Gulfport Energy Corporation (NASDAQ:GPOR) (“Gulfport” or the
“Company”) today reported financial and operational results for the
quarter and year ended December 31, 2017 and provided an
update on its 2018 activities. Key information includes the
following:
- Year-end 2017 total proved reserves grew to 5.4 Tcfe, as
compared to 2.3 Tcfe at year-end 2016, an increase of 132%
year-over-year.
- Net of the SCOOP acquisition, year-end 2017 total proved
reserves grew to 3.9 Tcfe, as compared to 2.3 Tcfe at year-end
2016, an increase of 70% year-over-year.
- SEC PV-10 value grew to $2.9 billion at year-end 2017, as
compared to $696 million at year-end 2016, an increase of 314%
year-over-year.
- Net production during 2017 averaged 1,089.2 MMcfe per day.
- Net income of $435.2 million, or $2.41 per diluted share, for
2017.
- Adjusted net income (as defined and reconciled below) of $254.0
million, or $1.41 per diluted share, for 2017.
- Adjusted EBITDA (as defined and reconciled below) of $730.2
million for 2017.
- Reduced unit lease operating expense for 2017 by 23% to $0.20
per Mcfe from $0.26 per Mcfe for 2016.
- Reduced unit general and administrative expense for 2017 by 19%
to $0.13 per Mcfe from $0.16 per Mcfe for 2016.
- Budgeted 2018 total capital expenditures are $770 million to
$835 million to be funded within cash flow.
- Forecasted 2018 full year net production is estimated to
average 1,250 MMcfe to 1,300 MMcfe per day, an increase of
approximately 15% to 19% over the average daily net production of
1,089.2 MMcfe per day during 2017.
- Increased hedge position to approximately 908 MMcf per day of
natural gas fixed price swaps for 2018 at an average fixed price of
$3.06 per Mcf, securing approximately 80% of anticipated natural
gas production.
- Initiated stock repurchase program to acquire up to $100
million of outstanding common stock.
Michael G. Moore, Chief Executive Officer and
President, commented, "2017 was a pivotal year for Gulfport as our
Utica asset provided reliable, repeatable growth throughout the
year and we began the journey of increasing recoveries and further
delineating the underappreciated, multi-zone opportunities across
our SCOOP position. We experienced a year of strong production
growth and our reserve report for year-end 2017 truly highlights
the depth and quality of Gulfport's asset base.
We believe our 2017 development activities have
enabled us to reach a size and scale, both financially and
operationally, that allows us to navigate the current commodity
price environment and align our business model to deliver a strong
rate of growth within cash flow for 2018. In addition to our
planned operational activity for 2018, we recently announced a
stock repurchase program. The repurchase program underscores the
confidence we have in our business model, financial performance and
top-tier asset base and further demonstrates our commitment to
recognizing value for our shareholders. We are eager to initiate
the program and plan to be aggressive in repurchasing our shares,
subject to market conditions."
Financial Results
For the fourth quarter of 2017, Gulfport
reported net income of $156.5 million, or $0.85 per diluted share,
on oil and natural gas revenues of $397.8 million. For
the fourth quarter of 2017, EBITDA (as defined and reconciled
below) was $299.2 million and cash flow from operating activities
before changes in operating assets and liabilities was $196.8
million. Gulfport’s GAAP net income for the fourth quarter of
2017 includes the following items:
- Aggregate non-cash derivative gain of $59.1 million.
- Aggregate loss of $1,000 in connection with the
acquisition of oil and natural gas assets from Vitruvian II
Woodford, LLC ("Vitruvian").
- Aggregate gain of $15.7 million in connection with Gulfport's
equity interests in certain equity investments.
- Associated adjusted taxable benefit of $1.0 million.
Excluding the effect of these items, Gulfport’s
financial results for the fourth quarter of 2017 would have been as
follows:
- Adjusted oil and natural gas revenues of $338.7 million.
- Adjusted net income of $81.7 million, or $0.45 per diluted
share.
- Adjusted EBITDA of $224.4 million.
For the full year of 2017, Gulfport reported net
income of $435.2 million, or $2.41 per diluted share, on oil and
natural gas revenues of $1.3 billion. For the full year of
2017, EBITDA was $911.4 million and cash flow from operating
activities before changes in operating assets and liabilities was
$631.7 million. Gulfport’s GAAP net loss for the full year of 2017
includes the following items:
- Aggregate non-cash derivative gain of $188.8 million.
- Aggregate loss of $2.4 million in connection with the
acquisition of oil and natural gas assets from Vitruvian.
- Aggregate loss of $5.3 million in connection with Gulfport's
equity interests in certain equity investments.
- Associated adjusted taxable expense of $1.8 million.
Excluding the effect of these items, Gulfport’s
financial results for the full year of 2017 would have been
as follows:
- Adjusted oil and natural gas revenues of $1.1 billion.
- Adjusted net income of $254.0 million, or $1.41 per diluted
share.
- Adjusted EBITDA of $730.2 million.
Production and Realized Prices
Gulfport’s net daily production for the fourth
quarter of 2017 averaged approximately 1,263.3 MMcfe per day. For
the fourth quarter of 2017, Gulfport’s net daily production mix was
comprised of approximately 89% natural gas, 7% natural gas liquids
("NGL") and 4% oil. Gulfport’s net daily production for the full
year of 2017 averaged approximately 1,089.2 MMcfe per day. For the
full year of 2017, Gulfport’s net daily production mix was
comprised of approximately 88% natural gas, 8% NGL and 4% oil.
Gulfport’s realized prices for the fourth
quarter of 2017 were $3.26 per Mcf of natural gas, $32.04 per
barrel of oil and $0.63 per gallon of NGL, resulting in a total
equivalent price of $3.42 per Mcfe. Gulfport's realized prices for
the fourth quarter of 2017 include an aggregate non-cash derivative
gain of $59.1 million. Before the impact of derivatives, realized
prices for the fourth quarter of 2017, including transportation
costs, were $2.32 per Mcf of natural gas, $53.71 per barrel of oil
and $0.76 per gallon of NGL, for a total equivalent price of $2.80
per Mcfe.
Gulfport’s realized prices for the full year of
2017 were $3.08 per Mcf of natural gas, $46.99 per barrel of oil
and $0.54 per gallon of NGL, resulting in a total equivalent price
of $3.32 per Mcfe. Gulfport's realized prices for the full
year of 2017 include an aggregate non-cash derivative gain of
$188.8 million. Before the impact of derivatives, realized prices
for the full year of 2017, including transportation costs, were
$2.42 per Mcf of natural gas, $48.29 per barrel of oil and $0.61
per gallon of NGL, for a total equivalent price of $2.78 per
Mcfe.
|
GULFPORT ENERGY CORPORATION |
PRODUCTION SCHEDULE |
(Unaudited) |
|
Three Months Ended |
|
Twelve Months Ended |
|
December 31, |
|
December 31, |
Production
Volumes: |
2017 |
|
2016 |
|
2017 |
|
2016 |
|
|
|
|
|
|
|
|
Natural gas (MMcf) |
103,049 |
|
|
63,362 |
|
|
350,061 |
|
|
227,594 |
|
Oil (MBbls) |
730 |
|
|
451 |
|
|
2,579 |
|
|
2,126 |
|
NGL (MGal) |
61,555 |
|
|
44,345 |
|
|
224,038 |
|
|
161,562 |
|
Gas equivalent
(MMcfe) |
116,225 |
|
|
72,404 |
|
|
397,543 |
|
|
263,430 |
|
Gas equivalent (Mcfe
per day) |
1,263,319 |
|
|
786,998 |
|
|
1,089,159 |
|
|
719,753 |
|
|
|
|
|
|
|
|
|
Average
Realized Prices |
|
|
|
|
|
|
|
(before the
impact of derivatives): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per
Mcf) |
$ |
2.32 |
|
|
$ |
2.34 |
|
|
$ |
2.42 |
|
|
$ |
1.85 |
|
Oil (per Bbl) |
$ |
53.71 |
|
|
$ |
45.15 |
|
|
$ |
48.29 |
|
|
$ |
38.18 |
|
NGL (per Gal) |
$ |
0.76 |
|
|
$ |
0.56 |
|
|
$ |
0.61 |
|
|
$ |
0.37 |
|
Gas equivalent (per
Mcfe) |
$ |
2.80 |
|
|
$ |
2.67 |
|
|
$ |
2.78 |
|
|
$ |
2.13 |
|
|
|
|
|
|
|
|
|
Average
Realized Prices: |
|
|
|
|
|
|
|
(including cash-settlement of derivatives and excluding
non-cash derivative gain or loss): |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per
Mcf) |
$ |
2.50 |
|
|
$ |
2.49 |
|
|
$ |
2.49 |
|
|
$ |
2.45 |
|
Oil (per Bbl) |
$ |
51.93 |
|
|
$ |
45.37 |
|
|
$ |
49.88 |
|
|
$ |
43.29 |
|
NGL (per Gal) |
$ |
0.70 |
|
|
$ |
0.55 |
|
|
$ |
0.58 |
|
|
$ |
0.36 |
|
Gas equivalent (per
Mcfe) |
$ |
2.91 |
|
|
$ |
2.8 |
|
|
$ |
2.85 |
|
|
$ |
2.69 |
|
|
|
|
|
|
|
|
|
Average
Realized Prices: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per
Mcf) |
$ |
3.26 |
|
|
$ |
0.41 |
|
|
$ |
3.08 |
|
|
$ |
1.12 |
|
Oil (per Bbl) |
$ |
32.04 |
|
|
$ |
32.41 |
|
|
$ |
46.99 |
|
|
$ |
35.65 |
|
NGL (per Gal) |
$ |
0.63 |
|
|
$ |
0.52 |
|
|
$ |
0.54 |
|
|
$ |
0.35 |
|
Gas equivalent (per
Mcfe) |
$ |
3.42 |
|
|
$ |
0.88 |
|
|
$ |
3.32 |
|
|
$ |
1.46 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The table below summarizes Gulfport’s fourth
quarter of 2017 and the twelve-month period ended December 31,
2017 production by asset area:
|
GULFPORT ENERGY CORPORATION |
PRODUCTION BY AREA |
(Unaudited) |
|
Three months ended |
|
Twelve Months Ended |
|
December 31, |
|
December 31, |
|
2017 |
|
2017 |
Utica
Shale |
|
|
|
Natural gas (MMcf) |
90,374 |
|
309,450 |
Oil (MBbls) |
107 |
|
473 |
NGL (MGal) |
33,875 |
|
139,634 |
Gas equivalent
(MMcfe) |
95,854 |
|
332,238 |
|
|
|
|
SCOOP(1) |
|
|
|
Natural gas (MMcf) |
12,648 |
|
40,501 |
Oil (MBbls) |
401 |
|
1,083 |
NGL (MGal) |
27,660 |
|
84,283 |
Gas equivalent
(MMcfe) |
19,008 |
|
59,038 |
|
|
|
|
Southern
Louisiana |
|
|
|
Natural gas (MMcf) |
19 |
|
75 |
Oil (MBbls) |
210 |
|
974 |
NGL (MGal) |
— |
|
— |
Gas equivalent
(MMcfe) |
1,280 |
|
5,917 |
|
|
|
|
Other |
|
|
|
Natural gas (MMcf) |
8 |
|
35 |
Oil (MBbls) |
12 |
|
50 |
NGL (MGal) |
20 |
|
121 |
Gas equivalent
(MMcfe) |
84 |
|
351 |
|
|
|
|
(1)
SCOOP production included from closing date of the Vitruvian
acquisition on February 17, 2017. |
|
2017 Capital Expenditures For
the year ended December 31, 2017, Gulfport’s drilling and
completion capital expenditures totaled $1.1 billion, midstream
capital expenditures totaled $46.1 million and leasehold capital
expenditures totaled $132.5 million.
2017 Financial Position and
LiquidityAs of December 31, 2017, Gulfport had cash
on hand of approximately $99.6 million. In addition, as of
December 31, 2017, Gulfport’s revolving credit facility of
$1.2 billion, with elected commitments under this facility of $1.0
billion, was undrawn and $759.0 million was available for future
borrowing after giving effect to outstanding letters of credit
totaling $241.0 million.
2018 Capital Budget and Production GuidanceFor
2018, Gulfport estimates total capital expenditures will be in the
range of $770 million to $835 million, which will be funded within
cash flow at current strip pricing. The 2018 budget includes
approximately $630 million to $685 million for D&C
activities and approximately $140 million to $150 million for
non-D&C activities, including midstream capital expenditures
associated with its investment in Strike Force Midstream LLC and
leasehold activities during 2018. With this level of
capital spend, Gulfport forecasts its 2018 average daily net
production will be in the range of 1,250 MMcfe to 1,300 MMcfe per
day, an increase of 15% to 19% over its 2017 average daily net
production of 1,089.2 MMcfe per day.
Utilizing current strip pricing at the various
regional pricing points at which the Company sells its natural
gas, Gulfport forecasts 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 $0.72
per Mcf below NYMEX settlement prices in 2018. Gulfport expects its
2018 realized NGL price, before the effect of hedges and including
transportation expense, will be approximately 45% to 50% of
WTI and its 2018 realized oil price will be in the range of $3.00
to $3.50 per barrel below WTI.
The table below summarizes the Company’s full
year 2018 guidance:
|
GULFPORT ENERGY CORPORATION |
COMPANY GUIDANCE |
|
|
Year Ending |
|
|
12/31/18 |
|
|
Low |
|
High |
Forecasted Production |
|
|
|
|
Average Daily Gas
Equivalent (MMcfepd) |
|
1,250 |
|
|
|
1,300 |
|
|
% Gas |
~ 89% |
|
% NGL |
~7% |
|
% Oil |
~4% |
|
|
|
|
|
Forecasted Realizations (before the effects of
hedges) |
|
|
|
|
Natural Gas
(Differential to NYMEX Settled Price) - $/Mcf |
$ |
(0.58 |
) |
|
$ |
(0.72 |
) |
|
NGL (% of WTI) |
|
45 |
% |
|
|
50 |
% |
|
Oil (Differential to
NYMEX WTI) $/Bbl |
$ |
(3.00 |
) |
|
$ |
(3.50 |
) |
|
|
|
|
|
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: |
|
|
|
|
Operated |
$ |
490 |
|
|
$ |
525 |
|
|
Non-Operated |
$ |
140 |
|
|
$ |
160 |
|
|
Total Budgeted D&C
Capital Expenditures |
$ |
630 |
|
|
$ |
685 |
|
|
|
|
|
|
Budgeted Non-D&C Expenditures - In
Millions: |
$ |
140 |
|
|
$ |
150 |
|
|
|
|
|
|
Total Capital Expenditures - In Millions: |
$ |
770 |
|
|
$ |
835 |
|
|
|
|
|
|
Net
Wells Drilled |
|
|
|
|
Utica - Operated |
|
26 |
|
|
|
29 |
|
|
Utica -
Non-Operated |
|
7 |
|
|
|
8 |
|
|
Total |
|
33 |
|
|
|
37 |
|
|
|
|
|
|
|
SCOOP - Operated |
|
10 |
|
|
|
11 |
|
|
SCOOP -
Non-Operated |
|
4 |
|
|
|
5 |
|
|
Total |
|
14 |
|
|
|
16 |
|
|
|
|
|
|
Net
Wells Turned-to-Sales |
|
|
|
|
Utica - Operated |
|
33 |
|
|
|
37 |
|
|
Utica -
Non-Operated |
|
9 |
|
|
|
10 |
|
|
Total |
|
42 |
|
|
|
47 |
|
|
|
|
|
|
|
SCOOP - Operated |
|
16 |
|
|
|
18 |
|
|
SCOOP -
Non-Operated |
|
2 |
|
|
|
3 |
|
|
Total |
|
18 |
|
|
|
21 |
|
|
|
|
|
|
|
|
|
|
|
Operational Update and 2018 Outlook
The table below summarizes Gulfport's activity
for the twelve-month period ended December 31, 2017 and the
number of net wells expected to be drilled and turned-to-sales
during 2018:
|
GULFPORT ENERGY CORPORATION |
ACTIVITY SUMMARY |
(Unaudited) |
|
|
|
|
|
|
|
|
|
Three Months ended |
Three Months ended |
Three Months ended |
Three Months ended |
Twelve Months ended |
|
|
|
March 31, |
June 30, |
September 30, |
December 31, |
December 31, |
|
Guidance (1) |
|
2017 |
2017 |
2017 |
2017 |
2017 |
|
2018E |
Net Wells
Drilled |
|
|
|
|
|
|
|
Utica - Operated |
24 |
|
26 |
|
23 |
|
16 |
|
89 |
|
|
27.5 |
|
Utica -
Non-Operated |
2 |
|
2 |
|
1 |
|
3 |
|
8 |
|
|
7.5 |
|
Total |
26 |
|
28 |
|
24 |
|
19 |
|
97 |
|
|
35.0 |
|
|
|
|
|
|
|
|
|
SCOOP - Operated |
4 |
|
2 |
|
6 |
|
4 |
|
16 |
|
|
10.5 |
|
SCOOP -
Non-Operated |
0.5 |
|
0.3 |
|
— |
|
0.2 |
|
1 |
|
|
4.5 |
|
Total |
5 |
|
2 |
|
6 |
|
4 |
|
17 |
|
|
15.0 |
|
|
|
|
|
|
|
|
|
Net Wells
Turned-to-Sales |
|
|
|
|
|
|
|
Utica - Operated |
5 |
|
27 |
|
18 |
|
11 |
|
61 |
|
|
35.0 |
|
Utica -
Non-Operated |
1 |
|
4 |
|
2 |
|
2 |
|
9 |
|
|
9.5 |
|
Total |
6 |
|
31 |
|
20 |
|
13 |
|
70 |
|
|
44.5 |
|
|
|
|
|
|
|
|
|
SCOOP - Operated |
— |
|
1 |
|
6 |
|
4 |
|
11 |
|
|
17.0 |
|
SCOOP -
Non-Operated |
0.2 |
|
0.1 |
|
0.4 |
|
0.1 |
|
0.8 |
|
|
2.5 |
|
Total |
0.2 |
|
1 |
|
6 |
|
4 |
|
12 |
|
|
19.5 |
|
|
|
|
|
|
|
|
|
(1)
Utilizes mid-point of publicly provided 2018 guidance |
|
|
|
|
|
|
|
Utica ShaleIn the Utica Shale,
during the twelve months ended December 31, 2017, Gulfport
spud 94 gross (88.7 net) operated wells. The wells drilled during
2017 had an average lateral length of approximately 8,150 feet.
Normalizing to an 8,000 foot lateral length, Gulfport's average
drilling days during 2017 from spud to rig release totaled
approximately 19.2 days, a decrease of 16% over full year 2016. In
addition, Gulfport turned-to-sales 68 gross (61.1 net) operated
wells with an average stimulated lateral length of approximately
7,700 feet.
Net production for the full year of 2017 from
Gulfport’s Utica acreage averaged approximately 910.2 MMcfe per
day, an increase of 30% over the full year of 2016.
During 2018, Gulfport has budgeted to drill
approximately 36 to 40 gross (26 to 29 net) horizontal Utica wells
with an average lateral length of 11,200 feet. In addition,
Gulfport plans to turn-to-sales 33 to 37 gross and net horizontal
Utica wells with an average lateral length of 8,000 feet.
Gulfport intends to participate in non-operated
activities taking place on its acreage by other operators that plan
to drill approximately 7 to 8 horizontal wells and turn-to-sales 9
to 10 horizontal wells, in each case net to Gulfport’s
interest.
At present, Gulfport has three operated
horizontal rigs drilling in the play and it expects to release a
rig in March of 2018 as its contract expires. Gulfport plans to
run, on average, approximately 2.5 operated horizontal rigs in the
Utica Shale during 2018.
SCOOPIn the SCOOP, during the
twelve months ended December 31, 2017, Gulfport spud 19 gross
(15.7 net) operated wells. The wells drilled during 2017 had an
average lateral length of approximately 7,200 feet. Normalizing to
a 7,500 foot lateral length, Gulfport's average drilling days
during 2017 from spud to rig release totaled approximately 72.1
days. In addition, Gulfport turned-to-sales 13 gross (11.0 net)
operated wells with an average stimulated lateral length of
approximately 6,800 feet.
During the period February 17, 2017 (the date
Gulfport completed its acquisition of the acreage) through December
31, 2017, net production from Gulfport’s SCOOP acreage averaged
approximately 185.7 MMcfe per day.
During 2018, Gulfport has budgeted to drill
approximately 15 to 16 gross (10 to 11 net) horizontal SCOOP wells
with an average lateral length of 8,900 feet. In addition, Gulfport
plans to turn-to-sales 20 to 22 gross (16 to 18 net) horizontal
SCOOP wells with an average lateral length of 8,600 feet.
Gulfport intends to participate in non-operated
activities taking place on its acreage by other operators that plan
to drill approximately 4 to 5 horizontal wells and turn-to-sales 2
to 3 horizontal wells, in each case net to Gulfport’s interest.
At present, Gulfport has four operated
horizontal rigs drilling in the play and it expects to release two
rigs mid-summer 2018 as contracts expire. Gulfport plans to run, on
average, approximately 3 operated horizontal rigs in the SCOOP
during 2018.
Southern LouisianaAt its West
Cote Blanche Bay and Hackberry fields, Gulfport performed 81
recompletions during 2017. Net production for the full year of 2017
at these fields totaled approximately 16.2 MMcfe per day.
During 2018, Gulfport plans to run one
recompletion rig in these fields.
SCOOP Well Results
Gulfport recently turned-to-sales 6 gross
Woodford wells located in the wet gas window in central Grady
County, Oklahoma. The North Cheyenne 3-10X3H has a stimulated
lateral length of 7,218 feet and a 24-hour initial peak production
rate of 10.0 MMcf per day and 343 barrels of oil per day. Based
upon the composition analysis, the gas being produced is 1,162 BTU
gas and yielding 44.1 barrels of NGL per MMcf of natural gas and
results in a natural gas shrink of 15%. On a three-stream basis,
the North Cheyenne 3-10X3H produced at a 24-hour initial production
peak rate of 13.2 MMcfe per day, or 1,829 Mcfe per 1,000 foot of
lateral, which is comprised of approximately 64% natural gas,
20% NGL and 16% oil.
The North Cheyenne 4-10X3H has a stimulated
lateral length of 6,867 feet and a 24-hour initial peak production
rate of 10.6 MMcf per day and 465 barrels of oil per day. Based
upon the composition analysis, the gas being produced is 1,162 BTU
gas and yielding 44.1 barrels of NGL per MMcf of natural gas and
results in a natural gas shrink of 15%. On a three-stream basis,
the North Cheyenne 4-10X3H produced at a 24-hour initial production
peak rate of 14.6 MMcfe per day, or 2,130 Mcfe per 1,000 foot of
lateral, which is comprised of approximately 62% natural gas,
19% NGL and 19% oil.
The North Cheyenne 5-10X3H has a stimulated
lateral length of 5,782 feet and a 24-hour initial peak production
rate of 15.3 MMcf per day and 601 barrels of oil per day.
Based upon the composition analysis, the gas being produced is
1,152 BTU gas and yielding 41.7 barrels of NGL per MMcf of natural
gas and results in a natural gas shrink of 14%. On a three-stream
basis, the North Cheyenne 5-10X3H produced at a 24-hour initial
production peak rate of 20.6 MMcfe per day, or 3,566 Mcfe per 1,000
foot of lateral, which is comprised of approximately 64%
natural gas, 19% NGL and 17% oil.
The North Cheyenne 6-10X3H has a stimulated
lateral length of 6,002 feet and a 24-hour initial peak production
rate of 14.4 MMcf per day and 572 barrels of oil per day.
Based upon the composition analysis, the gas being produced is
1,152 BTU gas and yielding 41.7 barrels of NGL per MMcf of natural
gas and results in a natural gas shrink of 14%. On a three-stream
basis, the North Cheyenne 6-10X3H produced at a 24-hour initial
production peak rate of 19.4 MMcfe per day, or 3,226 Mcfe per 1,000
foot of lateral, which is comprised of approximately 64%
natural gas, 19% NGL and 17% oil.
The North Cheyenne 7-10X3H has a stimulated
lateral length of 6,379 feet and a 24-hour initial peak production
rate of 9.2 MMcf per day and 347 barrels of oil per day.
Based upon the composition analysis, the gas being produced is
1,162 BTU gas and yielding 43.9 barrels of NGL per MMcf of natural
gas and results in a natural gas shrink of 15%. On a three-stream
basis, the North Cheyenne 7-10X3H produced at a 24-hour initial
production peak rate of 12.3 MMcfe per day, or 1,924 Mcfe per 1,000
foot of lateral, which is comprised of approximately 63%
natural gas, 20% NGL and 17% oil.
The North Cheyenne 8-10X3H has a stimulated
lateral length of 6,413 feet and a 24-hour initial peak production
rate of 12.7 MMcf per day and 523 barrels of oil per day.
Based upon the composition analysis, the gas being produced is
1,162 BTU gas and yielding 43.9 barrels of NGL per MMcf of natural
gas and results in a natural gas shrink of 15%. On a three-stream
basis, the North Cheyenne 8-10X3H produced at a 24-hour initial
production peak rate of 17.2 MMcfe per day, or 2,688 Mcfe per 1,000
foot of lateral, which is comprised of approximately 63%
natural gas, 19% NGL and 18% oil.
During its initial 60 days of production, the
Serenity 5-22H, targeting the Sycamore formation in the SCOOP, has
cumulatively produced 739.5 MMcf of natural gas and 14.1 thousand
barrels of oil. Based upon the composition analysis, the gas
being produced is 1,143 BTU gas and yielding 39.2 barrels of NGL
per MMcf of natural gas and results in a natural gas shrink of 13%.
On a three-stream basis, the Serenity 5-22H produced at a 60-day
production rate of 15.4 MMcfe per day, or 2,567 Mcfe per 1,000 foot
of lateral, which is comprised of approximately 70% gas, 19% NGL
and 11% oil.
During its initial 60 days of production, the
Winham 7-22H, targeting the Woodford formation in the SCOOP, has
cumulatively produced 861.8 MMcf of natural gas and 30.1 thousand
barrels of oil. Based upon the composition analysis, the gas
being produced is 1,146 BTU gas and yielding 40.0 barrels of NGL
per MMcf of natural gas and results in a natural gas shrink of 13%.
On a three-stream basis, the Winham 7-22H produced at a 60-day
production rate of 19.0 MMcfe per day, or 3,869 Mcfe per 1,000 foot
of lateral, which is comprised of approximately 66% gas, 18% NGL
and 16% oil.
During its initial 60 days of production, the
Lauper 4-26H, targeting the Springer formation in the SCOOP, has
cumulatively produced 29.2 thousand barrels of oil and 22.1 MMcf of
natural gas. Based upon the composition analysis, the gas
being produced is 1,418 BTU gas and yielding 120.8 barrels of NGL
per MMcf of natural gas and results in a natural gas shrink of 34%.
On a three-stream basis, the Lauper 4-26H produced at a 60-day
production rate of 480 Boe per day, or 106 Boe per 1,000 foot of
lateral, which is comprised of approximately 77% oil, 12% NGL and
11% natural gas.
The following table summarizes the Company’s
recent 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
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 |
|
North Cheyenne
3-10X3H |
Central Grady |
Woodford Wet Gas |
7,218 |
1,162 |
44.1 |
15 |
% |
64 |
% |
20 |
% |
16 |
% |
13.2 |
|
— |
|
— |
|
— |
|
North Cheyenne
4-10X3H |
Central Grady |
Woodford Wet Gas |
6,867 |
1,162 |
44.1 |
15 |
% |
62 |
% |
19 |
% |
19 |
% |
14.6 |
|
— |
|
— |
|
— |
|
North Cheyenne
5-10X3H |
Central Grady |
Woodford Wet Gas |
5,782 |
1,152 |
41.7 |
14 |
% |
64 |
% |
19 |
% |
17 |
% |
20.6 |
|
— |
|
— |
|
— |
|
North Cheyenne
6-10X3H |
Central Grady |
Woodford Wet Gas |
6,002 |
1,152 |
41.7 |
14 |
% |
64 |
% |
19 |
% |
17 |
% |
19.4 |
|
— |
|
— |
|
— |
|
North Cheyenne
7-10X3H |
Central Grady |
Woodford Wet Gas |
6,379 |
1,162 |
43.9 |
15 |
% |
63 |
% |
20 |
% |
17 |
% |
12.3 |
|
— |
|
— |
|
— |
|
North Cheyenne
8-10X3H |
Central Grady |
Woodford Wet Gas |
6,413 |
1,162 |
43.9 |
15 |
% |
63 |
% |
19 |
% |
18 |
% |
17.2 |
|
— |
|
— |
|
— |
|
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 |
% |
28 |
% |
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 |
13 |
% |
64 |
% |
18 |
% |
18 |
% |
23.4 |
|
19.9 |
|
19.0 |
|
— |
|
Serenity 5-22H |
S
Grady |
Sycamore |
5,980 |
1,143 |
39.2 |
13 |
% |
70 |
% |
19 |
% |
11 |
% |
15.7 |
|
15.8 |
|
15.4 |
|
— |
|
Lauper 4-26H |
SE
Grady |
Springer Oil |
4,527 |
1,418 |
120.8 |
34 |
% |
10 |
% |
11 |
% |
79 |
% |
4.7 |
|
3.2 |
|
2.9 |
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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. |
|
Stock Repurchase ProgramAs previously
announced, Gulfport's board of directors has approved a stock
repurchase program to acquire up to $100 million of the Company's
outstanding common stock during 2018. Purchases under the
repurchase program may be made from time to time in open market or
privately negotiated transactions, and will be subject to market
conditions, applicable legal requirements, contractual obligations
and other factors. The repurchase program does not require the
Company to acquire any specific number of shares. The Company
intends to purchase shares under the repurchase program
opportunistically while maintaining sufficient liquidity to fund
its 2018 capital development program. This repurchase program is
authorized to extend through December 31, 2018 and may be suspended
from time to time, modified, extended or discontinued by the board
of directors at any time.
DerivativesGulfport has hedged a portion of its
expected production to lock in prices and returns that provide
certainty of cash flow to execute on its capital plans. The table
below sets forth the Company's hedging positions as
of February 21, 2018.
|
GULFPORT ENERGY CORPORATION |
COMMODITY DERIVATIVES - HEDGE
POSITION |
(Unaudited) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1Q2018 |
|
2Q2018 |
|
3Q2018 |
|
4Q2018 |
Natural
gas: |
|
|
|
|
|
|
|
Swap contracts
(NYMEX) |
|
|
|
|
|
|
|
Volume (BBtupd) |
850 |
|
|
880 |
|
|
950 |
|
|
950 |
|
Price ($ per
MMBtu) |
$ |
3.18 |
|
|
$ |
3.02 |
|
|
$ |
3.02 |
|
|
$ |
3.02 |
|
|
|
|
|
|
|
|
|
Swaption contracts
(NYMEX) |
|
|
|
|
|
|
|
Volume (BBtupd) |
20 |
|
|
50 |
|
|
50 |
|
|
50 |
|
Price ($ per
MMBtu) |
$ |
2.91 |
|
|
$ |
3.13 |
|
|
$ |
3.13 |
|
|
$ |
3.13 |
|
|
|
|
|
|
|
|
|
Basis Swap
Contract (NGPL MC) |
|
|
|
|
|
|
|
Volume (BBtupd) |
50 |
|
|
— |
|
|
— |
|
|
— |
|
Differential ($ per
MMBtu) |
$ |
(0.26 |
) |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
|
|
|
|
|
|
|
|
Oil: |
|
|
|
|
|
|
|
Swap contracts
(LLS) |
|
|
|
|
|
|
|
Volume (Bblpd) |
— |
|
|
2,000 |
|
|
2,000 |
|
|
2,000 |
|
Price ($ per Bbl) |
$ |
— |
|
|
$ |
56.22 |
|
|
$ |
56.22 |
|
|
$ |
56.22 |
|
|
|
|
|
|
|
|
|
Swap contracts
(WTI) |
|
|
|
|
|
|
|
Volume (Bblpd) |
5,967 |
|
|
4,170 |
|
|
4,500 |
|
|
4,500 |
|
Price ($ per Bbl) |
$ |
54.95 |
|
|
$ |
54.59 |
|
|
53.72 |
|
|
53.72 |
|
|
|
|
|
|
|
|
|
NGL: |
|
|
|
|
|
|
|
C3 Propane Swap
Contracts |
|
|
|
|
|
|
|
Volume (Bblpd) |
4,000 |
|
|
4,000 |
|
|
4,000 |
|
|
4,000 |
|
Price ($ per Gal) |
$ |
0.69 |
|
|
$ |
0.69 |
|
|
$ |
0.69 |
|
|
$ |
0.69 |
|
|
|
|
|
|
|
|
|
C5+ Swap Contracts |
|
|
|
|
|
|
|
Volume (Bblpd) |
500 |
|
|
500 |
|
|
500 |
|
|
500 |
|
Price ($ per Gal) |
$ |
1.11 |
|
|
$ |
1.11 |
|
|
$ |
1.11 |
|
|
$ |
1.11 |
|
|
|
|
|
|
|
|
|
|
2018 |
|
2019 |
|
|
|
|
Natural
gas: |
|
|
|
|
|
|
|
Swap contracts
(NYMEX) |
|
|
|
|
|
|
|
Volume (BBtupd) |
908 |
|
|
512 |
|
|
|
|
|
Price ($ per
MMBtu) |
$ |
3.06 |
|
|
$ |
2.86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Swaption contracts
(NYMEX) |
|
|
|
|
|
|
|
Volume (BBtupd) |
43 |
|
|
135 |
|
|
|
|
|
Price ($ per
MMBtu) |
$ |
3.10 |
|
|
$ |
3.07 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Basis Swap
Contract (NGPL MC) |
|
|
|
|
|
|
|
Volume (BBtupd) |
12 |
|
|
— |
|
|
|
|
|
Differential ($ per
MMBtu) |
$ |
(0.26 |
) |
|
$ |
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil: |
|
|
|
|
|
|
|
Swap contracts
(LLS) |
|
|
|
|
|
|
|
Volume (Bblpd) |
1,507 |
|
|
— |
|
|
|
|
|
Price ($ per Bbl) |
$ |
56.22 |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
Swap contracts
(WTI) |
|
|
|
|
|
|
|
Volume (Bblpd) |
4,779 |
|
|
2,000 |
|
|
|
|
|
Price ($ per Bbl) |
$ |
54.29 |
|
|
57.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL: |
|
|
|
|
|
|
|
C3 Propane Swap
Contracts |
|
|
|
|
|
|
|
Volume (Bblpd) |
4,000 |
|
|
— |
|
|
|
|
|
Price ($ per Gal) |
$ |
0.69 |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
C5+ Swap Contracts |
|
|
|
|
|
|
|
Volume (Bblpd) |
500 |
|
|
— |
|
|
|
|
|
Price ($ per Gal) |
$ |
1.11 |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year-End 2017 Reserves
Gulfport reported year-end 2017 total proved
reserves of 5.4 Tcfe, consisting of 4.8 Tcf of natural gas, 19.2
MMBbls of oil and 75.8 MMBbls of natural gas liquids.
Gulfport's year-end total proved reserves increased 132% over
year-end 2016. The table below provides information regarding the
components driving the 2017 net proved reserve increase:
|
GULFPORT ENERGY CORPORATION |
DECEMBER 31, 2017 NET PROVED RESERVE
RECONCILIATION |
(Unaudited) |
|
|
|
|
|
Gas Equivalent |
|
|
BCFE |
|
|
|
Proved reserve balance
at December 31, 2016 |
|
2,321.1 |
|
Purchases in oil and
natural gas reserves in place |
|
1,511.1 |
|
Extensions and
discoveries |
|
1,628.2 |
|
Revisions of prior
reserve estimates: |
|
|
Reclassification of PUD to unproved under SEC 5-year rule |
|
(46.3 |
) |
Performance and price revisions |
|
378.3 |
|
Current production |
|
(397.5 |
) |
|
|
|
Proved reserve
balance at December 31, 2017 |
|
5,394.9 |
|
|
|
|
|
Proved developed reserves increased by 120% from
December 31, 2016 to approximately 1,895.9 Bcfe as of
December 31, 2017. At year-end 2017, approximately 35% of
Gulfport’s proved reserves were classified as proved developed
reserves. Proved undeveloped reserves increased by 139% from
December 31, 2016 to approximately 3,499.0 Bcfe as of
December 31, 2017. The table below summarizes the
Company’s 2017 net proved reserves:
|
GULFPORT ENERGY CORPORATION |
DECEMBER 31, 2017 NET PROVED
RESERVES |
(Unaudited) |
|
|
|
|
|
|
|
|
|
Natural Gas |
|
Oil |
|
Natural Gas Liquids |
|
Gas Equivalent |
|
BCF |
|
MMBBL |
|
MMBBL |
|
BCFE |
|
|
|
|
|
|
|
|
Proved Developed
Producing |
1,495.5 |
|
|
8.5 |
|
|
33.5 |
|
|
1,747.4 |
|
Proved Developed
Non-Producing |
121.4 |
|
|
1.7 |
|
|
2.8 |
|
|
148.5 |
|
Proved Undeveloped |
3,208.4 |
|
|
9.0 |
|
|
39.5 |
|
|
3,499.0 |
|
|
|
|
|
|
|
|
|
Total Proved
Reserves |
4,825.3 |
|
|
19.2 |
|
|
75.8 |
|
|
5,394.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table presents Gulfport’s 2017 net
proved reserves by major operating areas:
|
GULFPORT ENERGY CORPORATION |
DECEMBER 31, 2017 NET PROVED RESERVES BY ASSET
AREA |
(Unaudited) |
|
|
|
2017 |
|
BCFE |
|
|
Utica |
3,926.7 |
SCOOP |
1,452.1 |
Southern Louisiana |
14.1 |
Other |
2.0 |
|
|
Total Proved
Reserves |
5,394.9 |
|
|
In accordance with Securities and Exchange
Commission guidelines, at year-end 2017, reserve calculations were
based on the average first day of the month price for the prior 12
months. The prices utilized for Gulfport’s year-end 2017
reserve report were $51.34 per barrel of oil and $2.98 per MMBtu of
natural gas, in each case as adjusted by lease for transportation
fees and regional price differentials. Utilizing these
prices, the present value of Gulfport’s total proved reserves
discounted at 10% (referred to as “PV-10”) was $2.9 billion at
December 31, 2017. PV-10 is a non-GAAP measure because it excludes
income tax effects. Management believes that the presentation of
the non-GAAP financial measure of PV-10 provides useful information
to investors because it is widely used by professional analysts and
sophisticated investors in evaluating oil and gas companies. PV-10
is not a measure of financial or operating performance under GAAP.
PV-10 should not be considered as an alternative to the
standardized measure as defined under GAAP. We have included a
reconciliation of PV-10 of proved reserves to the standardized
measure of discounted future net cash flows, the most directly
comparable GAAP measure.
|
GULFPORT ENERGY CORPORATION |
DECEMBER 31, 2017 PV-10 |
(Unaudited) |
|
|
|
SEC Case |
|
($MM) |
|
|
Proved Developed
Producing |
$ |
1,699 |
Proved Developed
Non-Producing |
166 |
Proved Undeveloped |
1,018 |
|
|
Total Proved
Reserves |
$ |
2,883 |
|
|
|
The following table reconciles the standardized measure of
future net cash flows to the PV-10 value of Gulfport’s proved
reserves:
GULFPORT ENERGY CORPORATION |
DECEMBER 31, 2017 PV-10
RECONCILITATION |
(Unaudited) |
|
|
|
|
|
SEC Case |
|
|
($MM) |
|
|
|
Standardized measure of
discounted future net cash flows (1) |
|
$ |
2,644 |
Add: Present value of
future income tax discounted at 10% |
|
239 |
|
|
|
PV-10
value |
|
$ |
2,883 |
|
|
|
¹ The standardized measure represents the present value of
estimated future cash inflows from proved oil and natural gas
reserves, less future development, abandonment, production, and
income tax expenses, discounted at 10% per annum to reflect timing
of future cash flows and using the same pricing assumptions
as were used to calculate PV-10. Standardized measure differs from
PV-10 because standardized measure includes the effect of future
income taxes. |
PresentationAn 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 CallGulfport will
hold a conference call on Thursday, February 22, 2018, at 8:00 a.m.
CST to discuss its fourth quarter and full-year of 2017 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 GulfportGulfport 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 25% equity interest in
Mammoth Energy Services, Inc. (NASDAQ:TUSK) and has a position in
the Alberta Oil Sands in Canada through an approximately 25%
interest in Grizzly Oil Sands ULC. For more information, please
visit www.gulfportenergy.com.
Forward Looking StatementsThis
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
MeasuresEBITDA is a non-GAAP financial measure equal to
net (loss) income, the most directly comparable GAAP financial
measure, plus interest expense, income tax (benefit) expense,
accretion expense, depreciation, depletion and amortization and
impairment of oil and gas properties. Adjusted EBITDA is a non-GAAP
financial measure equal to EBITDA less non-cash derivative gain,
acquisition expense 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 gain, acquisition expense, (income) loss from equity
method investments and tax (benefit) expense excluding adjustments.
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.
General Reserve Information
Notes:Gulfport's estimated proved reserves as of
December 31, 2017 were prepared by Netherland, Sewell &
Associates, Inc. ("NSAI") with respect to Gulfport's assets in the
Utica Shale of Eastern Ohio, Gulfport's SCOOP Woodford assets in
Oklahoma and Gulfport's WCBB and Hackberry fields and by Gulfport's
personnel with respect to its Niobrara field, overriding royalty
and non-operated interests (less than 1% of its proved reserves at
December 31, 2017), and comply with definitions promulgated by
the SEC. NSAI is an independent petroleum engineering firm.
Investor & Media
Contact:Jessica Wills – Director, Investor
Relationsjwills@gulfportenergy.com405-252-4550
|
GULFPORT ENERGY
CORPORATIONCONSOLIDATED BALANCE
SHEETS(Unaudited) |
|
December 31, 2017 |
|
December 31, 2016 |
|
(In thousands, except share data) |
Assets |
|
|
|
Current assets: |
|
|
|
Cash and
cash equivalents |
$ |
99,557 |
|
|
$ |
1,275,875 |
|
Restricted cash |
— |
|
|
185,000 |
|
Accounts
receivable—oil and natural gas |
182,213 |
|
|
136,761 |
|
Accounts
receivable—related parties |
— |
|
|
16 |
|
Prepaid
expenses and other current assets |
4,912 |
|
|
3,135 |
|
Short-term derivative instruments |
78,847 |
|
|
3,488 |
|
Total current assets |
365,529 |
|
|
1,604,275 |
|
Property and
equipment: |
|
|
|
Oil and
natural gas properties, full-cost accounting, $2,912,974 and
$1,580,305 excluded from amortization in 2017 and 2016,
respectively |
9,169,156 |
|
|
6,071,920 |
|
Other
property and equipment |
86,754 |
|
|
68,986 |
|
Accumulated depletion, depreciation, amortization and
impairment |
(4,153,733 |
) |
|
(3,789,780 |
) |
Property and equipment, net |
5,102,177 |
|
|
2,351,126 |
|
Other assets: |
|
|
|
Equity
investments |
302,112 |
|
|
243,920 |
|
Long-term
derivative instruments |
8,685 |
|
|
5,696 |
|
Deferred
tax asset |
1,208 |
|
|
4,692 |
|
Inventories |
8,227 |
|
|
4,504 |
|
Other
assets |
19,814 |
|
|
8,932 |
|
Total other assets |
340,046 |
|
|
267,744 |
|
Total assets |
$ |
5,807,752 |
|
|
$ |
4,223,145 |
|
Liabilities and stockholders’ equity |
|
|
|
Current
liabilities: |
|
|
|
Accounts
payable and accrued liabilities |
$ |
553,609 |
|
|
$ |
265,124 |
|
Asset
retirement obligation—current |
120 |
|
|
195 |
|
Short-term derivative instruments |
32,534 |
|
|
119,219 |
|
Current
maturities of long-term debt |
622 |
|
|
276 |
|
Total current liabilities |
586,885 |
|
|
384,814 |
|
Long-term derivative
instruments |
2,989 |
|
|
26,759 |
|
Asset retirement
obligation—long-term |
74,980 |
|
|
34,081 |
|
Other non-current
liabilities |
2,963 |
|
|
— |
|
Long-term debt, net of
current maturities |
2,038,321 |
|
|
1,593,599 |
|
Total liabilities |
2,706,138 |
|
|
2,039,253 |
|
Commitments and
contingencies |
|
|
|
Preferred stock, $.01
par value; 5,000,000 authorized, 30,000 authorized as redeemable
12% cumulative preferred stock, Series A; 0 issued and
outstanding |
— |
|
|
— |
|
Stockholders’
equity: |
|
|
|
Common stock, $.01 par
value; 200,000,000 authorized, 183,105,910 issued and outstanding
in 2017 and 158,829,816 in 2016 |
1,831 |
|
|
1,588 |
|
Paid-in
capital |
4,416,250 |
|
|
3,946,442 |
|
Accumulated other comprehensive loss |
(40,539 |
) |
|
(53,058 |
) |
Retained
deficit |
(1,275,928 |
) |
|
(1,711,080 |
) |
Total stockholders’ equity |
3,101,614 |
|
|
2,183,892 |
|
Total liabilities and
stockholders’ equity |
$ |
5,807,752 |
|
|
$ |
4,223,145 |
|
|
|
|
|
|
|
|
|
|
GULFPORT ENERGY
CORPORATIONCONSOLIDATED STATEMENTS OF
OPERATIONS(Unaudited) |
|
Three Months Ended December 31, |
|
Twelve Months Ended December 31, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
(In thousands, except share data) |
|
(In thousands, except share data) |
Revenues: |
|
|
|
|
|
|
|
Natural
gas sales |
$ |
239,455 |
|
|
$ |
148,255 |
|
|
$ |
845,999 |
|
|
$ |
420,128 |
|
Oil and
condensate sales |
39,230 |
|
|
20,374 |
|
|
124,568 |
|
|
81,173 |
|
Natural
gas liquid sales |
47,072 |
|
|
24,917 |
|
|
136,057 |
|
|
59,115 |
|
Net gain
(loss) on natural gas, oil, and NGL derivatives |
72,091 |
|
|
(130,130 |
) |
|
213,679 |
|
|
(174,506 |
) |
|
397,848 |
|
|
63,416 |
|
|
1,320,303 |
|
|
385,910 |
|
Costs and
expenses: |
|
|
|
|
|
|
|
Lease
operating expenses |
20,202 |
|
|
20,088 |
|
|
80,246 |
|
|
68,877 |
|
Production taxes |
6,662 |
|
|
3,784 |
|
|
21,126 |
|
|
13,276 |
|
Midstream
gathering and processing |
72,737 |
|
|
43,496 |
|
|
248,995 |
|
|
165,972 |
|
Depreciation, depletion and amortization |
109,742 |
|
|
62,560 |
|
|
364,629 |
|
|
245,974 |
|
Impairment of oil and natural gas properties |
— |
|
|
113,689 |
|
|
— |
|
|
715,495 |
|
General
and administrative |
15,016 |
|
|
10,468 |
|
|
52,938 |
|
|
43,409 |
|
Accretion
expense |
463 |
|
|
280 |
|
|
1,611 |
|
|
1,057 |
|
Acquisition expense |
1 |
|
|
— |
|
|
2,392 |
|
|
— |
|
|
224,823 |
|
|
254,365 |
|
|
771,937 |
|
|
1,254,060 |
|
INCOME (LOSS)
FROM OPERATIONS |
173,025 |
|
|
(190,949 |
) |
|
548,366 |
|
|
(868,150 |
) |
OTHER (INCOME)
EXPENSE: |
|
|
|
|
|
|
|
Interest
expense |
33,401 |
|
|
18,638 |
|
|
108,198 |
|
|
63,530 |
|
Interest
income |
(82 |
) |
|
(408 |
) |
|
(1,009 |
) |
|
(1,230 |
) |
Insurance
proceeds |
— |
|
|
(1,968 |
) |
|
— |
|
|
(5,718 |
) |
Loss on
debt extinguishment |
— |
|
|
23,776 |
|
|
— |
|
|
23,776 |
|
(Income)
loss from equity method investments |
(15,688 |
) |
|
8,409 |
|
|
5,257 |
|
|
33,985 |
|
Other
(income) expense |
(178 |
) |
|
132 |
|
|
(1,041 |
) |
|
129 |
|
|
17,453 |
|
|
48,579 |
|
|
111,405 |
|
|
114,472 |
|
INCOME (LOSS) BEFORE
INCOME TAXES |
155,572 |
|
|
(239,528 |
) |
|
436,961 |
|
|
(982,622 |
) |
INCOME TAX (BENEFIT)
EXPENSE |
(954 |
) |
|
842 |
|
|
1,809 |
|
|
(2,913 |
) |
NET INCOME
(LOSS) |
$ |
156,526 |
|
|
$ |
(240,370 |
) |
|
$ |
435,152 |
|
|
$ |
(979,709 |
) |
NET INCOME
(LOSS) PER COMMON SHARE: |
|
|
|
|
|
|
|
Basic |
$ |
0.85 |
|
|
$ |
(1.86 |
) |
|
$ |
2.42 |
|
|
$ |
(7.97 |
) |
Diluted |
$ |
0.85 |
|
|
$ |
(1.86 |
) |
|
$ |
2.41 |
|
|
$ |
(7.97 |
) |
Weighted average common
shares outstanding—Basic |
183,090,659 |
|
|
129,450,895 |
|
|
179,834,146 |
|
|
122,952,866 |
|
Weighted average common
shares outstanding—Diluted |
183,090,659 |
|
|
129,450,895 |
|
|
180,253,024 |
|
|
122,952,866 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GULFPORT ENERGY CORPORATION |
RECONCILIATION OF EBITDA AND CASH
FLOW |
(Unaudited) |
|
|
|
|
|
|
|
|
|
Three Months Ended December
31, |
|
Twelve Months Ended December
31, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
(In thousands) |
|
(In thousands) |
|
|
|
|
|
|
|
|
Net income (loss) |
$ |
156,526 |
|
|
$ |
(240,370 |
) |
|
$ |
435,152 |
|
|
$ |
(979,709 |
) |
Interest expense |
33,401 |
|
|
18,638 |
|
|
108,198 |
|
|
63,530 |
|
Income tax (benefit)
expense |
(954 |
) |
|
842 |
|
|
1,809 |
|
|
(2,913 |
) |
Accretion expense |
463 |
|
|
280 |
|
|
1,611 |
|
|
1,057 |
|
Depreciation, depletion
and amortization |
109,742 |
|
|
62,560 |
|
|
364,629 |
|
|
245,974 |
|
Impairment of oil and
gas properties |
— |
|
|
113,689 |
|
|
— |
|
|
715,495 |
|
EBITDA |
$ |
299,178 |
|
|
$ |
(44,361 |
) |
|
$ |
911,399 |
|
|
$ |
43,434 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended December
31, |
|
Twelve Months Ended December
31, |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
|
(In thousands) |
|
(In thousands) |
|
|
|
|
|
|
|
|
Cash provided by
operating activity |
$ |
188,156 |
|
|
$ |
92,568 |
|
|
$ |
679,889 |
|
|
$ |
337,843 |
|
Adjustments: |
|
|
|
|
|
|
|
Changes in
operating assets and liabilities |
8,689 |
|
|
(6,472 |
) |
|
(48,239 |
) |
|
29,049 |
|
Operating Cash
Flow |
$ |
196,845 |
|
|
$ |
86,096 |
|
|
$ |
631,650 |
|
|
$ |
366,892 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GULFPORT ENERGY CORPORATION |
RECONCILIATION OF ADJUSTED
EBITDA |
(Unaudited) |
|
Three Months Ended |
|
Twelve Months Ended |
|
December 31, 2017 |
|
December 31, 2017 |
|
(In thousands) |
|
|
|
|
EBITDA |
$ |
299,178 |
|
|
$ |
911,399 |
|
|
|
|
|
Adjustments: |
|
|
|
Non-cash derivative
gain |
|
(59,109 |
) |
|
|
(188,802 |
) |
Acquisition
expense |
|
1 |
|
|
|
2,392 |
|
(Income) Loss from
equity method investments |
|
(15,688 |
) |
|
|
5,257 |
|
|
|
|
|
|
|
|
|
Adjusted EBITDA |
$ |
224,382 |
|
|
$ |
730,246 |
|
|
|
|
|
|
|
|
|
|
GULFPORT ENERGY CORPORATION |
RECONCILIATION OF ADJUSTED NET
INCOME |
(Unaudited) |
|
|
|
|
|
|
|
Three Months Ended |
|
Twelve Months Ended |
|
|
December 31, 2017 |
|
December 31, 2017 |
|
|
(In thousands, except share
data) |
|
|
|
|
|
Pre-tax net income
excluding adjustments |
|
$ |
155,572 |
|
|
$ |
436,961 |
|
Adjustments: |
|
|
|
|
Non-cash derivative
gain |
|
|
(59,109 |
) |
|
|
(188,802 |
) |
Acquisition
expense |
|
|
1 |
|
|
|
2,392 |
|
(Income) Loss from
equity method investments |
|
|
(15,688 |
) |
|
|
5,257 |
|
Pre-tax net income
excluding adjustments |
|
|
80,776 |
|
|
|
255,808 |
|
|
|
|
|
|
Tax (benefit) expense
excluding adjustments |
|
|
(954 |
) |
|
|
1,809 |
|
|
|
|
|
|
Adjusted net
income |
|
$ |
81,730 |
|
|
$ |
253,999 |
|
|
|
|
|
|
Adjusted net income per
common share: |
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.45 |
|
|
$ |
1.41 |
|
|
|
|
|
|
Diluted |
|
$ |
0.45 |
|
|
$ |
1.41 |
|
|
|
|
|
|
Basic weighted average
shares outstanding |
|
|
183,090,659 |
|
|
|
179,834,146 |
|
|
|
|
|
|
Diluted weighted
average shares outstanding |
|
|
183,090,659 |
|
|
|
180,253,024 |
|
|
|
|
|
|
|
|
|
|
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Gulfport Energy (NASDAQ:GPOR)
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From Apr 2023 to Apr 2024