Gulfport Energy Corporation Reports Third Quarter 2018 Results
OKLAHOMA CITY, Nov. 01, 2018 (GLOBE NEWSWIRE) -- Gulfport Energy Corporation (NASDAQ: GPOR) (“Gulfport” or the “Company”) today reported financial and operational results for the three-months and nine-months ended September 30, 2018 and provided an update on its 2018 activities. Key information includes the following:
Net production averaged 1,427.5 MMcfe per day during the third quarter of 2018.
Net income of $95.2 million, or $0.55 per diluted share, for the third quarter of 2018.
Adjusted net income (as defined and reconciled below) of $84.6 million, or $0.49 per diluted share, for the third quarter of 2018.
Adjusted EBITDA (as defined and reconciled below) of $238.8 million for the third quarter of 2018.
Budgeted 2018 total capital expenditures to be approximately $815 million.
Increased estimated 2018 full year net production and now forecast an average of 1,360 MMcfe to 1,370 MMcfe per day, an increase of approximately 25% to 26% over the average daily net production of 1,089.2 MMcfe per day during 2017.
2018 hedge position of approximately 948 BBtu per day of natural gas fixed price swaps at an average fixed price of $3.05 per MMBtu and large base level of approximately 1,154 BBtu per day of natural gas fixed price swaps during 2019 at an average fixed price of $2.81 per MMBtu.
Third Quarter of 2018 Financial Results For the third quarter of 2018, Gulfport reported net income of $95.2 million, or $0.55 per diluted share, on revenues of $361.0 million. For the third quarter of 2018, EBITDA (as defined and reconciled below for each period presented) was $249.4 million and cash flow from operating activities before changes in operating assets and liabilities (as defined and reconciled below for each period presented) was $210.5 million. Gulfport’s GAAP net income for the third quarter of 2018 includes the following items:
Aggregate non-cash derivative loss of $4.1 million.
Aggregate loss of $0.9 million in connection with a litigation settlement.
Aggregate gain of $2.7 million in connection with the sale of Gulfport's equity interests in certain equity investments.
Aggregate gain of $12.9 million in connection with Gulfport's equity interests in certain equity investments.
Excluding the effect of these items, Gulfport’s financial results for the third quarter of 2018 would have been as follows:
Adjusted oil and gas revenues of $365.1 million.
Adjusted net income of $84.6 million, or $0.49 per diluted share.
Adjusted EBITDA of $238.8 million.
Nine-Months Ended September 30, 2018 Financial Results For the nine-month period ended September 30, 2018, Gulfport reported net income of $296.6 million, or $1.68 per diluted share, on revenues of $939.1 million. For the nine-month period ended September 30, 2018, EBITDA (as defined and reconciled below for each period presented) was $753.3 million and cash flow from operating activities before changes in operating assets and liabilities (as defined and reconciled below for each period presented) was $611.3 million. Gulfport’s GAAP net income for the nine-month period ended September 30, 2018 includes the following items:
Aggregate non-cash derivative loss of $106.4 million.
Aggregate gain of $0.2 million attributable to net insurance proceeds.
Aggregate loss of $0.9 million in connection with a litigation settlement.
Aggregate gain of $124.8 million in connection with the sale of Gulfport's equity interests in certain equity investments.
Aggregate gain of $35.3 million in connection with Gulfport's equity interests in certain equity investments.
Excluding the effect of these items, Gulfport’s financial results for the nine-month period ended September 30, 2018 would have been as follows:
Adjusted oil and gas revenues of $1,045.5 million.
Adjusted net income of $243.5 million, or $1.38 per diluted share.
Adjusted EBITDA of $700.3 million.
Production and Realized Prices Gulfport’s net daily production for the third quarter of 2018 averaged approximately 1,427.5 MMcfe per day. For the third quarter of 2018, Gulfport’s net daily production mix was comprised of approximately 89% natural gas, 8% natural gas liquids ("NGL") and 3% oil.
Gulfport’s realized prices for the third quarter of 2018 were $2.44 per Mcf of natural gas, $51.26 per barrel of oil and $0.57 per gallon of NGL, resulting in a total equivalent price of $2.75 per Mcfe. Gulfport's realized prices for the third quarter of 2018 include an aggregate non-cash derivative loss of $4.1 million. Before the impact of derivatives, realized prices for the third quarter of 2018, including transportation costs, were $2.32 per Mcf of natural gas, $68.73 per barrel of oil and $0.74 per gallon of NGL, for a total equivalent price of $2.82 per Mcfe.
GULFPORT ENERGY CORPORATION
PRODUCTION SCHEDULE
(Unaudited)
Three months ended
Nine Months Ended
September 30,
September 30,
Production Volumes:
2018
2017
2018
2017
Natural gas (MMcf)
116,994
97,825
327,272
247,012
Oil (MBbls)
665
685
2,166
1,849
NGL (MGal)
72,427
59,008
196,695
162,483
Gas equivalent (MMcfe)
131,328
110,367
368,366
281,318
Gas equivalent (Mcfe per day)
1,427,479
1,199,636
1,349,326
1,030,468
Average Realized Prices:
(before the impact of derivatives):
Natural gas (per Mcf)
$
2.32
$
2.28
$
2.30
$
2.46
Oil (per Bbl)
$
68.73
$
45.90
$
64.96
$
46.15
NGL (per Gal)
$
0.74
$
0.57
$
0.72
$
0.55
Gas equivalent (per Mcfe)
$
2.82
$
2.61
$
2.81
$
2.78
Average Realized Prices:
(including cash-settlement of derivatives and excluding non-cash derivative gain or loss):
Natural gas (per Mcf)
$
2.40
$
2.41
$
2.44
$
2.49
Oil (per Bbl)
$
53.97
$
50.26
$
54.68
$
49.07
NGL (per Gal)
$
0.67
$
0.54
$
0.66
$
0.54
Gas equivalent (per Mcfe)
$
2.78
$
2.74
$
2.84
$
2.82
Average Realized Prices:
Natural gas (per Mcf)
$
2.44
$
2.21
$
2.22
$
3.01
Oil (per Bbl)
$
51.26
$
36.32
$
44.10
$
52.90
NGL (per Gal)
$
0.57
$
0.41
$
0.60
$
0.51
Gas equivalent (per Mcfe)
$
2.75
$
2.41
$
2.55
$
3.28
The table below summarizes Gulfport’s third quarter of 2018 and nine-month period ended September 30, 2018 production by asset area:
GULFPORT ENERGY CORPORATION
PRODUCTION BY AREA
(Unaudited)
Three months ended
Nine months ended
September 30,
September 30,
2018
2017
2018
2017
Utica Shale
Natural gas (MMcf)
100,274
85,275
280,140
219,076
Oil (MBbls)
74
113
234
367
NGL (MGal)
29,806
34,076
92,389
105,759
Gas equivalent (MMcfe)
104,975
90,822
294,741
236,383
SCOOP(1)
Natural gas (MMcf)
16,704
12,505
47,071
27,852
Oil (MBbls)
412
303
1,316
682
NGL (MGal)
42,593
24,958
104,241
56,623
Gas equivalent (MMcfe)
25,259
17,888
69,862
40,030
Southern Louisiana
Natural gas (MMcf)
6
35
17
57
Oil (MBbls)
167
256
559
763
NGL (MGal)
—
—
—
—
Gas equivalent (MMcfe)
1,009
1,571
3,370
4,637
Other
Natural gas (MMcf)
9
11
43
27
Oil (MBbls)
12
13
57
38
NGL (MGal)
29
(26
)
65
101
Gas equivalent (MMcfe)
85
86
393
267
(1) SCOOP 2017 production adjusted for closing date of February 17, 2017.
2018 Financial Position and Liquidity As of September 30, 2018, Gulfport had cash on hand of approximately $124.6 million. As of September 30, 2018, Gulfport’s $1.4 billion revolving credit facility, under which Gulfport has an elected commitment of $1.0 billion, had outstanding borrowings of $60.0 million and outstanding letters of credit totaling $316.2 million.
As of September 30, 2018, Gulfport's net debt-to-trailing twelve months EBITDA ratio was 2.1 times.
2018 Capital Budget and Production Guidance Update For the nine-month period ended September 30, 2018, Gulfport’s drilling and completion ("D&C") capital expenditures totaled $638.1 million and non-D&C capital expenditures totaled $96.3 million. For 2018, Gulfport forecasts that its 2018 total capital expenditures will be at the high-end of the previously provided capital budget and expects total capital expenditures to be approximately $815 million.
Gulfport remains committed to funding its 2018 capital budget from cash flow as well as dedicated to being within the range of our previously provided capital budget. Capital spend will decrease significantly during the fourth quarter of 2018, with activity decreasing quarter over quarter and remaining nimble in its operations to adhere to the commitment of capital discipline and the 2018 capital budget.
Based on results during the nine-month period ended September 30, 2018, Gulfport has increased its production guidance and now forecasts its 2018 average daily net production will be in the range of 1,360 MMcfe to 1,370 MMcfe per day.
Utilizing current strip pricing at the various regional pricing points at which the Company sells its natural gas, Gulfport has improved its natural gas differential guidance and forecasts that its realized natural gas price, before the effect of hedges and inclusive of the Company’s firm transportation expense, will average in the range of $0.58 to $0.61 per Mcf below NYMEX settlement prices in 2018. In addition, Gulfport has improved its oil differential guidance and now forecasts that its 2018 realized oil price will be in the range of $1.75 to $2.00 per barrel below WTI. With respect to its expected realized NGL price, Gulfport reiterates that its 2018 realized NGL price, before the effect of hedges and including transportation expense, will be approximately 45% to 50% of WTI.
The table below summarizes the Company’s updated full year 2018 guidance:
GULFPORT ENERGY CORPORATION
COMPANY GUIDANCE
Year Ending
2018
Low
High
Forecasted Production
Average Daily Gas Equivalent (MMcfepd)
1,360
1,370
% Gas
~89%
% Natural Gas Liquids
~7%
% Oil
~4%
Forecasted Realizations (before the effects of hedges)
Natural Gas (Differential to NYMEX Settled Price) - $/Mcf
$
(0.58
)
$
(0.61
)
NGL (% of WTI)
45
%
50
%
Oil (Differential to NYMEX WTI) $/Bbl
$
(1.75
)
$
(2.00
)
Projected Operating Costs
Lease Operating Expense - $/Mcfe
$
0.17
$
0.19
Production Taxes - $/Mcfe
$
0.06
$
0.08
Midstream Gathering and Processing - $/Mcfe
$
0.57
$
0.63
General and Administrative - $/Mcfe
$
0.12
$
0.14
Depreciation, Depletion and Amortization - $/Mcfe
$
0.95
$
1.05
Total
Budgeted D&C Expenditures - In Millions:
$
685
Budgeted Non-D&C Expenditures - In Millions:
$
130
Total Capital Expenditures - In Millions:
$
815
Net Wells Drilled
Utica - Operated
20
Utica - Non-Operated
7
Total
27
SCOOP - Operated
13
SCOOP - Non-Operated
3
Total
16
Net Wells Turned-to-Sales
Utica - Operated
35
Utica - Non-Operated
10
Total
45
SCOOP - Operated
12
SCOOP - Non-Operated
4
Total
16
Operational Update The table below summarizes Gulfport's activity for the nine-month period ended September 30, 2018 and the number of net wells expected to be drilled and turned-to-sales for the remainder of 2018:
GULFPORT ENERGY CORPORATION
ACTIVITY SUMMARY
(Unaudited)
Three Months ended
Three Months ended
Three Months ended
March 31,
June 30,
September 30,
Remaining Wells
Guidance
2018
2018
2018
2018
2018
Net Wells Drilled
Utica - Operated
10.0
6.8
2.8
—
20.0
Utica - Non-Operated
1.8
2.5
2.6
0.1
7.0
Total
11.8
9.3
5.4
0.1
27.0
SCOOP - Operated
3.8
3.7
3.5
2.0
13.0
SCOOP - Non-Operated
2.6
0.3
0.1
—
3.0
Total
6.4
4.0
3.6
2.0
16.0
Net Wells Turned-to-Sales
Utica - Operated
3.0
14.0
11.0
7.0
35.0
Utica - Non-Operated
3.1
1.5
4.5
0.9
10.0
Total
6.1
15.5
15.5
7.9
45.0
SCOOP - Operated
6.3
0.5
5.8
—
12.0
SCOOP - Non-Operated
0.4
0.4
0.1
3.1
4.0
Total
6.7
0.9
5.9
2.5
16.0
Utica Shale In the Utica Shale, during the third quarter of 2018, Gulfport spud 2.8 net operated wells. In addition, Gulfport turned-to-sales 11 net operated wells during the third quarter of 2018.
During the third quarter of 2018, net production from Gulfport’s Utica acreage averaged approximately 1,141.0 MMcfe per day, an increase of 7% over the second quarter of 2018 and an increase of 16% over the third quarter of 2017.
For the nine-month period ended September 30, 2018, Gulfport spud 19.6 net operated wells. The wells drilled during this period had an average lateral length of approximately 10,350 feet. Normalizing to an 8,000 foot lateral length, Gulfport's average drilling days from spud to rig release totaled approximately 19.5 days, in line with the Company's full year 2017 results. In addition, Gulfport turned-to-sales 28 net operated wells with an average stimulated lateral length of approximately 7,700 feet during the nine-month period ended September 30, 2018.
At present, Gulfport does not have any operated horizontal drilling rigs running in the play.
SCOOP In the SCOOP, during the third quarter of 2018, Gulfport spud 3.5 net operated wells. In addition, Gulfport turned-to-sales 5.8 net operated wells during the third quarter of 2018.
During the third quarter of 2018, net production from Gulfport's SCOOP acreage averaged approximately 274.6 MMcfe per day, an increase of 11% over the second quarter of 2018 and an increase of 41% over the third quarter of 2017.
For the nine-month period ended September 30, 2018, Gulfport spud 11.0 net operated wells. The wells drilled during this period had an average lateral length of approximately 8,100 feet. Normalizing to a 7,500 foot lateral length, Gulfport's average drilling days from spud to rig release totaled approximately 64.9 days, a 10% improvement from the Company's full year 2017 results. In addition, Gulfport turned-to-sales 12.6 net operated wells with an average stimulated lateral length of approximately 7,750 feet during the nine-month period ended September 30, 2018.
At present, Gulfport has two operated horizontal drilling rigs active in the play.
Southern Louisiana At its West Cote Blanche Bay and Hackberry fields, during the third quarter of 2018, Gulfport performed zero recompletions at the fields. Net production during the third quarter of 2018 totaled approximately 11.0 MMcfe per day.
SCOOP Production Results During the third quarter of 2018, Gulfport turned-to-sales six gross Woodford wet gas wells, including the previously announced EJ Craddock 1R-28X21H and EJ Craddock 2-28X21H wells, and one gross Sycamore well.
The EJ Craddock 3-28X21H, targeting the Woodford formation in the SCOOP, has a stimulated lateral length of 9,065 feet and a 24-hour initial production peak rate of 9.9 MMcf per day and 351 barrels of oil per day. Based upon the composition analysis, the gas being produced is 1,176 BTU gas and yielding 48.5 barrels of NGL per MMcf of natural gas and results in a natural gas shrink of 16%. On a three-stream basis, the EJ Craddock 3-28X21H produced at a 24-hour initial production peak rate of 13.3 MMcfe per day, or 1,465 Mcfe per 1,000 foot of lateral, which is comprised of approximately 62% natural gas, 22% NGL and 16% oil. During its initial 30 days of production, the EJ Craddock 3-28X21H cumulatively produced 272.1 MMcf of natural gas and 8.8 thousand barrels of oil or, on a three-stream basis, at an average 30-day production rate of 12.0 MMcfe per day, or 1,325 Mcfe per 1,000 foot of lateral, which is comprised of approximately 63% natural gas, 22% NGL and 15% oil.
The EJ Craddock 4-28X21H, targeting the Woodford formation in the SCOOP, has a stimulated lateral length of 9,532 feet and a 24-hour initial production peak rate of 9.8 MMcf per day and 304 barrels of oil per day. Based upon the composition analysis, the gas being produced is 1,176 BTU gas and yielding 48.5 barrels of NGL per MMcf of natural gas and results in a natural gas shrink of 16%. On a three-stream basis, the EJ Craddock 4-28X21H produced at a 24-hour initial production peak rate of 12.9 MMcfe per day, or 1,352 Mcfe per 1,000 foot of lateral, which is comprised of approximately 64% natural gas, 22% NGL and 14% oil. During its initial 30 days of production, the EJ Craddock 4-28X21H cumulatively produced 264.6 MMcf of natural gas and 8.0 thousand barrels of oil or, on a three-stream basis, at an average 30-day production rate of 11.6 MMcfe per day, or 1,214 Mcfe per 1,000 foot of lateral, which is comprised of approximately 64% natural gas, 22% NGL and 14% oil.
The Lilly 1-15X10H, targeting the Woodford formation in the SCOOP, has a stimulated lateral length of 7,166 feet and a 24-hour initial production peak rate of 15.3 MMcf per day and 319 barrels of oil per day. Based upon the composition analysis, the gas being produced is 1,173 BTU gas and yielding 46.4 barrels of NGL per MMcf of natural gas and results in a natural gas shrink of 15%. On a three-stream basis, the Lilly 1-15X10H produced at a 24-hour initial production peak rate of 19.2 MMcfe per day, or 2,683 Mcfe per 1,000 foot of lateral, which is comprised of approximately 68% natural gas, 22% NGL and 10% oil. During its initial 30 days of production, the Lilly 1-15X10H cumulatively produced 446.3 MMcf of natural gas and 8.3 thousand barrels of oil or, on a three-stream basis, at an average 30-day production rate of 18.5 MMcfe per day, or 2,576 Mcfe per 1,000 foot of lateral, which is comprised of approximately 69% natural gas, 22% NGL and 9% oil.
The Lilly 2-15X10H, targeting the Woodford formation in the SCOOP, has a stimulated lateral length of 7,110 feet and a 24-hour initial production peak rate of 13.6 MMcf per day and 404 barrels of oil per day. Based upon the composition analysis, the gas being produced is 1,173 BTU gas and yielding 46.4 barrels of NGL per MMcf of natural gas and results in a natural gas shrink of 15%. On a three-stream basis, the Lilly 2-15X10H produced at a 24-hour initial production peak rate of 17.8 MMcfe per day, or 2,506 Mcfe per 1,000 foot of lateral, which is comprised of approximately 65% natural gas, 21% NGL and 14% oil. During its initial 30 days of production, the Lilly 2-15X10H cumulatively produced 391.4 MMcf of natural gas and 9.2 thousand barrels of oil or, on a three-stream basis, at an average 30-day production rate of 16.6 MMcfe per day, or 2,328 Mcfe per 1,000 foot of lateral, which is comprised of approximately 67% natural gas, 22% NGL and 11% oil.
The Miller 8-13X12H targeting the Sycamore Shale formation in the SCOOP, has a stimulated lateral length of 9,670 feet and a 24-hour initial production peak rate of 531 barrels of oil per day and 3.8 MMcf per day. Based upon the composition analysis, the gas being produced is 1,273 BTU gas and yielding 77.3 barrels of NGL per MMcf of natural gas and results in a natural gas shrink of 23%. On a three-stream basis, the Miller 8-13X12H produced at a 24-hour initial production peak rate of 1,303 Boe per day, which is comprised of approximately 41% oil, 37% natural gas and 22% NGL.
During its initial 30 days of production, the EJ Craddock 1R-28X21H cumulatively produced 509.7 MMcf of natural gas and 10.7 thousand barrels of oil or, on a three-stream basis, at an average 30-day production rate of 20.9 MMcfe per day, or 2,315 Mcfe per 1,000 foot of lateral, which is comprised of approximately 72% natural gas, 18% NGL and 10% oil. During the initial 60 days of production, the EJ Craddock 1R-28X21H cumulatively produced 984.7 MMcf of natural gas and 19.0 thousand barrels of oil or, on a three-stream basis, at an average 60-day production rate of 20.0 MMcfe per day, or 2,217 Mcfe per 1,000 foot of lateral, which is comprised of approximately 72% natural gas, 18% NGL and 10% oil.
During its initial 30 days of production, the EJ Craddock 2-28X21H cumulatively produced 514.9 MMcf of natural gas and 11.9 thousand barrels of oil or, on a three-stream basis, at an average 30-day production rate of 21.3 MMcfe per day, or 2,142 Mcfe per 1,000 foot of lateral, which is comprised of approximately 71% natural gas, 18% NGL and 11% oil. During its initial 60 days of production, the EJ Craddock 2-28X21H cumulatively produced 980.8 MMcf of natural gas and 22.8 thousand barrels of oil or, on a three-stream basis, or at an average 60-day production rate of 20.3 MMcfe per day, or 2,040 Mcfe per 1,000 foot of lateral, which is comprised of approximately 71% natural gas, 18% NGL and 11% oil.
During its initial 60 days of production, the Cleburne 7R-12X13H cumulatively produced 732.5 MMcf of natural gas or at an average 60-day production rate of 12.2 MMcf per day, or 1,301 Mcfe per 1,000 foot of lateral, comprised of approximately 100% natural gas. During its initial 90 days of production, the Cleburne 7R-12X13H cumulatively produced 1.0 Bcf of natural gas, or at an average 90-day production rate of 11.5 MMcf per day, or 1,224 Mcfe per 1,000 foot of lateral, comprised of approximately 100% natural gas.
During its initial 90 days of production, the Lilly 3-15X10H cumulatively produced 1.1 Bcf of natural gas and 21.3 thousand barrels of oil, or on a three-stream basis, at an average 90-day production rate of 14.5 MMcfe per day, or 2,130 Mcfe per 1,000 foot of lateral, which is comprised of approximately 69% natural gas, 21% NGL and 10% oil.
During its initial 90 days of production, the Lilly 4-15X10H cumulatively produced 863.1 MMcf of natural gas and 20.2 thousand barrels of oil or, on a three-stream basis, at an average 90-day production rate of 12.1 MMcfe per day, or 1,651 Mcfe per 1,000 foot of lateral, which is comprised of approximately 68% natural gas, 21% NGL and 11% oil.
The table below summarizes the Company’s recent SCOOP well results:
GULFPORT ENERGY CORPORATION
SCOOP WELL RESULTS SUMMARY
(Unaudited)
Phase
Stimulated
Wellhead
NGLs
Product Mix(1)
Average Prod. Rates (MMcfepd)
County
Window
Lateral
BTU
Per MMcf
% Shrink
Gas
NGLs
Oil
24-Hr
30-Day
60-Day
90-Day
EJ Craddock 1R-28X21H
Central Grady
Woodford Wet Gas
9,008
1,133
36.9
12%
70%
18%
12%
20.9
20.9
20.0
—
EJ Craddock 2-28X21H
Central Grady
Woodford Wet Gas
9,939
1,133
36.9
12%
69%
17%
14%
21.0
21.3
20.3
—
EJ Craddock 3-28X21H
Central Grady
Woodford Wet Gas
9,065
1,176
48.5
16%
62%
22%
16%
13.3
12.0
—
—
EJ Craddock 4-28X21H
Central Grady
Woodford Wet Gas
9,532
1,176
48.5
16%
64%
22%
14%
12.9
11.6
—
—
EJ Craddock 8-28X21H
Central Grady
Woodford Wet Gas
7,961
1,171
47.0
16%
55%
19%
26%
19.7
17.3
16.1
15.2
Lilly 1-15X10H
Central Grady
Woodford Wet Gas
7,166
1,173
46.4
15%
68%
22%
10%
19.2
18.5
—
—
Lilly 2-15X10H
Central Grady
Woodford Wet Gas
7,110
1,173
46.4
15%
65%
21%
14%
17.8
16.6
—
—
Lilly 3-15X10H
Central Grady
Woodford Wet Gas
6,816
1,157
43.3
14%
66%
20%
14%
18.4
16.7
15.7
14.5
Lilly 4-15X10H
Central Grady
Woodford Wet Gas
7,323
1,157
43.3
14%
63%
19%
18%
14.5
13.1
12.4
12.1
North Cheyenne 3-10X3H
Central Grady
Woodford Wet Gas
7,218
1,162
44.1
15%
64%
20%
16%
13.2
12.1
11.3
10.6
North Cheyenne 4-10X3H
Central Grady
Woodford Wet Gas
6,867
1,162
44.1
15%
62%
19%
19%
14.6
13.4
12.6
11.9
North Cheyenne 5-10X3H
Central Grady
Woodford Wet Gas
5,782
1,152
41.7
14%
64%
19%
17%
20.6
18.4
16.9
15.9
North Cheyenne 6-10X3H
Central Grady
Woodford Wet Gas
6,002
1,152
41.7
14%
64%
19%
17%
19.4
16.8
15.3
14.1
North Cheyenne 7-10X3H
Central Grady
Woodford Wet Gas
6,379
1,162
43.9
15%
63%
20%
17%
12.3
12.7
12.1
11.5
North Cheyenne 8-10X3H
Central Grady
Woodford Wet Gas
6,413
1,162
43.9
15%
62%
19%
18%
17.2
16.1
15.2
14.2
Pauline 3-27X22H
Central Grady
Woodford Wet Gas
4,322
1,212
57.3
18%
49%
21%
30%
8.8
8.0
7.4
6.8
Pauline 4-27X22H
Central Grady
Woodford Wet Gas
7,978
1,212
57.3
18%
52%
22%
26%
17.3
16.1
15.0
14.1
Pauline 5-27X22H
Central Grady
Woodford Wet Gas
7,929
1,216
57.4
22%
50%
22%
27%
22.2
19.1
17.4
16.0
Pauline 6-27X22H
Central Grady
Woodford Wet Gas
7,273
1,216
57.4
22%
50%
22%
28%
22.9
19.6
17.7
16.2
Pauline 8-27X22H
Central Grady
Woodford Wet Gas
7,658
1,210
58.8
19%
51%
22%
27%
18.4
18.6
17.6
16.6
Vinson 2-22X27H
SE Grady
Woodford Wet Gas
8,539
1,118
35.7
11%
79%
19%
2%
16.5
15.7
14.4
13.4
Vinson 3R-22X27H
SE Grady
Woodford Wet Gas
8,475
1,118
35.7
11%
79%
19%
2%
19.0
18.7
17.3
16.3
Winham 7-22H
S Grady
Woodford Wet Gas
4,898
1,146
40.0
13%
64%
18%
18%
23.4
19.9
19.0
17.9
Cleburne 7R-12X13H
W Grady
Woodford Dry Gas
9,386
—
—
—
100%
—
—
14.5
13.1
12.2
11.5
Miller 8-13X12H
Central Grady
Upper Sycamore
9,670
1,273
77.3
23%
37%
22%
41%
7.8
—
—
—
Serenity 5-22H
S Grady
Lower Sycamore
5,980
1,143
39.2
13%
70%
19%
11%
15.7
15.8
15.4
15.0
Lauper 4-26H
SE Grady
Springer Oil
4,527
1,418
120.8
34%
10%
11%
79%
4.7
3.2
2.9
2.6
Note: All well results presented are based upon three-stream production data and assume contractual ethane recovery.
1. Product mix calculated utilizing 24-hr initial production rate.
Derivatives Gulfport has hedged a portion of its expected production to lock in prices and returns that provide certainty of cash flow to execute on its capital plans. The table below sets forth the Company's hedging positions as of October 31, 2018.
GULFPORT ENERGY CORPORATION
COMMODITY DERIVATIVES - HEDGE POSITION
(Unaudited)
4Q2018
Natural gas:
Swap contracts (NYMEX)
Volume (BBtupd)
1,010
Price ($ per MMBtu)
$
3.01
Swaption contracts (NYMEX)
Volume (BBtupd)
50
Price ($ per MMBtu)
$
3.13
Basis Swap contracts (Transco Zone 4)
Volume (BBtupd)
40
Price ($ per MMBtu)
$
(0.05
)
Oil:
Swap contracts (LLS)
Volume (Bblpd)
2,000
Price ($ per Bbl)
$
56.22
Swap contracts (WTI)
Volume (Bblpd)
4,500
Price ($ per Bbl)
$
53.72
NGL:
C3 Propane Swap contracts
Volume (Bblpd)
4,250
Price ($ per Gal)
$
0.70
C5+ Swap contracts
Volume (Bblpd)
500
Price ($ per Gal)
$
1.11
2018
2019
Natural gas:
Swap contracts (NYMEX)
Volume (BBtupd)
948
1,154
Price ($ per MMBtu)
$
3.05
$
2.81
Swaption contracts (NYMEX)
Volume (BBtupd)
43
135
Price ($ per MMBtu)
$
3.10
$
3.07
Basis Swap contracts (NGPL MC)
Volume (BBtupd)
12
—
Differential ($ per MMBtu)
$
(0.26
)
$
—
Basis Swap contracts (Transco Zone 4)
Volume (BBtupd)
10
60
Differential ($ per MMBtu)
$
(0.05
)
$
(0.05
)
Oil:
Swap contracts (LLS)
Volume (Bblpd)
1,507
1,000
Price ($ per Bbl)
$
56.22
$
59.55
Swap contracts (WTI)
Volume (Bblpd)
4,779
4,000
Price ($ per Bbl)
$
54.29
$
58.28
NGL:
C2 Ethane Swap contracts
Volume (Bblpd)
—
1,000
Price ($ per Gal)
—
$
0.44
C3 Propane Swap contracts
Volume (Bblpd)
4,063
3,815
Price ($ per Gal)
$
0.69
$
0.69
C5 Pentane Swap contracts
Volume (Bblpd)
500
500
Price ($ per Gal)
$
1.11
1.29
Stock Repurchase Program As of October 31, 2018, the Company has repurchased 10.5 million shares at a weighted-average share price of $10.47 during 2018. Since initiating the share repurchase program in February 2018, Gulfport has reduced its shares outstanding by over five percent.
Gulfport's board of directors has authorized the Company to acquire up to $200 million of its outstanding common stock during 2018 and approximately $90 million remains under the current authorization. Purchases under the repurchase program may be made from time to time in open market or privately negotiated transactions, and will be subject to market conditions, applicable legal requirements, contractual obligations and other factors. The repurchase program does not require the Company to acquire any specific number of shares. The Company intends to purchase shares under the repurchase program opportunistically with available funds while maintaining sufficient liquidity to fund its 2018 capital development program. This repurchase program is authorized to extend through December 31, 2018 and may be suspended from time to time, modified, extended or discontinued by the board of directors at any time.
Presentation An updated presentation has been posted to the Company’s website. The presentation can be found at www.gulfportenergy.com under the “Company Information” section on the “Investor Relations” page. Information on the Company’s website does not constitute a portion of this press release.
Conference Call Gulfport will hold a conference call on Friday, November 2, 2018 at 8:00 a.m. CDT to discuss its third quarter of 2018 financial and operational results and to provide an update on the Company’s recent activities.
Interested parties may listen to the call via Gulfport’s website at www.gulfportenergy.com or by calling toll-free at 866-373-3408 or 412-902-1039 for international callers. A replay of the call will be available for two weeks at 877-660-6853 or 201-612-7415 for international callers. The replay passcode is 13622396. The webcast will also be available for two weeks on the Company’s website and can be accessed on the Company’s “Investor Relations” page.
About Gulfport Gulfport Energy is an independent natural gas and oil company focused on the exploration and development of natural gas and oil properties in North America and is one of the largest producers of natural gas in the contiguous United States. Headquartered in Oklahoma City, Gulfport holds significant acreage positions in the Utica Shale of Eastern Ohio and the SCOOP Woodford and SCOOP Springer plays in Oklahoma. In addition, Gulfport holds an acreage position along the Louisiana Gulf Coast, has an approximately 22% equity interest in Mammoth Energy Services, Inc. (NASDAQ:TUSK) and has a position in the Alberta Oil Sands in Canada through its 25% interest in Grizzly Oil Sands ULC. For more information, please visit www.gulfportenergy.com.
Forward Looking Statements This press release includes “forward-looking statements” for purposes of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that Gulfport expects or anticipates will or may occur in the future, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of Gulfport's business and operations, plans, market conditions, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. These statements are based on certain assumptions and analyses made by Gulfport in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. However, whether actual results and developments will conform with Gulfport's expectations and predictions is subject to a number of risks and uncertainties, general economic, market, credit or business conditions that might affect the timing and amount of the repurchase program; the opportunities (or lack thereof) that may be presented to and pursued by Gulfport; Gulfport’s ability to identify, complete and integrate acquisitions of properties and businesses; competitive actions by other oil and gas companies; changes in laws or regulations; and other factors, many of which are beyond the control of Gulfport. Information concerning these and other factors can be found in the Company's filings with the Securities and Exchange Commission, including its Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in this press release are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by Gulfport will be realized, or even if realized, that they will have the expected consequences to or effects on Gulfport, its business or operations. Gulfport has no intention, and disclaims any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.
Non-GAAP Financial Measures EBITDA is a non-GAAP financial measure equal to net income, the most directly comparable GAAP financial measure, plus interest expense, income tax (benefit) expense, accretion expense and depreciation, depletion and amortization. Adjusted EBITDA is a non-GAAP financial measure equal to EBITDA less non-cash derivative loss (gain), litigation settlement, insurance proceeds, gain on sale of equity method investments and (income) loss from equity method investments. Cash flow from operating activities before changes in operating assets and liabilities is a non-GAAP financial measure equal to cash provided by operating activity before changes in operating assets and liabilities. Adjusted net income is a non-GAAP financial measure equal to pre-tax net income less non-cash derivative loss (gain), litigation settlement, insurance proceeds, gain on sale of equity method investments and (income) loss from equity method investments. The Company has presented EBITDA and adjusted EBITDA because it uses these measures as an integral part of its internal reporting to evaluate its performance and the performance of its senior management. These measures are considered important indicators of the operational strength of the Company's business and eliminate the uneven effect of considerable amounts of non-cash depletion, depreciation of tangible assets and amortization of certain intangible assets. A limitation of these measures, however, is that they do not reflect the periodic costs of certain capitalized tangible and intangible assets used in generating revenues in the Company's business. Management evaluates the costs of such tangible and intangible assets and the impact of related impairments through other financial measures, such as capital expenditures, investment spending and return on capital. Therefore, the Company believes that these measures provide useful information to its investors regarding its performance and overall results of operations. EBITDA, adjusted EBITDA, adjusted net income and cash flow from operating activities before changes in operating assets and liabilities are not intended to be performance measures that should be regarded as an alternative to, or more meaningful than, either net income as an indicator of operating performance or to cash flows from operating activities as a measure of liquidity. In addition, EBITDA, adjusted EBITDA, adjusted net income and cash flow from operating activities before changes in operating assets and liabilities are not intended to represent funds available for dividends, reinvestment or other discretionary uses, and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. The EBITDA, adjusted EBITDA, adjusted net income and cash flow from operating activities before changes in operating assets and liabilities presented in this press release may not be comparable to similarly titled measures presented by other companies, and may not be identical to corresponding measures used in the Company's various agreements.
