Annual report pursuant to Section 13 and 15(d)

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)

v3.24.0.1
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)
 12 Months Ended
Dec. 31, 2023
Extractive Industries [Abstract]  
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)
The Company is making the following supplemental disclosures of oil and gas activities, in accordance with the full cost method of accounting for its oil and gas exploration and development activities. The Company owns a 24.5% interest in Grizzly. However, Grizzly did not have any material activity or proved reserves in the years presented below. As such, amounts related to Grizzly have been omitted below.
The following table provides historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United States:
Capitalized Costs Related to Oil and Gas Producing Activities (in thousands)
Successor
Year Ended December 31, 2023 Year Ended December 31, 2022
Proved properties $ 2,904,519  $ 2,418,666 
Unproved properties 204,233  178,472 
Total oil and natural gas properties 3,108,752  2,597,138 
Accumulated depletion and amortization (862,253) (543,780)
Net capitalized costs $ 2,246,499  $ 2,053,358 
Costs Incurred in Oil and Gas Property Acquisition and Development Activities (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
Acquisition $ 93,905  $ 29,675  $ 13,411  $ 3,922 
Development 419,431  441,458  191,193  112,986 
Exploratory —  —  —  — 
Total $ 513,336  $ 471,133  $ 204,604  $ 116,908 

Capitalized interest is included as part of the cost of oil and natural gas properties. The Company did not capitalize interest expense for the year ended December 31, 2022, or Prior Predecessor Period. The Company capitalized $4.1 million for the year ended December 31, 2023, and $0.2 million during the Prior Successor Period based on the Company's weighted average cost of borrowings used to finance expenditures.
In addition to capitalized interest, the Company capitalized internal costs totaling $22.8 million, $20.2 million, $11.9 million and $8.0 million during the years ended December 31, 2023, December 31, 2022, Prior Successor Period and Prior Predecessor Period, respectively, which were directly related to the acquisition, exploration and development of the Company's oil and natural gas properties.
Results of Operations for Producing Activities (in thousands)
The following table sets forth the revenues and expenses related to the production and sale of oil and natural gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas production.
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
Revenues $ 1,051,383  $ 2,330,859  $ 1,092,584  $ 410,276 
Production costs (450,996) (482,175) (274,428) (192,959)
Depletion (318,473) (266,449) (159,518) (60,831)
Impairment —  —  (117,813) — 
Income tax benefit 525,156  —  39  7,968 
Results of operations from producing activities $ 807,070  $ 1,582,235  $ 540,864  $ 164,454 
Depletion per Mcf of gas equivalent (Mcfe) $ 0.83  $ 0.74  $ 0.69  $ 0.45 
Oil and Natural Gas Reserves
The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2023, 2022 and 2021 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2023, 2022 and 2021, in accordance with guidelines of the SEC applicable to reserves estimates. The prices used for the 2023 reserve report are $78.21 per barrel of oil, $2.64 per MMbtu and $31.42 per barrel for NGL, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2022 and 2021 for reserve report purposes are $94.14 per barrel, $6.36 per MMbtu and $47.86 per barrel for NGL and $66.55 per barrel, $3.60 per MMbtu and $31.90 per barrel for NGL, respectively.
Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.
Oil (MMBbl) Natural Gas (Bcf) NGL (MMBbl) Natural Gas Equivalent (Bcfe)
Proved Reserves
December 31, 2020 (Predecessor) 13  2,281  38  2,588 
Purchases of reserves —  —  —  — 
Extensions and discoveries 2  617  11  695 
Sales of reserves —  —  —  — 
Revisions of prior reserve estimates 2  913  9  982 
Current production (2) (333) (4) (366)
December 31, 2021 (Successor) 16  3,478  54  3,898 
Purchases of reserves —  —  —  — 
Extensions and discoveries 3  391  5  439 
Sales of reserves —  —  —  — 
Revisions of prior reserve estimates —  66  —  70 
Current production (2) (322) (4) (359)
December 31, 2022 (Successor) 18  3,612  54  4,048 
Purchases of reserves —  —  —  — 
Extensions and discoveries 6  875  14  996 
Sales of reserves —  —  —  — 
Revisions of prior reserve estimates (4) (411) (1) (445)
Current production (1) (350) (4) (385)
December 31, 2023 (Successor) 19  3,725  63  4,214 
Proved developed reserves
December 31, 2020 (Predecessor) 7  1,358  22  1,527 
December 31, 2021 (Successor) 8  1,928  31  2,165 
December 31, 2022 (Successor) 9  2,034  34  2,295 
December 31, 2023 (Successor) 6  1,980  31  2,203 
Proved undeveloped reserves
December 31, 2020 (Predecessor) 7  923  16  1,061 
December 31, 2021 (Successor) 8  1,550  22  1,733 
December 31, 2022 (Successor) 9  1,578  20  1,752 
December 31, 2023 (Successor) 12  1,746  32  2,011 
Totals may not sum or recalculate due to rounding.
In 2023, the Company experienced extensions of 995.7 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions, 789.2 Bcfe was attributable to the addition of 67 Utica PUD locations, 88.6 Bcfe was attributable to the addition of 12 Marcellus PUD locations, and 110.4 Bcfe was attributable to the addition of 14 SCOOP PUD locations. The Company experienced total downward revisions of 444.9 Bcfe in estimated proved reserves. 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. 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. The development schedule changes reflect our ongoing commitment to optimizing the long-term plan to best develop our asset, maximize cash flow, and overall economic returns. These locations excluded from our SEC reserves report remain in Gulfport's development plan. Additionally, downward revisions of 159.7 Bcfe due to commodity price changes. 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 increased 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. Finally, downward revisions of 49.1 Bcfe were a result of a combination of various economic assumption updates.
In 2022, the Company experienced extensions of 438.9 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions, 295.9 Bcfe was attributable to the addition of 36 PUD locations in the Utica, 72.1 Bcfe was attributable to the addition of 8 PUD locations in the Marcellus and 65.4 Bcfe was attributable to the addition of 5 PUD locations in the SCOOP. The Company experienced total upward revisions of approximately 69.7 Bcfe in estimated proved reserves, of which 47.7 Bcfe was the result of improved commodity prices. The 12-month average price for natural gas increased from $3.60 per MMBtu for 2021 to $6.36 per MMBtu for 2022, the 12-month average price for NGL increased from $31.90 per barrel for 2021 to $47.86 per barrel for 2022, and the 12-month average price for crude oil increased from $66.55 per barrel for 2021 to $94.14 per barrel for 2022. Upward revisions of 144.5 Bcfe were a result of an increase in working interest and net revenue interests as a result of our successful leasing efforts through 2022. Downward revisions of 95.6 Bcfe were experienced as a result of the SEC five-year development window, which removed 4 PUD locations in the Utica and 5 PUD locations in the SCOOP. The development plan changes reflect our commitment to optimizing the long-term development schedule to maximize cash flow and overall economic returns. A small downward revision of 26.9 Bcfe was primarily a result of performance changes to several wells and changes in PUD location forecasts.
In 2021, the Company experienced extensions of 694.6 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica and SCOOP acreage. Of the total extensions, 352.2 Bcfe was attributable to the addition of 29 PUD locations in the Utica, 342.2 Bcfe was attributable to the addition of 34 PUD locations in the SCOOP. The Company experienced total upward revisions of approximately 982.2 Bcfe in estimated proved reserves, of which 889.2 Bcfe was the result of improved commodity prices. The 12-month average price for natural gas increased from $1.99 per MMBtu for 2020 to $3.60 per MMBtu for 2021, the 12-month average price for NGL increased from $15.40 per barrel for 2020 to $31.90 per barrel for 2021, and the 12-month average price for crude oil increased from $39.54 per barrel for 2020 to $66.55 per barrel for 2021. Upward revisions of 157.6 Bcfe were experienced from a combination of well performance, operating and development cost improvements and working interest changes. This was partially offset by a downward revision of 64.6 Bcfe, which was primarily a result of the exclusion of 4 PUD locations in the Utica when changes in the Company's schedule moved development of these PUD locations beyond five years of initial booking. The development plan change reflects the Company's commitment to capital discipline, funding future activities within cash flow and ongoing optimization of our development plan. Finally, during 2021, we sold approximately 0.2 Bcfe of proved oil and natural gas reserves through various sales of our non-operated interests in our other non-core assets.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2023, 2022 and 2021 using an unweighted average first-of-the-month price for the period January through December 31, 2023, 2022 and 2021. The average gas prices used were $2.64, $6.36 and $3.60 for the periods ended December 31, 2023, 2022 and 2021, respectively. The average oil prices used were $78.21, $94.14 and $66.55, for the periods ended December 31, 2023, 2022 and 2021, respectively. The average NGL prices used were $31.42, $47.86 and $31.90, for the periods ended December 31, 2023, 2022 and 2021, respectively.
Year ended operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop proved developed non-producing and proved undeveloped reserves are approximately $246.3 million in 2024, $328.7 million in 2025 and $282.6 million in 2026. Estimated future development costs include capital spending on major development projects. Gulfport believes cash flow from its operating activities, cash on hand and borrowings under its Credit Facility will be sufficient to cover these estimated future development costs.
The assumptions used to derive the standardized measure of discounted future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes but should not be solely relied upon in evaluating Gulfport or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below:
•Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations.
•Future operating and capital costs will likely differ from those required to be used in these calculations and do not reflect cost savings of Company owned midstream operations on future operating expenses.
•Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and condensate and gas may cause production rates in future years to vary significantly from those rates used in the calculations.
•Future revenues may be subject to different production, severance and property taxation rates.
•The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.
The following table summarizes estimated future net cash flows from natural gas and crude oil reserves (in millions):
Successor
Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Future cash flows $ 12,338  $ 26,677  $ 14,938 
Future development and abandonment costs (1,625) (1,588) (1,141)
Future production costs (5,641) (5,872) (5,227)
Future production taxes (303) (553) (336)
Future income taxes (63) (2,609) (437)
Future net cash flows 4,706  16,055  7,797 
10% discount to reflect timing of cash flows (2,323) (7,776) (3,659)
Standardized measure of discounted future net cash flows $ 2,383  $ 8,279  $ 4,138 
Totals may not sum or recalculate due to rounding.
Future development and abandonment costs include not only development costs but also all future costs to settle asset retirement obligations. The following table summarizes the total of all future costs to settle asset retirement obligations that are included in future development and abandonment costs above (in millions):
Successor
Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Future asset retirement obligations $ 229  $ 222  $ 205 
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The principal source of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below (in millions):
Successor
Year Ended December 31, 2023 Year Ended December 31, 2022 Year Ended December 31, 2021
Sales and transfers of oil and gas produced, net of production costs $ (600) $ (1,849) $ (1,035)
Net changes in prices, production costs, and development costs (7,181) 5,130  2,596 
Acquisition of oil and gas reserves in place —  —  — 
Extensions and discoveries 581  941  639 
Previously estimated development costs incurred during the period 263  204  149 
Revisions of previous quantity estimates, less related production costs (278) 154  858 
Sales of oil and gas reserves in place —  (1) (1)
Accretion of discount 828  414  54 
Net changes in income taxes 1,219  (1,067) (178)
Change in production rates and other (728) 215  516 
Total change in standardized measure of discounted future net cash flows $ (5,896) $ 4,141  $ 3,598