Annual report pursuant to Section 13 and 15(d)

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

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)
 12 Months Ended
Dec. 31, 2021
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 is historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United States:
Capitalized Costs Related to Oil and Gas Producing Activities (in thousands)
Year ended December 31,
Successor Predecessor
2021 2020
Proved properties $ 1,917,833  $ 9,359,866 
Unproved properties 211,007  1,457,043 
Total oil and natural gas properties 2,128,840  10,816,909 
Accumulated depreciation, depletion, amortization and impairment (277,331) (8,778,759)
Net capitalized costs $ 1,851,509  $ 2,038,150 
Costs Incurred in Oil and Gas Property Acquisition and Development Activities (in thousands)
Successor Predecessor
Period from May 18, 2021 through December 31, 2021 Period from January 1, 2021 through May 17, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Acquisition $ 13,411  $ 3,922  $ 15,260  $ 37,598 
Development 191,193  112,986  276,622  594,673 
Exploratory —  —  —  9,762 
Total $ 204,604  $ 116,908  $ 291,882  $ 642,033 
Capitalized interest is included as part of the cost of oil and natural gas properties. The Company did not capitalize interest expense for the 2021 Predecessor Period, and capitalized $0.2 million, $0.9 million and $3.4 million during the Successor Period, 2020, 2019, respectively, based on the Company's weighted average cost of borrowings used to finance expenditures.
In addition to capitalized interest, the Company capitalized internal costs totaling $8.0 million, $11.9 million, $25.0 million and $30.1 million during the Predecessor Period, the Successor Period, and the years ended December 31, 2020, and 2019, 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 schedule sets forth the revenues and expenses related to the production and sale of oil and natural gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas production.
Successor Predecessor
Period from May 18, 2021 through December 31, 2021 Period from January 1, 2021 through May 17, 2021 Year Ended December 31, 2020 Year Ended December 31, 2019
Revenues $ 1,092,584  $ 410,276  $ 801,251  $ 1,354,766 
Production costs (274,428) (192,959) (537,609) (620,412)
Depletion (159,518) (60,831) (229,702) (539,379)
Impairment (117,813) —  (1,357,099) (2,039,770)
Income tax benefit (expense) 39  7,968  (7,290) 7,563 
Results of operations from producing activities $ 540,864  $ 164,454  $ (1,330,449) $ (1,837,232)
Depletion per Mcf of gas equivalent (Mcfe) $ 0.69  $ 0.45  $ 0.61  $ 1.08 
Oil and Natural Gas Reserves
The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2021, 2020 and 2019 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, 2021, 2020 and 2019, in accordance with guidelines of the SEC applicable to reserves estimates. The prices used for the 2021 reserve report are $66.55 per barrel of oil, $3.60 per MMbtu and $31.90 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, 2020 and 2019 for reserve report purposes are $39.54 per barrel, $1.99 per MMbtu and $15.40 per barrel for NGL and $55.85 per barrel, $2.58 per MMbtu and $21.25 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, 2018 (Predecessor) 21  4,134  81  4,743 
Purchases of reserves —  —  —  — 
Extensions and discoveries 4  997  13  1,097 
Sales of reserves (2) (63) —  (77)
Revisions of prior reserve estimates (2) (562) (27) (734)
Current production (2) (458) (5) (502)
December 31, 2019 (Predecessor) 18  4,048  62  4,528 
Purchases of reserves —  —  —  — 
Extensions and discoveries 1  216  3  240 
Sales of reserves —  (74) —  (75)
Revisions of prior reserve estimates (4) (1,564) (23) (1,725)
Current production (2) (345) (4) (380)
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 
Proved developed reserves
December 31, 2019 (Predecessor) 8  1,757  30  1,984 
December 31, 2020 (Predecessor) 7  1,358  22  1,527 
December 31, 2021 (Successor) 8  1,928  31  2,165 
Proved undeveloped reserves
December 31, 2019 (Predecessor) 10  2,291  32  2,544 
December 31, 2020 (Predecessor) 7  923  16  1,061 
December 31, 2021 (Successor) 8  1,550  22  1,733 
Totals may not sum or recalculate due to rounding.
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 acreages. Of the total extensions, 352.2 Bcfe was attributable to the addition of 29 PUD locations in the Utica field, 342.2 Bcfe was attributable to the addition of 34 PUD locations in the SCOOP field. 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 Company's Utica field 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.
In 2020, the Company experienced extensions of 239.8 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica and SCOOP acreages. Of the total extensions, 150.6 Bcfe was attributable to the addition of 14 PUD locations in the Utica field, 87.8 Bcfe was attributable to the addition of eight PUD locations in the SCOOP field. The Company experienced total downward revisions of approximately 1.7 Tcfe in estimated proved reserves, of which 1,268.4 Bcfe was the result of commodity price changes. Commodity prices experienced volatility
throughout 2020 and the 12-month average price for natural gas decreased from $2.58 per MMBtu for 2019 to $1.99 per MMBtu for 2020, the 12-month average price for NGL decreased from $21.25 per barrel for 2019 to $15.40 per barrel for 2020, and the 12-month average price for crude oil decreased from $55.85 per barrel for 2019 to $39.54 per barrel for 2020. An additional 720.3 Bcfe in downward revisions was a result of the exclusion of 48 PUD locations in the Utica field and 31 PUD locations in the SCOOP field, which was a result of changes in the Company's schedule that moved development of these PUD locations beyond five years of initial booking. The development plan change reflected the Company's commitment to capital discipline, funding future activities within cash flow and ongoing optimization of our development plan. Positive revisions of 263.8 Bcfe were experienced from a combination of operating and development cost improvements, well performance and working interest changes.
In 2019, the Company experienced extensions of 1.1 Tcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica and SCOOP acreages. Of the total extensions, 793.5 Bcfe was attributable to the addition of 72 PUD locations in the Utica field, 302.9 Bcfe was attributable to the addition of 37 PUD locations in the SCOOP field. The Company experienced total downward revisions of approximately 733.8 Bcfe in estimated proved reserves, of which 347.2 Bcfe was a result of the exclusion of nine PUD locations in the Utica field and 22 PUD locations in the SCOOP field, which was a result of changes in the Company's schedule that moved development of these PUD locations beyond five years of initial booking. The development plan change reflects the Company's commitment capital discipline and funding future activities within cash flow. An additional 296.4 Bcfe in downward revisions was the result of commodity price changes. Commodity prices experienced volatility throughout 2019 and the 12-month average price for natural gas decreased from $3.10 per MMBtu for 2018 to $2.58 per MMBtu for 2019, the 12- month average price for NGL decreased from $32.02 per barrel for 2018 to $21.25 per barrel for 2019, and the 12-month average price for crude oil decreased from $65.56 per barrel for 2018 to $55.85 per barrel for 2019. The Company also experienced downward revisions of 90.2 Bcfe from a combination of working interest changes, optimization of well design in the current commodity price environment and well performance.
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, 2021, 2020 and 2019 using an unweighted average first-of-the-month price for the period January through December 31, 2021, 2020 and 2019. The average gas prices used were $3.60, $1.99, and $2.58 for the periods ended December 31, 2021, 2020, and 2019, respectively. The average oil prices used were $66.55, $39.54, and $55.85, for the periods ended December 31, 2021, 2020, and 2019, respectively. The average NGL prices used were $31.90, $15.40, and $21.25, for the periods ended December 31, 2021, 2020, and 2019, 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 undeveloped reserves are approximately $234.1 million in 2022, $184.0 million in 2023 and $178.7 million in 2024. 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 New 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):
  Year ended December 31,
Successor Predecessor
  2021 2020 2019
Future cash flows $ 14,938  $ 4,079  $ 10,451 
Future development and abandonment costs (1,141) (652) (2,058)
Future production costs (5,227) (2,325) (4,513)
Future production taxes (336) (137) (333)
Future income taxes (437) —  — 
Future net cash flows 7,797  965  3,547 
10% discount to reflect timing of cash flows (3,659) (425) (1,844)
Standardized measure of discounted future net cash flows $ 4,138  $ 540  $ 1,703 
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):
  Year ended December 31,
Successor Predecessor
  2021 2020 2019
Sales and transfers of oil and gas produced, net of production costs $ (1,035) $ (264) $ (734)
Net changes in prices, production costs, and development costs 2,596  (954) (1,372)
Acquisition of oil and gas reserves in place —  —  — 
Extensions and discoveries 639  38  388 
Previously estimated development costs incurred during the period 149  215  406 
Revisions of previous quantity estimates, less related production costs 858  (255) (321)
Sales of oil and gas reserves in place (1) (6) (49)
Accretion of discount 54  170  298 
Net changes in income taxes (178) —  425 
Change in production rates and other 516  (109) (319)
Total change in standardized measure of discounted future net cash flows $ 3,598  $ (1,165) $ (1,278)