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What changed in GULFPORT ENERGY CORP's 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of GULFPORT ENERGY CORP's 2022 and 2023 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2023 report.

+322 added−342 removedSource: 10-K (2024-02-28) vs 10-K (2023-03-01)

Top changes in GULFPORT ENERGY CORP's 2023 10-K

322 paragraphs added · 342 removed · 254 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

84 edited+19 added−28 removed65 unchanged
Biggest change(2) All six gross wells that were drilled in 2022 had turned to sales as of December 31, 2022. 11 Table of Contents Index to Financial Statements 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.
Biggest change(2) The two gross wells that were drilled in 2023 were completed as producing wells as of December 31, 2023. 11 Table of Contents Inde x to Financial Statements 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, 2023 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 sales Natural gas production volumes (MMcf) 350,306 322,366 208,641 124,279 Natural gas production volumes (MMcf) per day 960 883 915 907 Total sales $ 831,812 $ 1,998,452 $ 906,096 $ 344,390 Average price without the impact of derivatives ($/Mcf) $ 2.37 $ 6.20 $ 4.34 $ 2.77 Impact from settled derivatives ($/Mcf) $ 0.42 $ (3.11) $ (1.44) $ (0.03) Average price, including settled derivatives ($/Mcf) $ 2.79 $ 3.09 $ 2.90 $ 2.74 Oil and condensate sales Oil and condensate production volumes (MBbl) 1,363 1,610 1,167 531 Oil and condensate production volumes (MBbl) per day 4 4 5 4 Total sales $ 99,854 $ 147,444 $ 81,347 $ 29,106 Average price without the impact of derivatives ($/Bbl) $ 73.27 $ 91.58 $ 69.71 $ 54.81 Impact from settled derivatives ($/Bbl) $ (2.53) $ (24.32) $ (8.33) $ — Average price, including settled derivatives ($/Bbl) $ 70.74 $ 67.26 $ 61.38 $ 54.81 NGL sales NGL production volumes (MBbl) 4,386 4,483 2,658 1,211 NGL production volumes (MBbl) per day 12 12 12 9 Total sales $ 119,717 $ 184,963 $ 105,141 $ 36,780 Average price without the impact of derivatives ($/Bbl) $ 27.29 $ 41.26 $ 39.56 $ 30.37 Impact from settled derivatives ($/Bbl) $ 2.07 $ (2.80) $ (4.88) $ — Average price, including settled derivatives ($/Bbl) $ 29.36 $ 38.46 $ 34.68 $ 30.37 Natural gas, oil and condensate and NGL sales Natural gas equivalents (MMcfe) 384,802 358,924 231,594 134,735 Natural gas equivalents (MMcfe) per day 1,054 983 1,016 983 Total sales $ 1,051,383 $ 2,330,859 $ 1,092,584 $ 410,276 Average price without the impact of derivatives ($/Mcfe) $ 2.73 $ 6.49 $ 4.72 $ 3.05 Impact from settled derivatives ($/Mcfe) $ 0.40 $ (2.94) $ (1.39) $ (0.02) Average price, including settled derivatives ($/Mcfe) $ 3.13 $ 3.55 $ 3.33 $ 3.03 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.18 $ 0.18 $ 0.14 $ 0.14 Average taxes other than income ($/Mcfe) $ 0.09 $ 0.17 $ 0.13 $ 0.09 Average transportation, gathering, processing and compression ($/Mcfe) $ 0.91 $ 1.00 $ 0.92 $ 1.20 Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.17 $ 1.34 $ 1.19 $ 1.43 Totals may not sum or recalculate due to rounding. 12 Table of Contents Inde x to Financial Statements The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2023: Successor Predecessor Year Ended December 31, 2023 Year Ended December 31, 2022 Period from May 18, 2021 through December 31, 2021 Period from January 1, 2021 through May 17, 2021 Utica & Marcellus Net Production Natural gas (MMcf) 279,428 246,123 166,906 106,968 Oil (MBbl) 255 244 220 183 NGL (MBbl) 856 885 562 361 Total (MMcfe) 286,095 252,895 171,598 110,235 Average price without the impact of derivatives: Natural gas ($/Mcf) $ 2.34 $ 6.14 $ 4.33 $ 2.64 Oil ($/Bbl) $ 70.18 $ 90.60 $ 66.94 $ 52.43 NGL ($/Bbl) $ 33.63 $ 48.21 $ 47.16 $ 37.21 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.16 $ 0.17 $ 0.13 $ 0.13 Average taxes other than income ($/Mcfe) 0.05 0.06 0.07 0.06 Average transportation, gathering, processing and compression ($/Mcfe) 0.97 1.08 0.98 1.26 Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.18 $ 1.31 $ 1.18 $ 1.45 SCOOP Net Production Natural gas (MMcf) 70,878 76,242 41,724 17,302 Oil (MBbl) 1,108 1,366 933 344 NGL (MBbl) 3,530 3,598 2,095 849 Total (MMcfe) 98,707 106,024 59,893 24,461 Average price without the impact of derivatives: Natural gas ($/Mcf) $ 2.53 $ 6.38 $ 4.40 $ 3.59 Oil ($/Bbl) $ 73.98 $ 91.71 $ 70.37 $ 56.05 NGL ($/Bbl) $ 25.76 $ 39.56 $ 37.51 $ 27.46 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.25 $ 0.20 $ 0.17 $ 0.22 Average taxes other than income ($/Mcfe) 0.17 0.38 0.29 0.20 Average transportation, gathering, processing and compression ($/Mcfe) 0.73 0.78 0.74 0.90 Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.15 $ 1.36 $ 1.20 $ 1.32 Our Investments Grizzly Oil Sands .
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.
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, 58, 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.
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.
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/Marcellus and SCOOP operating areas.
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.
Reliable technologies were used to support the undeveloped locations in the Utica/Marcellus and SCOOP operating areas. The Company used public and proprietary geologic and engineering data to establish continuity of the formation and its producing properties.
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.
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, 2023. 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.
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.
To that end, we provided all of our employees with annual 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.
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. 14 Table of Contents Index to Financial Statements 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.
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. 14 Table of Contents Inde x to Financial Statements 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.
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, 51, 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.
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.
Over the course of 2023, 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.
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. 6 Table of Contents Index to Financial Statements 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.
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. 6 Table of Contents Inde x to Financial Statements 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.
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.
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 years ended December 31, 2023, December 31, 2022, Prior Successor Period, and Prior Predecessor Period were as follows: % of Sales Year Ended December 31, 2023 (Successor) Vitol Inc. 12 % 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 % Competition The oil and natural gas industry is intensely competitive, and we compete with many other companies that have greater resources than we have.
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, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.5% interest in Grizzly. As of December 31, 2023, 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 2015. Additionally, Grizzly had no proved reserves as of December 31, 2023.
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.
All PUD drilling locations included in our 2023 reserve report are scheduled to be drilled within five years of initial booking. As of December 31, 2023, 0.34% of our total proved reserves were classified as proved developed non-producing. Reserves Estimation Reserve estimates for the years ended December 31, 2023, 2022 and 2021, were prepared by Netherland, Sewell & Associates, Inc.
Totals may not sum due to rounding. 10 Table of Contents Index to Financial Statements Drilling Activity The following table sets forth information with respect to operated wells drilled during the periods indicated.
Totals may not sum due to rounding. 10 Table of Contents Inde x to Financial Statements Drilling Activity The following table sets forth information with respect to operated wells drilled during the periods indicated.
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 has over 25 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.
“ Risk Factors ” contained elsewhere in this Form 10-K. 5 Table of Contents Index to Financial Statements 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.
“ Risk Factors ” contained elsewhere in this Form 10-K. 5 Table of Contents Inde x to Financial Statements The tables below set forth information as of December 31, 2023, 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.
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.
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. 2024 Outlook Our 2024 capital expenditure program is expected to be in a range of $380 million to $420 million.
Our aggregate payments for the retainer and clean-up services during each of 2022 and 2021 were immaterial.
Our aggregate payments for the retainer and clean-up services during each of 2023 and 2022 were immaterial.
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.
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 2023, we produced approximately 270 MMcfe per day net to our interests in this area and it accounts for approximately 26% of our total production.
The technical persons responsible for preparing our proved reserve estimates meet the 8 Table of Contents Index to Financial Statements 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.
The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Reinhart previously served as President, Chief Executive Officer and member of the board of directors of Blue Ridge Mountain Resources and as Chief Operating 18 Table of Contents Index to Financial Statements 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 previously served as President, Chief Executive Officer and member of the board of directors of Blue Ridge Mountain Resources and as Chief Operating 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.
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.
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 995.7 Bcfe of proved reserves were primarily attributable to the continued development of our Utica/Marcellus and SCOOP acreage.
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.
We have approximately 193,000 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 2023, we produced approximately 784 MMcfe per day net to our interests in this area and it accounts for approximately 74% of our total production.
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.
He is a petroleum engineer with over 27 years of reservoir and operations experience. In addition, our geoscience staff has approximately 48 years combined industry experience and our reservoir staff has approximately 58 years combined experience. Internal Controls Over Proved Reserve Estimates Our proved reserve estimates are prepared in accordance with our internal control procedures.
("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.
("NSAI") for all of our operating areas. 8 Table of Contents Inde x to Financial Statements 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.
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.
These downward revisions were offset by upward revisions of 192.0 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 $362.9 million in 2023.
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.
If future developments result in 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.
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.
The following table summarizes the changes in our estimated proved undeveloped reserves during 2023 (in Bcfe): Proved Undeveloped Reserves, December 31, 2022 (Successor) 1,752 Sales of oil and natural gas reserves in place — Extensions and discoveries 988 Conversion to proved developed reserves (420) Revisions of prior reserve estimates (310) Proved Undeveloped Reserves, December 31, 2023 (Successor) 2,011 Total may not sum due to rounding.
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.
The following table summarizes the changes in our estimated proved reserves during 2023 (in Bcfe): Proved Reserves, December 31, 2022 (Successor) 4,048 Sales of oil and natural gas reserves in place — Extensions and discoveries 996 Revisions of prior reserve estimates (445) Current production (385) Proved Reserves, December 31, 2023 (Successor) 4,214 Total may not sum due to rounding.
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.
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 $26 million as of December 31, 2023.
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.
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 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.
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. 13 Table of Contents Inde x to Financial Statements Mammoth Energy.
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.
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.
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.
Revisions represent changes in previous reserve estimates, either upward or downward, resulting from development plan changes, new information normally obtained from development drilling and production history or a change in economic factors, such as commodity prices, operating costs or development costs. We experienced total downward revisions of 444.9 Bcfe in estimated proved reserves.
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.
PV-10 Sensitivities As noted above, our proved reserves at December 31, 2023, were calculated using prices based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for 2023 of $78.21 per barrel and $2.64 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 $86.03 per barrel and $2.90 per MMBtu, or a 10% increase, this would have resulted in an increase of 53 Bcfe of our total proved reserves and a $0.6 billion increase in PV-10 value at December 31, 2023.
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.
We also own additional spill kits with oil booms and absorbent pads that are readily available, if needed. In 16 Table of Contents Inde x to Financial Statements addition, we have emergency response companies on retainer.
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.
Year Ended December 31, 2023 2022 2021 Gross Net Gross Net Gross Net Development: Productive 24 21.9 25 21.7 29 26.6 Dry — — — — — — Total 24 21.9 25 21.7 29 26.6 Exploratory: Productive — — — — — — Dry — — — — — — Total — — — — — — The following table presents activity by operating area for the year ended December 31, 2023: Operated Non-Operated Field Drilled Turned to Sales Drilled Turned to Sales Gross Net Gross Net Gross Net Gross Net Utica & Marcellus (1) 22.0 20.2 22.0 20.2 10.0 0.3 7.0 0.1 SCOOP (2) 2.0 1.7 2.0 1.7 19.0 0.0 11.0 0.0 Total 24.0 21.9 24.0 21.9 29.0 0.3 18.0 0.1 _____________________ (1) Of the 22 gross wells drilled in 2023, 16 were completed as producing wells and six were in various stages of drilling and completion as of December 31, 2023.
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.
We cannot predict with any reasonable degree of certainty our future exposure concerning such 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.
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.
Our Marcellus development area is approximately 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.
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.
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 expect this drilling program to result in approximately 1,000 to 1,040 MMcfe per day of production in 2023. 4 Table of Contents Index to Financial Statements Additionally, in 2023, we expect continuation of shareholder return actions through our common share repurchase program.
We expect this drilling program to result in approximately 1,045 to 1,080 MMcfe per day of production in 2024. 4 Table of Contents Inde x to Financial Statements Additionally, in 2024, we expect continuation of shareholder return actions through our Repurchase Program.
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.
Holding production and development costs constant, if SEC pricing were $70.39 per barrel and $2.37 per MMBtu, or a 10% decrease, this would have resulted in a decrease of 313 Bcfe of our total proved reserves and a $0.6 billion decrease in PV-10 value at December 31, 2023.
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.
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.
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.
Our 2023 development activities resulted in the conversion of approximately 419.7 Bcfe into proved developed producing reserves, attributable to 20 PUD locations in the Utica, 2 PUD locations in our Marcellus acreage and 3 PUD locations in the SCOOP. These 25 PUDs represent a conversion rate of 19% for 2023. Revision of prior reserve estimates.
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.
Reinhart, 55, as President and Chief Executive Officer, effective as of January 24, 2023. Mr. Reinhart joined the Company with over two decades of oil and gas industry leadership experience.
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.
Commodity prices experienced volatility throughout 2023 and the 12-month average price for natural gas decreased from $6.36 per MMBtu for 2022 to $2.64 per MMBtu for 2023, the 12-month average price for NGL decreased from $47.86 per barrel for 2022 to $31.42 per barrel for 2023, and the 12-month average price for crude oil decreased from $94.14 per barrel for 2022 to $78.21 per barrel for 2023.
December 31, 2022 Proved Developed Proved Undeveloped Total Proved ($ 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.
December 31, 2023 Proved Developed Proved Undeveloped Total Proved ($ in millions) Estimated future net revenue (1) $ 2,535 $ 2,235 $ 4,769 Present value of estimated future net revenue (PV-10) (1) $ 1,590 $ 819 $ 2,409 Standardized measure (1) $ 2,383 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, 2023, and assuming commodity prices as set forth below.
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 7 Table of Contents Index to Financial Statements Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information , in Note 20 of our consolidated financial statements.
Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2023, 2022 and 2021, and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information , in Note 20 of our consolidated financial statements. 7 Table of Contents Inde x to Financial Statements Proved Undeveloped Reserves As of December 31, 2023, our PUDs totaled 1,746 Bcf of natural gas, 12 MMBbl of oil and 32 MMBbl of NGL, for a total of 2,011 Bcfe.
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.
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 minimum limit of $25 million for single well limits and $37.5 million limit for multi-well pads.
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.
Mr. 18 Table of Contents Inde x to Financial Statements 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. Matthew Rucker, Senior Vice President of Operations Mr.
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.
Approximately 79% and 21% of our PUD reserves at year-end 2023 were located in Utica/Marcellus 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 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.
Additionally, we continued the WORK GREEN program, 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.
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.
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 targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations.
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.
During 2023, we repurchased 1.5 million shares for $148.9 million at a weighted average price of $101.53 per share, leaving $250.4 million remaining on our Repurchase Program. Operating Areas Utica/Marcellus - The Utica covers hydrocarbon-bearing rock formations located in the Appalachian Basin of the United States and Canada.
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.
Extensions and discoveries. Our extensions of approximately 988.2 Bcfe were primarily attributed to the addition of 93 PUD drilling locations as a result of our current five-year development plan that is focused on generating sustainable cash flow. These additions included 79 PUD drilling locations in the Utica/Marcellus and 14 PUD drilling locations in the SCOOP. Conversion to proved developed reserves.
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.
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. Michael Hodges, Executive Vice President and Chief Financial Officer On April 3, 2023, the Board of Directors appointed Mr. Hodges, 45, as Executive Vice President and Chief Financial Officer.
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 Utica, we intend to complete drilling on approximately 17 gross (16.4 net) operated horizontal wells and commence sales on approximately 16 gross (15.5 net) operated horizontal wells. In the SCOOP, we intend to complete drilling on approximately five gross (4.1 net) operated horizontal wells and commence sales on three gross (2.4 net) operated horizontal wells.
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.
He serves on the Marietta College Industry Advisory Council and is a member of the Society of Petroleum Engineers. Michael Sluiter, Senior Vice President of Reservoir Engineering Mr. Sluiter, 51, 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.
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.
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, 2023.
He holds a degree in Mineral Land Management from 19 Table of Contents Index to Financial Statements 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.
He holds a degree in Mineral Land Management from 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.
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.
These consisted of upward revisions of 24.9 Bcfe as a result of positive well performance and 293.9 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts through 2023.
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.
While our Board remains a group of highly qualified directors, our gender or ethnically diverse population among our Board has increased by 20% from 2022. We also remain committed to evaluating our hiring and promotion practices to ensure that diversity, equity and inclusion are considered and included throughout the Company.
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.
We experienced total downward revisions of 309.8 Bcfe in estimated proved undeveloped reserves. This included 501.8 Bcfe of downward revisions with changes in our development schedule. The schedule changes moved the development of 36 Utica/Marcellus PUD locations and 8 SCOOP PUD locations beyond the SEC requirement of developing PUDs five years from initial booking.
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.
See the Risk Factors described in Item 1A. of this report for further discussion of 15 Table of Contents Inde x to Financial Statements governmental regulation and ongoing regulatory changes, including with respect to environmental matters. The SEC has also indicated plans to propose various other disclosure regulations, including regarding human capital and other ESG matters.
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.
We partnered with third-party recruiting websites and utilized other tools to expand our reach to diverse candidates, which represented almost 39% of our new hires in 2023, an increase of approximately 6% over 2022.
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.
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".
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.
The Marcellus covers hydrocarbon bearing rock formations that overlay the Utica. We have identified approximately 17,000 net reservoir acres of our existing leasehold for Marcellus development and have 15 PUD Marcellus locations within our Utica operating area. In 2023 we drilled, completed, and turned to sales two Marcellus wells.
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.
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.
This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $51 million 16 Table of Contents Index to Financial Statements comprehensive general liability umbrella insurance program.
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 comprehensive general liability umbrella insurance program.
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 focus on making substantive improvements to key areas that impact our employees. During 2023, we continued making significant investments in our talent management and retention processes, including increasing funds allocated to annual salary increases, short-term incentive payments, long-term incentive equity awards, and 401(k) matches for eligible employees.
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. 20 Table of Contents Index to Financial Statements
The executive officers serve at the pleasure of the Company's Board of Directors. 19 Table of Contents Inde x to Financial Statements
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 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.
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).
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). 17 Table of Contents Inde x to Financial Statements As part of our focus on continuous improvement, we monitor and communicate key environmental and safety metrics both internally and externally.
For each of these scenarios, the 133 PUDs that were economic at SEC pricing were included. 9 Table of Contents Index to Financial Statements 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.
For the low price scenario 132 PUDs were PV-10 economic. 9 Table of Contents Inde x to Financial Statements Acreage The following table presents our total gross and net developed and undeveloped acres as of December 31, 2023: Developed Acreage Undeveloped Acreage Field Gross Net Gross Net Utica & Marcellus 148,747 121,387 75,547 72,058 SCOOP 49,909 35,844 8,537 6,035 Total 198,656 157,231 84,084 78,093 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.
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.
These were offset by downward revisions of 554.9 Bcfe which were primarily a result of development schedule changes with some PUD well design changes. The schedule changes moved the development of 36 Utica/Marcellus PUD locations and 8 SCOOP PUD locations beyond the SEC requirement of developing these wells five years from initial booking.
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, 2023 Oil (MMBbl) Natural Gas (Bcf) NGL (MMBbl) Total (Bcfe) Utica & Marcellus Proved developed (1) 2 1,520 7 1,576 Proved undeveloped (1) 10 1,421 17 1,585 Total proved (1) 13 2,941 24 3,160 SCOOP Proved developed 4 459 24 627 Proved undeveloped 2 325 15 426 Total proved 6 785 39 1,053 Total Proved developed 6 1,980 31 2,203 Proved undeveloped 12 1,746 32 2,011 Total proved 19 3,725 63 4,214 Totals may not sum or recalculate due to rounding. _____________________ (1) Includes approximately 17 Bcfe and 108 Bcfe of net developed and undeveloped reserves, respectively, located in the Marcellus target formation.
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.
The following table sets forth the potential expiration periods of gross and net undeveloped leasehold acres as of December 31, 2023: Undeveloped Acres Years Ending December 31, Gross Acres Net Acres 2024 3,029 2,704 2025 5,070 5,061 2026 4,507 4,430 After 2026 12,054 11,984 Held by production 59,424 53,914 Total 84,084 78,093 Productive Wells The following table presents our total gross and net productive wells, expressed separately for oil and gas, as of December 31, 2023: NRI/WI Productive Oil Wells Productive Gas Wells Total Wells Field Percentages Gross Net Gross Net Gross Net Utica & Marcellus 49.16/60.23 3 1.4 708 426.8 711 428.2 SCOOP 21.58/26.69 101 9.6 540 161.5 641 171.1 Total (1) 117 11.0 1,416 588.3 1,533 599.3 _____________________ (1) We also have override/royalty interests in 181 wells with an average NRI of 0.6%, which are not material to our operations.
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.
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, 2023, we had 4.2 Tcfe of proved reserves with a Standardized Measure of $2.4 billion and a PV-10 of $2.4 billion.
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.
We continue to provide professional and workplace-related 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.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeThese 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.
Biggest changeThese 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. 34 Table of Contents Inde x to Financial Statements 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.
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.
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 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.
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.
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/Marcellus 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.
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.
With respect to our Utica/Marcellus 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.
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.
Even with natural gas, oil and NGL derivatives currently in place to mitigate price risks associated with a portion of our 2024 cash flows, we have substantial exposure to natural gas prices, and to a lesser extent, oil and NGL prices, in 2024 and beyond.
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.
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/Marcellus we drill multiple wells from a single pad.
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.
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, which may be exacerbated by climate change; • 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.
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.
In our Utica/Marcellus 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.
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.
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, use, share, 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.
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.
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, 2023, we did not hedge our interest rate risk.
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.
Policy makers at both the 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.
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.
Further, the Bureau for Land Management (BLM) issued a proposed Methane Waste Prevention 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.
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. 21 Table of Contents Index to Financial Statements 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.
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 and exports; • 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; • weather conditions; • acts of terrorism; and • domestic and global economic conditions. 20 Table of Contents Inde x to Financial Statements 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.
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.
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, 2023, our aggregate long-term contractual obligation under these agreements was approximately $1.4 billion.
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.
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, which may be exacerbated by climate change, could have an adverse effect on our operations and could increase our costs.
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.
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 approximately 86% of our Utica/Marcellus acreage is held by existing production, the remaining acreage is subject to expiration.
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 debt and other financial commitments may limit our financial and operating flexibility. Our total principal debt was approximately $668.0 million at December 31, 2023. We also had various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services, products and properties.
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: 27 Table of Contents Index to Financial Statements • 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.
The success and timing of development and exploration activities on properties operated by others will depend upon a number of factors that will be largely outside of our control, including: • the timing and amount of capital expenditures; • the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel; • the operator's expertise and financial resources; • approval of other participants in drilling wells; • selection of technology; and • the rate of production of the reserves.
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 22 Table of Contents Index to Financial Statements compliance with the financial covenants in our debt instruments in the future.
If commodity prices decline and we reduce our level of capital spending and production declines or we incur additional impairment expense or the value of our proved reserves declines, we may not be able to incur additional indebtedness, may need to repay outstanding indebtedness and may not be in compliance 21 Table of Contents Inde x to Financial Statements with the financial covenants in our debt instruments in the future.
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.
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. 35 Table of Contents Inde x to Financial Statements ITEM 1B.
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.
For example, the California Consumer Privacy Act (CCPA), as amended by the California Privacy Rights Act (CPRA), establishes certain transparency rules and creates new data privacy rights for individuals, including limitations on our use of certain sensitive personal information and more ability for individuals to control the purposes for which their data is shared with third parties.
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 33 Table of Contents Index to Financial Statements opportunities with other operators have been exhausted.
While our objective is to recycle or share 100% of all produced water, we do inject water into third-party commercially operated disposal wells in line with all state and federal mandated practices and cease produced water recycle whenever fracture stimulation operations are idle once sharing opportunities with other operators have been exhausted.
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 34 Table of Contents Index to Financial Statements 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.
We will continue to monitor and assess the impact of these state laws, which may impose substantial penalties for violations, impose significant costs for investigations and compliance, require us to change our business practices, allow private class-action litigation and carry significant potential liability for our business should we fail to comply with any such applicable laws.
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.
The CPRA also provides for statutory fines for data security breaches or other CPRA violations. Meanwhile, many other states enacted, and others have considered, privacy laws like the CPRA.
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 31 Table of Contents Index to Financial Statements set new minimum federal safety standards for onshore gas gathering lines.
Further, legislation funding PHMSA through 2023 requires the agency to engage in additional rulemaking to amend the integrity management program, emergency response plan, operation and maintenance manual, and pressure control recordkeeping requirements for gas distribution operators; to create new leak detection and repair program obligations; and to set new minimum federal safety standards for onshore gas gathering lines.
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. 30 Table of Contents Index to Financial Statements We may engage in acquisition and divestiture activities that involve substantial risks.
In addition, new laws and regulations governing data privacy, cybersecurity, and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability. We may engage in acquisition and divestiture activities that involve substantial risks.
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. 26 Table of Contents Index to Financial Statements Oil and natural gas operations are uncertain and involve substantial costs and risks.
If we are unable to fund renewals of expiring leases, we could lose portions of our acreage and our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. Oil and natural gas operations are uncertain and involve substantial costs and risks.
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 28 Table of Contents Index to Financial Statements delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
Shortages of and increased costs for drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.
Drilling results in our newer oil and 25 Table of Contents Index to Financial Statements 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.
Drilling results in our newer oil and liquids-rich shale plays may be more uncertain than in shale plays that are more developed and have longer established production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries will be ultimately successful when used in newly developed shale formations.
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 24 Table of Contents Index to Financial Statements undeveloped reserves and may result in some projects becoming uneconomical.
Delays in the development of our reserves, further decreases in commodity prices or increases in costs to drill and develop such reserves will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical.
If 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.
If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow. 28 Table of Contents Inde x to Financial Statements We are required to pay fees to some of our midstream service providers based on minimum volumes regardless of actual volume throughput.
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.
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. 25 Table of Contents Inde x to Financial Statements Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production.
In addition, the concentration of voting power may adversely affect the trading price and liquidity of the Common Stock. 35 Table of Contents Index to Financial Statements 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 addition, the concentration of voting power may adversely affect the trading price and liquidity of the Common Stock. There may be future dilution of our Common Stock, which could adversely affect the market price of our Common Stock. We are not restricted from issuing additional shares of our Common Stock.
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.
These activities and the global transition to a low carbon economy 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 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.
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. 23 Table of Contents Inde x to Financial Statements As of December 31, 2023, approximately 48% of our total estimated proved reserves were PUDs and may not be ultimately developed or produced.
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.
The December 31, 2023 present value is based on a $2.64 per MMBtu of gas price and a $78.21 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.
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 Inflation Reduction Act of 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.
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.
At December 31, 2023, amounts borrowed under our Credit Facility bore interest at the weighted average rate of 8.15%. A 1% increase in the average interest rate would increase our interest expense by approximately $1.2 million based on outstanding borrowings under our Credit Facility at December 31, 2023.
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.
Of the remaining 14% of our Utica/Marcellus acreage not held by production, approximately 10% will be subject to expiration in 2024, 5% in 2025, 10% in 2026 and approximately 75% thereafter, although a portion of our Utica/Marcellus leases generally grant us the right to extend these leases for an additional three or five-year period.
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.
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.
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.
A cyberattack 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. 29 Table of Contents Inde x to Financial Statements In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
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.
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.
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.
For example, during 2022, West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or 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.
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 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, approximately 80% will be subject to expiration in 2024, less than 1% in 2025, 19% in 2026 and none thereafter.
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.
These fees could be significant and may have a material adverse effect on our results of operations. A deterioration in general economic, business or industry conditions would have a material adverse effect on our results of operations, liquidity and financial condition.
In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels. 32 Table of Contents Index to Financial Statements 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.
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.
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.
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.
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.
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.
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.
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. 33 Table of Contents Inde x to Financial Statements Future U.S. and state tax legislation may adversely affect our business, results of operations, financial condition and cash flow.
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.
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. On January 26, 2024, President Biden paused approvals for pending and future applications to export liquified natural gas (LNG) on non-FTA countries.
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.
Our systems for protecting against cybersecurity risks may not be sufficient. As cyberattacks continue to evolve, including those leveraging artificial intelligence, 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 cyberattacks.
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.
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. 26 Table of Contents Inde x to Financial Statements 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.
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.
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.
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.
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.
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.
During 2023, WTI prices ranged from $66.61 to $93.67 per barrel and the Henry Hub spot market price of natural gas ranged from $1.74 to $3.78 per MMBtu.
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.
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. 32 Table of Contents Inde x to Financial Statements 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.
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 assets owned by our midstream service providers are subject to stringent and complex regulations related to pipeline safety and integrity management.
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.
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.
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.
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.
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.
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 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.
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, 2023, accounted for approximately 12% of our total natural gas, oil and NGL revenues.
As of December 31, 2022, we had a net operating loss, or NOL, carryforward of approximately $1.6 billion for federal 23 Table of Contents Index to Financial Statements income tax purposes.
Future non-cash asset impairments could negatively affect our results of operations. 22 Table of Contents Inde x to Financial Statements A change of control could limit our use of net operating losses to reduce future taxable income. As of December 31, 2023, we had a net operating loss, or NOL, carryforward of approximately $1.8 billion for federal income tax purposes.
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.
The impact on the pause and similar federal actions remain unclear. 31 Table of Contents Inde x to Financial Statements States in which we operate have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities.
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.
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. 24 Table of Contents Inde x to Financial Statements 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.
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.
Constrained supply chain for environmental control devices along with the significant estimated costs of compliance with these new and proposed rules could have a material impact on our operations. We may be required to make large, sometimes unexpected, expenditures to comply with applicable governmental laws, rules, regulations, permits or orders.
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.
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. 27 Table of Contents Inde x to Financial Statements 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.
Removed
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.
Added
For example, in December 2023, the United States Environmental Protection Agency (USEPA), announced its final methane rules to reduce methane emissions from both new and existing oil and natural gas facilities and the Inflation Reduction Act of 2022 established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from the same facilities.
Removed
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.
Added
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. 30 Table of Contents Inde x to Financial Statements Pipeline Safety.
Removed
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.
Added
The Department of Energy will conduct a review during the pause that will look at the economic and environmental impacts of projects seeking approval to export LNG to Europe and Asia.
Removed
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.
Added
In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.
Removed
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.
Added
In November 2023, the international community gathered in Dubai at COP28 and announced a new climate deal that calls on countries to reduce carbon pollution and transition away from fossil fuels in energy systems to achieve "net zero" by 2050.
Removed
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.
Removed
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.
Removed
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.
Removed
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. 29 Table of Contents Index to Financial Statements 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.

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Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeIssuer 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.
Biggest changeIssuer 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, which has subsequently been increased up to $650 million and extended through December 31, 2024.
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 performance graph below illustrates changes over the period of May 19, 2021 through December 31, 2023, 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]
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, 2023. ITEM 6. [RESERVED]
Recent Sales of Unregistered Securities None. 37 Table of Contents Index to Financial Statements 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.
Recent Sales of Unregistered Securities None. 38 Table of Contents Inde x to Financial Statements 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 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.
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 may be suspended from time to time, modified, extended or discontinued by the Board of Directors at any time.
During the year ended December 31, 2022, the Company paid $5.4 million of cash dividends to holders of our Preferred Stock.
During the years ended December 31, 2023 and December 31, 2022, the Company paid $4.8 million and $5.4 million, respectively, of cash dividends to holders of our Preferred 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.
Shareholders At the close of business on February 14, 2024, there were approximately 8,635 holders of record of our Common Stock. Dividends Subsequent to our emergence from bankruptcy, we have not paid dividends on our Common Stock.
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.
As of December 31, 2023, the Company had repurchased 4.4 million shares for $399.6 million at a weighted average price of $91.53 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.
The following table provides a summary of our Common Stock repurchase activity for the three months ended December 31, 2023: 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 8,446 $ 115.40 8,398 $ 315,350,000 November 1 - November 30 94,240 $ 131.89 94,240 $ 302,921,000 December 1 - December 31 387,116 $ 135.83 387,037 $ 250,351,000 Total 489,802 $ 134.72 489,675 _____________________ (1) We repurchased and canceled 48 and 79 shares of our Common Stock at a weighted average price of $123.84 and $121.31 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards during October and December 2023, respectively.

Item 6. [Reserved]

Selected Financial Data — reserved (removed by SEC in 2021)

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Biggest changeITEM 6. RESERVED 38 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 38 RESULTS OF OPERATIONS 41 LIQUIDITY AND CAPITAL RESOURCES 47 CRITICAL ACCOUNTING POLICIES AND ESTIMATES 52 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 53 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 56
Biggest changeITEM 6. RESERVED 39 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 39 RESULTS OF OPERATIONS 43 LIQUIDITY AND CAPITAL RESOURCES 48 CRITICAL ACCOUNTING POLICIES AND ESTIMATES 53 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 55 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 57

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

79 edited+44 added−48 removed23 unchanged
Biggest changeNatural 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 $ 1,092,584 $ 410,276 Average price without the impact of derivatives ($/Mcfe) $ 6.49 $ 4.72 $ 3.05 Impact from settled derivatives ($/Mcfe) $ (2.94) $ (1.39) $ (0.02) Average price, including settled derivatives ($/Mcfe) $ 3.55 $ 3.33 $ 3.03 41 Table of Contents Index to Financial Statements 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 sales $ 1,998,452 $ 906,096 $ 344,390 Oil and condensate sales 147,444 81,347 29,106 Natural gas liquid sales 184,963 105,141 36,780 Total natural gas, oil and condensate, and NGL sales $ 2,330,859 $ 1,092,584 $ 410,276 For the year ended December 31, 2022, our total unhedged natural gas, oil and condensate and NGL revenues increased approximately $1.2 billion, or 113%, compared to the Prior Successor Period.
Biggest changeNatural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands) Successor Year Ended December 31, 2023 Year Ended December 31, 2022 Natural gas (MMcf/day) Utica & Marcellus production volumes 766 674 SCOOP production volumes 194 209 Total production volumes 960 883 Total sales $ 831,812 $ 1,998,452 Average price without the impact of derivatives ($/Mcf) $ 2.37 $ 6.20 Impact from settled derivatives ($/Mcf) $ 0.42 $ (3.11) Average price, including settled derivatives ($/Mcf) $ 2.79 $ 3.09 Oil and condensate (MBbl/day) Utica & Marcellus production volumes 1 1 SCOOP production volumes 3 4 Total production volumes 4 4 Total sales $ 99,854 $ 147,444 Average price without the impact of derivatives ($/Bbl) $ 73.27 $ 91.58 Impact from settled derivatives ($/Bbl) $ (2.53) $ (24.32) Average price, including settled derivatives ($/Bbl) $ 70.74 $ 67.26 NGL (MBbl/day) Utica & Marcellus production volumes 2 2 SCOOP production volumes 10 10 Total production volumes 12 12 Total sales $ 119,717 $ 184,963 Average price without the impact of derivatives ($/Bbl) $ 27.29 $ 41.26 Impact from settled derivatives ($/Bbl) $ 2.07 $ (2.80) Average price, including settled derivatives ($/Bbl) $ 29.36 $ 38.46 Total (MMcfe/day) Utica & Marcellus production volumes 784 693 SCOOP production volumes 270 290 Total production volumes 1,054 983 Total sales $ 1,051,383 $ 2,330,859 Average price without the impact of derivatives ($/Mcfe) $ 2.73 $ 6.49 Impact from settled derivatives ($/Mcfe) $ 0.40 $ (2.94) Average price, including settled derivatives ($/Mcfe) $ 3.13 $ 3.55 43 Table of Contents Inde x to Financial Statements Successor Year Ended December 31, 2023 Year Ended December 31, 2022 % Change Natural gas $ 831,812 $ 1,998,452 (58) % Oil and condensate 99,854 147,444 (32) % NGL 119,717 184,963 (35) % Total natural gas, oil and condensate and NGL sales $ 1,051,383 $ 2,330,859 (55) % The decrease in natural gas sales without the impact of derivatives when comparing the year ended December 31, 2023, to the year ended December 31, 2022, was due to a 62% decrease in realized natural gas prices, partially offset by a 9% increase in sales volumes.
To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 5 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes.
To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 5 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.
As discussed in Note 6 of our consolidated financial statements, holders of Preferred Stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference (as defined below) with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of Preferred Stock (“PIK Dividends”).
As discussed in Note 6 of our consolidated financial statements, holders of Preferred Stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of Preferred Stock (“PIK Dividends”).
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.
Impact of the War in Ukraine and the Israel-Hamas War 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 the global energy markets and the amplification of inflation and supply chain constraints.
The Amendment, among other things, (a) increased the borrowing base under the Credit Facility from $850 million to $1.0 billion, with the elected commitments remaining at $700 million, (b) amended certain covenants related to hedging to ease certain requirements and limitations, (c) amended the covenants governing restricted payments to (i) increased the Net Leverage Ratio allowing unlimited restricted payments from 1.00 to 1.00 to 1.25 to 1.00 and (ii) permitted additional restricted payments to redeem preferred equity until December 31, 2022, provided certain leverage, no event of default or borrowing base deficiency and availability tests were met and (d) provided for the transition from a LIBOR to a SOFR benchmark, with a 10 basis point credit spread adjustment for all tenors.
The amendment, among other things, (a) increased the borrowing base under the Credit Facility from $850 million to $1.0 billion with elected commitments remaining at $700 million, (b) amended certain covenants related to hedging to ease certain requirements and limitations and (c) amended the covenants governing restricted payments to (i) increase the Net Leverage Ratio allowing unlimited restricted payments from 1.00 to 1.00 to 1.25 to 1.00 and (ii) permit additional restricted payments to redeem preferred equity until December 31, 2022 provided certain leverage, no event of default or borrowing base deficiency and availability tests are met and (d) provided for the transition from a LIBOR to a SOFR benchmark, with a 10 basis point credit spread adjustment for all tenors.
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.
Business and Industry Outlook The Company's primary focus going into 2024 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately support our expected free cash flow generation.
The 2026 Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under the Credit Facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2026 Senior Notes.
The 2026 Senior Notes and the guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations under our amended and restated credit agreement) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness and other liabilities of any of our subsidiaries that do not guarantee the 2026 Senior Notes.
See Note 5 of our consolidated financial statements for additional discussion of our outstanding post-emergence debt. Preferred Stock Dividends .
See Note 5 of our consolidated financial statements for additional discussion of our outstanding debt. Preferred Stock Dividends .
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.
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 54% of our expected 2024 production, at an average floor price of $3.70 per Mcf.
Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities. 50 Table of Contents Index to Financial Statements See Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" for further information regarding our open derivative instruments at December 31, 2022.
Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities. See Item 7A. "Quantitative and Qualitative Disclosures about Market Risk" for further information regarding our open derivative instruments at December 31, 2023.
The Existing Credit Facility also provides for a $175.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit. On May 2, 2022, we entered into the Amendment to Borrowing Base Redetermination Agreement and First Amendment to our Credit Agreement (“Amendment”), which amended the Existing Credit Facility (as amended, the "Credit Facility").
The credit agreement also provides for a $175.0 million sublimit of the aggregate commitments that is available for the issuance of letters of credit. On May 2, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Amendment to Borrowing Base Redetermination Agreement and First Amendment to our Credit Agreement, which amended the Existing Credit Facility.
As of December 31, 2022, we had $7.3 million of cash and cash equivalents compared to $3.3 million as of December 31, 2021, and a net working capital deficit of $391.1 million as of December 31, 2022, compared to a net working capital deficit of $361.4 million as of December 31, 2021.
As of December 31, 2023, we had $1.9 million of cash and cash equivalents compared to $7.3 million as of December 31, 2022, and a net working capital of $52.4 million as of December 31, 2023, compared to a net working capital deficit of $391.1 million as of December 31, 2022.
As of December 31, 2022, our working capital deficit includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, 2022, was $695.0 million compared to $714.0 million as of December 31, 2021.
As of December 31, 2023, our net working capital includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, 2023, was $668.0 million compared to $695.0 million as of December 31, 2022.
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.
Certain of our capital expenditures and expenses are affected by general inflation and we expect costs for 2024 to continue to be a function of supply and demand; however, we do not expect inflation to significantly impact cash flow in 2024 as a result of commitments that were entered into during 2023.
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.
Henry Hub averaged $2.53 per MMBtu in 2023 vs $6.44 per MMBtu in 2022. As we look into 2024, we expect continued volatility in natural gas prices.
Derivative Instruments. We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts.
We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. All derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value.
Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 20 of our consolidated financial statements for further information. Income Taxes.
The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 20 of our consolidated financial statements for further information. Income Taxes.
We believe our annual free cash flow generation, cash on hand, and borrowing capacity under the Credit Facility will provide sufficient liquidity to fund our operations, capital expenditures, interest expense, debt repayments and any return of capital to shareholders authorized by the Board, during the next 12 months and the foreseeable future.
We believe our annual free cash flow generation, borrowing capacity under the Credit Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense and share repurchases during the next 12 months and the foreseeable future.
The 2026 Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Credit Facility or certain other debt (collectively the “Guarantors”). The 2026 Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC (the “Non-Guarantors”).
The 2026 Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Credit Facility or certain other debt (the “Guarantors”). The 2026 Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC (the “Non-Guarantors”). The Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several.
Our capital expenditures have historically been related to the execution of our drilling and completion activities in addition to certain lease acquisition activities. Our capital investment strategy is focused on developing projects we believe offer the highest rate of return and allow us to generate sustainable cash flow, considering current and forecasted commodity prices.
Our capital expenditures have historically been related to the execution of our drilling and completion activities in addition to certain lease acquisition activities. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices.
Refer to Note 2 and Note 3 of our consolidated financial statements for more information on the events of the bankruptcy proceedings as well as the accounting and reporting impacts of the reorganization. Oil and Natural Gas Properties . We use the full cost method of accounting for oil and natural gas operations.
Refer to Note 2 and Note 3 of our consolidated financial statements for more information on the events of the bankruptcy proceedings as well as the accounting and reporting impacts of the reorganization. 53 Table of Contents Inde x to Financial Statements Oil and Natural Gas Properties .
The Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan.
There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan.
On October 31, 2022, the Company completed its semi-annual borrowing base redetermination during which the borrowing base under the Credit Facility was reconfirmed at $1.0 billion with the elected commitments remaining at $700 million. Additionally, on the Emergence Date, pursuant to the terms of the Plan, we issued our 2026 Senior Notes.
On October 27, 2023, Gulfport completed its semi-annual borrowing base redetermination during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million. Additionally, on the Emergence Date, pursuant to the terms of the Plan, we issued our 2026 Senior Notes.
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.
If this occurs or if our production estimates change or our exploration or 51 Table of Contents Inde x to Financial Statements 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.
If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly. We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC on a quarterly basis.
Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.
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.
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. 41 Table of Contents Inde x to Financial Statements In 2023, natural gas prices continued to be volatile as spot prices ranged from $1.74 to $3.78 per MMBtu.
The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. 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.
The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. During 2023, WTI prices ranged from $66.61 to $93.67 per barrel and the Henry Hub spot market price of natural gas ranged from $1.74 to $3.78 per MMBtu.
See Note 18 of our consolidated financial statements for further discussion of our firm transportation and gathering commitments. (3) See Note 18 of our consolidated financial statements for a description of our other operational commitments. (4) See Note 10 of our consolidated financial statements for a description of our operating lease liabilities.
See Note 5 of our consolidated financial statements for a description of our long-term debt. (2) See Note 18 of our consolidated financial statements for further discussion of our firm transportation and gathering commitments. (3) See Note 18 of our consolidated financial statements for a description of our other operational commitments.
All derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures.
We estimate the fair value of all derivative instruments using industry-standard models 54 Table of Contents Inde x to Financial Statements that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures.
(5) This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 13 and 4 of our consolidated financial statements, respectively. Off-balance Sheet Arrangements. We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations.
(4) See Note 10 of our consolidated financial statements for a description of our operating lease liabilities. (5) This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 13 and 4 of our consolidated financial statements, respectively. Off-balance Sheet Arrangements.
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").
Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2022 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 2023 to the period ended December 31, 2022.
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.
On October 31, 2022, the Company completed its semi-annual borrowing base redetermination and entered into the Borrowing Base Reaffirmation Agreement and Second Amendment to our Credit Agreement, which amended the Existing Credit Facility. The amendment, among other things, reconfirmed the borrowing base under the Credit Facility at $1.0 billion and the elected commitments at $700 million.
See Note 5 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes. As of February 23, 2023, we had $25.6 million of cash and cash equivalents, $79.0 million borrowings under our Credit Facility, $113.4 million of letters of credit outstanding, and $550 million of outstanding 2026 Senior Notes.
See Note 5 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes. 48 Table of Contents Inde x to Financial Statements As of February 26, 2024, we had $7.1 million of cash and cash equivalents, $51.0 million borrowings under our Credit Facility, $63.8 million of letters of credit outstanding, and $550 million of outstanding 2026 Senior Notes.
Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves.
We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized.
In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions.
The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements.
At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. Historically, our actual payments received have not significantly deviated from our accruals.
Variances between our estimated revenue and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. Historically, our actual payments received have not significantly deviated from our accruals. Derivative Instruments.
For the year ended December 31, 2022, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, and our primary uses of cash have been share repurchases pursuant to the Repurchase Program, repayments under the Credit Facility, dividend payments on our Preferred Stock and the development of our oil and natural gas properties.
For the year ended December 31, 2023, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases and discretionary acreage acquisitions.
During 2021, WTI prices ranged from $47.47 to $85.64 per barrel and the Henry Hub spot market price of natural gas ranged from $2.43 to $23.86 per MMBtu.
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.
During the year ended December 31, 2022, the Company's borrowing on its Credit Facility decreased $19 million. As of February 23, 2023, the Company had $79.0 million in borrowings outstanding on its Credit Facility. Repurchases of Common Stock.
During the year ended December 31, 2023, the Company had $971.0 million and $998.0 million in borrowings and repayments, respectively, on its Credit Facility. As of February 26, 2024, the Company had $51.0 million in borrowings outstanding on its Credit Facility. Repurchases of Common Stock.
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.
Our principal properties are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and 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.
During the year ended December 31, 2022, we spud 19 gross (17.4 net) wells and commenced sales from 15 gross (13.4 net) wells in the Utica for a total cost of approximately $271.8 million and we spud 6 gross (4.3 net) and commenced sales from 13 gross (10.3 net) wells in the SCOOP for a total cost of approximately $126.9 million.
During the year ended December 31, 2023, we spud 20 gross (17.9 net) wells and commenced sales from 22 gross (20.2 net) wells in the Utica/Marcellus for a total cost of approximately $344.4 million and we spud 5 gross (3.2 net) and commenced sales from 2 gross (1.7 net) wells in the SCOOP for a total cost of approximately $37.3 million.
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.
Interest rates on our Credit Facility borrowings have increased from a weighted average of 5.19% for the year ended December 31, 2022, to 8.15% for the year ended December 31, 2023. Additional increases in interest rates may have a negative impact on the Company’s ability to continue to execute its business strategy.
During the Prior Predecessor Period, we received approximately $50.0 million in proceeds related to our Preferred Stock issuance. Preferred Stock Dividends. During the year ended December 31, 2022, the Company paid $5.4 million of cash dividends to holders of our Preferred Stock compared to $1.5 million of cash dividends to holders of our Preferred Stock in the Prior Successor Period.
During the year ended December 31, 2023, the Company paid $4.8 million of cash dividends to holders of our Preferred Stock compared to $5.4 million in the year ended December 31, 2022. Other.
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.
Discussions of 2021 items and comparisons between 2022, Prior Successor Period and Prior Predecessor Period 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, 2022. 39 Table of Contents Inde x to Financial Statements Overview Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins.
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.
During the year ended December 31, 2023, the Company repurchased 1.5 million shares for approximately $148.9 million under the Repurchase Program at a weighted average price of $101.53 per share. For the same period in 2022, the Company repurchased 2.9 million shares for $250.8 million at a weighted average price of $86.47 per share.
See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting. 52 Table of Contents Index to Financial Statements Oil, Natural Gas and NGL Reserves.
See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting. Oil, Natural Gas and NGL Reserves. Estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates.
Sources and Uses of Cash The following table presents the major changes in cash and cash equivalents for the year ended December 31, 2022, Prior Successor Period and Prior Predecessor Period (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 Net cash provided by operating activities $ 739,077 $ 292,985 $ 172,155 Additions to oil and natural gas properties (460,780) (207,113) (102,330) Debt activity, net (19,000) (138,751) (147,660) Repurchases of Common Stock (250,482) — — Proceeds from issuance of Preferred Stock — — 50,000 Preferred Stock dividends (5,444) (1,503) — Other 628 (1,775) (2,609) Net change in cash, cash equivalents and restricted cash $ 3,999 $ (56,157) $ (30,444) Cash, cash equivalents and restricted cash at end of period $ 7,259 $ 3,260 $ 59,417 Net cash provided by operating activities.
Sources and Uses of Cash The following table presents the major changes in cash and cash equivalents for the year ended December 31, 2023 and December 31, 2022 (in thousands): Successor Year Ended December 31, 2023 Year Ended December 31, 2022 Net cash provided by operating activities $ 723,181 $ 739,077 Additions to oil and natural gas properties (537,360) (460,780) Debt activity, net (27,000) (19,000) Repurchases of Common Stock (149,165) (250,482) Preferred Stock dividends (4,840) (5,444) Other (10,146) 628 Net change in cash and cash equivalents (5,330) 3,999 Cash and cash equivalents at end of period $ 1,929 $ 7,259 Net cash provided by operating activities.
We derive almost all of our revenue from the sale of natural gas, crude oil and NGL produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery.
Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive.
This quarterly review is referred to as a ceiling test. Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2022.
Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2023. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices can have a material impact on the present value of estimated future net revenues.
Liquidity and Capital Resources Overview . We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility, fund our development projects, operations and capital expenditures and return capital to shareholders. We utilize derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company's cash flows.
See Note 11 of our consolidated financial statements for further discussion of our income tax benefit. Liquidity and Capital Resources Overview . We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility, fund our development projects, operations and capital expenditures and return capital to shareholders.
The following table sets forth our contractual and commercial obligations at December 31, 2022 (in thousands): Payment due by period Contractual Obligations Total 2023 2024-2025 2026-2027 2028 and Thereafter Long-term debt (1): Principal $ 695,000 $ — $ 145,000 $ 550,000 $ — Interest 148,500 44,000 88,000 16,500 — Firm transportation and gathering contracts (2) 1,618,385 231,123 360,578 274,802 751,882 Other operational commitments (3) 83,900 52,700 31,200 — — Operating lease liabilities (4) 26,713 12,414 13,738 561 — Total contractual cash obligations (5) $ 2,572,498 $ 340,237 $ 638,516 $ 841,863 $ 751,882 _____________________ (1) The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations.
The following table sets forth our contractual and commercial obligations at December 31, 2023 (in thousands): Payment due by period Contractual Obligations Total 2024 2025-2026 2027-2028 2029 and Thereafter Long-term debt (1) : Principal $ 668,000 $ — $ 550,000 $ 118,000 $ — Interest 108,167 44,000 64,167 — — Firm transportation and gathering contracts (2) 1,364,389 219,367 271,985 273,006 600,031 Other operational commitments (3) 28,938 28,938 — — — Operating lease liabilities (4) 14,298 12,958 1,330 10 — Total contractual cash obligations (5) $ 2,183,792 $ 305,263 $ 887,482 $ 391,016 $ 600,031 _____________________ (1) The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations.
Drilling and completion costs discussed above reflect incurred costs while drilling and completion costs presented in the table below reflect cash payments for drilling and completions. Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle.
Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle.
The Company expects to enter into similar contractual arrangements in the future in order to support the Company's business plans. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. Capital Expenditures.
There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 18 of our consolidated financial statements for further discussion of the various financial guarantees we have issued. Capital Expenditures.
The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2022, the Prior Successor Period and the Prior Predecessor Period represented approximately 86%, 88% and 86%, respectively, of our total sales volumes for the applicable year or period.
The NGL production remained consistent when comparing the year ended December 31, 2023 to the year ended December 31, 2022. 44 Table of Contents Inde x to Financial Statements Natural Gas, Oil and NGL Derivatives (in thousands) The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2023 and 2022, represented approximately 95% and 86%, respectively, of our total sales volumes for the applicable year.
The Preferred Stock has no stated maturity and will remain outstanding indefinitely unless repurchased or redeemed by the Company or converted into Common Stock. During the year ended December 31, 2022, and Prior Successor Period, the Company paid $5.4 million and $1.5 million, respectively, of cash dividends to holders of our Preferred Stock. Supplemental Guarantor Financial Information .
During the year ended December 31, 2023, and the year ended December 31, 2022, the Company paid $4.8 million and $5.4 million, respectively, of cash dividends to holders of our Preferred Stock. 49 Table of Contents Inde x to Financial Statements Supplemental Guarantor Financial Information .
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. 39 Table of Contents Index to Financial Statements • 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.
The ultimate impact of the war in Ukraine and the Israel-Hamas war will depend on future developments and the timing and extent to which normal economic and operating conditions resume. 2023 Operational and Financial Highlights During 2023, we had the following notable achievements: • Reported total net production of 1,054 MMcfe per day. • Generated $723.2 million of operating cash flows. • Turned to sales 24 gross (21.9 net) wells, which included our first two operated Marcellus wells. • Total lease operating expenses, midstream costs and taxes other than income per Mcfe decreased 13%. • Expanded common share repurchase program to $650 million and returned $148.9 million to shareholders through the repurchase of 1.5 million shares at a weighted average price of $101.53 per share. • Reduced total debt by $27 million. • Achieved MIQ certification for all Appalachian assets. • Reported year-end estimated net proved reserves of 4.2 Tcfe.
Deferred tax assets are recognized in the year in which realization becomes determinable. Quarterly, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors.
Deferred tax assets are recognized in the year in which realization becomes determinable. At each reporting period, the Company weighs all available positive and negative evidence to determine whether its deferred tax assets are more likely than not to be realized.
As 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. As of February 23, 2023, we repurchased 3.1 million shares for approximately $264.4 million under the Repurchase Program at a weighted average price of $85.14 per share. Issuance of Preferred Stock.
As of February 26, 2024, we repurchased 4.5 million shares for approximately $413.6 million under the Repurchase Program at a weighted average price of $92.41 per share. Preferred Stock Dividends.
Cash capital expenditures for the year ended December 31, 2022, Prior Successor Period and Prior Predecessor Period were as follows (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 Oil and Natural Gas Property Cash Expenditures: Drilling and completion costs $ 410,281 $ 183,333 $ 94,128 Leasehold acquisitions 32,708 13,022 2,752 Other 17,791 10,758 5,450 Total oil and natural gas property expenditures $ 460,780 $ 207,113 $ 102,330 51 Table of Contents Index to Financial Statements Debt Activity.
Cash capital expenditures for the year ended December 31, 2023 and December 31, 2022, were as follows (in thousands): Successor Year Ended December 31, 2023 Year Ended December 31, 2022 Oil and Natural Gas Property Cash Expenditures: Drilling and completion costs $ 413,258 $ 410,281 Leasehold acquisitions 101,191 32,708 Other 22,911 17,791 Total oil and natural gas property expenditures $ 537,360 $ 460,780 Debt activity, net.
For the year ended December 31, 2022, the Company's incurred capital expenditures totaled $449.2 million, of which $411.8 million related to drilling and completion activity and $37.4 million related to leasehold and land investment. Our capital expenditures for 2023 are currently estimated to be in the range of $375 million to $400 million for drilling and completion expenditures.
For the year ended December 31, 2023, the Company's incurred capital expenditures totaled $491.5 million, of which $388.6 million related to drilling and completion activities, $54.8 million related to maintenance leasehold and land investment and $48.0 million related to discretionary acreage acquisitions.
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.
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. The inflationary environment has impacted interest rates on our Credit Facility borrowings throughout 2023.
We currently have the option to pay either a cash or PIK dividend on a 48 Table of Contents Index to Financial Statements quarterly basis. Each share of Preferred Stock has a liquidation preference of $1,000 (the "Liquidation Preference").
We currently have the option to pay either cash dividends or PIK dividends on a quarterly basis.
The Company did not record an impairment of its oil and natural gas properties for the year ended December 31, 2022. The Company recorded impairment of its oil and natural gas properties of $117.8 million for the Prior Successor Period.
Any excess of the net book value, less deferred income taxes, is generally written off as an expense. The Company did not record an impairment of its oil and natural gas properties for the year ended December 31, 2023 or December 31, 2022.
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. 38 Table of Contents Index to Financial Statements 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").
To accomplish these goals, we allocate capital to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts. Recent Developments Leadership Changes In January 2023, ou r CEO Tim Cutt, resigned his position as CEO. Mr.
Subsequent to December 31, 2022 and as of February 23, 2023, we entered into the following natural gas, oil, and NGL derivative contracts: Period Type of Derivative Instrument Index Daily Volume (MMbtu) Weighted Average Price 2023 Basis Swaps TETCO M2 76,219 $(0.85) 2023 Basis Swaps Rex Zone 3 59,452 $(0.22) 2023 Basis Swaps NGPL TXOK 42,685 $(0.34) 2024 Swaps NYMEX Henry Hub 30,000 $3.90 2024 Costless Collars NYMEX Henry Hub 60,000 $3.17 / $3.96 Additionally, subsequent to year end, the Company restructured a portion of its natural gas sold call position, by buying back a portion of its 2023 natural gas sold call position, and selling additional natural gas calls for 2023 and 2025.
Subsequent to December 31, 2023 and as of February 26, 2024, we entered into the following natural gas, oil, and NGL derivative contracts: Period Type of Derivative Instrument Index Daily Volume Weighted Average Price Natural Gas (MMBtu/d) ($/MMBtu) 2024 Swaps NYMEX Henry Hub 40,219 $2.66 2024 Basis Swaps TETCO M2 18,306 $(0.90) 2025 Basis Swaps TETCO M2 100,000 $(0.99) 2025 Costless Collars NYMEX Henry Hub 30,000 $3.25 / $4.03 NGL (Bbl/d) ($/Bbl) 2025 Swaps Mont Belvieu C3 1,000 $30.14 50 Table of Contents Inde x to Financial Statements Contractual and Commercial Obligations.
As of December 31, 2022, our material off-balance sheet arrangements and transactions include $113.4 million in letters of credit outstanding against our revolving credit facility and $33.5 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, the majority of which are related to firm transportation agreements.
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2023, our material off-balance sheet arrangements and transactions include $63.8 million in letters of credit outstanding against our Credit Facility and $43.3 million in surety bonds issued.
Historically, we have generally funded our operations, planned capital expenditures, acquisitions of additional oil and 47 Table of Contents Index to Financial Statements natural gas properties and any debt or share repurchases with cash flow from our operating activities, cash on hand, borrowings under our revolving credit facility and issuances of equity and debt securities.
We utilize derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company's cash flows. We generally fund our operations, planned capital expenditures and any share repurchases with cash flow from our operating activities, cash on hand, and borrowings under our Credit Facility.
As discussed in Note 5 of our consolidated financial statements, when we entered into the Existing Credit Facility on October 14, 2021, it provided for an aggregate maximum principal amount of up to $1.5 billion, an initial borrowing base of $850.0 million and an initial aggregate elected commitment amount of $700.0 million.
Debt. On October 14, 2021, we entered into the Third Amended and Restated Credit Agreement JPMorgan Chase Bank, N.A., as administrative agent, and various lender parties. The Existing Credit Facility provides for an aggregate maximum principal amount of up to $1.5 billion.
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. 40 Table of Contents Index to Financial Statements 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.
With the weakening in commodity prices, we could begin to see additional deflationary pressures during 2024 as well as less frequent supply chain constraints. 42 Table of Contents Inde x to Financial Statements Results of Operations Comparison of the Year Ended December 31, 2023 and 2022 We reported net income of $1.5 billion for the year ended December 31, 2023, compared to a net income of 494.7 million for the year ended December 31, 2022.
The tax expense is entirely attributable to the Oklahoma refund claim that was filed during the third quarter, resulting in an adjustment to the benefit recorded during the Prior Predecessor Period. We did not record any additional income tax expense for the Prior Successor Period as a result of maintaining a full valuation allowance against our net deferred tax asset.
The income tax benefit primarily related to the partial release of the valuation allowance maintained against our net deferred tax asset position. For the year ended December 31, 2022, the Company's effective tax rate was 0% and we did not record any income tax expense, as a result of maintaining a full valuation allowance against our net deferred tax asset.
Natural Gas, Oil and NGL Derivatives (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 derivatives - fair value gains (losses) $ 32,797 $ (223,512) $ (123,080) Natural gas derivatives - settlement losses (1,002,098) (300,172) (3,362) Total losses on natural gas derivatives (969,301) (523,684) (126,442) Oil and condensate derivatives - fair value gains (losses) 6,618 (5,128) (6,126) Oil and condensate derivatives - settlement losses (39,163) (9,720) — Total losses on oil and condensate derivatives (32,545) (14,848) (6,126) NGL derivatives - fair value gains (losses) 14,648 (5,322) (4,671) NGL derivatives - settlement losses (12,549) (12,965) — Total gains (losses) on NGL derivatives 2,099 (18,287) (4,671) Total losses on natural gas, oil and NGL derivatives $ (999,747) $ (556,819) $ (137,239) Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 13 of our consolidated financial statements.
Successor Year Ended December 31, 2023 Year Ended December 31, 2022 Natural gas derivatives - fair value gains $ 584,563 $ 32,797 Natural gas derivatives - settlement gains (losses) 146,381 (1,002,098) Total gains (losses) on natural gas derivatives 730,944 (969,301) Oil and condensate derivatives - fair value gains 5,971 6,618 Oil and condensate derivatives - settlement losses (3,272) (39,163) Total gains (losses) on oil and condensate derivatives 2,699 (32,545) NGL derivatives - fair value (losses) gains (2,414) 14,648 NGL derivatives - settlement gains (losses) 9,090 (12,549) Total gains on NGL derivatives 6,676 2,099 Total gains (losses) on natural gas, oil and NGL derivatives $ 740,319 $ (999,747) We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period.
Net cash provided by operating activities was $739.1 million for the year ended December 31, 2022, compared to $293.0 million for the Prior Successor Period and $172.2 million for the Prior Predecessor Period.
Net cash provided by operating activities was $723.2 million for the year ended December 31, 2023, compared to $739.1 million for the year ended December 31, 2022. The decrease was primarily the result of a decrease in revenue due to a decline in commodity prices partially offset by an increase of cash receipts from settled derivative instruments.
The increase in per unit taxes other than income when comparing the year ended December 31, 2022, to both the Prior Successor Period and Prior Predecessor Period, was primarily related to an increase in production taxes resulting from the significant increase in our natural gas, oil and condensate and NGL revenues excluding the impact of hedges discussed above. 43 Table of Contents Index to Financial Statements Transportation, Gathering, Processing and Compression (in thousands, except per unit) 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 Transportation, gathering, processing and compression $ 357,246 $ 212,013 $ 161,086 Transportation, gathering, processing and compression per Mcfe $ 1.00 $ 0.92 $ 1.20 The increase in transportation, gathering, processing and compression when comparing the year ended December 31, 2022, to both the Prior Successor Period and Prior Predecessor Period, was primarily related to the timing of our emergence from bankruptcy.
LOE per unit for the year ended December 31, 2023 was consistent with the year ended December 31, 2022. 45 Table of Contents Inde x to Financial Statements Taxes Other Than Income (in thousands, except per unit) Successor Year Ended December 31, 2023 Year Ended December 31, 2022 % Change Production taxes $ 25,564 $ 48,145 (47) % Property taxes 6,160 7,146 (14) % Other 1,993 4,847 (59) % Total taxes other than income $ 33,717 $ 60,139 (44) % Total taxes other than income per Mcfe $ 0.09 $ 0.17 (47) % The decrease in total and per unit taxes other than income for the year ended December 31, 2023, compared to the year ended December 31, 2022, was primarily related to a decrease in production taxes resulting from the decrease in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.
See Note 3 of our consolidated financial statements for more information on fresh start adjustments. 45 Table of Contents Index to Financial Statements Interest Expense (in thousands, except per unit) 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 Interest on 2026 Senior Notes $ 44,000 $ 27,476 $ — Interest on Credit Facility 12,799 1,978 — Amortization of loan costs 2,914 1,663 — Interest on Exit Facility — 5,810 — Interest on First-Out Term Loan — 3,564 — Interest on DIP Credit Facility — — 3,104 Interest expense on Pre-Petition Revolving Credit Facility — — 2,044 Other 60 362 (989) Total interest expense $ 59,773 $ 40,853 $ 4,159 Interest expense per Mcfe $ 0.17 $ 0.18 $ 0.03 The increase in interest expense during the year ended December 31, 2022, compared to both the Prior Successor Period and the Prior Predecessor Period, was primarily related to the timing of our emergence from bankruptcy.
Interest Expense (in thousands, except per unit) Successor Year Ended December 31, 2023 Year Ended December 31, 2022 % Change Interest on 2026 Senior Notes $ 44,000 $ 44,000 — % Interest on Credit Facility 13,810 12,799 8 % Amortization of loan costs 3,256 2,914 12 % Capitalized interest (4,147) — 100 % Other 150 60 150 % Total interest expense $ 57,069 $ 59,773 (5) % Interest expense per Mcfe $ 0.15 $ 0.17 (12) % Interest expense on our Credit Facility increased 8% for the year ended December 31, 2023, compared to the year ended December 31, 2022, as a result of increased interest rates resulting from the current inflationary environment.
Our hedging program incurred cash settlements of $1,053.8 million for the year ended December 31, 2022, compared to $322.9 million for the Prior Successor Period and $3.4 million for the Prior Predecessor Period. 42 Table of Contents Index to Financial Statements Lease Operating Expenses (in thousands, except per unit) 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 Lease operating expenses Utica $ 43,775 $ 21,841 $ 13,991 SCOOP 21,015 10,247 5,449 Other 1 84 84 Total lease operating expenses $ 64,790 $ 32,172 $ 19,524 Lease operating expenses per Mcfe Utica $ 0.17 $ 0.13 $ 0.13 SCOOP 0.20 0.17 0.22 Other 0.15 0.81 2.15 Total lease operating expenses per Mcfe $ 0.18 $ 0.14 $ 0.14 The increase in total LOE when comparing the year ended December 31, 2022, to the Prior Successor Period, was primarily driven by the timing of our emergence from bankruptcy.
Lease Operating Expenses (in thousands, except per unit) Successor Year Ended December 31, 2023 Year Ended December 31, 2022 % Change Lease operating expenses Utica & Marcellus $ 44,394 $ 43,775 1 % SCOOP 24,254 21,015 15 % Total lease operating expenses $ 68,648 $ 64,790 6 % Lease operating expenses per Mcfe Utica & Marcellus $ 0.16 $ 0.17 (6) % SCOOP 0.25 0.20 25 % Total lease operating expenses per Mcfe $ 0.18 $ 0.18 — % The increase in total LOE for the year ended December 31, 2023, compared to the year ended December 31, 2022, was primarily the result of a 7% increase in production.
The increase on a per unit basis when comparing the year ended December 31, 2022, to the Prior Successor Period, was primarily due to an increase in minimum volume commitments, combined with an increase in rates on certain gathering and transportation systems.
Transportation, Gathering, Processing and Compression (in thousands, except per unit) Successor Year Ended December 31, 2023 Year Ended December 31, 2022 % Change Transportation, gathering, processing and compression $ 348,631 $ 357,246 (2) % Transportation, gathering, processing and compression per Mcfe $ 0.91 $ 1.00 (9) % Transportation, gathering, processing and compression for the year ended December 31, 2023, compared to the year ended December 31, 2022, decreased on a per unit basis primarily as a result of lower minimum volume commitments as a result of our 7% increase in production.
See Note 5 of our consolidated financial statements for additional discussion of the Credit Facility.
See Note 5 of our consolidated financial statements for additional discussion of the Credit Facility. On October 27, 2023, Gulfport completed its semi-annual borrowing base redetermination during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million.
Loss (Gain) on Debt Extinguishment During the Prior Successor Period, the Company recognized a loss of $3.0 million associated with the extinguishment of capitalized commitment fees related to the Exit Credit Facility as discussed in Note 5 of our consolidated financial statements.
The increase was primarily related to a $6.8 million increase in debt issuance costs as a result of the Third Amendment to the Credit Facility which increased the commitment and redetermined its borrowing base, as discussed in Note 5 of our consolidated financial statements.
A valuation allowance for our deferred tax assets is established, if in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2022, a valuation allowance of $803.3 million had been established to fully offset our net deferred tax asset on our accompanying consolidated balance sheet. Revenue Recognition.
A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized.
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Financial Statements and Supplementary Data” of this report.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeExecutive management is involved in all risk management activities and the Board of Directors reviews our derivative program at its quarterly Board meetings. We believe we have sufficient internal controls to prevent unauthorized trading. 53 Table of Contents Index to Financial Statements We use derivative instruments to achieve our risk management objectives, including swaps, options and costless collars.
Biggest changeExecutive management is involved in all risk management activities and the Board of Directors reviews our derivative program at its quarterly board meetings. We use derivative instruments to achieve our risk management objectives, including swaps, options and costless collars. All of these are described in more detail below.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Natural Gas, Oil and Natural Gas Liquids Derivative Instruments. Our results of operations and cash flows are impacted by changes in market prices for oil, natural gas and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Natural Gas, Oil and Natural Gas Liquids Derivative Instruments. Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments.
At the time of settlement, if the market price exceeds the fixed price of the call option, we would pay the counterparty the excess on sold call options, and we would receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we would receive the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party.
The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter into the original derivative position. We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves, discount factors and option pricing models. These estimates are compared to counterparty valuations for reasonableness.
The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter the original derivative position. We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves, discount factors and option pricing models. These estimates are compared to counterparty valuations for reasonableness.
We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering into a new trade that effectively reverses the current position.
We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering a new trade that effectively reverses the current position.
We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of likely production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels.
We determine the notional volume potentially subject to derivative contracts by reviewing our overall estimated future production levels, which are derived from extensive examination of existing producing reserve estimates and estimates of estimated production from new drilling. Production forecasts are updated at least monthly and adjusted if necessary to actual results and activity levels.
The actual fixed price on our derivative instruments is derived from the reference from third-party indices such as NYMEX. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.
The actual fixed prices on our derivative instruments is derived from the reference prices from third-party indices such as NYMEX. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.
However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument. For more information regarding the Company's commodity derivative transactions, refer to Note 13 of our consolidated financial statements. 54 Table of Contents Index to Financial Statements Counterparty Credit Risk.
However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument. For more information regarding the Company's commodity derivative transactions, refer to Note 13 of our consolidated financial statements. Counterparty Credit Risk.
As of December 31, 2022, our natural gas, oil, and NGL derivative instruments consistent of the following types of instruments: • Swaps : We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity.
As of December 31, 2023, our natural gas, oil, and NGL derivative instruments consisted of the following types of instruments: • Swaps : We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity.
Our hedge arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or commodity prices increase. At December 31, 2022, we had a net liability derivative position of $347.9 million, compared to a net liability derivative position of $402.0 million as of December 31, 2021.
Our hedge arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or commodity prices increase. At December 31, 2023, we had a net asset derivative position of $240.2 million, compared to a net liability derivative position of $347.9 million as of December 31, 2022.
In exchange for higher fixed prices on certain of our swap trades, we may sell call options. • Basis Swaps : These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point.
In exchange for higher fixed prices on certain of our swap trades, we may sell call options. 55 Table of Contents Inde x to Financial Statements • Basis Swaps : These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point.
All of these are described in more detail below. We typically use swaps for a large portion of the oil and natural gas price risk we hedge. We have also sold calls in the past to take advantage of premiums associated with market price volatility.
We typically use swaps for a large portion of the oil and natural gas price risk we hedge. We have also sold calls in the past to take advantage of premiums associated with market price volatility.
As of December 31, 2022, we did not have any interest rate swaps to hedge our interest risks. 55 Table of Contents Index to Financial Statements
As of December 31, 2023, we did not have any interest rate swaps to hedge our interest risks. 56 Table of Contents Inde x to Financial Statements
At December 31, 2022, we had $145.0 million in borrowings outstanding under our Credit Facility which bore interest at the weighted average rate of 7.39%. A 1% increase in the average interest rate would increase interest expense by approximately $1.5 million based on outstanding borrowings under our Credit Facility at December 31, 2022.
At December 31, 2023, we had $118.0 million in borrowings outstanding under our Credit Facility which bore interest at the weighted average rate of 8.15% for the year ended December 31, 2023. A 1% increase in the average interest rate would increase interest expense by approximately $1.2 million based on outstanding borrowings under our Credit Facility at December 31, 2023.
Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have increased our liability by approximately $171.9 million, while a 10% decrease in underlying commodity prices would have decreased our liability by approximately $165.6 million.
Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have decreased our asset by approximately $88.3 million, while a 10% decrease in underlying commodity prices would have increased our asset by approximately $86.5 million.

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