Annual report pursuant to Section 13 and 15(d)

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

v3.19.3.a.u2
Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited)
 12 Months Ended
Dec. 31, 2019
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 24.9999% interest in Grizzly, which interest is shown 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
 
2019
 
2018
 
(In thousands)
Proved properties
$
8,909,069

 
$
7,153,799

Unproved properties
1,686,666

 
2,873,037

 
10,595,735

 
10,026,836

Accumulated depreciation, depletion, amortization and impairment
(7,191,957
)
 
(4,613,293
)
Net capitalized costs
$
3,403,778

 
$
5,413,543

 
 
 
 
Equity investment in Grizzly Oil Sands ULC
 
 
 
Proved properties
$
64,476

 
$
67,475

Unproved properties
85,395

 
79,605

 
149,871

 
147,080

Accumulated depreciation, depletion, amortization and impairment
(1,634
)
 
(1,553
)
Net capitalized costs
$
148,237

 
$
145,527


Costs Incurred in Oil and Gas Property Acquisition and Development Activities
 
2019
 
2018
 
2017
 
(In thousands)
Acquisition
$
37,598

 
$
119,444

 
$
1,946,416

Development
594,673

 
714,269

 
1,138,951

Exploratory
9,762

 
22,081

 
9,058

Total
$
642,033

 
$
855,794

 
$
3,094,425

 
 
 
 
 
 
Equity investment in Grizzly Oil Sands ULC
 
 
 
 
 
Acquisition
$
—

 
$
238

 
$
503

Development
—

 
—

 
—

Exploratory
849

 
—

 
—

Total
$
849

 
$
238

 
$
503



Capitalized interest is included as part of the cost of oil and natural gas properties. The Company capitalized $3.4 million, $4.5 million and $9.5 million during 2019, 2018, and 2017, 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 $30.1 million, $37.7 million and $35.7 million during 2019, 2018, and 2017, 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.
 
2019
 
2018
 
2017
 
(In thousands)
Revenues
$
1,137,648

 
$
1,478,523

 
$
1,106,624

Production costs
(403,294
)
 
(415,308
)
 
(350,367
)
Depletion
(539,379
)
 
(476,517
)
 
(358,792
)
Impairment
(2,039,770
)
 
—

 
—

Income tax benefit
7,563

 
68

 
240

Results of operations from producing activities
$
(1,837,232
)
 
$
586,766

 
$
397,705

Depletion per Mcf of gas equivalent (Mcfe)
$
1.08

 
$
0.96

 
$
0.90

 
 
 
 
 
 
Results of Operations from equity method investment in Grizzly Oil Sands ULC
 
 
 
 
 
Revenues
$
—

 
$
—

 
$
—

Production costs
—

 
—

 
—

Depletion
—

 
—

 
—

Income tax expense
—

 
—

 
—

Results of operations from producing activities
$
—

 
$
—

 
$
—


Oil and Natural Gas Reserves
The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2019, 2018 and 2017 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, 2019, 2018 and 2017, in accordance with guidelines of the SEC applicable to reserves estimates. Volumes for oil are stated in thousands of barrels (Mbbls) and volumes for natural gas are stated in millions of cubic feet (MMcf). The prices used for the 2019 reserve report are $55.85 per barrel of oil, $2.58 per MMbtu and $21.25 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, 2018 and 2017 for reserve report purposes are $65.56 per barrel, $3.10 per MMbtu and $32.02 per barrel for NGL and $51.34 per barrel, $2.98 per MMbtu and $18.40 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.
 
2019
 
2018
 
2017
 
Oil
 
Natural Gas
 
NGL
 
Oil
 
Natural Gas
 
NGL
 
Oil
 
Natural Gas
 
NGL
 
(Mbbls)
 
(MMcf)
 
(Mbbls)
 
(Mbbls)
 
(MMcf)
 
(Mbbls)
 
(Mbbls)
 
(MMcf)
 
(Mbbls)
Proved Reserves
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning of the period
21,050

 
4,133,889

 
80,520

 
19,157

 
4,825,310

 
75,766

 
5,546

 
2,167,068

 
20,127

Purchases in oil and natural gas reserves in place
—

 
—

 
—

 
—

 
—

 
—

 
15,132

 
1,098,644

 
53,617

Extensions and discoveries
3,612

 
997,014

 
12,992

 
5,205

 
622,271

 
9,631

 
951

 
1,594,734

 
4,619

Sales of oil and natural gas reserves in place
(2,369
)
 
(62,557
)
 
—

 
(134
)
 
(43,444
)
 
(112
)
 
—

 
—

 
—

Revisions of prior reserve estimates
(1,749
)
 
(561,890
)
 
(26,909
)
 
(377
)
 
(826,506
)
 
1,228

 
107

 
314,925

 
2,737

Current production
(2,186
)
 
(458,178
)
 
(5,074
)
 
(2,801
)
 
(443,742
)
 
(5,993
)
 
(2,579
)
 
(350,061
)
 
(5,334
)
End of period
18,357

 
4,048,279

 
61,528

 
21,050

 
4,133,889

 
80,520

 
19,157

 
4,825,310

 
75,766

Proved developed reserves
7,887

 
1,757,303

 
29,898

 
9,570

 
1,813,184

 
40,810

 
10,245

 
1,616,930

 
36,247

Proved undeveloped reserves
10,470

 
2,290,976

 
31,630

 
11,480

 
2,320,705

 
39,710

 
8,912

 
3,208,380

 
39,519

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Equity investment in Grizzly Oil Sands ULC
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Beginning of the period
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Purchases in oil and natural gas reserves in place
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Extensions and discoveries
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Revisions of prior reserve estimates
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Current production
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

End of period
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Proved developed reserves
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Proved undeveloped reserves
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—


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 Shale 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.
Subsequent to completion of estimates of proved reserves at December 31, 2019, management lowered its 2020 budgeted capital expenditures due to the expectation of continued depressed commodities pricing. All PUD locations in the
December 31, 2019 proved reserve estimates remained in the development plan and are scheduled to be drilled within five years from the time of initial booking. However, development of several PUD locations was delayed. Management analyzed the impact of the timing of development and determined total proved reserves was materially unchanged and the total PV-10 value of reserves decreased by approximately 0.5%. Management determined these changes were immaterial and did not adjust its estimates of proved reserves at December 31, 2019 for the impact of these timing changes.
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 Shale 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.
In 2017, the Company purchased 1.5 Tcfe through its acquisition of SCOOP properties discussed in Note 2. Also in 2017, the Company experienced extensions and discoveries of 1.6 Tcfe of estimated proved reserves primarily attributable to the continued development of the Company's Utica Shale acreage. In 2017, the Company experienced upward revisions of 201.3 Bcfe in estimated proved reserves due to an increase in well performance, 214.1 Bcfe due to the increase in pricing and 95.9 Bcfe due to changes in its ownership interests. These positive revisions were partially offset by downward revisions of 133.0 Bcfe due to a decline in well performance specific to one area in the Company's Utica field and a decline of 45.7 Bcfe in estimated proved reserves in 2017 primarily due to the exclusion of ten PUD locations in the Company's Utica field, five of which were operated by the Company and five of which were operated by other operators, that were excluded due to changes in drilling schedules. Additional downward revision of 0.6 Bcfe was due to the removal of two PUD locations in the Company's Southern Louisiana fields that had not been drilled within five years of initial booking.
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, 2019, 2018 and 2017 using an unweighted average first-of-the-month price for the period January through December 31, 2019, 2018 and 2017.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves  
 
Year ended December 31,
 
2019
 
2018
 
2017
 
(In thousands)
Future cash flows
$
10,451,179

 
$
14,483,197

 
$
11,202,692

Future development and abandonment costs
(2,058,374
)
 
(2,437,853
)
 
(3,005,217
)
Future production costs
(4,512,940
)
 
(5,067,554
)
 
(2,152,821
)
Future production taxes
(332,525
)
 
(455,840
)
 
(289,944
)
Future income taxes
—

 
(943,293
)
 
(573,965
)
Future net cash flows
3,547,340

 
5,578,657

 
5,180,745

10% discount to reflect timing of cash flows
(1,843,753
)
 
(2,595,932
)
 
(2,537,181
)
Standardized measure of discounted future net cash flows
$
1,703,587

 
$
2,982,725

 
$
2,643,564

 
 
 
 
 
 
Equity investment in Grizzly Oil Sands ULC Standardized measure of discounted cash flows
 
 
 
 
 
Future cash flows
$
—

 
$
—

 
$
—

Future development and abandonment costs
—

 
—

 
—

Future production costs
—

 
—

 
—

Future production taxes
—

 
—

 
—

Future income taxes
—

 
—

 
—

Future net cash flows
—

 
—

 
—

10% discount to reflect timing of cash flows


 


 


Standardized measure of discounted future net cash flows
$
—

 
$
—

 
$
—


Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
 
Year ended December 31,
 
2019
 
2018
 
2017
 
(In thousands)
Sales and transfers of oil and gas produced, net of production costs
$
(734,354
)
 
$
(1,063,215
)
 
$
(756,257
)
Net changes in prices, production costs, and development costs
(1,372,443
)
 
590,519

 
913,714

Acquisition of oil and gas reserves in place
—

 
—

 
703,866

Extensions and discoveries
388,151

 
519,137

 
618,039

Previously estimated development costs incurred during the period
405,979

 
402,156

 
390,673

Revisions of previous quantity estimates, less related production costs
(321,397
)
 
(356,933
)
 
155,200

Sales of oil and gas reserves in place
(48,547
)
 
(25,882
)
 
—

Accretion of discount
298,273

 
264,356

 
68,804

Net changes in income taxes
424,628

 
(185,157
)
 
(231,545
)
Change in production rates and other
(319,428
)
 
194,180

 
93,030

Total change in standardized measure of discounted future net cash flows
$
(1,279,138
)
 
$
339,161

 
$
1,955,524

 
 
 
 
 
 
Equity investment in Grizzly Oil Sands ULC Changes in standardized measure of discounted cash flows
 
 
 
 
 
Sales and transfers of oil and gas produced, net of production costs
$
—

 
$
—

 
$
—

Net changes in prices, production costs, and development costs
—

 
—

 
—

Acquisition of oil and gas reserves in place
—

 
—

 
—

Extensions and discoveries
—

 
—

 
—

Previously estimated development costs incurred during the period
—

 
—

 
—

Revisions of previous quantity estimates, less related production costs
—

 
—

 
—

Accretion of discount
—

 
—

 
—

Net changes in income taxes
—

 
—

 
—

Change in production rates and other
—

 
—

 
—

Total change in standardized measure of discounted future net cash flows
$
—

 
$
—

 
$
—