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 , 2022
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
(Exact Name of Registrant As Specified in Its Charter)
| (State or Other Jurisdiction of Incorporation or Organization) | (IRS Employer Identification Number) | |||||||
| (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 class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||||||
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).
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):
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. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
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, 2022 was approximately $911.7 million. As of February 23, 2023, there were 18,847,841 shares of our $0.0001 par value common stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Gulfport Energy Corporation’s Proxy Statement for the 2023 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K.
GULFPORT ENERGY CORPORATION
TABLE OF CONTENTS
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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: | ||
1145 Indenture. Agreement dated May 17, 2021 between the Company, UMB Bank, National Association, as trustee, and the guarantors party thereto, under section 1145 of the Bankruptcy Code for our 8.000% Senior Notes due 2026. | ||
2019 Plan. 2019 Amended and Restated Stock Incentive Plan. | ||
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. | ||
2026 Senior Notes. 8.000% Senior Notes due 2026. | ||
4(a)(2) Indenture. Certain eligible holders have made an election entitling such holders to receive senior notes issued pursuant to an indenture, dated as of May 17, 2021, by and among the Company, UMB Bank, National Association, as trustee, and the guarantors party thereto, under Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”) as opposed to its share of the up to $550 million aggregate principal amount of our Senior Notes due 2026. The 4(a)(2) Indenture’s terms are substantially similar to the terms of the 1145 Indenture. The primary differences between the terms of the 4(a)(2) Indenture and the terms of the 1145 Indenture are that (i) affiliates of the Issuer holding 4(a)(2) Notes are permitted to vote in determining whether the holders of the required principal amount of indenture securities have concurred in any direction or consent under the 4(a)(2) Indenture, while affiliates of the Issuer holding 1145 Notes will not be permitted to vote on such matters under the 1145 Indenture, (ii) the covenants of the 1145 Indenture (other than the payment covenant) require that the Issuer comply with the covenants of the 4(a)(2) Indenture, as amended, and (iii) the 1145 Indenture requires that the 1145 Securities be redeemed pro rata with the 4(a)(2) Securities and that the 1145 Indenture be satisfied and discharged if the 4(a)(2) Indenture is satisfied and discharged. | ||
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. | ||
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, with one barrel of NGL and crude oil being equivalent to 6,000 cubic feet of natural gas. | ||
Board of Directors (Board). The board of directors of Gulfport Energy Corporation. | ||
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. | ||
Common Stock. $0.0001 par value common stock issued by the Successor on the Emergence Date. | ||
Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas, oil and NGL. | ||
Credit Facility. The Existing Credit Facility, as amended by the Borrowing Base Redetermination Agreement and First Amendment to Credit Agreement dated as of May 2, 2022. | ||
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. | ||
Developed Acreage. The number of acres allocated or assignable to productive wells or wells capable of production. | ||
DIP Credit Facility. Senior secured superpriority debtor-in-possession revolving credit facility in an aggregate principal amount of $262.5 million. | ||
Disputed Claims Reserve. Reserve used to settle any pending claims of unsecured creditors that were in dispute as of the effective date of the Plan. | ||
Dry Hole. A well that does not produce crude oil and/or natural gas in economically producible quantities. | ||
Existing 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. | ||
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 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. | ||
Incentive Plan. Gulfport Energy Corporation 2021 Stock Incentive Plan, effective on the Emergence Date. | ||
Indentures. Collectively, the 1145 Indenture and the 4(a)(2) Indenture governing the 2026 Senior Notes. | ||
IRC. The Internal Revenue Code of 1986, as amended. | ||
LIBOR. London Interbank Offered Rate. | ||
LOE. Lease operating expenses. | ||
Marcellus. Refers to the Marcellus Play that includes the hydrocarbon bearing rock formations commonly referred to as the Marcellus formation located in the Appalachian Basin of the United States and Canada. Our acreage is located primarily in Belmont County in eastern Ohio. | ||
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, with one barrel of NGL and crude oil being equivalent to 6,000 cubic feet of natural gas. | ||
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, with one barrel of NGL and crude oil being equivalent to 6,000 cubic feet of natural gas. | ||
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. | ||
NYMEX. New York Mercantile Exchange. | ||
OCC. Oklahoma Corporation Commission. | ||
Parent. Gulfport Energy Corporation or its successor to the Credit Facility. | ||
Petition Date. November 13, 2020. | ||
Plan. The Amended Joint Chapter 11 Plan of Reorganization of Gulfport Energy Corporation and Its Debtor Subsidiaries. | ||
Predecessor. The pre-emergence from bankruptcy organization for periods on or prior to May 17, 2021. | ||
Predecessor Senior Notes. Collectively, the 2023 Notes, 2024 Notes, 2025 Notes and 2026 Notes. | ||
Preferred Stock. $0.0001 par value preferred stock issued by the Successor on the Emergence Date. | ||
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. | ||
Prior Predecessor Period. Period from January 1, 2021 through May 17, 2021. | ||
Prior Successor Period. Period from May 18, 2021 through December 31, 2021. | ||
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 (PDP). 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 (PUD). 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 $300 million of Gulfport's outstanding Common Stock. It is authorized to extend through June 30, 2023, 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. | ||
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. | ||
SOFR. Secured Overnight Financing Rate. | ||
Standardized Measure. Standardized measure of discounted future net cash flows. | ||
Successor. The post-emergence from bankruptcy reorganized organization for periods subsequent to May 17, 2021. | ||
Tcfe. One trillion cubic feet of natural gas equivalent, with one barrel of NGL and crude oil being equivalent to 6,000 cubic feet of natural gas. | ||
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. | ||
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. | ||
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 the expected impact of the novel coronavirus disease (COVID-19) pandemic and the war in Ukraine 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 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.
•All of our producing properties are located in eastern Ohio and central 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.
•The COVID-19 pandemic has negatively affected, and may in the future negatively affect, our operations, financial performance and condition, operating results and cash flows.
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•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.
Environmental, 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.
•Increased attention to Environmental, Social and Governance ("ESG") matters may impact our business, financial results, or stock price.
•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 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 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, 2022, we had 4.0 Tcfe of proved reserves with a Standardized Measure of $8.3 billion and a PV-10 of $9.5 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".
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 a manner that generates sustainable cash flow, improves margins and operating efficiencies, while improving our ESG and safety performance. 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. We believe our plan to generate free cash flow on an annual basis will allow us to further strengthen our balance sheet, return capital to shareholders and increase our resource depth through incremental leasehold opportunities that provide optionality to our future development plans.
2023 Outlook
Our 2023 capital expenditure program is expected to be in a range of $425 million to $475 million. In the Utica, we intend to spud 15 to 17 gross (13 to 15 net) operated horizontal wells, complete drilling on 15 to 17 gross (13 to 15 net) operated horizontal wells and commence sales on 18 to 20 gross (16 to 18 net) horizontal wells. In the Marcellus, we intend to spud, complete drilling and commence sales on two gross (1.9 net) operated horizontal wells. In the SCOOP, we intend to spud, complete drilling and commence sales on two gross (1.6 net) operated horizontal wells. We expect to fund these expenditures with our operating cash flow and borrowings under our Credit Facility.
We expect this drilling program to result in approximately 1,000 to 1,040 MMcfe per day of production in 2023.
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Additionally, in 2023, we expect continuation of shareholder return actions through our common share repurchase program. During 2022, we repurchased 2.9 million shares for $250.8 million, leaving $49.2 million remaining on our Repurchase Program.
Operating Areas
Utica - The Utica covers hydrocarbon-bearing rock formations located in the Appalachian Basin of the United States and Canada. We have approximately 188,000 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 2022, we produced approximately 693 MMcfe per day net to our interests in this area and it accounts for approximately 70% of our total production.
The Marcellus covers hydrocarbon bearing rock formations that overlay the Utica. We have identified 15,000 net reservoir acres in Belmont County in eastern Ohio for Marcellus development and in 2022 we added 8 PUD Marcellus locations within our Utica operating area. Our Marcellus development area is 3,500 to 4,500 feet shallower than the Utica.
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 73,000 net reservoir acres (comprised of approximately 41,000 in the Woodford formation and approximately 32,000 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 2022, we produced approximately 290 MMcfe per day net to our interests in this area and it accounts for approximately 30% of our total production.
Oil, Natural Gas and NGL Reserves
Reserve engineering is a subjective process of estimating volumes of economically recoverable oil, natural gas and NGL 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, 2022, with respect to our estimated proved developed and undeveloped oil, natural gas and NGL 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, 2022 | |||||||||||||||||||||||
| Oil (MMBbl) | Natural Gas (Bcf) | NGL (MMBbl) | Total (Bcfe) | ||||||||||||||||||||
| Utica | |||||||||||||||||||||||
| Proved developed | 2 | 1,523 | 9 | 1,591 | |||||||||||||||||||
Proved undeveloped(1) | 7 | 1,256 | 6 | 1,335 | |||||||||||||||||||
| Total proved | 9 | 2,779 | 15 | 2,926 | |||||||||||||||||||
| SCOOP | |||||||||||||||||||||||
| Proved developed | 7 | 511 | 25 | 704 | |||||||||||||||||||
| Proved undeveloped | 2 | 322 | 14 | 417 | |||||||||||||||||||
| Total proved | 9 | 833 | 39 | 1,121 | |||||||||||||||||||
| Total | |||||||||||||||||||||||
| Proved developed | 9 | 2,034 | 34 | 2,295 | |||||||||||||||||||
| Proved undeveloped | 9 | 1,578 | 20 | 1,752 | |||||||||||||||||||
| Total proved | 18 | 3,612 | 54 | 4,048 | |||||||||||||||||||
| Totals may not sum or recalculate due to rounding. | |||||||||||||||||||||||
(1) Includes approximately 72 Bcfe of net reserves located in the Marcellus target formation.
| December 31, 2022 | |||||||||||||||||
| Proved Developed | Proved Undeveloped | Total Proved | |||||||||||||||
| ($ in millions) | |||||||||||||||||
Estimated future net revenue(1) | $ | 10,712 | $ | 7,951 | $ | 18,663 | |||||||||||
Present value of estimated future net revenue (PV-10)(1) | $ | 5,803 | $ | 3,721 | $ | 9,524 | |||||||||||
Standardized measure(1) | $ | 8,279 | |||||||||||||||
| 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, 2022, 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, 2022. The prices used in our PV-10 measure were $94.14 per barrel and $6.36 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, 2022. 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 $1.2 billion as of December 31, 2022.
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 developed and undeveloped 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. Reliable technologies were used to support the undeveloped locations in the Utica and SCOOP operating areas. The Company used public and proprietary geologic and engineering data to establish continuity of the formation and its producing properties. This data included performance data, seismic data, open hole log information, petro-physical analysis of log data, mud logs, log cross-sections, gas sample analysis, statistical analysis and measurements of total organic content and thermal maturity. In our development area, these data demonstrated consistent and continuous reservoir characteristics. 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 2022 (in Bcfe):
| Proved Reserves, December 31, 2021 (Successor) | 3,898 | ||||
| Sales of oil and natural gas reserves in place | — | ||||
| Extensions and discoveries | 439 | ||||
| Revisions of prior reserve estimates | 70 | ||||
| Current production | (359) | ||||
| Proved Reserves, December 31, 2022 (Successor) | 4,048 | ||||
| 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 proved reserves during a period. During 2022, 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 438.9 Bcfe of proved reserves were primarily attributable to the continued development of our Utica and SCOOP acreage. We added 44 PUD locations in the Utica which included 36 PUD locations in our Utica acreage for 295.9 Bcfe and 8 PUD locations in our Marcellus acreage for 72.1 Bcfe. In our SCOOP acreage we added 5 PUD locations for 65.4 Bcfe. New to 2022 was the addition of the 8 Marcellus PUD locations, which we have grouped into the Utica for this report. 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 69.7 Bcfe in estimated proved reserves, of which 47.7 Bcfe was the result of commodity price changes. Commodity prices experienced volatility throughout 2022 and the 12-month average price for natural gas increased from $3.60 per MMBtu for 2021 to $6.36 per MMBtu for 2022, the 12-month average price for NGL increased from $31.90 per barrel for 2021 to $47.86 per barrel for 2022, and the 12-month average price for crude oil increased from $66.55 per barrel for 2021 to $94.14 per barrel for 2022.
Upward revisions of 144.5 Bcfe were a result of an increase in working interest and net revenue interest as a result of our successful leasing efforts through 2022. Downward revisions of 95.6 Bcfe were experienced as a result of the exclusion of 4 PUD locations in the Utica and 5 PUD locations in the SCOOP when changes in our schedule moved the development of these PUD locations beyond five years of initial booking. The development plan change reflects our commitment to optimizing the long-term development schedule to maximize cash flow and overall economic returns. Finally, a small downward revision of 26.9 Bcfe was primarily a result of performance changes to several wells or PUD location forecasts.
Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2022, 2021 and 2020, and changes in proved reserves during the last three years are contained in the
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Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information, in Note 20 of our consolidated financial statements.
Proved Undeveloped Reserves
As of December 31, 2022, our PUDs totaled 1,578 Bcf of natural gas, 9 MMBbl of oil and 20 MMBbl of NGL, for a total of 1,752 Bcfe. Approximately 76% and 24% of our PUDs at year-end 2022 were located in Utica and SCOOP, respectively. Our PUDs will be converted from undeveloped to developed as the applicable wells commence production or when there are no material incremental completion capital expenditures associated with such proved developed reserves.
We record PUD drilling locations 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 drilling 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 2022 (in Bcfe):
| Proved Undeveloped Reserves, December 31, 2021 (Successor) | 1,733 | ||||
| Sales of oil and natural gas reserves in place | — | ||||
| Extensions and discoveries | 433 | ||||
| Conversion to proved developed reserves | (474) | ||||
| Revisions of prior reserve estimates | 60 | ||||
| Proved Undeveloped Reserves, December 31, 2022 (Successor) | 1,752 | ||||
| Total may not sum due to rounding. | |||||
Extensions and discoveries. Our extensions of approximately 433.4 Bcfe were primarily attributed to the addition of 49 PUD drilling locations as a result of our current five-year development plan that is focused on generating sustainable cash flow. These additions included 36 PUD drilling locations in our Utica acreage, 8 PUD drilling locations in our Marcellus acreage and 5 PUD drilling locations in the SCOOP. The Marcellus PUD drilling locations have been grouped into the Utica for this report.
Conversion to proved developed reserves. Our 2022 development activities resulted in the conversion of approximately 474.2 Bcfe into proved developed producing reserves, attributable to 15 PUD locations in the Utica and 31 PUD locations in the SCOOP. These 46 PUDs represent a conversion rate of 33% for 2022.
Revision of prior reserve estimates. We experienced total upward revisions of 59.7 Bcfe in estimated proved undeveloped reserves. This included 92.3 Bcfe of downward revisions as a result of the exclusion of 4 PUD locations in the Utica and 5 PUD locations in the SCOOP 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 152.0 Bcfe in estimated proved reserves from a combination of changes including working interest and net revenue interest, well development design and well forecasts.
Costs incurred relating to the development of PUDs were approximately $271.6 million in 2022.
All PUD drilling locations included in our 2022 reserve report are scheduled to be drilled within five years of initial booking.
As of December 31, 2022, 0.60% of our total proved reserves were classified as proved developed non-producing.
Reserves Estimation
Reserve estimates for the years ended December 31, 2022, 2021 and 2020, were prepared by Netherland, Sewell & Associates, Inc. ("NSAI") for all of our operating areas.
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
8
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 25 years of reservoir and operations experience. In addition, our geoscience staff has approximately 46 years combined industry experience and our reservoir staff has approximately 55 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 proved reserves at December 31, 2022, were calculated using prices based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for 2022 of $94.14 per barrel and $6.36 per MMBtu. Holding production and development costs constant, if SEC pricing were $103.55 per barrel and $6.99 per MMBtu, or a 10% increase, this would have resulted in an increase of 4.2 Bcfe of our total proved reserves and a $1.4 billion increase in PV-10 value at December 31, 2022. Holding production and development costs constant, if SEC pricing were $84.73 per barrel and $5.72 per MMBtu, or a 10% decrease, this would have resulted in a decrease of 6.1 Bcfe of our total proved reserves and a $1.4 billion decrease in PV-10 value at December 31, 2022. For each of these scenarios, the 133 PUDs that were economic at SEC pricing were included.
9
Acreage
The following table presents our total gross and net developed and undeveloped acres as of December 31, 2022:
| Developed Acreage | Undeveloped Acreage | ||||||||||||||||||||||
| Field | Gross | Net | Gross | Net | |||||||||||||||||||
| Utica | 135,817 | 109,797 | 83,166 | 78,185 | |||||||||||||||||||
| SCOOP | 50,041 | 35,783 | 7,975 | 5,718 | |||||||||||||||||||
| Other | — | — | 232 | 232 | |||||||||||||||||||
| Total | 185,858 | 145,580 | 91,373 | 84,135 | |||||||||||||||||||
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, 2022:
| Undeveloped Acres | |||||||||||
| Gross Acres | Net Acres | ||||||||||
| Years Ending December 31, | |||||||||||
| 2023 | 12,292 | 11,418 | |||||||||
| 2024 | 3,522 | 3,323 | |||||||||
| 2025 | 4,296 | 4,283 | |||||||||
| After 2025 | 5,782 | 5,660 | |||||||||
| Held by production | 65,248 | 59,219 | |||||||||
Total(1) | 91,140 | 83,903 | |||||||||
(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, 2022:
| NRI/WI | Productive Oil Wells | Productive Gas Wells | Total Wells | ||||||||||||||||||||||||||||||||||||||
| Field | Percentages | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||||||
| Utica | 48.78/60.19 | 146 | 41.9 | 526 | 362.5 | 672 | 404.4 | ||||||||||||||||||||||||||||||||||
| SCOOP | 20.71/27.76 | 106 | 16.1 | 556 | 167.7 | 662 | 183.8 | ||||||||||||||||||||||||||||||||||
Total(1) | 309 | 58.0 | 1,189 | 530.2 | 1,498 | 588.2 | |||||||||||||||||||||||||||||||||||
(1) We also have override/royalty interests in 164 wells with an average NRI of 0.6%, 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, | |||||||||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||
| Development: | |||||||||||||||||||||||||||||||||||
| Productive | 25 | 21.7 | 29 | 26.6 | 26 | 24.4 | |||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Total | 25 | 21.7 | 29 | 26.6 | 26 | 24.4 | |||||||||||||||||||||||||||||
| Exploratory: | |||||||||||||||||||||||||||||||||||
| Productive | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Dry | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Total | — | — | — | — | — | — | |||||||||||||||||||||||||||||
The following table presents activity by operating area for the year ended December 31, 2022:
| Operated | Non-Operated | ||||||||||||||||||||||||||||||||||||||||||||||
| Field | Drilled | Turned to Sales | Drilled | Turned to Sales | |||||||||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||||||||||||
Utica(1) | 19 | 17.4 | 15 | 13.4 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
SCOOP(2) | 6 | 4.3 | 13 | 10.3 | 13 | 0.1 | 40 | 2.7 | |||||||||||||||||||||||||||||||||||||||
| Total | 25 | 21.7 | 28 | 23.7 | 13 | 0.1 | 40 | 2.7 | |||||||||||||||||||||||||||||||||||||||
(1) Of the 19 gross wells drilled in 2022, five were completed as producing wells, eight were in various stages of drilling and six were waiting on completion as of December 31, 2022.
(2) All six gross wells that were drilled in 2022 had turned to sales as of December 31, 2022.
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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):
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Period from May 18, 2021 through December 31, 2021 | Period from January 1, 2021 through May 17, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| Natural gas sales | ||||||||||||||||||||||||||
| Natural gas production volumes (MMcf) | 322,366 | 208,641 | 124,279 | 344,999 | ||||||||||||||||||||||
| Natural gas production volumes (MMcf/d) | 883 | 915 | 907 | 943 | ||||||||||||||||||||||
| Total sales | $ | 1,998,452 | $ | 906,096 | $ | 344,390 | $ | 671,535 | ||||||||||||||||||
| Average price without the impact of derivatives ($/Mcf) | $ | 6.20 | $ | 4.34 | $ | 2.77 | $ | 1.95 | ||||||||||||||||||
Impact from settled derivatives ($/Mcf)(1) | $ | (3.11) | $ | (1.44) | $ | (0.03) | $ | 0.33 | ||||||||||||||||||
| Average price, including settled derivatives ($/Mcf) | $ | 3.09 | $ | 2.90 | $ | 2.74 | $ | 2.28 | ||||||||||||||||||
| Oil and condensate sales | ||||||||||||||||||||||||||
| Oil and condensate production volumes (MBbl) | 1,610 | 1,167 | 531 | 1,803 | ||||||||||||||||||||||
| Oil and condensate production volumes (MBbl/d) | 4 | 5 | 4 | 5 | ||||||||||||||||||||||
| Total sales | $ | 147,444 | $ | 81,347 | $ | 29,106 | $ | 62,902 | ||||||||||||||||||
| Average price without the impact of derivatives ($/Bbl) | $ | 91.58 | $ | 69.71 | $ | 54.81 | $ | 34.88 | ||||||||||||||||||
Impact from settled derivatives ($/Bbl)(2) | $ | (24.32) | $ | (8.33) | $ | — | $ | 25.76 | ||||||||||||||||||
| Average price, including settled derivatives ($/Bbl) | $ | 67.26 | $ | 61.38 | $ | 54.81 | $ | 60.64 | ||||||||||||||||||
| NGL sales | ||||||||||||||||||||||||||
| NGL production volumes (MBbl) | 4,483 | 2,658 | 1,211 | 3,964 | ||||||||||||||||||||||
| NGL production volumes (MBbl/d) | 12 | 12 | 9 | 11 | ||||||||||||||||||||||
| Total sales | $ | 184,963 | $ | 105,141 | $ | 36,780 | $ | 66,814 | ||||||||||||||||||
| Average price without the impact of derivatives ($/Bbl) | $ | 41.26 | $ | 39.56 | $ | 30.37 | $ | 16.86 | ||||||||||||||||||
| Impact from settled derivatives ($/Bbl) | $ | (2.80) | $ | (4.88) | $ | — | $ | (0.04) | ||||||||||||||||||
| Average price, including settled derivatives ($/Bbl) | $ | 38.46 | $ | 34.68 | $ | 30.37 | $ | 16.82 | ||||||||||||||||||
| Natural gas, oil and condensate and NGL sales | ||||||||||||||||||||||||||
| Natural gas equivalents (MMcfe) | 358,924 | 231,594 | 134,735 | 379,600 | ||||||||||||||||||||||
| Natural gas equivalents (MMcfe/d) | 983 | 1,016 | 983 | 1,037 | ||||||||||||||||||||||
| Total sales | $ | 2,330,859 | $ | 1,092,584 | $ | 410,276 | $ | 801,251 | ||||||||||||||||||
| Average price without the impact of derivatives ($/Mcfe) | $ | 6.49 | $ | 4.72 | $ | 3.05 | $ | 2.11 | ||||||||||||||||||
| Impact from settled derivatives ($/Mcfe) | $ | (2.94) | $ | (1.39) | $ | (0.02) | $ | 0.42 | ||||||||||||||||||
| Average price, including settled derivatives ($/Mcfe) | $ | 3.55 | $ | 3.33 | $ | 3.03 | $ | 2.53 | ||||||||||||||||||
| Production Costs: | ||||||||||||||||||||||||||
| Average lease operating expenses ($/Mcfe) | $ | 0.18 | $ | 0.14 | $ | 0.14 | $ | 0.14 | ||||||||||||||||||
| Average taxes other than income ($/Mcfe) | $ | 0.17 | $ | 0.13 | $ | 0.09 | $ | 0.08 | ||||||||||||||||||
| Average transportation, gathering, processing and compression ($/Mcfe) | $ | 1.00 | $ | 0.92 | $ | 1.20 | $ | 1.20 | ||||||||||||||||||
| Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) | $ | 1.34 | $ | 1.19 | $ | 1.43 | $ | 1.42 | ||||||||||||||||||
| Totals may not sum or recalculate due to rounding. | ||||||||||||||||||||||||||
_____________________
(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 $40.5 million.
12
The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2022:
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2022 | Period from May 18, 2021 through December 31, 2021 | Period from January 1, 2021 through May 17, 2021 | Year Ended December 31, 2020 | |||||||||||||||||||||||
| Utica | ||||||||||||||||||||||||||
| Net Production | ||||||||||||||||||||||||||
| Natural gas (MMcf) | 246,123 | 166,906 | 106,968 | 291,133 | ||||||||||||||||||||||
| Oil (MBbl) | 244 | 220 | 183 | 393 | ||||||||||||||||||||||
| NGL (MBbl) | 885 | 562 | 361 | 1,077 | ||||||||||||||||||||||
| Total (MMcfe) | 252,895 | 171,598 | 110,235 | 299,955 | ||||||||||||||||||||||
| Average price without the impact of derivatives: | ||||||||||||||||||||||||||
| Natural gas ($/Mcf) | $ | 6.14 | $ | 4.33 | $ | 2.64 | $ | 1.97 | ||||||||||||||||||
| Oil ($/Bbl) | $ | 90.60 | $ | 66.94 | $ | 52.43 | $ | 33.41 | ||||||||||||||||||
| NGL ($/Bbl) | $ | 48.21 | $ | 47.16 | $ | 37.21 | $ | 18.55 | ||||||||||||||||||
| Production Costs: | ||||||||||||||||||||||||||
| Average lease operating expenses ($/Mcfe) | $ | 0.17 | $ | 0.13 | $ | 0.13 | $ | 0.13 | ||||||||||||||||||
| Average taxes other than income ($/Mcfe) | $ | 0.06 | $ | 0.07 | $ | 0.06 | $ | 0.07 | ||||||||||||||||||
| Average transportation, gathering, processing and compression ($/Mcfe) | $ | 1.08 | $ | 0.98 | $ | 1.26 | $ | 1.29 | ||||||||||||||||||
| Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) | $ | 1.31 | $ | 1.18 | $ | 1.45 | $ | 1.49 | ||||||||||||||||||
| SCOOP | ||||||||||||||||||||||||||
| Net Production | ||||||||||||||||||||||||||
| Natural gas (MMcf) | 76,242 | 41,724 | 17,302 | 53,853 | ||||||||||||||||||||||
| Oil (MBbl) | 1,366 | 933 | 344 | 1,392 | ||||||||||||||||||||||
| NGL (MBbl) | 3,598 | 2,095 | 849 | 2,886 | ||||||||||||||||||||||
| Total (MMcfe) | 106,024 | 59,893 | 24,461 | 79,519 | ||||||||||||||||||||||
| Average price without the impact of derivatives: | ||||||||||||||||||||||||||
| Natural gas ($/Mcf) | $ | 6.38 | $ | 4.40 | $ | 3.59 | $ | 1.83 | ||||||||||||||||||
| Oil ($/Bbl) | $ | 91.71 | $ | 70.37 | $ | 56.05 | $ | 35.31 | ||||||||||||||||||
| NGL ($/Bbl) | $ | 39.56 | $ | 37.51 | $ | 27.46 | $ | 16.23 | ||||||||||||||||||
| Production Costs: | ||||||||||||||||||||||||||
| Average lease operating expenses ($/Mcfe) | $ | 0.20 | $ | 0.17 | $ | 0.22 | $ | 0.18 | ||||||||||||||||||
| Average taxes other than income ($/Mcfe) | $ | 0.38 | $ | 0.29 | $ | 0.20 | $ | 0.10 | ||||||||||||||||||
| Average transportation, gathering, processing and compression ($/Mcfe) | $ | 0.78 | $ | 0.74 | $ | 0.90 | $ | 0.86 | ||||||||||||||||||
| Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) | $ | 1.36 | $ | 1.20 | $ | 1.32 | $ | 1.14 | ||||||||||||||||||
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, 2022, 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, 2022. We elected to cease funding capital calls in 2019, and we have no obligation to fund any future projects Grizzly may consider pursuing. Failure to fund capital calls will 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 the 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 year ended December 31, 2022, Prior Successor Period, Prior Predecessor Period and year ended December 31, 2020 were as follows:
| % of Sales | ||||||||
| Year Ended December 31, 2022 (Successor) | ||||||||
| ECO-Energy | 20 | % | ||||||
| Clearwater | 11 | % | ||||||
| Period from May 18, 2021 through December 31, 2021 (Successor) | ||||||||
| ECO-Energy | 20 | % | ||||||
| Macquarie | 10 | % | ||||||
| Period from January 1, 2021 through May 17, 2021 (Predecessor) | ||||||||
| ECO-Energy | 14 | % | ||||||
| Macquarie | 12 | % | ||||||
| Citadel | 11 | % | ||||||
| Year Ended December 31, 2020 (Predecessor) | ||||||||
| ECO-Energy | 12 | % | ||||||
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, service providers, employees and contractors 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, as well as third-party midstream and downstream pipeline 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 at the time we are preparing to develop the undeveloped leases and 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 additional regulations or changes to existing regulations, which could have a material adverse effect on our business. In
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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, safety and health protection and 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.
We maintain a control of well insurance policy with a $25 million single well limit and up to a $37.5 million limit on multi-well pads. This policy 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
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comprehensive general liability umbrella insurance program. 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, as well as auto liability for our company vehicles. 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 2022 and 2021 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.
Enterprise Risk Management
Through our Enterprise Risk Management (ERM) program, internal risk committees comprised of senior management and subject matter experts across the Company review and assess the Company’s risks. Our Board of Directors plays a key role in risk management, providing oversight of the Company’s management team, strategic initiatives, and operations. The Board committees oversee corporate governance, risk management, regulatory compliance and ESG matters.
Cybersecurity remains a top identified enterprise-wide risk for our business and is overseen by our Chief Information Officer who is responsible for identifying and mitigating information security risks. The Audit Committee receives a detailed cybersecurity update annually from the Chief Information Officer and receives a cybersecurity update quarterly through the ERM program as a key risk. The Company provides an information security training program to all employees and regularly conducts external audits of its cybersecurity program. There have not been any material information security incidents over the last three years.
Human Capital Management
Employees
As of December 31, 2022, we had 223 employees, an increase of approximately 5% from the 212 employees at December 31, 2021. The increase in 2022 was driven by hiring across our business throughout the year. All of our employees are non-bargaining.
The attraction and retention of qualified employees continues to be one of our highest priorities. We focus on making substantive improvements to key areas that impact our employees. During 2022, we continued making significant investments in our hiring and retention processes, including increasing funds allocated to our annual merit process and increasing our 401(k) match for all employees. We remain committed to providing development opportunities to existing employees as an additional retention tool, as their continued commitment to the Company is critical to our success.
We continue to respond quickly to situations that might be conducive to the spread of COVID-19 or other airborne pathogens. In 2022, our focus on healthy working conditions helped protect the safety of employees, minimize the risk of disease transmission at Gulfport locations and keep our operations online with minimal disruption.
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Inclusion & Diversity
During 2022, we continued to build on our previously-announced diversity and inclusiveness initiatives, including by training all managers and supervisors to identify and eliminate bias in the workplace. We also partnered with a third-party recruiting website and utilized other tools to expand our reach to diverse candidates, which represented almost 33% of our new hires in 2022, an increase of approximately 10% over 2021. We are also pleased by growing numbers of diverse employees in key managerial, supervisory, and professional positions throughout the Company.
There were no changes to the composition of our Board of Directors in 2022 and it remains a group of highly qualified directors, 40% of whom are diverse candidates. We remain committed to evaluating our hiring and promotion practices to ensure that diversity and inclusion are considered and included throughout the Company.
Over the course of 2022, Gulfport continued to develop and revise Company policies, including those intended to implement our Business Code of Conduct and Ethics, which provides a framework for how we interact with our employees, vendors and other stakeholders when conducting our operations. To that end, we provided all of our employees with annual or refresher trainings focused on the guidelines, rules, and principles that must be followed when acting on the Company's behalf. We remain committed to maintaining the highest standards of business ethics.
Health, Safety & Environment
Safety is at the forefront of everything we do. We have a robust annual training program, including 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 highlighting 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 annually.
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. An environmental training on the elements of WORK GREEN was created and delivered to all employees.
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 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
John Reinhart, President and Chief Executive Officer
On January 18, 2023, the Board of Directors appointed Mr. Reinhart, 54, as President and Chief Executive Officer, effective as of January 24, 2023. Mr. Reinhart joins the Company with over two decades of oil and gas industry leadership experience. Most recently, he served as President, Chief Executive Officer and member of the board of directors of Montage Resources Corporation where he led actions that positioned Montage as an attractive strategic partner with sufficient scale, low debt profile and achievement of top-quartile operational and financial metrics. Mr. Reinhart previously served as President, Chief Executive Officer and member of the board of directors of Blue Ridge Mountain Resources and as Chief Operating
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Officer at Ascent Resources. He started his oil and gas career at Schlumberger before joining Chesapeake Energy Corporation, where he held operations roles with increasing responsibility. Mr. Reinhart began his career in the United States Army, serving tours in Panama and Iraq. Mr. Reinhart graduated from West Virginia University with a Bachelor of Science degree in Mechanical Engineering.
Timothy J. Cutt, Executive Chairman of the Board
On January 24, 2023, Mr. Cutt resigned as Chief Executive Officer of the Company and was appointed as Executive Chairman of the Company. Mr. Cutt, 62, 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, 51, 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, 50, 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 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, 50, 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. Prior to joining Noble in 2007, he spent over 20 years developing his skills and expertise in unconventional resource development, reservoir engineering, subsurface development, business development/M&A, and leadership at 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.
Lester Zitkus, Senior Vice President of Land
Mr. Zitkus has served as Senior Vice President of Land since January 2017 and joined the Company as Vice President of Land in March 2014. Prior to joining the Company, Mr. Zitkus served as an independent consultant from October 2013 to March 2014 and as Vice President of Land for Chesapeake Energy Corporation from May 2007 to October 2013. During his 20-year tenure with Equitable Resources Inc. (now EQT Corp.), he held various positions, including Vice President of Operations and Senior Vice President of Land, between 1987 and 2007. He holds a degree in Mineral Land Management from
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the University of Evansville. Mr. Zitkus is a member of the American Association of Professional Landmen and Past Regional Director of the Independent Petroleum Association of America.
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 natural gas, oil, 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 2021, West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or 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. During 2022, WTI prices ranged from $71.05 to $123.64 per barrel and the Henry Hub spot market price of natural gas ranged from $3.46 to $9.85 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
•domestic and global economic conditions.
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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 2023 cash flows, we have substantial exposure to natural gas prices, and to a lesser extent, oil and NGL prices, in 2024 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 Credit Facility, which is structured under floating rate terms. As such, our interest expense is sensitive to fluctuations in the SOFR benchmark. At December 31, 2022, amounts borrowed under our Credit Facility bore interest at the weighted average rate of 7.39%. A 1% increase in the average interest rate would increase our interest expense by approximately $1.5 million based on outstanding borrowings under our Credit Facility at December 31, 2022. An increase in our interest rate at the time we have variable interest rate borrowings outstanding under our 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, 2022, we did not hedge our interest rate risk.
Our debt and other financial commitments may limit our financial and operating flexibility.
Our total principal debt was approximately $695.0 million at December 31, 2022. We also had various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services, products and 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
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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 5 of our consolidated financial statements for more information regarding the financial covenants and our Credit Facility.
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. 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. 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 through a variety of means. We cannot guarantee 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. In addition, we may be unable to implement our development plan, complete acquisitions, 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.
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 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 NGL to one MCF of natural gas at the ratio of six Mcf of natural gas to one barrel of oil.
Under the full cost method of accounting for oil and gas properties, we 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. 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, 2022, we had a net operating loss, or NOL, carryforward of approximately $1.6 billion for federal
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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, 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 may have greater access to the capital and credit markets. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. As a result, these competitors may be able to address these competitive factors more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.
Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively may be diminished. We also compete for the equipment required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of drilling rigs and other oilfield equipment and services, which could adversely affect our ability to execute our development plans on a timely basis and within budget.
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, 2022, approximately 43% 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. 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
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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, 2022 present value is based on a $6.36 per MMBtu of gas price and a $94.14 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. In addition, the 10% discount factor that is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes is not necessarily the most appropriate discount factor. Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor.
Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
We acquire significant amounts of unproven properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells.
Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling and completion operations may be curtailed, delayed or 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
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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 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 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.
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 84% of our Utica acreage is held by existing production, the remaining acreage is subject to expiration. Of the remaining 16% of our Utica acreage not held by production, 37% will be subject to expiration in 2023, 10% in 2024, 14% in 2025 and 39% 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, 6% will be subject to expiration in 2023, 91% in 2024, 3% in 2025 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.
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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 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;
•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:
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•the timing and amount of capital expenditures;
•the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
•the operator's expertise and financial resources;
•approval of other participants in drilling wells;
•selection of technology; and
•the rate of production of the reserves.
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.
All of our producing properties are located in eastern Ohio and central Oklahoma, making us vulnerable to risks associated with operating in only these regions.
Our largest fields by production are located in eastern Ohio and central 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 year ended December 31, 2022 accounted for approximately 20% 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
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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, trucks and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be limited or denied. In certain resource plays, the capacity of gathering and transportation systems is insufficient to accommodate potential production from existing and new wells. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations.
With respect to our Utica acreage where we are focusing a portion of our exploration and development activity, operations may be 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. As a result, we may experience delays or curtailments in producing and selling our natural gas, oil and NGL. In such event, we might have to shut in or curtail 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, 2022, our aggregate long-term contractual obligation under these agreements was approximately $1.6 billion. These fees could be significant and may have a material adverse effect on our results of operations.
The COVID-19 pandemic has affected, and may in the future materially adversely affect, our operations, financial performance and condition, operating results and cash flows.
We are subject to public health crises such as the COVID-19 pandemic, which has previously significantly impacted, and may in the future impact, our business and results of operations. For example, the COVID-19 pandemic resulted in authorities implementing numerous preventative measures to contain or mitigate the outbreak of the virus, such as travel bans and restrictions, limitations on business activity, quarantines and shelter-in-place orders, which have previously caused, and may in the future cause, business slowdowns or shutdowns in certain affected countries and regions. These developments led to volatility in the demand for and pricing of natural gas, oil and NGL at various points throughout the pandemic, and we may experience similar effects in the future. In addition to potentially negative impacts on our sales and revenue, the pandemic exposes our business, operations, and workforce to a variety of other risks, including:
•volatility and disruption of global financial markets, which could negatively impact our ability to access capital in the future;
•illnesses to key employees or a significant portion of our workforce, which may result in inefficiencies, delays or disruptions that could lower our production volumes;
•disruptions to the third-party midstream services that we rely on for the transmission, gathering and processing of a significant portion of our produced natural gas, oil and NGL; and
•potentially heightened exposure to 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.
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The rapid development and fluidity of COVID-19 pandemic 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. Any of these developments may in the future negatively 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.
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.
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 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.
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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.
Environmental, 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 conditions are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. For example, on December 6, 2022, the United States Environmental Protection Agency (USEPA), proposed a new methane rule which established guidelines for existing sources of methane emissions from existing facilities. Constrained supply chain for environmental control devices along with the significant estimated costs of compliance could have a material impact on our operations. Further, the Bureau for Land Management (BLM) issued a proposed Waste Minimization Rule on November 30, 2022. The rule adds additional requirements for operators on federal and Indian leases and includes new air quality requirements along with waste prevention provisions. 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
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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 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 incentivizing 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 Inflation Reduction Act, which Congress passed and President Biden signed into law in August 2022, both imposes new climate related requirements on oil and gas operations and appropriates significant federal funding for renewable energy initiatives. Also, for the first time ever, the law imposes a fee on greenhouse gas (GHG) emissions from certain facilities. The emissions fee and funding provisions of the Inflation Reduction Act could increase our operating costs and accelerate the transition away from fossil fuels, which could in turn adversely affect our business, results of operations and financial position.
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.
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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. Potential adverse effects could include damages to our facilities, the costs of less efficient or non-routine operating practices necessitated by weather events, or increased costs for insurance coverage. 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 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
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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.
Increased attention to ESG matters may impact our business, financial results, or stock price.
In recent years, increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, activist investors, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change, advocating for changes to companies’ boards of directors, and promoting the use of energy saving building materials. These activities may result in reduced demand for our oil, natural gas and NGL, reduced profits, increased investigations and litigation, each of which could have negative impacts on our access to capital markets.
In addition, we note that standards and expectations regarding carbon accounting and the processes for measuring and counting GHG emissions and GHG emission reductions are evolving, and it is possible that our approach to measuring both our emissions and our approaches to reducing emissions may be, either currently by some stakeholders or at some future point, considered inconsistent with common or best practices. A failure to comply with investor or customer expectations and standards, which are evolving, or if we are perceived to not have responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, could cause reputational harm to our business, increase our risk of litigation, and could have a material adverse effect on our results of operations.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG matters. These ratings are used by some investors to inform their investment and voting decisions. We may take certain actions to improve the ESG profile of our company and/or products, but we cannot guarantee that such actions will have the desired effect. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.
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, as amended by the California Privacy Rights Act (CPRA), establishes certain transparency rules and create new data privacy rights for users, including limitations on our use of certain sensitive personal information and more ability for users to control the purposes for which their data is shared with third parties. The CPRA also provides for statutory fines for data security breaches or other CPRA violations. Meanwhile, many other states have considered privacy laws like the CPRA. 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
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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 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 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 Common Stock. The market price of our Common Stock could be subject to wide fluctuations in response to, and the level of trading that develops with our 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 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 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 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 Common Stock.
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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 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.
| ITEM 4. | MINE SAFETY DISCLOSURES | ||||
Not applicable.
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PART II
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES | ||||
Common Stock
Shares of our Common Stock are listed on the NYSE under the symbol "GPOR". See Note 7 of our consolidated financial statements for further discussion of our Common Stock.
Shareholders
At the close of business on February 21, 2023, there were approximately 823 holders of record of our Common Stock.
Dividends
Subsequent to our emergence from bankruptcy, we did not pay dividends on our Common Stock in 2021 and 2022. 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 factors deemed relevant by our Board. Our Credit Facility also requires us to meet certain financial covenants at the time dividend payments are made.
During the Prior Successor Period, the Company paid dividends on our Preferred Stock, which included 3,071 shares of 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 Preferred Stock. During the year ended December 31, 2022, the Company paid $5.4 million of cash dividends to holders of our Preferred Stock.
Issuer Purchases of Equity Securities
In November 2021, the Company's Board of Directors approved the Repurchase Program to acquire up to $100 million of Common Stock and subsequently increased the authorization from $100 million to $200 million in April 2022 and then from $200 million to $300 million in July 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 the Company to acquire any specific number of shares of Common Stock. The Company intends to purchase shares under the Repurchase Program with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program is authorized to extend through June 30, 2023, and may be suspended from time to time, or modified, extended or discontinued by the Board of Directors at any time. As of December 31, 2022, the Company had repurchased 2.9 million shares for $250.8 million at a weighted average price of $86.47 per share.
The following table provides a summary of our Common Stock repurchase activity for the three months ended December 31, 2022:
| Period | Total Number of Shares Purchased(1) | Average Price Paid per Share | Total number of shares purchased as part of publicly announced plans or programs | Approximate maximum dollar value of shares that may yet be purchased under the plans or programs | ||||||||||||||||||||||
| October 1 - October 31 | 64,355 | $ | 90.53 | 64,266 | $ | 66,603,000 | ||||||||||||||||||||
| November 1 - November 30 | 78,370 | $ | 84.09 | 78,161 | $ | 60,013,000 | ||||||||||||||||||||
| December 1 - December 31 | 150,510 | $ | 71.63 | 150,510 | $ | 49,231,000 | ||||||||||||||||||||
| Total | 293,235 | $ | 79.11 | 292,937 | ||||||||||||||||||||||
(1) We repurchased and canceled 89 and 209 shares of our Common Stock at a weighted average price of $87.71 and $85.83 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards during October and November 2022, respectively.
Recent Sales of Unregistered Securities
None.
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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, 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, 2022, 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, 2022.
| 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 2021 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 2022 to the period from May 18, 2021 through December 31, 2021 ("Prior Successor Period") and the period from January 1, 2021 through May 17, 2021 ("Prior Predecessor Period"). Discussions of 2020 items and year-to-year comparisons between 2021 and 2020 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, 2021.
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.
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Recent Developments
Credit Facility
On May 2, 2022, the Company entered into the Borrowing Base Redetermination Agreement and First Amendment to the Credit Agreement (the "Amendment"), which amended the Company's Existing Credit Facility (as amended, the "Credit Facility"). The Amendment, among other things, increased the borrowing base under the Credit Facility from $850 million to $1.0 billion, with the elected commitments remaining at $700 million. On October 31, 2022, the Company completed its semi-annual borrowing base redetermination, during which the borrowing base was reconfirmed at $1.0 billion, with the elected commitments remaining at $700 million. See Note 5 of our consolidated financial statements for additional discussion of the Credit Facility.
Stock Repurchase Program
In November 2021 the Company's Board of Directors approved the Repurchase Program to acquire up to $100 million of Common Stock and subsequently increased the authorization from $100 million to $200 million in April 2022 and then from $200 million to $300 million in July 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 the Company to acquire any specific number of shares of Common Stock. The Company intends to purchase shares under the Repurchase Program with available funds while maintaining sufficient liquidity to fund its capital development program. The Repurchase Program is authorized to extend through June 30, 2023, and may be suspended from time to time, or modified, extended or discontinued by the Board of Directors at any time. As of December 31, 2022, the Company repurchased 2.9 million shares for $250.8 million at a weighted average price of $86.47 per share.
Inflation, Rising Interest Rates and Changes in Commodity Prices
The annual rate of inflation in the United States was measured at 6.5% in December 2022 by the Consumer Price Index, representing a significant increase to the historical inflation observed in recent years. Inflation and increased commodity prices have caused drilling and completion costs to increase from the prior year. In addition, the Federal Reserve has tightened monetary policy by approving a series of increases to the Federal Funds Rate. Furthermore, the Chairman of the Federal Reserve signaled that the Federal Reserve would continue to take necessary action to bring inflation down and to ensure price stability, including continued rate increases. The inflationary environment has impacted interest rates on our Credit Facility borrowings throughout 2022. Interest rates on our Credit Facility borrowings have increased from 3.19% at December 31, 2021, to 7.39% at December 31, 2022. Additional increases in interest rates may have a negative impact on the Company’s ability to continue to execute its business strategy.
Our revenues, the value of our assets, and our ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in natural gas, oil and NGL prices and the costs to produce our reserves. Natural gas, oil and NGL prices are subject to significant fluctuations that are beyond our ability to control or predict. Certain of our capital expenditures and expenses are affected by general inflation and we expect costs for 2023 to continue to be a function of supply and demand; however, we do not expect inflation to significantly impact cash flow in 2023.
Impact of the War in Ukraine
The invasion of Ukraine by Russia and the sanctions imposed in response to the crisis have increased volatility in the global financial markets and are expected to have further global economic consequences, including disruptions of global energy markets and the amplification of inflation and supply chain constraints. The ultimate impact of the war in Ukraine will depend on future developments and the timing and extent to which normal economic and operating conditions resume.
2022 Operational and Financial Highlights
During 2022, we had the following notable achievements:
•Reported total net production of 983.4 MMcfe per day.
•Generated $739.1 million of operating cash flows.
•Turned to sales 28 gross (23.6 net) wells; including the Extreme pad in the Utica, which was brought online at a combined gross peak production rate of approximately 140 MMcfe per day.
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•Returned $250.8 million to shareholders through the repurchase of 2.9 million shares at a weighted average price of $86.47 per share.
•Increased the borrowing base under the Credit Facility from $850 million to $1.0 billion.
•Reduced total debt by $19 million.
•Reported year-end estimated net proved reserves of 4.0 Tcfe.
Business and Industry Outlook
The Company's primary focus going into 2023 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately support our expected free cash flow generation. 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. Throughout the year, we plan to maintain capital discipline, prioritizing free cash flow generation and preserving our strong financial position, while returning capital to shareholders and increasing our resource depth through incremental leasehold opportunities.
In 2022, natural gas prices improved significantly, but continue to be volatile as spot prices ranged from $3.46 to $9.85 per MMBtu. Henry Hub averaged $6.44 per MMBtu in 2022 vs $3.89 per MMBtu in 2021. As we look into 2023, we expect continued volatility in natural gas prices. To mitigate our exposure to commodity market volatility and to help provide a level of certainty around our financial strength, we have entered into a combination of natural gas swaps and collars, representing approximately 58% of our expected 2023 production, at an average floor price of $3.58 per Mcf.
Our 2023 capital expenditure program is expected to be in a range of $425 million to $475 million. Prior to 2022, general inflation was moderate; however, during 2022 our capital and operating costs were negatively impacted by the volatility in commodity prices, a significant rise in inflation and a lack of long-term contracts entering the year. With the recent weakening in commodity prices, we could begin to see deflationary pressures during 2023 as well as less frequent supply chain constraints. We will continue to monitor and manage inflationary and supply chain pressures caused by increased activities in the field and any future increases in commodity prices.
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Results of Operations
Comparison of the Year Ended December 31, 2022, Prior Successor Period and Prior Predecessor Period
We reported net income of $494.7 million for the year ended December 31, 2022, compared to a net loss of $112.8 million for the Prior Successor Period and a net income of $251.0 million for the Prior Predecessor Period. 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 the below section may not sum or recalculate due to rounding.
Natural Gas, Oil and Condensate and NGL Sales (sales totals in thousands)
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2022 | Period from May 18, 2021 through December 31, 2021 | Period from January 1, 2021 through May 17, 2021 | ||||||||||||||||||
| Natural gas (MMcf/day) | ||||||||||||||||||||
| Utica production volumes | 674 | 732 | 781 | |||||||||||||||||
| SCOOP production volumes | 209 | 183 | 126 | |||||||||||||||||
| Total production volumes | 883 | 915 | 907 | |||||||||||||||||
| Total sales | $ | 1,998,452 | $ | 906,096 | $ | 344,390 | ||||||||||||||
| Average price without the impact of derivatives ($/Mcf) | $ | 6.20 | $ | 4.34 | $ | 2.77 | ||||||||||||||
| Impact from settled derivatives ($/Mcf) | $ | (3.11) | $ | (1.44) | $ | (0.03) | ||||||||||||||
| Average price, including settled derivatives ($/Mcf) | $ | 3.09 | $ | 2.90 | $ | 2.74 | ||||||||||||||
| Oil and condensate (MBbl/day) | ||||||||||||||||||||
| Utica production volumes | 1 | 1 | 1 | |||||||||||||||||
| SCOOP production volumes | 4 | 4 | 3 | |||||||||||||||||
| Total production volumes | 4 | 5 | 4 | |||||||||||||||||
| Total sales | $ | 147,444 | $ | 81,347 | $ | 29,106 | ||||||||||||||
| Average price without the impact of derivatives ($/Bbl) | $ | 91.58 | $ | 69.71 | $ | 54.81 | ||||||||||||||
| Impact from settled derivatives ($/Bbl) | $ | (24.32) | $ | (8.33) | $ | — | ||||||||||||||
| Average price, including settled derivatives ($/Bbl) | $ | 67.26 | $ | 61.38 | $ | 54.81 | ||||||||||||||
| NGL (MBbl/day) | ||||||||||||||||||||
| Utica production volumes | 2 | 2 | 3 | |||||||||||||||||
| SCOOP production volumes | 10 | 9 | 6 | |||||||||||||||||
| Total production volumes | 12 | 11 | 9 | |||||||||||||||||
| Total sales | $ | 184,963 | $ | 105,141 | $ | 36,780 | ||||||||||||||
| Average price without the impact of derivatives ($/Bbl) | $ | 41.26 | $ | 39.56 | $ | 30.37 | ||||||||||||||
| Impact from settled derivatives ($/Bbl) | $ | (2.80) | $ | (4.88) | $ | — | ||||||||||||||
| Average price, including settled derivatives ($/Bbl) | $ | 38.46 | $ | 34.68 | $ | 30.37 | ||||||||||||||
| Total (MMcfe/day) | ||||||||||||||||||||
| Utica production volumes | 693 | 753 | 805 | |||||||||||||||||
| SCOOP production volumes | 290 | 263 | 179 | |||||||||||||||||
| Total production volumes | 983 | 1,016 | 983 | |||||||||||||||||
| Total sales | $ | 2,330,859 | ||||||||||||||||||