, attributable to 12 PUD locations in the Utica field and 11 PUD locations in the SCOOP field. These 23 PUDs represent a conversion rate of 28% for 2021.
Revision of prior reserve estimates. We experienced total upward revisions of 340.8 Bcfe in estimated proved undeveloped reserves, of which 340.8 Bcfe was the result of improved commodity prices. The 12-month average price for natural gas increased from $1.99 per MMBtu for 2020 to $3.60 per MMBtu for 2021, the 12-month average price for NGL increased from $15.40 per barrel for 2020 to $31.90 per barrel for 2021, and the 12-month average price for crude oil increased from $39.54 per barrel for 2020 to $66.55 per barrel for 2021.
We also experienced 67.6 Bcfe of downward revisions as a result of the exclusion of 4 PUD locations in our Utica field when changes in our schedule moved development of these PUD locations beyond five years of initial booking. These downward revisions were offset by upward revisions of 67.6 Bcfe in estimated proved reserves from a combination of working interest changes, well development design updates and operating and development cost improvements.
Costs incurred relating to the development of PUDs were approximately $268.1 million in 2021.
All PUD drilling locations included in our 2021 reserve report are scheduled to be drilled within five years of initial booking.
As of December 31, 2021, 0.01% of our total proved reserves were classified as proved developed non-producing.
Reserves Estimation
Reserve estimates for the years ended December 31, 2021, 2020 and 2019 were prepared by Netherland, Sewell & Associates, Inc. ("NSAI") for all of our operating areas.
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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 to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. 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 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 geoscience staff has approximately 85 years combined industry experience and our reservoir staff has approximately 75 years combined experience.
Internal Controls Over Proved Reserve Estimates
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 year-end reserve estimates by NSAI in coordination with our experienced reservoir engineers;
direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer;
review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions;
provision of quarterly updates to our board of directors regarding operational data, including production, drilling and completion activity levels and any significant changes in our reserves;
annual review by our board of directors of our year-end reserve report and year-over-year changes in our proved reserves, as well as any changes to our previously adopted development plans;
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, 2021 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 2021 of $66.55 per barrel and $3.60 per MMBtu. Holding production and development costs constant, if SEC pricing were $73.21 per barrel and $3.96 per MMBtu, or a 10% increase, this would have resulted in an increase of 16.2 Bcfe of our total proved reserves and a $787 million increase in PV-10 value at December 31, 2021. Holding production and development costs constant, if SEC pricing were $59.90 per barrel and $3.24 per MMBtu, or a 10% decrease, this would have resulted in a decrease of 23.8 Bcfe of our total proved reserves and a $787 million decrease in PV-10 value at December 31, 2021. For each of these scenarios, the 139 PUDs that were economic at SEC pricing were included.
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Acreage
The following table presents our total gross and net developed and undeveloped acres as of December 31, 2021:
Developed
Acreage
Undeveloped
Acreage
FieldGrossNetGrossNet
Utica127,590101,97991,033 85,330 
SCOOP49,104 34,934 7,959 5,673 
Other 1,021 395 4,377 1,253 
Total177,715 137,308 103,369 92,256 
Of our leases that are not held by production, most have a 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 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, 2021:
Undeveloped Acres
Gross AcresNet Acres
Years Ending December 31:
202215,960 14,494 
202313,937 13,045 
2024261 253 
After 20242,637 2,565 
Held by production or operations70,342 61,667 
Total(1)
103,137 92,024 
(1) Does not include acreage not subject to expiration.
Productive Wells
The following table presents our total gross and net productive wells, expressed separately for oil and gas, as of December 31, 2021:
Average NRI/WIProductive
Oil Wells
Productive
Gas Wells
Total Wells
FieldPercentagesGrossNetGrossNetGrossNet
Utica48.75/59.71147 42.8 514 352.0 661 394.7 
SCOOP23.17/28.80105 16.7 516 161.8 621 178.6 
OtherVarious20 1.3 0.1 28 1.4 
Total(1)
331 60.8 1,141 513.9 1,472 574.7 
(1) We also have override/royalty interests in 162 wells with an average NRI of 0.5%, which are not material to our operations. Totals may not sum due to rounding.
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Drilling Activity
The following table sets forth information with respect to operated wells drilled 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.
Year Ended December 31,
202120202019
GrossNetGrossNetGrossNet
Development:
Productive29 26.6 26 24.4 25 22.4 
Dry— — — — — — 
Total29 26.6 26 24.4 25 22.4 
Exploratory:
Productive— — — — 0.8 
Dry— — — — — — 
Total— — — — 0.8 
The following table presents activity by operating area for the year ended December 31, 2021:
OperatedNon-Operated
FieldDrilledTurned to SalesDrilledTurned to Sales
GrossNetGrossNetGrossNetGrossNet
Utica(1)
20 18.9 17 17.0 — — — — 
SCOOP(2)
7.7 11 9.4 25 1.77 21 0.05 
Total29 26.6 28 26.4 25 1.77 21 0.05 
_____________________
(1)    Of the 20 gross wells drilled in 2021, 10 were completed as producing wells, nine were in various stages of drilling and one was waiting on completion as of December 31, 2021.
(2)    Of the nine gross wells drilled in 2021, four were in various stages of drilling and five were in various stages of completion as of December 31, 2021.
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Production, Prices and Production Costs
The following table presents our production volumes, average prices received and average production costs during the periods indicated (sales totals in thousands):
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through December 31, 2021Period from January 1, 2021 through May 17, 2021Year Ended December 31, 2021Year Ended December 31, 2020Year Ended December 31, 2019
Natural gas sales
Natural gas production volumes (MMcf)208,641 124,279 332,921 344,999 458,178 
Natural gas production volumes (MMcf/d)915 907 912 943 1,255 
Total sales$906,096 $344,390 $1,250,486 $671,535 $1,135,381 
Avg. price without the impact of derivatives ($/Mcf)$4.34 $2.77 $3.76 $1.95 $2.48 
Impact from settled derivatives ($/Mcf)(1)
$(1.44)$(0.03)$(0.91)$0.33 $0.23 
Avg. price, including settled derivatives ($/Mcf)$2.90 $2.74 $2.85 $2.28 $2.71 
Oil and condensate sales
Oil and condensate production volumes (MBbl)1,167 531 1,699 1,803 2,186 
Oil and condensate production volumes (MBbl/d)
Total sales$81,347 $29,106 $110,453 $62,902 $117,937 
Avg. price without the impact of derivatives ($/Bbl)$69.71 $54.81 $65.01 $34.88 $53.95 
Impact from settled derivatives ($/Bbl)$(8.33)$— $(5.72)$25.76 $1.86 
Avg. price, including settled derivatives ($/Bbl)$61.38 $54.81 $59.29 $60.64 $55.81 
NGL sales
NGL production volumes (MBbl)2,658 1,211 3,869 3,964 5,074 
NGL production volumes (MBbl/d)12 11 11 14 
Total sales$105,141 $36,780 $141,921 $66,814 $101,448 
Avg. price without the impact of derivatives ($/Bbl)$39.56 $30.37 $36.68 $16.86 $19.99 
Impact from settled derivatives ($/Bbl)(2)
$(4.88)$— $(3.35)$(0.04)$2.79 
Avg. price, including settled derivatives ($/Bbl)$34.68 $30.37 $33.33 $16.82 $22.78 
Natural gas, oil and condensate and NGL sales
Natural gas equivalents (MMcfe)231,594 134,735 366,329 379,600 501,742 
Natural gas equivalents (MMcfe/d)1,016 983 1,004 1,037 1,375 
Total sales$1,092,584 $410,276 $1,502,860 $801,251 $1,354,766 
Avg. price without the impact of derivatives ($/Mcfe)$4.72 $3.05 $4.10 $2.11 $2.70 
Impact from settled derivatives ($/Mcfe)$(1.39)$(0.02)$(0.89)$0.42 $0.24 
Avg. price, including settled derivatives ($/Mcfe)$3.33 $3.03 $3.21 $2.53 $2.94 
Production Costs:
Avg. lease operating expenses ($/Mcfe)$0.14 $0.14 $0.14 $0.14 $0.15 
Avg. taxes other than income ($/Mcfe)$0.13 $0.09 $0.12 $0.08 $0.08 
Avg. transportation, gathering, processing and compression ($/Mcfe)$0.92 $1.20 $1.02 $1.20 $1.01 
Total LOE, midstream costs and taxes ($/Mcfe)$1.19 $1.43 $1.28 $1.42 $1.24 
(1) In November 2020, the Company early terminated certain gas sold call options which resulted in a cash payment of $60.2 million.
(2) In April 2020, the Company early terminated certain oil fixed price swaps which resulted in a cash receipt of $40.5 million.
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The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2021:
 SuccessorPredecessorNon-GAAP CombinedPredecessor
 Period from May 18, 2021 through December 31, 2021Period from January 1, 2021 through May 17, 2021Year Ended December 31, 2021Year Ended December 31, 2020Year Ended December 31, 2019
Utica
Net production
Natural gas (MMcf)166,906 106,968 273,874 291,133 387,473 
Oil (MBbl)220 183 403 393 247 
NGL (MBbl)562 361 924 1,077 1,812 
Total (MMcfe)171,598 110,235 281,833 299,955 399,828 
Avg. price without the impact of derivatives:
Natural gas ($/Mcf)$4.33 $2.64 $3.67 $1.97 $2.28 
Oil ($/Bbl)$66.94 $52.43 $60.35 $33.41 $51.11 
NGL ($/Bbl)$47.16 $37.21 $43.27 $18.55 $19.74 
Production costs:
Avg. lease operating expenses ($/Mcfe)$0.13 $0.13 $0.13 $0.13 $0.12 
Avg. taxes other than income ($/Mcfe)$0.07 $0.06 $0.07 $0.07 $0.07 
Avg. transportation, gathering, processing and compression ($/Mcfe)$0.98 $1.26 $1.09 $1.29 $1.07 
Total LOE, midstream costs and taxes ($/Mcfe)$1.18 $1.45 $1.29 $1.49 $1.26 
SCOOP
Net production
Natural gas (MMcf)41,724 17,302 59,026 53,853 70,669 
Oil (MBbl)933 344 1,276 1,392 1,610 
NGL (MBbl)2,095 849 2,945 2,886 3,261 
Total (MMcfe)59,893 24,461 84,353 79,519 99,891 
Avg. price without the impact of derivatives:
Natural gas ($/Mcf)$4.40 $3.59 $4.16 $1.83 $2.13 
Oil ($/Bbl)$70.37 $56.05 $66.51 $35.31 $53.32 
NGL ($/Bbl)$37.51 $27.46 $34.61 $16.23 $20.13 
Production costs:
Avg. lease operating expenses ($/Mcfe)$0.17 $0.22 $0.19 $0.18 $0.18 
Avg. taxes other than income ($/Mcfe)$0.29 $0.20 $0.26 $0.10 $0.14 
Avg. transportation, gathering, processing and compression ($/Mcfe)$0.74 $0.90 $0.78 $0.86 $0.80 
Total LOE, midstream costs and taxes ($/Mcfe)$1.20 $1.32 $1.23 $1.14 $1.12 
Our Investments
Grizzly Oil Sands. We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.5% interest in Grizzly. As of December 31, 2021, Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly's operations have been suspended since 2016. Additionally, Grizzly had no proved reserves as of December 31, 2021. 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 continued dilution of our equity ownership interest in Grizzly. Upon emergence from bankruptcy, we determined that we no longer had the ability to exercise significant influence over operating and financial policies of Grizzly. As such, we discontinued equity method of accounting for our investment in Grizzly.
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Mammoth Energy. As discussed in Note 15 of our consolidated financial statements, the Company's previously owned shares of the outstanding common stock of Mammoth Energy were used to settle Class 4A claims during 2021. The Company no longer owns any common stock of Mammoth Energy.
Marketing
The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including securing and negotiating commodity transactions, gathering, hauling, processing and transportation services, contract administration and nomination services for production from Gulfport-marketed wells. 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 of our sales contracts being shorter term in nature.
We have entered into long-term gathering, processing and transportation contracts with various parties that reserve capacity for 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. In addition, we periodically enter into 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 firm transportation 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. See Note 18 of our consolidated financial statements for further discussion of our commitments.
Major Customers
Our total natural gas, oil and NGL sales, before the effects of hedging, to major customers (purchasers in excess of 10% of total natural gas, oil and NGL sales) for the Successor Period, Predecessor Period, and years ended December 31, 2020 and 2019 were as follows:
% of Sales
Period from May 18, 2021 through December 31, 2021 (Successor)
ECO-Energy20 %
Macquarie10 %
Period from January 1, 2021 through May 17, 2021 (Predecessor)
ECO-Energy14 %
Macquarie12 %
Citadel11 %
Year Ended December 31, 2020 (Predecessor)
ECO-Energy12 %
Year Ended December 31, 2019 (Predecessor)
Morgan Stanley Capital14 %
Competition
The oil and natural gas industry is intensely competitive, and we compete with many other companies that have greater resources than we have. Competition can negatively impact our ability to successfully source quality vendors and service providers, to secure optimal pipeline access and end markets in which to sell our production, to acquire new properties, and our search for, and the development of, reserves. Many of our competitors not only explore for and produce oil and natural gas, but also have midstream and further downstream operations and market a variety of hydrocarbon products on a regional, national or worldwide basis. 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 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.
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Seasonality
Gulfport drills and completes wells throughout the year, but adverse weather conditions can impact drilling, completion, and field operations, which can impact overall production volumes. Seasonal anomalies can minimize or exaggerate the impact on these operations, while extreme weather events can materially constrain our operations for short periods of time.
Title to Oil and Natural Gas Properties
It is customary in the oil and natural gas industry to make only a preliminary 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 certain imperfections in title, encumbrances, easements, servitudes or other restrictions, none of which, in management's opinion, will in the aggregate materially restrict our operations.
Regulation - Environment, Health and Safety
Exploration and Production, Environmental, Health and Safety, and Occupational Laws and Regulations
Our operations are subject to federal, tribal, state, and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to, the following:
reporting of workplace injuries and illnesses;
industrial hygiene monitoring;
worker protection and workplace safety;
approval or permits to drill and to conduct operations;
provision of financial assurances (such as bonds) covering drilling and well operations;
calculation and disbursement of royalty payments and production taxes;
seismic operations and data;
location, drilling, cementing and casing of wells;
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 completing wells;
hydraulic fracturing;
water withdrawal;
well production and operations, including processing and gathering systems;
emergency response, contingency plans and spill prevention plans;
air emissions and fluid discharges;
climate change;
use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
surface usage, maintenance, monitoring and the restoration of properties associated with well pads, pipelines, impoundments and access roads;
plugging and abandoning of wells; and
transportation of production.
Shortly after taking office in January 2021, President Biden issued a series of executive orders designed to address climate change and requiring agencies to review environmental actions taken by the Trump administration, as well as a memorandum to departments and agencies to refrain from proposing or issuing rules until a departmental or agency head appointed or designated by the Biden administration has reviewed and approved the rule. These executive orders in part led to the US again depositing an instrument of acceptance of the Paris Agreement, created in 2015 during the United Nations (“U.N.”) Climate Change Conference, which thereafter re-entered into force for the US on February 19, 2021. The Paris Agreement requires countries to review and “represent a progression” in their nationally determined contributions, which set emissions reduction goals, every five years beginning in 2020. The terms of the Paris Agreement and the executive orders are expected to result in
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additional regulations or changes to existing regulations, which could have a material adverse effect on our business. In addition, incentives to conserve energy or use alternative energy sources could have a negative impact on our business. The executive orders and international accord may result in the development of additional regulations or changes to existing regulations. Failure to comply with laws and regulations 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 environmental, safety and health laws and regulations without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on policy and 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.
Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, 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 gas properties. In the United States, some states allow the compulsory pooling or integration of tracts to facilitate exploration and development. Other states rely on voluntary pooling of lands and leases which may make it more difficult to develop oil and gas properties. In addition, federal and state conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain requirements regarding the ratable purchase of production. These regulations often impose additional operational costs to us and can also limit the amounts of oil and gas we can produce from our wells and the number of wells or the locations at which we can drill.
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 agencies have continued to assess the potential impacts of hydraulic fracturing, which could spur further action toward federal, state and/or local legislation and regulation. Further restrictions of hydraulic fracturing could reduce the amount of natural gas, oil and NGL that we are ultimately able to produce in commercial quantities from our properties.
Certain of our U.S. natural gas and oil 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, among other matters, drilling and operations on lands covered by these leases and calculation and disbursement of royalty payments to the federal government, tribes or tribal members. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and royalty payment obligations for production from federal lands. In addition, on January 20, 2021, the Acting Secretary for the Department of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. To the extent that the review results in the development of additional restrictions on drilling, limitations on the availability of leases, or restrictions on the ability to obtain required permits, it could have a material adverse impact on our operations.
Permitting activities on federal lands are also subject to 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 imposition of fines and penalties.
Operating Hazards and Insurance
The oil and natural gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could suffer substantial losses 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 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.
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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 $51 million comprehensive general liability umbrella insurance policy. In addition, 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 these policies are customary in the industry, they do not provide complete coverage against all operating risks, and policy limits scale to our working interest percentage in certain situations. In addition, our insurance does not cover penalties or fines that may be assessed by a 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. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.
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 go through a technical review every five years and are updated as necessary. As required by applicable regulations, our facilities are built with secondary containment systems to capture potential releases. We also own additional spill kits with oil booms and absorbent pads that are readily available, if needed. In addition, we have emergency response companies on retainer. These companies specialize in the clean-up of hydrocarbons as a result of spills, blow-outs and natural disasters, and are on call to us 24 hours a day, seven days a week when their services are needed. We pay these companies a retainer plus additional amounts when they provide us with clean up services. Our aggregate payments for the retainer and clean-up services during each of 2021 and 2020 were 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.
Human Capital Management
Employees
As of December 31, 2021, we had 212 employees, a reduction from 256 employees the previous year. The reduction was due to the rightsizing of our organization through a controlled hiring program and a small reduction in workforce in August of 2021. All of our employees are non-bargaining. Attraction and retention of people remains one of the highest strategic goals of the organization. We remain focused on the retention and development of existing employees, as their continued commitment is critical to our success.
During 2021, we continued to adapt to the changing nature of the COVID-19 pandemic, by regularly assessing COVID-19 employee protocols, minimizing the numbers of people in our offices at times, conducting daily health screenings for all employees and visitors, and completing thorough contact tracing. These efforts helped protect the safety of employees, minimize the risk of transmission at Gulfport locations and keep our operations online with minimal disruption.
Inclusion & Diversity
During 2021, we continued to work on the diversity and inclusion projects that we announced in 2020 and held peer-led, small group discussions for all employees aimed at understanding how they view diversity and ways we could continue to focus on it in a meaningful way going forward. Based partly on feedback from those discussions, the Company delivered an unconscious bias training program for all employees to better help them understand themselves and how they view those around them. The results of these efforts have been overwhelmingly positive and have positioned us to further our diversity and inclusion initiatives in 2022 and beyond.
During 2021, our Board of Directors completely turned over as a result of the bankruptcy process and is now comprised of 40% of highly qualified diverse candidates as of the end of 2021. While 2021 was a year in which we again added very few new employees, approximately 29% of our newly hired employees were diverse hires. We are committed to evaluating our hiring and promotion practices to make sure that a diversity and inclusion mindset is considered and included throughout the Company.
In 2021, many Gulfport policies were added or revised, and a new Business Code of Conduct and Ethics training was provided to all employees. We are committed to maintaining the highest standards of business ethics and the employee training provided a clear review of our expectations.
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Health, Safety & Environment (HSE)
Safety is at the forefront of everything we do. We have a robust annual training program, which includes environmental, health, and safety topics. Our safety program, WORK SAFE, is comprised of twelve key topics including critical tasks and cultural conditions. We hold regular safety briefings to discuss daily operations and routinely have safety stand-down meetings to highlight potential risks. Every employee is empowered to use their stop-work authority to cease operating if work is being performed in an unsafe manner. We monitor employee safety by establishing annual company-wide key safety metrics tied to leading indicators (i.e., incident reporting and investigations, hazard observations, safety and health meetings) and lagging indicators (i.e., injury rates and preventable motor vehicle accidents).
As part of our focus on continuous improvement, we monitor and communicate key environmental and safety metrics both internally and externally. Trend analysis guides us to make operational changes and policy updates as necessary to protect our employees, the public, and the environment. We establish and carefully track key environmental and safety metrics that are a component of every employee’s incentive compensation opportunity for 2021.
We have established several programs to ensure that our employees and external partners are appropriately trained to perform the critical work we do safely and effectively. We continued to reinforce our Work Safe Program and provided training to leaders on reinforcement strategies. Additionally, we launched the Work Green program in 2021, which focuses on protecting the air, land and water where we operate and includes community-based volunteer events targeting environmental clean-up and habitat improvement initiatives.
Training & Development
Gulfport invests in our employees' professional growth to build strong teams and develop leaders for today and the future. We build our dynamic team of industry-leading professionals by engaging them in interesting and rewarding work and by providing training and development opportunities. We utilize in-person training sessions developed by safety experts and supplement these sessions with computer-based modules to support a safety-first mindset in everything we do. We continue to provide training resources to employees through universities, electronic content services and specialized courses related to our industry through our tuition reimbursement program or third-party providers.
Executive Officers
Timothy J. Cutt, Chief Executive Officer and Chairman of the Board
Mr. Cutt, 61, joined Gulfport as the Interim Chief Executive Officer in May 2021, and assumed the role of Chief Executive Officer in September 2021. Mr. Cutt is a Petroleum Engineer with 38 years of energy experience. He served as Chief Executive Officer and as a director of QEP Resources from January 2019 to March 2021. Prior to joining QEP, Mr. Cutt was the Chief Executive Officer and a director of Cobalt International Energy from 2016 to 2018. Previously, Mr. Cutt held several executive positions with BHP Billiton before serving as President of the Petroleum Division from 2013 to 2016. During this time, he was also a member of BHP Billiton’s Corporate Leadership Team. Mr. Cutt began his career with Mobil and worked for ExxonMobil for 24 years and served in various management roles including President of ExxonMobil de Venezuela, President ExxonMobil Canada Energy and President Hibernia Management & Development Company. Mr. Cutt served as a board member of the American Petroleum Institute (API) from 2013 to 2018.
William J. Buese, Chief Financial Officer
Mr. Buese, 50, joined Gulfport as the Chief Financial Officer in May 2021. Most recently, Mr. Buese served as Vice President, Chief Financial Officer and Treasurer of QEP Resources from January 2020 to March 2021. He joined QEP Resources in 2012 and held positions of increasing responsibility over a nine-year period, including Vice President of Finance and Treasurer and Director of Finance. Prior to joining QEP, Mr. Buese was Director of Finance at MarkWest Energy Partners, LP and served in various finance, treasury, accounting and investor relations roles from 2005 to 2012. Mr. Buese holds over 16 years of financial expertise in the energy industry and more than 25 years of financial experience overall. Mr. Buese received his Bachelor of Arts degree in Accounting from Michigan State University and Master of Science degree in Information Systems from the University of Colorado Denver.
Patrick K. Craine, Chief Legal and Administrative Officer
Mr. Craine, 49, has served as Chief Legal and Administrative Officer since June 2021 and joined Gulfport as Executive Vice President, General Counsel and Corporate Secretary in May 2019. Prior to joining the Company, Mr. Craine served as
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Deputy General Counsel – Chief Risk and Compliance Officer at Chesapeake Energy Corporation. Prior to joining Chesapeake in 2013, Mr. Craine was a partner with Bracewell LLP, a global law firm, where his practice focused on securities and corporate regulatory matters and investigations. Before Mr. Craine entered private practice, he served as a lawyer with the U.S. Securities and Exchange Commission and the Financial Industry Regulatory Authority where he held leadership positions in their Oil and Gas Task Forces. 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 particular expertise in the energy industry. Mr. Craine received his Bachelor of Arts degree, summa cum laude, Phi Beta Kappa, from Wabash College, and his Juris Doctorate, cum laude, from the Southern Methodist University Dedman School of Law.
Michael J. Sluiter, Senior Vice President of Reservoir Engineering
Mr. Sluiter, 49, joined Gulfport as the Senior Vice President of Reservoir Engineering in December 2018 from Noble Energy, Inc., where he most recently served as the Permian Basin Business Unit Manager at Noble Energy, Inc. Prior to joining Noble in 2007, he spent over 17 years developing his skills and expertise in unconventional resource development, reservoir engineering, subsurface development, business development/M&A, and leadership at Noble Energy, Santos Australia and Santos USA. Mr. Sluiter began his career as a wireline field services engineer for Schlumberger in Thailand. Mr. Sluiter is a graduate of the University of Sydney, Australia, with a Bachelor of Science degree in Chemical Engineering.
RJ Moses, Senior Vice President of Operations and Drilling
Mr. Moses, 42, has served as Senior Vice President of Operations and Drilling since March 2020 and joined Gulfport Energy as the Vice President of Operations, Appalachia in August 2019. Prior to joining the Company, Mr. Moses spent over 15 years at Noble Energy, Inc., where he most recently served as a Director of Operations for Noble’s Eagleford and Denver-Julesburg (DJ) business units, managing approximately one-third of Noble’s total production at the time. Prior to that, he held various leadership roles including Operations Manager for Noble’s Marcellus business unit along with several international roles including Asset Manager for the Tamar asset (offshore Israel), Project Manager for West Africa subsea development and Lead Reservoir Engineer for West Africa. In addition, Mr. Moses served as a Senior Financial Analyst in the International division and also spent four years as an international drilling and completion engineer for Noble. Mr. Moses graduated from Texas A&M University with a Bachelor of Science degree in Petroleum Engineering and holds a Master of Business Administration degree from Texas Christian University.
There is no family relationship between any of our officers or between any of them and the Company's Board of Directors. The executive officers serve at the pleasure of the Company's Board of Directors.
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ITEM 1A.RISK FACTORS
There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a summary 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 company. Additional risks and uncertainties 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.
Financial, Liquidity and Commodity Price Risks
Natural gas, oil and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse effect on our 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 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 properties.
Historically, the markets for natural gas, oil and NGL have been volatile, and they are likely to continue to be volatile. For example, during 2020, West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, prices ranged from $(36.98) to $63.27 per barrel and the Henry Hub spot market price of natural gas ranged from $1.33 to $3.14 per MMBtu. During 2021, WTI prices ranged from $47.47 to $85.64 per barrel and the Henry Hub spot market price of natural gas ranged from $2.43 to $23.86 per MMBtu.
Wide fluctuations in natural gas, oil and NGL prices may result from factors that are beyond our control, including:
domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural 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;
the cost of exploring for, developing, producing and delivering oil and natural gas;
the expected rates of declining current production;
the price and availability of alternative fuels;
technological advances affecting energy consumption;
risks associated with operating drilling rigs;
the effectiveness of worldwide conservation measures;
the availability, proximity and capacity of pipelines, 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 and others to agree to and maintain oil price and production controls;
political or economic instability or armed conflict in oil and natural gas producing regions, including the Middle East, Africa, South America and Russia;
weather conditions;
acts of terrorism; and
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domestic and global economic conditions.
These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and NGL price movements with any certainty. Even with natural gas, oil and NGL derivatives currently in place to mitigate price risks associated with a portion of our 2022 cash flows, we have substantial exposure to natural gas prices, and to a lesser extent, oil and NGL prices, in 2023 and beyond. In addition, a prolonged extension of lower prices could reduce the quantities of reserves that we 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.
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 also may be unable to mitigate price volatility due to our exposure to long-dated call options and restrictions in our credit facility. 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.
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 London Interbank Offered Rate. At December 31, 2021, amounts borrowed under our revolving credit facility bore interest at the weighted average rate of 3.19%. A 1% increase in the average interest rate would increase our interest expense by approximately $2 million based on outstanding borrowings under our revolving credit facility at December 31, 2021. An increase in our interest rate at the time we have variable interest rate borrowings outstanding under our revolving credit facility will increase our costs, which may have a material adverse effect on our results of operations and financial condition. As of December 31, 2021, we did not hedge our interest rate risk.
We have exposure to LIBOR through credit agreements. Certain tenors of LIBOR began being phased out in late 2021, with full discontinuation planned for mid-2023. We believe the rate selected as the preferred alternative to LIBOR will be an acceptable replacement rate when LIBOR is fully discontinued. However, we are still currently evaluating the impact of any such potential benchmark replacements or unavailability of LIBOR. 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 benchmark rates or disruption in the financial markets could materially and adversely affect our financial condition, results of operations and cash flows.
Our debt and other financial commitments may limit our financial and operating flexibility.
Our total principal debt was approximately $714 million at December 31, 2021. We also had various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services, products and
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properties. Our financial commitments could have important consequences to our business, including, but not limited to, limiting our ability to fund future working capital and capital expenditures, to engage in future acquisitions or development activities, to pay dividends, to repurchase shares of our common and preferred stock, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flows from operations to make payments on our debt or to comply with restrictive terms of our debt. Higher levels of debt may make us more vulnerable to general adverse economic and industry conditions. Additionally, the agreement governing our credit facility and the indentures governing our senior notes contain a number of covenants that impose constraints on us, including requirements to comply with certain financial covenants and restrictions on our ability to dispose of assets, make certain investments, incur liens and additional debt, and engage in consolidations, mergers and acquisitions. If commodity prices decline and we reduce our level of capital spending and production declines or we incur additional impairment expense or the value of our proved reserves declines, we may not be able to incur additional indebtedness, may need to repay outstanding indebtedness and may not be in compliance with the financial covenants in our debt instruments in the future. Refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of this Annual Report on Form 10-K and Note 6 of our consolidated financial statements for more information regarding the financial covenants and our revolving credit agreement.
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.
Historically, we have financed capital expenditures primarily with cash flow from operations, the issuance of equity and debt securities and borrowings under our revolving credit 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 2022 could exceed our capital expenditure budget. In the event our capital expenditure requirements at any time are greater than the amount of capital we have available, we could be required to seek additional sources of capital, which may include traditional reserve base borrowings, debt financing, joint venture partnerships, production payment financings, sales of assets, offerings of debt or equity securities or other means. We cannot assure you that we will be able to obtain debt or equity financing on terms favorable to us, or at all.
If we are unable to fund our capital requirements, we may be required to curtail our operations relating to the exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves, or we may be otherwise unable to implement our development plan, complete acquisitions or take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. In addition, a delay in or the failure to complete proposed or future infrastructure projects could delay or eliminate potential efficiencies.
Under our method of accounting for oil and natural gas properties, declines in commodity prices may result in impairment of asset value.
We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of
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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 oil and NGLs to one MCF of natural gas 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 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 write-down 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. Future non-cash asset impairments could negatively affect our results of operations.
A change of control could limit our use of net operating losses to reduce future taxable income.
As of December 31, 2021, we had a net operating loss, or NOL, carryforward of approximately $1.4 billion for federal income tax purposes. If we were to experience an “ownership change,” as determined under IRC Section 382, 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 ownership 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.
Emergence from Chapter 11 bankruptcy proceedings resulted in an ownership change for purposes of IRC Section 382. We currently expect to apply rules under IRC Section 382(l)(5) that would allow us to mitigate the limitations imposed under IRC Section 382 with respect to our NOLs that existed at the time of such ownership change. However, if we were to experience a second ownership change, then our ability to utilize our NOLs could potentially be subject to a more restrictive limitation under IRC Section 382.
Industry, Business and Operational Risks
The oil and gas development, 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
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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.
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, 2021, approximately 44% of our total estimated proved reserves were 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, 2021 present value is based on a $3.60 per MMBtu of gas price and a $66.55 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;
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
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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 cancelled 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.
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 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
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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.
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.
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. Although 80% of our Utica acreage is held by existing production, the remaining acreage is subject to expiration. Of the remaining 20% of our Utica acreage not held by production, 39% will be subject to expiration in 2022, 35% in 2023, 8% in 2024 and 18% thereafter, although a portion of our Utica leases generally grant us the right to extend these leases for an additional five-year period. Although 99% of our SCOOP acreage is held by existing production, the remaining acreage is subject to expiration. Of the remaining 1% of our SCOOP acreage not held by production, 17% will be subject to expiration in 2022, 6% in 2023, 77% in 2024 and none thereafter. 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.
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 9% of our daily production volumes from properties which we did not serve as operator as of December 31, 2021, 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 cancelled 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;
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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, cybersecurity breaches, 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 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.
Multi-well pad drilling may result in volatility in our operating results and delay the conversion of our PUD reserves.
We utilize multi-well pad drilling where practical. For example, in the Utica we drill multiple wells from a single pad. Wells drilled on a pad are not turned to sales until all wells on the pad are drilled and cased and the drilling rig is moved from the location. In addition, existing wells that offset newly drilled wells may be temporarily shut-in during the drilling and completion process. As a result, multi-well pad drilling delays the completion of wells and the commencement of production from new wells, and may negatively affect the production from existing offset wells, all of which may cause volatility in our operating results from period to period. Finally, delays in completion of wells may impact planned conversion of PUD reserves to PDP reserves.
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
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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.
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.
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.
Substantially all of our producing properties are located in Eastern Ohio and Oklahoma, making us vulnerable to risks associated with operating in only 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 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 Predecessor Period and Successor Period accounted for approximately 14% and 20%, respectively, 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.
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 and increased costs for 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.
Our operations may be adversely affected by pipeline, trucking and gathering system capacity constraints and may be subject to interruptions that could adversely affect our cash 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
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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 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 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. 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 and the other areas in which we operate. Until this new capacity is available, we may experience delays in producing and selling our natural gas, oil and NGL. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity or sell natural gas, oil or NGL production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.
A portion of our natural gas, oil and NGL production in any region may be interrupted, or shut 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 substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow.
We are required to pay fees to some of our midstream service providers based on minimum volumes regardless of actual volume throughput.
We have contracts with some of our third-party service providers for gathering, processing and transportation services with minimum volume delivery commitments under which we are obligated to pay certain fees on minimum volumes regardless of actual volume throughput. As of December 31, 2021, our aggregate long-term contractual obligation under these agreements was approximately $1.8 billion. These fees could be significant and may have a material adverse effect on our results of operations.
The outbreak of the novel coronavirus, or COVID-19, has affected and may materially adversely affect, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our operations, financial performance and condition, operating results and cash flows.
The recent outbreak of COVID-19 has affected, and may materially adversely affect, our business and financial and operating results. The severity, magnitude and duration of the current COVID-19 outbreak is uncertain, rapidly changing and hard to predict. In 2021, the outbreak has significantly impacted economic activity and markets around the world, and COVID-19 or another similar outbreak could negatively impact our business in numerous ways, including, but not limited to, the following:
our revenue may be reduced if the outbreak results in an economic downturn or recession, as many experts predict, to the extent it leads to a prolonged decrease in the demand for natural gas and, to a lesser extent, NGL and oil;
our operations may be disrupted or impaired, thus lowering our production level, if a significant portion of our employees or contractors are unable to work due to illness or if our field operations are suspended or temporarily shut-down or restricted due to control measures designed to contain the outbreak;
the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced natural gas, oil and NGL, may be disrupted or suspended in response to containing the outbreak, and/or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers, which may result in substantial discounts in the prices we receive for our produced natural gas, oil and NGL or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties; and
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the disruption and instability in the financial markets and the uncertainty in the general business environment may affect our ability to execute on our business strategy, including our focus on reducing our leverage profile. If we are not able to successfully execute our plan to reduce our leverage profile, 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, could result in a default under our revolving credit facility or the indentures governing our senior notes. Additionally, our credit ratings may be lowered, we may reduce or delay our planned capital expenditures or investments, and we may revise or delay our strategic plans.
We expect that the principal areas of operational risk for us are availability of service providers and supply chain disruption, which has recently become more acute. Active development operations, including drilling and fracking operations, represent the greatest risk for transmission given the number of personnel and contractors on site. While we believe that we are following best practices under COVID-19 guidance, the potential for transmission still exists. In certain instances, it may be necessary or determined advisable for us to delay development operations.
In addition, the COVID-19 pandemic has increased volatility and caused negative pressure in the capital and credit markets. As a result, we may experience difficulty accessing the capital or financing needed to fund our exploration and production operations, which have substantial capital requirements, or refinance our upcoming maturities on satisfactory terms or at all. We typically fund our capital expenditures with existing cash and cash generated by operations (which is subject to a number of variables, including many beyond our control) and, to the extent our capital expenditures exceed our cash resources, from borrowings under our revolving credit facility and other external sources of capital. If our cash flows from operations or the borrowing capacity under our revolving credit facility are insufficient to fund our capital expenditures and we are unable to obtain the capital necessary for our planned capital budget or our operations, we could be required to curtail our operations and the development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operations and financial position.
To the extent the COVID-19 pandemic adversely affects our business and financial results, it may also have the effect of heightening many of the other risks set forth in Item 1A., “Risk Factors” in our Annual Report on Form 10-K, such as those relating to our financial performance and debt obligations. The rapid development and fluidity of this situation precludes any prediction as to the ultimate adverse impact of COVID-19 on our business, which will depend on numerous evolving factors and future developments that we are not able to predict, including the length of time that the pandemic continues, its effect on the demand for natural gas, NGL and oil, the response of the overall economy and the financial markets as well as the effect of governmental actions taken in response to the pandemic.
A deterioration in general economic, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the European, Asian and the United States financial markets have contributed to economic volatility and diminished expectations for the global economy. Historically, concerns about global economic growth have had a significant impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and materially adversely impact our results 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 precipitate, an economic slowdown.
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Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.
Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating 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 our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized 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 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 disclosure of, or 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 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-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 vulnerabilities to cyber-attacks. In addition, new laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability.
We may engage in acquisition and divestiture activities that involve substantial risks.
We may make acquisitions that complement or expand our current areas of operations. If we are unable to make attractive acquisitions, our future growth could be limited. Furthermore, even if we do make acquisitions, they may not result in an increase in our cash flow from operations or otherwise result in the benefits anticipated due to various risks, including, but not limited to:
mistaken estimates or assumptions about reserves, potential drilling locations, revenues and costs, including synergies and the overall costs of equity or debt;
difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and
unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.
In addition, from time to time, we may sell or otherwise dispose of certain of our properties or businesses as a result of an evaluation of our asset portfolio or to help enhance our liquidity. These transactions also have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets or businesses and potential post-closing claims for indemnification. Moreover, volatility in commodity prices may result in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a transaction prior to closing.
Legal and Regulatory Risks
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
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conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. For example, on January 20, 2021, the Acting Secretary for the Department of the Interior signed an order effectively suspending new fossil fuel leasing and permitting on federal lands for 60 days. Then on January 27, 2021, President Biden issued an executive order indefinitely suspending new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. To the extent that the review results in the development of additional restrictions on drilling, limitations on the availability of leases, or restrictions on the ability to obtain required permits, it could have a material adverse impact on our operations. In addition, we may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or 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.” Recent PHMSA rules have also extended certain requirements for integrity assessments and leak detections beyond high consequence areas. Further, legislation funding PHMSA through 2023 requires the agency to engage in additional rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines. At this time, we cannot predict the cost of these requirements or other potential new or amended regulations, but they 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 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.
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
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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 and incentivize energy conservation or the use of alternative energy sources. Policy makers at both the U.S. 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 and encourage consumers to the alternative energy sources. The Build Back Better Act, passed by the US House of Representatives and supported by President Biden, includes incentives to increase wind and solar electric generation and encourage consumers to use these alternative energy sources. States in which 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. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time. The development of a federal renewable energy standard, or the development of additional or more stringent renewable energy standards at the state level or other initiatives to incentivize the use of renewable energy could reduce the demand for oil and gas, thereby adversely impacting our earnings, cash flows and financial position. Cap and trade programs offer greenhouse gas emission allowances that are gradually reduced over time. A cap and trade program or expanded use of cap and trade programs at the state level 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. In addition, federal or state carbon taxes 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. Members of the investment community have also begun to screen companies such as ours for sustainability performance, including practices related to greenhouse gases and climate change, before investing in our common units. Any efforts to improve our sustainability practices in response to these pressures may increase our costs, and we may be forced to implement technologies that are not economically viable to improve our sustainability performance and to meet the specific requirements to perform services for certain customers. If we are unable to meet the ESG standard or investment, lending, ratings, or voting criteria and policies set by these parties, we may lose investors, investors may allocate a portion of their capital away from us, we may become a target for ESG-focused activism, our cost of capital may increase, the price of our securities may be negatively impacted, and our reputation may also be negatively affected.
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.
Severe weather events, such as storms, hurricanes, droughts, or floods, could have an adverse effect on our operations and could increase our costs. If climate changes result in more intense or frequent severe weather events, the physical and disruptive effects could have a material adverse impact on our operations and assets.
Air Emissions. The US Federal Clean Air Act and associated state laws and regulations restrict the emission of air pollutants from many sources, including oil and natural gas operations. New facilities may be required to obtain permits before operations can commence, and existing facilities may be required to obtain additional permits, and incur capital costs, in order to remain in compliance. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations. In general, we believe that compliance with the Clean Air Act and similar state laws and regulations will not have a material impact on our operations or financial condition.
Endangered Species. The Endangered Species Act (ESA) prohibits the taking of endangered or threatened species or their
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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 and SCOOP operations, we make an effort to reuse/recycle all produced water from production and completion activities through our fracture stimulation operations when active. While our objective is to recycle or share 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 once sharing opportunities with other operators have been exhausted. 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.
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.
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 costs as we collect and store personal data related to royalty owners. Any failure to comply with these laws and regulations could result in significant penalties and legal liability. 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 CCPA. We will continue to monitor and assess the impact of these state laws, which may impose substantial penalties for violations, impose significant costs for investigations and compliance, require us to change our business practices, allow private class-action litigation and carry significant potential liability for our business should we 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
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to significant fines, penalties, judgments and negative publicity, require us to change our business practices, increase the costs and 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 a violation of these laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.
Risks Associated with our Emergence from Bankruptcy
We recently emerged from bankruptcy, which may adversely affect our business and relationships.
It is possible that our having filed for bankruptcy and our recent emergence from bankruptcy may adversely affect our business and relationships with customers, vendors, contractors or employees. Due to uncertainties, many risks exist, including the following:
key vendors or other contract counterparties may terminate their relationships with us or require additional financial assurances or enhanced performance from us;
our ability to renew existing contracts and compete for new business may be adversely affected;
our ability to attract, motivate and/or retain key executives may be adversely affected; and
competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.
The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.
Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan and the transactions contemplated thereby.
In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results may vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.
Upon emergence from bankruptcy, the composition of our board of directors changed significantly.
The composition of our board of directors changed significantly upon emergence from bankruptcy. Our new board is comprised of five directors, including the Company's Chief Executive Officer, Timothy Cutt, and four non-employee directors, David Wolf, Guillermo Martinez, Jason Martinez and David Reganato. While we expect to engage in an orderly transition process as we integrate newly appointed board members, our new board of directors may change views on strategic initiatives and a range of issues that will determine the future of the Company. As a result, the future strategy and plans of the Company may differ materially from those of the past.
Risks Associated with an Investment in Us
The market price of our securities is subject to volatility.
Upon our emergence from bankruptcy, our old common stock was cancelled and we issued New Common Stock. The market price of our New Common Stock could be subject to wide fluctuations in response to, and the level of trading that develops with our New Common Stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the Plan, our
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limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part I, Item 1A of this Annual Report on Form 10-K.
Future sales or the availability for sale of substantial amounts of our common stock, or the perception that these sales may occur, could adversely affect the trading price of our common stock and could impair our ability to raise capital through future sales of equity securities.
A large percentage of our common stock is held by a relatively small number of investors. In connection with our emergence from bankruptcy protection, we entered into the Registration Rights Agreement pursuant to which we have agreed to file a registration statement with the SEC to facilitate potential future sales of our common stock by such investors. Sales of a substantial number of shares of our common stock in the public markets, or even the perception that these sales might occur (such as upon the filing of the aforementioned registration statement), could impair our ability to raise capital through a future sale of, or pay for acquisitions using, our equity securities.
We cannot predict the effect that future sales of our common stock will have on the price at which the common stock trades. Sales of substantial amounts of our common stock, or the perception that such sales could occur, may adversely affect the trading price of our common stock.
Certain of our stockholders own a significant portion of our outstanding debt and equity securities and their interests may not always coincide with the interests of other holders of the New Common Stock.
A large percentage of our debt and equity are held by a relatively small number of investors. As a result, these investors could have significant influence over all matters presented to our stockholders and debt holders for approval, including election and removal of our directors, change in control transactions and the outcome of all actions requiring majority stockholder approval.
The interests of these investors may not always coincide with the interests of the other holders of the New Common Stock and other debt holders, and the concentration of control in these investors may limit other stockholders' ability to influence corporate matters. The concentration of ownership and voting power of these investors may also delay, defer or even prevent an acquisition by a third party or other change of control transactions of our Company. This may make some transactions more difficult or impossible without their support, even if such events are in the best interests of our other stockholders. In addition, the concentration of voting power may adversely affect the trading price and liquidity of the New Common Stock.
There may be future dilution of our common stock, which could adversely affect the market price of our common stock.
We are not restricted from issuing additional shares of our common stock. In the future, we may issue shares of our common stock to raise cash for future capital expenditures, acquisitions or for general corporate purposes. We may also issue securities that are convertible into, exchangeable for or that represent the right to receive our common stock. Lastly, we currently issue restricted stock units and performance vesting restricted stock units to certain employees and directors as part of their compensation. Any of these events will dilute our shareholders' ownership interest in Gulfport and may reduce our earnings per share and have an adverse effect on the price of our common stock.
Our amended and restated certificate of incorporation provides, subject to certain exceptions, that the Court of Chancery of the State of Delaware will be the sole and exclusive forum for certain stockholder litigation matters, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or stockholders.
Our amended and restated certificate of incorporation provides, subject to limited exceptions, that the Court of Chancery of the State of Delaware will, to the fullest extent permitted by law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf; (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors or officers to us, our stockholders, our creditors or other constituents; (iii) any action asserting a claim against us, any director or our officers arising pursuant to any provision of the DGCL, our certificate of incorporation or our by-laws; or (iv) any action asserting a claim against us, any director or our officers that is governed by the internal affairs doctrine. This choice of forum
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provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or any of our directors or officers or stockholders which may discourage lawsuits with respect to such claims. Alternatively, if a court were to find the choice of forum provision contained in our certificate of incorporation to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could have a material adverse effect on our business, financial condition and results of operations.
ITEM 1B.UNRESOLVED STAFF COMMENTS
None.
ITEM 2.PROPERTIES
Information regarding our properties is included in Item 1 and in the Supplemental Information on Oil and Gas Exploration and Production Activities in Note 20 of our consolidated financial statements.
ITEM 3.LEGAL PROCEEDINGS
The Company is involved in various commercial and regulatory claims, litigation and other legal proceedings that arise in the ordinary course of its business.
While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on us, cannot be predicted with certainty, we believe that none of these matters, if ultimately decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.
The information with respect to this Item 3. Legal Proceedings is set forth in Note 19 of our consolidated financial statements. Additionally, see Note 1 and Note 2 of our consolidated financial statements for additional discussion of on-going claims and disputes from our Chapter 11 proceedings, certain of which may be material.
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
Common Stock
On November 27, 2020, our predecessor common stock was suspended from trading on NASDAQ. On November 30, 2020, our predecessor common stock began trading on the OTC Pink Marketplace maintained by the OTC Markets Group, Inc. under the symbol “GPORQ". On February 2, 2021, NASDAQ filed a Form 25 delisting our predecessor common stock from trading on NASDAQ, which delisting became effective 10 days after the filing of the Form 25. In accordance with Rule 12d2-2 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), the de-registration of our predecessor common stock under section 12(b) of the Exchange Act became effective on February 12, 2021.
On the Emergence Date, the predecessor common stock noted above was cancelled and we issued shares of new common stock. Shares of our new common stock are listed on the NYSE under the symbol "GPOR". See Note 7 of our consolidated financial statements for further discussion of our new common stock.
Shareholders
At the close of business on February 25, 2022, there were approximately 450 holders of record of our New Common Stock.
Dividends
We never paid dividends on our predecessor common stock. Subsequent to our emergence, we did not pay dividends on our New Common Stock in 2021. The declaration and payment of any future common stock dividend will be at the full discretion of the Board of Directors and will depend on our financial results, cash requirements, future prospects and other
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factors deemed relevant by our Board. Our New Credit Facility also requires us to meet certain financial covenants at the time dividend payments are made.
During the Successor Period, the company paid dividends on its New Preferred Stock, which included 3,071 shares of New Preferred Stock paid in kind, approximately $55 thousand of cash-in-lieu of fractional shares, and $1.5 million of cash dividends to holders of our New Preferred Stock.
Issuer Purchases of Equity Securities
On November 2, 2021, Gulfport announced the authorization by its Board of Directors to repurchase up to $100 million of the Company's outstanding shares of common stock through December 31, 2022. Purchases under the Repurchase Program may be made from time to time in open market or privately negotiated transactions, and will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements, contractual obligations and other factors. The Repurchase Program does not require us to acquire any specific number of shares of New Common Stock. We intend to purchase shares under our Repurchase Program opportunistically with available funds while maintaining sufficient liquidity to fund our capital development program.
The Company did not repurchase any common stock during the year ended December 31 2021.
Recent Sales of Unregistered Securities
None.
Stock Performance Graph
The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission (“SEC”), nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filings.
The performance graph below illustrates changes over the period of May 19, 2021 through December 31, 2021, in cumulative total stockholder return on the Successor common stock as measured against the cumulative total return of the S&P 500 Index and the S&P Oil & Gas Exploration and Production Index. The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends for the index securities) from May 19, 2021 to December 31, 2021.
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ITEM 6.[RESERVED]
ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis represents 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 “Item 8. Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2020 Annual Report on Form 10-K filing and analyzes the changes in the results of operations between the years ended December 31, 2021 and 2020. Discussions of 2019 items and year-to-year comparisons between 2020 and 2019 that are not included 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 for the year ended December 31, 2020.
Our results of operations as reported in our consolidated financial statements for the Successor Period and the Predecessor Period are in accordance with GAAP. Although GAAP requires that we report on our results for these periods separately, management views our operating results for the twelve months ended December 31, 2021, by combining the results of the Successor Period and the Predecessor Period ("Combined Period"). While these combined results do not comply with GAAP and have not been prepared as pro forma results under applicable regulations, they are presented because we believe they provide the most meaningful comparison of our results to prior periods. We do not believe reviewing these periods in isolation would be useful in identifying any trends in or reaching any conclusions regarding our overall operating performance. We believe the key performance indicators such as operating revenues and operating expenses for the Successor Period combined with the Predecessor Period provide more meaningful comparisons to other periods and are useful in understanding operational trends. Additionally, there were no material changes in policies between the periods and any material impacts as a result of fresh start accounting were included within the discussion of these changes.
Overview
Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal properties are located in Eastern Ohio targeting the Utica and in central Oklahoma targeting the SCOOP Woodford and SCOOP Springer formations. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders. To accomplish these goals, we allocate capital to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts.
Recent Developments
Emergence from voluntary reorganization under Chapter 11
On November 13, 2020, we and our subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the Southern District of Texas. The Chapter 11 Cases were administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ). The Bankruptcy Court confirmed the Plan and entered the confirmation order on April 28, 2021, and the Debtors emerged from the Chapter 11 Cases on the Emergence Date. On May 18, 2021, we began trading on the New York Stock Exchange under the symbol "GPOR."
Although we are no longer a debtor-in-possession, we operated as debtors-in-possession through the pendency of the Chapter 11 Cases. See Note 1 and Note 2 of our consolidated financial statements for a complete discussion of the Chapter 11 Cases.
We believe we have emerged from the Chapter 11 Cases as a fundamentally stronger company, built to generate sustainable free cash flow with a strengthened balance sheet. As a result of the Chapter 11 Cases, we reduced our total indebtedness by $1.4 billion by issuing equity in a reorganized entity to the holders of our unsecured notes and allowed general unsecured claimants. In addition, we reassessed our organizational needs post emergence and significantly reduced our general and administrative expense to ensure our cost structure is competitive with industry peers. We continue to focus on reducing our operating costs, per well drilling costs, general and administrative costs and managing our liquidity. We believe our plan to
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generate free cash flow on an annual basis will allow us to further strengthen our balance sheet and return capital to shareholders.
Changes in Chief Executive Officer and Chief Financial Officer
On May 17, 2021, the Board reached agreements with David M. Wood and Quentin R. Hicks that Messrs. Wood and Hicks would no longer serve as Chief Executive Officer and a member of the Board, in the case of Mr. Wood, and Chief Financial Officer, in the case of Mr. Hicks.
On May 17, 2021, the Board appointed Timothy J. Cutt as Interim Chief Executive Officer and Chair of the Board. On September 2, 2021, we reached agreement with Mr. Cutt, effective immediately, to fully assume the role of Chief Executive Officer, dropping the "Interim" designation from his title.
On May 17, 2021, the Board appointed William J. Buese as Chief Financial Officer.
New Credit Facility
On October 14, 2021, we entered into the New Credit Facility for an aggregate maximum principal amount of up to $1.5 billion, an initial borrowing base of $850.0 million and an initial aggregate elected commitment amount of $700.0 million. The New Credit Facility amended and refinanced the Exit Credit Facility. See Note 6 of our consolidated financial statements for additional discussion of the New Credit Facility.
Stock Repurchase Program
On November 1, 2021, our board of directors approved a stock repurchase program to acquire up to $100 million of our outstanding New Common Stock. Purchases under the Repurchase Program may be made from time to time in open market or privately negotiated transactions, and will be subject to available liquidity, market conditions, credit agreement restrictions, applicable legal requirements, contractual obligations and other factors. The Repurchase Program does not require the Company to acquire any specific number of shares of New Common Stock. The Company intends to purchase shares under the Repurchase Program opportunistically with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program is authorized to extend through December 31, 2022, and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time. Any shares of New Common Stock repurchased are expected to be cancelled. We have not repurchased any shares under this program as of December 31, 2021.
COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas
As a result of our business continuity measures, we have not experienced significant disruptions in executing our business operations due to COVID-19. While we did not experience significant disruptions to our operations in 2021, we are unable to predict the impact on our business, including our cash flows, liquidity, and results of operations in future periods due to numerous uncertainties. Restrictions may cause us, our suppliers and other business counterparties to experience operational delays, or delays in the delivery of materials and supplies. We expect the principal areas of operational risk for us are the availability and reliability of service providers and potential supply chain disruption. Additionally, the operations of our midstream service providers, on whom we rely for the transmission, gathering and processing of a significant portion of our produced natural gas, NGL and oil, may be disrupted or suspended in response to containing the outbreak, or the difficult economic environment may lead to the bankruptcy or closing of the facilities and infrastructure of our midstream service providers. This may result in substantial discount in the prices we receive for our produced natural gas, NGL and oil or result in the shut-in of producing wells or the delay or discontinuance of development plans for our properties.
We cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on our business, cash flows, liquidity, financial condition and results of operations at this time, due to numerous uncertainties. The ultimate impacts will depend on future developments and the timing and extent to which normal economic and operating conditions resume.
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2021 Operational and Financial Highlights
During 2021, we had the following notable achievements:
Emerged from Chapter 11 proceedings in May 2021 with improved balance sheet and fixed-cost structure.
In September 2021, we finalized a settlement agreement with TC Energy which rejected the firm transportation contracts between us and TC Energy without any further payment or obligation by us or TC. In exchange, we paid $43.8 million in cash to TC and expect to receive back a significant portion of such amount through future distributions with respect to the assigned claims.
In October 2021, we amended and refinanced our Exit Credit Facility with the New Credit Facility. The amendment increased our elected commitment from $580 million to $700 million and increased our liquidity by more than $160 million.
In December 2021, we reached an agreement with Stingray Pressure Pumping LLC that fully resolved the longstanding litigation between the parties.
Turned to sales 28 gross (26.4 net); including the Angelo pad which flowed at a sustained, gross peak rate of 250 MMcfe per day after it was brought online in early October.
Reported year-end estimated net proved reserves of 3.9 Tcfe.
Business and Industry Outlook
As discussed above, we emerged from voluntary reorganization under Chapter 11 in May 2021. Through our restructuring we were able to emerge with a strengthened balance sheet and materially improved fixed-cost structure. Gulfport is beginning this new chapter with a strategy focused on continuing to reduce costs and generating sustainable free cash flow in an effort to drive shareholder value. In addition, we are committed to an emphasis on sustainability, and we will continue to prioritize safety, environmental stewardship, and maintaining strong relationships with the communities in which we operate. As we enter 2022, we believe we are positioned for sustainable long-term success.
In 2021, natural gas prices improved significantly, but continue to be volatile as spot prices ranged from $2.43 to $23.86 per MMBtu. Henry Hub averaged $3.89 per MMBtu in 2021 vs $2.03 per MMBtu in 2020. As we look into 2022, we expect continued volatility in natural gas prices. To mitigate our exposure to commodity market volatility and ensure our continued financial strength we have entered into financial hedges representing approximately 86% of our expected 2022 production.
Our 2022 capital expenditure program is expected to be in a range of $340 million to $380 million. Prior to 2021, general inflation was moderate; however, our capital and operating costs were influenced to a large extent by the volatility in commodity prices. With the improved commodity price environment, we have experienced and expect to continue to experience inflationary pressures during 2022. We continue to monitor and manage inflationary pressures caused by increased activities in the field as well as supply chain pressures.
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Results of Operations
Comparison of the Predecessor Period, Successor Period and the Year Ended December 31, 2020
We reported net income of $251.0 million for the Predecessor Period and a net loss of $112.8 million for the Successor Period, as compared to a net loss of $1.6 billion for the year ended December 31, 2020. The material changes that lead to the increase in net income are further discussed by category on the following pages. Some totals and changes throughout below section may not sum or recalculate due to rounding.
Natural Gas, Oil and NGL Sales (sales totals in thousands)
SuccessorPredecessorNon-GAAP CombinedPredecessor
Period from May 18, 2021 through December 31, 2021Period from January 1, 2021 through May 17, 2021Year Ended December 31, 2021Year Ended December 31, 2020
Natural gas (MMcf/day)
Utica production volumes732 781 750 795 
SCOOP production volumes183 126 162 147 
Total production volumes915 907 912 943 
Total sales$906,096 $344,390 $1,250,486 $671,535 
Average price without the impact of derivatives ($/Mcf)$4.34 $2.77 $3.76 $1.95 
Impact from settled derivatives ($/Mcf)(1)
$