Annual report pursuant to Section 13 and 15(d)

Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)

v3.20.4
Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)
 12 Months Ended
Dec. 31, 2020
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 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
2020 2019
(In thousands)
Proved properties $ 9,359,866  $ 8,909,069 
Unproved properties 1,457,043  1,686,666 
10,816,909  10,595,735 
Accumulated depreciation, depletion, amortization and impairment (8,778,759) (7,191,957)
Net capitalized costs $ 2,038,150  $ 3,403,778 
Costs Incurred in Oil and Gas Property Acquisition and Development Activities
2020 2019 2018
(In thousands)
Acquisition $ 15,260  $ 37,598  $ 119,444 
Development 276,622  594,673  714,269 
Exploratory —  9,762  22,081 
Total $ 291,882  $ 642,033  $ 855,794 

Capitalized interest is included as part of the cost of oil and natural gas properties. The Company capitalized $0.9 million, $3.4 million and $4.5 million during 2020, 2019, 2018, 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 $25.0 million, $30.1 million and $37.7 million during 2020, 2019, and 2018, 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
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.
2020 2019 2018
(In thousands)
Revenues $ 801,251  $ 1,354,766  $ 1,675,180 
Production costs (537,609) (620,412) (611,965)
Depletion (229,702) (539,379) (476,517)
Impairment (1,357,099) (2,039,770) — 
Income tax (expense) benefit (7,290) 7,563  68 
Results of operations from producing activities $ (1,330,449) $ (1,837,232) $ 586,766 
Depletion per Mcf of gas equivalent (Mcfe) $ 0.61  $ 1.08  $ 0.96 
Oil and Natural Gas Reserves
The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2020, 2019 and 2018 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, 2020, 2019 and 2018, in accordance with guidelines of the SEC applicable to reserves estimates. The prices used for the 2020 reserve report are $39.54 per barrel of oil, $1.99 per MMbtu and $15.40 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, 2019 and 2018 for reserve report purposes are $55.85 per barrel, $2.58 per MMbtu and $21.25 per barrel for NGL and $65.56 per barrel, $3.10 per MMbtu and $32.02 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, 2017 19  4,825  76  5,395 
Purchases of reserves —  —  —  — 
Extensions and discoveries 5  622  10  711 
Sales of reserves —  (43) —  (45)
Revisions of prior reserve estimates —  (827) 1  (821)
Current production (3) (444) (6) (497)
December 31, 2018 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 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 13  2,281  38  2,588 
Proved developed reserves
December 31, 2018 10  1,813  41  2,115 
December 31, 2019 8  1,757  30  1,984 
December 31, 2020 7  1,358  22  1,527 
Proved undeveloped reserves
December 31, 2018 11  2,321  40  2,628 
December 31, 2019 10  2,291  32  2,544 
December 31, 2020 7  923  16  1,061 
Totals may not sum or recalculate due to rounding.
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 reflects 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.
In 2018, the Company experienced extensions and discoveries of 711.2 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 and discoveries, 556.3 Bcfe was attributable to the addition of 75 PUD locations in the Utica field, 90.1 Bcfe was attributable to the addition of 11 PUD locations in the SCOOP field and 3.0 Bcfe was attributable to the addition of 13 PUD locations in the Southern Louisiana fields as a result of the Company's current development plan that refocused some activity within existing fields. This change reflects the Company's ongoing efforts to optimize the development program with well selection based on economic returns, commodity mix and surface considerations.
In 2018, the Company experienced downward revisions of 1.0 Tcfe in estimated proved reserves with the exclusion of 127 PUD locations in the Company's Utica field and 12 PUD locations in the Company's SCOOP field, which was primarily the result of changes in the Company's development schedule moving development in excess of five years from initial booking. The development plan change, as approved by the Company's senior management and board of directors, is a result of continued focus on free cash flow generation. This downward revision was partially offset by upward revisions of 82.4 Bcfe in estimated proved reserves in 2018 due to changes in wellbore lateral length, 67.6 Bcfe due to changes in ownership interest, 27.9 Bcfe due to an increase in pricing and 8.3 Bcfe due to changes in well performance. In addition, the Company sold approximately 44.9 Bcfe of proved undeveloped oil and natural gas reserves associated with various non-operated interests, the majority of which were in the Company's Utica field.
Discounted Future Net Cash Flows
The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2020, 2019 and 2018 using an unweighted average first-of-the-month price for the period January through December 31, 2020, 2019 and 2018.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves  
  Year ended December 31,
  2020 2019 2018
(In millions)
Future cash flows $ 4,079  $ 10,451  $ 14,483 
Future development and abandonment costs (652) (2,058) (2,438)
Future production costs (2,325) (4,513) (5,068)
Future production taxes (137) (333) (456)
Future income taxes —  —  (943)
Future net cash flows 965  3,547  5,578 
10% discount to reflect timing of cash flows (425) (1,844) (2,596)
Standardized measure of discounted future net cash flows $ 540  $ 1,703  $ 2,982 
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
  Year ended December 31,
  2020 2019 2018
(In millions)
Sales and transfers of oil and gas produced, net of production costs $ (264) $ (734) $ (1,063)
Net changes in prices, production costs, and development costs (954) (1,372) 591 
Acquisition of oil and gas reserves in place —  —  — 
Extensions and discoveries 38  388  519 
Previously estimated development costs incurred during the period 215  406  402 
Revisions of previous quantity estimates, less related production costs (255) (321) (357)
Sales of oil and gas reserves in place (6) (49) (26)
Accretion of discount 170  298  264 
Net changes in income taxes —  425  (185)
Change in production rates and other (109) (319) 194 
Total change in standardized measure of discounted future net cash flows $ (1,165) $ (1,278) $ 339