august 2015 -...

Investor PresentationAugust 2015

Forward Looking Statement

This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the SecuritiesExchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical facts, included in this presentation that address activities, events or developmentsthat Gulfport Energy Corporation (“Gulfport” or “the Company”) expects or anticipates will or may occur in the future, including statements relating to the proposed transactions, future capitalexpenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of Gulfport’s business andoperations, plans, market conditions, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. These statements arebased 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 asother 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 anumber of risks and uncertainties, general economic, market, business or weather conditions; the opportunities (or lack thereof) that may be presented to and pursued by Gulfport; competitiveactions by other oil and gas companies; changes in laws or regulations; and other factors, many of which are beyond the control of Gulfport. Specifically, Gulfport cannot assure you that theproposed transactions described in this presentation will be consummated on the terms Gulfport currently contemplates, if at all. Information concerning these and other factors can be foundin the company’s filings with the Securities and Exchange Commission (“the SEC”), including its Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in thispresentation 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. We have no intention, and disclaim any obligation, to update or revise any forward-lookingstatements, whether as a result of new information, future results or otherwise.

Prior to 2010, the SEC generally permitted oil and gas companies, in their filings, to disclose only proved reserves that a company has demonstrated by actual production or conclusiveformation tests to be economically and legally producible under existing economic and operating conditions. Beginning with year-end reserves for 2009, the SEC permits the optional disclosureof probable and possible reserves that meet the SEC definitions of such terms. The SEC defines "probable reserves" as those additional reserves that are less certain to be recovered than provedreserves but which, in sum with proved reserves, are as likely as not to be recovered. The SEC defines "possible reserves" as those additional reserves that are less certain to be recovered thanprobable reserves. In this presentation, Gulfport provides disclosure with respect to its probable reserves as of December 31, 2014. However, in its filings with the SEC, Gulfport discloses onlyestimated proved reserves. Gulfport's estimated proved reserves as of December 31, 2014 were prepared by Ryder Scott Company, L.P. ("Ryder Scott") with respect to Gulfport's assets in theUtica Shale in Eastern Ohio (97% of its proved reserves at December 31, 2014), by Netherland, Sewell & Associates, Inc. ("NSAI") with respect to Gulfport's WCBB, Hackberry and Niobrara fields(3% of its proved reserves at December 31, 2014) and by Gulfport's personnel with respect to its overriding royalty and non-operated interests (less than 1% of its proved reserves at December31, 2014), and comply with definitions promulgated by the SEC. Each of Ryder Scott and NSAI is an independent petroleum engineering firm. In this press release, we may use the terms "unriskedresource potential," "unrisked resource," "contingent resource," or "EUR," or other descriptions of volumes of hydrocarbons to describe volumes of resources potentially recoverable throughadditional drilling or recovery techniques that the SEC's guidelines prohibit it from including in filings with the SEC. "Unrisked resource potential," "unrisked resource," "contingent resource," or"EUR," do not reflect volumes that are demonstrated as being commercially or technically recoverable. Even if commercially or technically recoverable, a significant recovery factor would beapplied to these volumes to determine estimates of volumes of proved reserves. Accordingly, these estimates are by their nature more speculative than estimates of proved reserves andaccordingly are subject to substantially greater risk of being actually realized by the Company. The methodology for "unrisked resource potential," "unrisked resource," "contingent resource," or"EUR," may also be different than the methodology and guidelines used by the Society of Petroleum Engineers and is different from the SEC's guidelines for estimating probable and possiblereserves.

EBITDA is a non-GAAP financial measure equal to net income, the most directly comparable GAAP financial measure, plus interest expense, income tax expense, accretion expense anddepreciation, depletion and amortization. We have presented EBITDA because we use EBITDA as an integral part of our internal reporting to measure our performance and to evaluate theperformance of our senior management. EBITDA is considered an important indicator of the operational strength of our business. EBITDA eliminates the uneven effect of considerable amountsof non-cash depletion, depreciation of tangible assets and amortization of certain intangible assets. A limitation of this measure, however, is that it does not reflect the periodic costs of certaincapitalized tangible and intangible assets used in generating revenues in our business. Management evaluates the costs of such tangible and intangible assets and the impact of relatedimpairments through other financial measures, such as capital expenditures, investment spending and return on capital. Therefore, we believe that EBITDA provides useful information to ourinvestors regarding our performance and overall results of operations. EBITDA is not intended to be a performance measure that should be regarded as an alternative to, or more meaningfulthan, either net income as an indicator of operating performance or to cash flows from operating activities as a measure of liquidity. In addition, EBITDA is not intended to represent fundsavailable 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 presented herein may not be comparable to similarly titled measures presented by other companies, and may not be identical to corresponding measures used in our variousagreements, including our debt agreements. For a reconciliation of EBITDA to net income, please refer to the filings we have made with the SEC.

2|WWW.GULFPORTENERGY.COM

http://www.gulfportenergy.com


Gulfport Today

Key Statistics Primary Areas of Operation (3)

1) Market capitalization calculated as of the close of the market on 8/4/2015 at a price of $33.02 per share using shares outstanding from the Company’s 2Q2015 financial statements.

2) Enterprise value calculated as of the close of the market on 8/4/2015 at a price of $33.02 per share using shares outstanding, short‐term debt, long‐term debt, and cash and cash equivalents from the

Company’s 2Q2015 financial statements.

3) Utica Shale acreage as of 8/5/2015 and pro forma for pending Paloma acquisition and customary post closing adjustments; all other acreage figures as of 6/30/2015.

4) Reserve and resource estimates based on Gulfport’s 24.9% interest in Grizzly Oil Sands ULC. For important qualifications and limitations relating to these oil sands reserves and resources, please see page

36 of this presentation.

Grizzly Oil Sands (4)

Acreage: ~200,000 Net Acres

Proved Reserves: 16.8 Net MMBbl

Probable Reserves: 48.3 Net MMBbl

Contingent Resource: 697.3 Net MMBbl

Utica ShaleAcreage: ~243,000 Net Acres

Proved Reserves: 907.0 Net Bcfe

Probable Reserves: 300.3 Net Bcfe

Southern LouisianaAcreage: ~11,002 Net Acres

Proved Reserves: 4.1 Net MMBoe

Probable Reserves: 8.1 Net MMBoe

Market Capitalization (1) $3.6 Billion

Enterprise Value (2) $4.0 Billion

2014 Average Daily Production 240.3 MMcfepd

1Q14 162.5 MMcfepd

2Q14 160.3 MMcfepd

3Q14 254.0 MMcfepd

4Q14 381.9 MMcfepd

2015E Average Daily Production 517 – 541 MMcfepd

1Q15 424.4 MMcfepd

2Q15 473.9 MMcfepd

Net Core Acreage

Utica Shale – Pro forma ~243,000 acres

Southern Louisiana ~11,002 acres

Canadian Oil Sands ~200,000 acres

2014 Proved Reserves 933.6 Bcfe

% Gas 77%





• Gulfport Energy Corporation (“GPOR”) is an independent E&P company based in Oklahoma City, OK

— Company born from legacy assets in South Louisiana

— Free cash flow from legacy assets facilitated expansion into North America’s premier resource plays

Overview of Gulfport

1997 – 1998 1998 – 2005

Phase 1:Formation/Asset Focus

Phase 2:Low Risk Development

Phase 3:Expansion/Diversification

2005 – 2007

Phase 4:Resource Play Addition

2007 – 2012 2012 – Today

Phase 5:Resource Development

• Gulfport Energy was formed in July 1997

• Initial assets were those of WRT Energy and a 50% working interest in the West Cote Blanche Bay (“WCBB”) field contributed by DLB Oil and Gas

• Gulfport divested a number of assets during this period leaving a cleaner balance sheet and focused asset base

• Focused on production and cash flow growth from low risk development activities principally in WCBB

• Reprocessed 3D seismic in WCBB field

• Created a track record of successful drilling

• Continued successful drilling and growth at the WCBB field

• Conducted a 3-D seismic shoot and drilled first exploratory wells in Hackberry field

• Amassed solid acreage position in Canadian Oil Sands and launched core hole drilling program

• Acquired interest in Phu Horm natural gas field in Thailand

• Acquired initial acreage position in Permian Basin and expanded through acquisitions

• Acquired larger interest in second natural gas field in Thailand

• Secured sizable position in the core of the Utica Shale achieving early entrant advantages

• Initiated aggressive drilling program to begin developing Utica Shale resource and currently running a four rig drilling program

• Contributed Permian Basin interests in Diamondback Energy, Inc. IPO to facilitate accelerated resource development




Key Investment and Financial Highlights

1) Excluding $301 million acquisition of Paloma and $407 million acquisition from AEU.2) Pro forma for pending acquisition of Paloma and customary post closing adjustments.3) Reserve and resource estimates based on Gulfport’s 24.9% interest in Grizzly Oil Sands ULC.4) Based on the midpoint of 2015 guidance.

Quality

Assets

Strong

Balance Sheet

Conservative

Financial

Strategy

• High quality, low cost assets allow Gulfport to grow production 115% to 125% over 2014, equating to 517 – 541 MMcfepd

— Anticipated 2015 E&P capital budget of $561 – $611 million and leasehold budget of $85 – $95 million (1)

• Most levered to the core of the Utica Shale of eastern Ohio with approximately 243,000 pro forma (2)

net acres under lease — Actively drilling horizontal wells; produced 458 MMcfepd during 2Q2015

— Development expected to provide further catalyst for reserves and production growth

• Canadian oil sands provides net exposure to over 762 million barrels of oil resource (3)

• South Louisiana oil production provides strong base of cash flows for resource play expansion — Produced 2,591 Boepd during 2Q2015; high quality Louisiana Sweet crude priced at a premium to WTI

• Strong balance sheet and cash flow expected to allow Gulfport to continue to drive production growth

— Current undrawn borrowing base of $575 million and expect the borrowing base to increase as Gulfport adds significant reserve volumes in the Utica Shale

• Remain committed to funding 2015 activities through operational cash flow, the Company's credit facility and other available sources of pro forma liquidity

— Capital will compete and be deployed into highest return projects

• Gulfport actively hedges a portion of its expected production to lock in prices and returns which provide certainty of cash flows to execute on its capital plans

— Currently ~57% (4) of 2015E natural gas production is hedged attractively at $3.94 per MMBtu

— Company targets to have 50% to 70% of expected twelve-month run rate total production hedged



Year Ending

12/31/2015

Forecasted Production

Average Daily Gas Equivalent Midpoint – MMcfepd 517 541

% Gas 75% 85%

% Liquids 25% 15%

Forecasted Realizations (before the effects of hedges)

Natural Gas (Differential to NYMEX) - $ per MMBtu ($0.52) ($0.58)

NGL ($ per gallon) $0.32 $0.37

Oil (Differential to NYMEX WTI) - $ per Bbl ($10.00)Projected Operating Costs

Lease Operating Expense - $/Mcfe $0.38 $0.32

Midstream Processing and Marketing - $/Mcfe $0.82 $0.77

Production Taxes - % of Revenue 3.5% 3.0%

General and Administrative (1) - $MM $52 $56

Depreciation, Depletion, and Amortization - $/Mcfe $2.50 $2.00

Budgeted E&P Capital Expenditures – in Millions:

Utica – Operated $416 $446

Utica – Non- Operated $125 $140

Southern Louisiana $20 $25

Total Budgeted E&P Capital Expenditures $561 $611

Budgeted Leasehold Capital Expenditures (2) – in Millions: $85 $95

Net Wells Drilled

Utica – Operated 32 36

Utica – Non- Operated 4 6

Total 36 42Net Wells Turned-to-Sales

Utica – Operated 42 46

Utica – Non- Operated 7 9

Total 49 55


Gulfport 2015 Guidance

Utica - Operated

$431.0

Utica

Non-

Operated

$132.5

S. Louisiana

$22.5

Leasehold$90.0

1) Inclusive of non-cash stock compensation.2) Does not include pending Paloma acquisition or AEU acquisitions.Note: Guidance for the year ending 12/31/15 is based on multiple assumptions and certain analyses made by the Company in light of its experience and perception of historical trends and current conditions and may change due to future developments. Actual results may not conform to the Company’s expectations and predictions. Please refer to page 2 for more detail of forward looking statements.



$0.00

$1.00

$2.00

$3.00

3Q'14 4Q'14 1Q'15 2Q'15

Mc

fe

LOE Production Taxes Midstream SG&A Interest

2nd Quarter 2015 Highlights


Increased 196% Year-over-Year

Total Production Production Mix

Utica Wells Turned-to-Sales Oil and Gas Revenues Per Unit Cash Costs

Increased 31% Year-over-Year

Produced~473.9 Mmcfe per day

during 2Q2015Production mix consisted of

77% gas and 23% liquids during 2Q2015

Approximately $147 million(1) in 2Q2015

$1.73 per Mcfe in 1Q2015, a decrease of 36%

Year-over-Year

At quarter end 2Q2015, 137 gross (104 net)

Utica wells producing

Utica Production Growth

Utica production of 457.6 Mmcfepd, an increase of

260% Year-over-Year

1) Second Quarter 2015 oil and gas revenues excluding the impact of the unrealized non-cash hedge loss.

77%

23%Gas

Liquids

YE 2012 YE 2013 YE 2014 YTD 2015

1

26

73

104

2

38

101 137

Net Wells Online

Gross Wells Online

$2.16$1.99

$1.73 $1.73

3Q'14 4Q'14 1Q'15 2Q'15

228.7

353.4

396.0

457.6

MMcfe per day



2011 2012 2013 2014 2015

49,000

106,000

157,200

184,000

243,000(1)

Net Acreage


Strong Growth Ahead

8

Key Highlights Total Net Production

• Gulfport’s total production during 2014 grew 255% over 2013

― Anticipate 2015 production to increase 115% to 125% over 2014

• Gulfport turned-to-sales 47 net operated and 7 net non-operated wells during 2014 in the Utica Shale

― Anticipate 49 to 55 net wells to be turned-to-sales during 2015

• During 2014 and YTD 2015, Gulfport continues to add acreage in the core of the Utica Shale and will hold ~243,000 (1) net acres pro forma for the pending and completed acquisitions

• Growth in the Utica Shale added significant proved reserve volumes during 2014, increasing 305% over 2013

Net Utica Wells Turned to Sales Total Reserve Growth

-

200

400

600

800

1,000

2011 2012 2013 2014

Bcfe

PDP

PDNP

PUD

11683

231

934

1) Pro forma for pending Paloma acquisition and customary post closing adjustments.2) Based on the midpoint of 2015 Guidance. Guidance for the year ending 12/31/15 is based on multiple assumptions and certain

analyses made by the Company in light of its experience and perception of historical trends and current conditions and may change due to future developments. Actual results may not conform to the Company’s expectations and predictions. Please referto page 2 for more detail of forward looking statements.

-

10

20

30

40

50

60

1Q'14 2Q'14 3Q'14 4Q'14 2014 2015E

11 7

14 16

47 44

-

1

3 3

7 8

Num

be

r o

f W

ells

Operated

Non-Operated

52 (2)55

1917

811

Net Utica Acreage

-

100

200

300

400

500

600

1Q'14 2Q'14 3Q'14 4Q'14 1Q'15 2Q'15 2015E

MM

cfe

/da

y

Liquids Gas

162.5 160.3

254.0

381.9

424.4

473.9

529.0 (2)

Contribution of Permian Basin

interests to Diamondback

77.4 MMcfe





$-

$200

$400

$600

$800

$1,000

$1,200

Credit Facilty Bank Debt (6/30/15) L/Cs Outstanding (6/30/15) Cash (6/30/15) Pending Paloma Acquisition Pro Forma Liquidity

($ M

illio

ns)

Liquidity, Capitalization and Hedge Position

1) Hedge volume and weighted average price includes swaptions. 2) Price forecast as of 8/4/2015.3) Based on the midpoint of 2015 guidance.

Pro Forma Liquidity Position

Gas Hedges (1) Key Highlights

• Strong liquidity and hedge position fund 2015 capital program and provide security of cash flows

— Liquidity at 6/30/2015 of $781.5 million

— Gulfport has locked approximately 57% (3) of expected natural gas production in 2015 at $3.94 per MMBtu

• Currently expect to exit 2015 at less than 2.5x debt-to-TTM EBITDA based of 2015 forecast at current commodity prices (2)


$575

$0($92.7)

$525.5$781.5

($226.3)

$3.94$3.65

$3.52$3.35 $3.37

$2.85$3.09

$3.23 $3.31 $3.31

$-

$1.00

$2.00

$3.00

$4.00

-

50

100

150

200

250

2015 2016 2017 2018 2019

Mm

cfp

d

Hedge Volume Average Weighted Hedge Price Nymex Strip (2)



Asset Overview






10

Utica Shale Overview

• Net proved reserves of 907.0 Bcfe (1)

• Net probable reserves of 300.3 Bcfe (1)

• ~ 243,000 net acres (2)

— Oil - ~ 5%

— Condensate - ~17%

— Wet Gas - ~ 14%

— Dry Gas - ~ 64%

Asset Overview

2015 Activities Update (3)

• Average net production of 457.6 MMcfepd

• ~97% of Gulfport’s total net production

2015 Planned Activities (2)

• Currently running 4 gross operated rigs

— + 1 non-operated rig running within RICE/GPOR AMI

• Operated CAPEX: $416 – $446 million

— Drill 50 to 56 gross (32 to 36 net) wells

— Turn-to-sales 49 to 53 gross (42 to 46 net) wells

• Non-Operated CAPEX: $125 – $140 million

— Drill 11 to 16 gross (4 to 6 net) wells

— Turn-to-sales 50 to 64 gross (7 to 9 net) wells

Note: Please refer to page 2 for detail on forward looking statements1) As of 12/31/20142) As of 8/5/2015 pro forma for pending Paloma acquisition and customary post closing adjustments.3) During the three months ended 6/30/2015 11|WWW.GULFPORTENERGY.COM

CarrizoRector 1H

AnteroWayne Pad

AnteroMiley Pad

Magnum Hunter

Farley Pad

Eclipse ResourcesTippens Pad

Rice EnergyBig Foot 9H

Rice EnergyBlue Thunder Unit

Chevron Howard Connor

Unit

ChesapeakeBuell #8H

HessCapstone 2H-

29

CONSOL / Hess

Athens A 1H-24

Gulfport Energy

Francis Pad

Gulfport Energy

Edge Pad

Gulfport Energy

Winesburg Pad

RICE/GPOR AMI RIG

LEGEND

Gulfport Acreage

Acquisition Acreage

GPOR Activity

Magnum Hunter

Stalder #3UH

Magnum Hunter

Ormet Pad

GastarSimms Pad

Gulfport Energy

Cattle Pad



Utica Shale – Drilling and Completion Activity

Net Wells Spud

Net Wells Turned to Sales

Forecast 23 to 29 gross drilled uncompleted wells in inventory at YE2015

1Q'14 2Q'14 3Q'14 4Q'14 2014 2015E (1)

3 6 3 12

3

8 5

-

16

12 4

5

17

13

40

22

3

3

4

2

11

5

Nu

mb

er

of

We

lls

Non-Op

Dry Gas

Wet Gas

Condensate

1Q'14 2Q'14 3Q'14 4Q'14 2014 2015E (1)

7 1 4

12 7

3 5

5

10

23

3 1

9

2

12

33

1

3 3

7 8

Nu

mb

er

of

We

lls

Non-Op

Dry Gas

Wet Gas

Condensate

10

19

32

18

79

39

117

17 19

5452


LEGEND

Gulfport Acreage

Acquisition Acreage

Drilled/Planned 2015

Drilled 2014

Drilled 2013

1) Based on midpoint of 2015 guidance.




Utica Shale – Type Curve Assumptions

Condensate Wet Dry Gas

Type Curve Assumptions (1) West East Gas West Central East

Lateral Length 8,000 8,000 8,000 8,000 8,000 8,000

Well Cost ($MM) $9.2 $9.2 $9.9 $10.2 $10.4 $10.7

Well Cost ($ per foot) $1,150 $1,150 $1,235 $1,270 $1,305 $1,340

Total EUR (Bcfe / 1,000) 0.7 1.0 2.0 2.2 2.4 2.6

Total EUR (Bcfe) 5.7 8.1 16.0 17.2 19.0 20.7

% Gas 42% 56% 77% 100% 100% 100%

Assumed Well Spacing (ft) 600 600 750 750 750 750

Net Undeveloped Locations 183 82 168 187 426 265

LEGEND

Gulfport Acreage

Acquisition Acreage

Utica Single Well Economics (1) (2)

183

82

168 187

426

265

12%10%

32%

56%59%

61%

-

50

100

150

200

250

300

350

400

450

0%

10%

20%

30%

40%

50%

60%

70%

Condensate

West

Condensate East Wet Gas Dry Gas West Dry Gas Central Dry Gas East

Ne

t Un

de

ve

lop

ed

Loc

atio

ns

IRR

Net Undeveloped Locations IRR

Note: See appendix slide 25 for detailed assumptions used to generate single well IRRs and slide 29 for net undeveloped locations. 1) Assumes ethane rejection.2) Well economics are based on flat price case of $3.50 / MMBtu gas, $58.00 / Bbl oil, and $14.00 / Bbl NGLs.




Utica Shale – Single Well Economics

Utica Shale Economics and Inventory (1)

12%

25%

38%

10%

21%

33%

11%

32%

57%

86%

11%

31%

56%

85%

118%

13%

34%

59%

88%

120%

15%

36%

61%

90%

121%

0%

20%

40%

60%

80%

100%

120%

140%

Gas $2.50 / Oil $42.50 /

NGL $10.00

Gas $3.00 / Oil $50.00 /

NGL $12.00

Gas $3.50 / Oil $58.00 /

NGL $14.00

Gas $4.00 / Oil $67.00 /

NGL $16.00

Gas $4.50 / Oil $75.00 /

NGL $18.00

Condensate West Condensate East Wet Gas Dry Gas West Dry Gas Central Dry Gas East

Condensate

West

Condensate

East

Wet

Gas

Dry Gas

West

Dry Gas

Central

Dry Gas

East

Net Undeveloped Locations 183 82 168 187 426 265

Note: See appendix slide 25 for detailed assumptions used to generate single well IRRs and slide 29 for net undeveloped locations. 1) Assumes ethane rejection.



Key Highlights

• Focused acreage position in the core of the play

• Consistency of the reservoir enables us to stay within the target zone, the Point Pleasant

─ Highly uniformed stratigraphy and limited reservoir variation

─ Structural simplicity, low dip and minimal faults

─ Petrophysical properties extremely uniform across the play

• Stratigraphy and structural simplicity allow for highly repeatable results

WestA

East Aʹ

SouthB

North Bʹ

A

Aʹ

B

Bʹ

116 ft 118 ft

122 ft98 ft

Utica Shale – Consistency of Reservoir

LEGEND

Gulfport Acreage

Acquisition Acreage




Conclusions

• Gulfport has collected production data from over 25 pads that were spaced at closer than 1,000’, including our three-well Darla pad

— Located across all three phase windows of the play

• Considering the stimulation treatments on the Darla pad, preliminary results suggest a lateral spacing of 600’ - 750’ is necessary to optimize propped fracture length

— Estimate average propped fracture half-length of 330’

• Technology study supports the maximum lateral spacing moving forward should be 750’ in the wet gas and dry gas windows of the play and 600’ in the condensate window of the play

— Conductive fracture length is the primary focus

3D Image of Darla Pad Schematics

Utica Shale – Well Spacing Conclusions


LEGEND

Gulfport Acreage

Acquisition Acreage

Wells Spaced <1,000’

Pilot Tests <1,000’ Interlateral Spacing



Microseismic

Fiber Optics

(DTS & DAS)

Chemical Tracers

Log Suites

(Pilot & Lateral Logs)

Discrete Fracture

Network Modeling

Production History

Matching

Economic

Simulation

― Gross Geometry― Anisotropy Representation― Indication of Natural Fracture

Spacing

― Indication of Propped Geometry

― Indication of System Permeability

― End of Job Cluster Efficiency― Cluster Contribution― Screen Off Effects and

Treatment Scheduling

― KEY TECHNOLOGY - Flow Metering (Production Log)

― Cluster Contribution― Well & Fracture Interaction

― Upper Boundary for Fracture Half Lengths

― Stress & Leakoff― Calibration to Existing Well

Control

― Calibration of Lateral Logs to Cluster Efficiency

― Gross Geometry― Propped Geometry― Calibration of Predictive Model

for Case Wells

― Cluster Efficiency― Basis of Design for Mangrove

Hydraulic Fracturing Simulator

― Flowing & Effective Fracture Half Lengths

― Calibration of Discrete Fracture Network Model

― System Permeability― Basis to Forecast Hydraulic

Fracture Design Optimization

Utica Shale – Technology Utilization & Integration

― Reservoir Simulation― Economic Sensitivities at

Various Spacing Regimes

― Economic Recoveries at Various Well Densities

― Economic Analysis of Completion Design


Inc

rea

sin

g R

efin

em

en

t



Utica Shale – Diversified Portfolio

Overview

SENECA PLANT

CADIZ PLANT

LEBANON

CLARINGTON &SWITZERLAND

DEFIANCE

DAWN

MICHCON

CHICAGO CITY GATE

CONSUMERS

ANR Pipeline (North)Amount: 250,000 Dth/d

Market: MidwestCurrently In-Service

Rover Pipeline (North)Amount: 125,000 Dth/d

Market: Midwest and DawnIn-Service 1H2017

Rover Pipeline (South)Amount: 25,000 Dth/d

Market: GulfIn-Service 1H2017

ANR Pipeline (South)Amount: 50,000 Dth/d

Market: GulfCurrently In-Service

Dominion Transmission Amount: 250,000 Dth/d

Market: LebanonCurrently In-Service

Dominion East OhioAmount: 520,000 Dth/d

Market: DTI, TGP, Rex, TETCOCurrently In-Service

Tennessee Gas Pipeline

Amount: 200,000 Dth/dMarket: Gulf

In-Service April 2015Texas Gas

TransmissionAmount: 104,000 Dth/d

Market: GulfIn-Service June 2016 and April 2017

Columbia (Leach/Rayne)Amount: 100,000 Dth/d

Market: GulfIn-Service November 2017

TETCO PipelineAmount: 147,000 Dth/d

Market: GulfIn-Service Nov 2015 and Nov 2017

Gas City

Rockies Express Amount: 315,000 Dth/dMarket: Midwest / Gulf

In-Service 2H2015

NGPL PipelineAmount: 20,000 Dth/d

Market: ChicagoCurrently In-Service




0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

1,400,000

MM

Btu

pe

r d

ay

Overview

Utica Shale – Firm Transportation and Sales Outlets

Firm Commitments (MMBtu per day)

YE2014 YE2015 YE2016 YE2017 +

(MMBtu / day)

Midwest Markets

ANR Pipeline 184,000 184,000 244,000 244,000

Dominion Transmission Pipeline 56,000 6,000 6,000

NGPL 20,000 20,000 20,000

Rockies Express Pipeline 63,000 153,000 153,000

Rover Pipeline 15,000 15,000

TETCO 46,000

Canadian Markets

ANR Pipeline 60,000 60,000


Gulf Coast Markets

ANR Pipeline 50,000 50,000 50,000

Tennessee Gas Pipeline 200,000 200,000 200,000

Texas Gas Transmission 50,000 104,000


Columbia 100,000

Firm Sales Agreements

Dominion South Point 5,000 5,000

TETCO M2 50,000 75,000 75,000 75,000

Chicago City Gate 50,000

Fixed Basis 33,000 194,000 154,000 124,000

TOTAL 382,000 907,000 1,102,000 1,272,000

Firm Transportation Costs ($ per MMBtu)

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

2015 2016 2017

$0.47 $0.50 $0.53

$0.12 $0.11 $0.11

$0.59 $0.61 $0.64

$ p

er

MM

Btu

Demand Variable

ANR (Midwest) – November 2016

ET Rover (Dawn) – November 2016

ET Rover (Midwest) – November 2016

Rex (Midwest) – Current

TGP (Gulf) – Current

ANR (Gulf) – Current

ANR (Dawn/Midwest) – Current

DTI (Midwest) – Current TGT (Gulf) – June 2016

NGPL (Midwest) – Current

ET Rover (Gulf) – November 2016

TETCO (Michcon) – November 2017

Firm Sales

Columbia (Gulf) – November 2017


ANR (Midwest) – Current



• Early access to premium Midwest markets and was a first-mover in securing early transport at low costs out of the basin

• For 2015, we estimate ~90% of Gulfport’s expected Utica gas production is being sold at premium pricing points

• Gulfport expects to realize a natural gas price of ($0.52) to ($0.58) below Henry Hub in 2015

• Currently have ~57% of 2015E natural gas production hedged which provides certainty to realizations and cash flows

Overview

Utica Shale – Transportation Improves Pricing

2015 Average Differential Firm Portfolio

2013 1Q 2015 Current

382,000

923,000

1,272,000

MM

Btu

pe

r d

ay

YE 2017 Secured Transport Commitments

2015E

Henry Hub ($/MMBtu) (1) $2.85

Basis Differential ($/MMBtu) (2) ($0.55)

BTU Uplift (MMBtu/Scf) $0.21

Pre-Hedge Realized Price ($/Mcf) $2.51

Hedging Impact $0.62

Post-Hedge Realized Price (S/Mcf) $3.13

1) Price forecast as of 8/4/15.2) Based on midpoint of 2015E guidance.

8%

21%

36%

7%

28%

Remainder 2015

Firm Sales (Index)

Firm Sales (Fixed)

Midwest

Canadian

Gulf Coast

3%7%

40%

11%

39%

2016 and Beyond




Utica Shale – NGL Infrastructure

Edmonton Markets

Midwest Markets

Ontario Markets

Northeast Markets

Mid-Atlantic Markets

Gulf Coast Markets

Marcus Hook

Chesapeake

Africa

Asia

South Am.

EuropeRail

PipeTruck

Key Highlights

• Gulfport anticipates to realize $0.32 to $0.37 per gallon for NGLS during 2015

• Mont Belvieu propane at lows not seen since 2002

— Compared to Mont Belvieu, Gulfport has more of the barrel subject to seasonal swings

• Expect NGL weakness to continue near-term but believe overall prices could show some improvement during the fourth quarter due to higher seasonal demand and additional export capacity coming on line.

12%

7%

6%

38%

37%

Mont Belvieu

Barrel Makeup

C2 Purity Ethane

C3 Propane

IC4 IsoButane

NC4 Normal Butane

C5+ Rest

14%

12%

11%

43%

20%

2Q GPOR

Barrel Makeup Markets % of 2015 C3+ Bbl

Northeast 43%

Export 15%

Gulf Coast 14%

Edmonton 10%

Midwest 9%

Mid-Atlantic 5%

Ontario 4%

100%

Transport Method % of 2015 C3+ Bbl

By Rail 60-65%

By Pipeline 30-35%

By Truck 5-10%

NGL Barrel Composition




Utica Shale – Midstream Infrastructure

Note: Per MarkWest Energy Partners 2Q2015 Earnings Update on August 5, 2015.

Utica Condensate JVStabilization Facility – 23,000 Bbl/d– Operational

Cadiz ComplexCadiz I & II – 325 MMcf/d – Operational

Cadiz III – 200 MMcf/d – 3Q15 Cadiz IV – 200 MMcf/d – 2Q16

De-ethanization – 40,000 Bbl/d – Operational

Hopedale FractionatorC3+ Fractionation I & II- 120,000 Bbl/d – Operational

C3+ Fractionation III - 60,000 Bbl/d –1Q16

Seneca ComplexSeneca I - IV- 800 MMcf/d – Operational

MarkWest Dry Gas SystemOperational

Rice Energy Dry Gas SystemOperational

AEU Dry Gas SystemOperational

LEGEND

GPOR Lease Acreage

Acquisition Acreage Area

MarkWest Wet System

MarkWest Dry System

MarkWest NGL Pipeline

Rice Dry System

AEU Dry System




Southern Louisiana

Asset Overview (1)

2015 Activities Update (2)

2015 Planned Activities (3)

• Net proved reserves of 4.1 MMBoe

• Net probable reserves of 8.1 MMBoe

• 11,002 net acres

• Gulfport operated

• Average net production of 2,591 Boepd

• ~3% of Gulfport’s total net production

• ~99% oil weighted production mix

— Priced as high quality LLS crude and sold at a premium to WTI

• Maintenance CAPEX: $20 – $25 million

Note: Please refer to page 2 for detail on forward looking statements1) As of 12/31/20142) During the three-month period ended 6/30/20153) As of 2/25/2015 23|WWW.GULFPORTENERGY.COM



Utica Appendix




CondensateWest

Condensate East

Wet Gas

Dry Gas West

Dry Gas Central

Dry Gas East

Identified Net Locations 183 82 168 187 426 265

Type Curve Assumptions

Lateral Length (ft.) 8,000 8,000 8,000 8,000 8,000 8,000

Initial Gas Production (Mcf/d) (1) 2,500 3,300 12,000 14,000 14,000 14,000

Flat Period (days) 90 90 274 243 274 304

Shrink 13% 13% 12% N/A N/A N/A

NGL Yield (Bbls/MMcf) 71 65 44 N/A N/A N/A

Residue BTU 1,140 1,135 1,095 1,070 1,060 1,050

Pre-Processed EUR (Bcfe) 4.9 6.7 14.0 17.2 19.0 20.7

Pre-Processed % Gas 56% 78% 100% 100% 100% 100%

Post-Processed EUR (Bcfe / 1,000') (2) 0.7 1.0 2.0 2.2 2.4 2.6

Post-Processed EUR (Bcfe) (2) 5.7 8.1 16.0 17.2 19.0 20.7

Oil (MBbl) 358 249 7 - - -

NGL (MBbl) 196 338 614 - - -

Residue Gas (MMcf) 2,389 4,527 12,227 17,202 18,952 20,711

Post Processed % Gas 42% 56% 77% 100% 100% 100%

Differentials (3)

Gas ($ / MMBtu off NYMEX) $ (0.65) $ (0.65) $ (0.65) $ (0.65) $ (0.65) $ (0.65)

Condensate ($ / Bbl off WTI) $ (10.00) $ (10.00) $ (10.00) $ (10.00) $ (10.00) $ (10.00)

NGL ($ / gallon) $ 12.60 $ 12.60 $ 12.60 $ 12.60 $ 12.60 $ 12.60

Operating Expenses

OPEX - Year 1

Fixed ($/well/mo) $ 25,000 $ 25,000 $ 25,000 $ 25,000 $ 25,000 $ 25,000

Variable ($/Mcf) $ 0.17 $ 0.15 $ 0.05 $ 0.05 $ 0.05 $ 0.05

OPEX - Year 2

Fixed ($/well/mo) $ 20,000 $ 20,000 $ 20,000 $ 20,000 $ 20,000 $ 20,000

Variable ($/Mcf) $ 0.09 $ 0.07 $ 0.02 $ 0.02 $ 0.02 $ 0.02

OPEX - Year 3+

Fixed ($/well/mo) $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000 $ 15,000

Variable ($/Mcf) $ 0.09 $ 0.07 $ 0.02 $ 0.02 $ 0.02 $ 0.02

Gathering & Compression ($/Mcf) $ 0.64 $ 0.64 $ 0.56 $ 0.40 $ 0.40 $ 0.40

Processing ($/Mcf) $ 0.65 $ 0.65 $ 0.52 N/A N/A N/A

Severance Tax 2.5% 2.5% 2.5% 2.5% 2.5% 2.5%

Well Cost Assumptions

Well Cost ($MM) $ 9.2 $ 9.2 $ 9.9 $ 10.2 $ 10.4 $ 10.7

Well Cost ($ per foot) $ 1,150 $ 1,150 $ 1,235 $ 1,270 $ 1,305 $ 1,340

Utica Shale – Type Curve Assumptions


Note: See appendix slide 29 for detailed assumptions used to net undeveloped locations. 1) Represents 24-hour rate well head gas production.2) Assumes ethane rejection.3) Includes transportation costs and basis differentials.



Utica Shale – Condensate Window Type Curves

Condensate Type Curves (1)

12%

25%

38%

10%

21%

33%

0%

10%

20%

30%

40%

Gas $2.50 / Oil $42.50 /

NGL $10.00

Gas $3.00 / Oil $50.00 /

NGL $12.00

Gas $3.50 / Oil $58.00 /

NGL $14.00

Gas $4.00 / Oil $67.00 /

NGL $16.00

Gas $4.50 / Oil $75.00 /

NGL $18.00

Condensate West Condensate East

Single Well Economics (1)

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Bc

feM

cfe

pe

r d

ay

Months0.7 Bcfe / 1,000' Daily Production 1.0 Bcfe / 1,000' Daily Production

0.7 Bcfe / 1,000' Cumulative Production 1.0 Bcfe / 1,000' Cumulative Production

Condensate

Type Curve Assumptions (1) West East

Lateral Length 8,000 8,000

Well Cost ($MM) $9.2 $9.2

Well Cost ($ per foot) $1,150 $1,150

Total EUR (Bcfe / 1,000) 0.7 1.0

Total EUR (Bcfe) 5.7 8.1

% Gas 42% 56%

Assumed Well Spacing (ft) 600 600

Net Undeveloped Locations 183 82





Utica Shale – Wet Gas Window Type Curve

Wet Gas Type Curves (1)

11%

32%

57%

86%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

Gas $2.50 / Oil $42.50 /

NGL $10.00

Gas $3.00 / Oil $50.00 /

NGL $12.00

Gas $3.50 / Oil $58.00 /

NGL $14.00

Gas $4.00 / Oil $67.00 /

NGL $16.00

Gas $4.50 / Oil $75.00 /

NGL $18.00

Wet Gas


0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

10.0

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

Bc

feM

cfe

pe

r d

ay

Months

2.0 Bcfe / 1,000' Daily Production 2.0 Bcfe / 1,000' Cumulative Production

Wet

Type Curve Assumptions (1) Gas

Lateral Length 8,000

Well Cost ($MM) $9.9

Well Cost ($ per foot) $1,235

Total EUR (Bcfe / 1,000) 2.0

Total EUR (Bcfe) 16.0

% Gas 77%

Assumed Well Spacing (ft) 750

Net Undeveloped Locations 168





Utica Shale – Dry Gas Window Type Curves

Dry Gas Type Curves (1)

11%

31%

56%

85%

118%

13%

34%

59%

88%

120%

15%

36%

61%

90%

121%

0%

20%

40%

60%

80%

100%

120%

Gas $2.50 / Oil $42.50 /

NGL $10.00

Gas $3.00 / Oil $50.00 /

NGL $12.00

Gas $3.50 / Oil $58.00 /

NGL $14.00

Gas $4.00 / Oil $67.00 /

NGL $16.00

Gas $4.50 / Oil $75.00 /

NGL $18.00

Dry Gas West Dry Gas Central Dry Gas East


0.0

2.0

4.0

6.0

8.0

10.0

12.0

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

Bc

feM

cfe

pe

r d

ay

Months

2.2 Bcfe / 1,000' Daily Production 2.4 Bcfe / 1,000' Daily Production 2.6 Bcfe / 1,000' Daily Production

2.2 Bcfe / 1,000' Cumulative Production 2.4 Bcfe / 1,000' Cumulative Production 2.6 Bcfe / 1,000' Cumulative Production

Dry Gas

Type Curve Assumptions (1) West Central East

Lateral Length 8,000 8,000 8,000

Well Cost ($MM) $10.2 $10.4 $10.7

Well Cost ($ per foot) $1,270 $1,305 $1,340

Total EUR (Bcfe / 1,000) 2.2 2.4 2.6

Total EUR (Bcfe) 17.2 19.0 20.7

% Gas 100% 100% 100%

Assumed Well Spacing (ft) 750 750 750

Net Undeveloped Locations 187 426 265





Determination of Identified Drilling Locations as of June 30, 2015

Net Undeveloped Locations: Calculated by taking Gulfport’s total net acreage and multiplying such amount by a risking factor which is then divided by Gulfport’s expected well spacing. Gulfport then subtracts net producing wells to arrive at undeveloped net drilling locations.

Net Undeveloped Utica Condensate West Locations: Gulfport assumes these locations have 8,000 foot laterals and 600 foot spacing between wells which yields approximately 110 acre spacing. We apply a 20% risking factor to the net acreage to account for inefficient unitization and the risk associated with the inability to force pool in Ohio.

Net Undeveloped Utica Condensate East Locations: Gulfport assumes these locations have 8,000 foot laterals and 600 foot spacing between wells which yields approximately 110 acre spacing. We apply a 20% risking factor to the net acreage to account for inefficient unitization and the risk associated with the inability to force pool in Ohio.

Net Undeveloped Utica Wet Gas Locations: Gulfport assumes these locations have 8,000 foot laterals and 750 foot spacing between wells which yields approximately 138 acre spacing. We apply a 20% risking factor to the net acreage to account for inefficient unitization and the risk associated with the inability to force pool in Ohio.

Net Undeveloped Utica Dry Gas West Locations: Gulfport assumes these locations have 8,000 foot laterals and 750 foot spacing between wells which yields approximately 138 acre spacing. We apply a 20% risking factor to the net acreage to account for inefficient unitization and the risk associated with the inability to force pool in Ohio.

Net Undeveloped Utica Dry Gas Central Locations: Gulfport assumes these locations have 8,000 foot laterals and 750 foot spacing between wells which yields approximately 138 acre spacing. We apply a 20% risking factor to the net acreage to account for inefficient unitization and the risk associated with the inability to force pool in Ohio.

Net Undeveloped Utica Dry Gas East Locations: Gulfport assumes these locations have 8,000 foot laterals and 750 foot spacing between wells which yields approximately 138 acre spacing. We apply a 20% risking factor to the net acreage to account for inefficient unitization and the risk associated with the inability to force pool in Ohio.

Additional Disclosures

Net Undeveloped Locations

Condensate

West

Condensate

East

Wet

Gas

Dry Gas

West

Dry Gas

Central

Dry Gas

East

Net Undeveloped Location Summary

Net Acres 26,799 13,376 33,651 33,964 76,422 45,895

Lateral Length 8,000 8,000 8,000 8,000 8,000 8,000

Location Spacing 600 600 750 750 750 750

Net Potential Locations 243 121 244 247 555 333

Less approximate wells turned to sales (1) 14 19 34 13 22 1

Unrisked Net Undeveloped Locations 229 102 210 234 532 332

Risking Factor 20% 20% 20% 20% 20% 20%

Risked Net Undeveloped Locations 183 82 168 187 426 265




Overview

Utica and SW Marcellus Proposed Pipeline Projects

Source: Wood Mackenzie, “United States gas markets long-term outlook 2015,” June 2015.

Project Name Pipeline Sponsor Delivery Area

Total Capacity

(MMBtu/day) Start-Up Date

Lebanon Lateral Reversal ANR Pipeline TransCanada Midwest 350 3/1/2014

SWLA Station 219 to Zone 1 500L Tennessee Pipeline Kinder Morgan South 400 4/1/2014

Lebanon West - Phase 1 Dominion Transmission Dominion Resources Lebanon 250 6/1/2014

Seneca Lateral Rockies Express Pipeline TallGrass REX Midwest 225 6/1/2014

SWLA Station 219 to Zone 1 500L Phase 2 Tennessee Pipeline Kinder Morgan South 200 6/1/2014

Team South Texas Eastern Transmission Spectra Energy South 300 9/1/2014

Team 2014 (M2 to Lebanon) Texas Eastern Transmission Spectra Energy Lebanon 50 10/1/2014

Team 2014 (M2 to M1 30") Texas Eastern Transmission Spectra Energy South 250 10/1/2014

Team 2014 (M2 to M3) Texas Eastern Transmission Spectra Energy Northeast Markets 300 10/1/2014

Jefferson Compressor Equitrans Pipeline EQT Midstream Partners Intra-Northeast 600 11/1/2014

Westside/Smithfield III to Leach Columbia Gas Transmission NiSource South 444 11/1/2014


East-to-West Rockies Express Pipeline TallGrass REX Midwest 1,200 4/1/2015

Broad Run Lateral Tennessee Pipeline Kinder Morgan South 590 11/1/2015

East-side expansion project Columbia Gas Transmission NiSource Southeast 312 11/1/2015

Lebanon Lateral Reversal ANR Pipeline TransCanada Midwest 600 11/1/2015

Lebanon Project Panhandle Eastern Pipeline Energy Transfer Midwest 275 11/1/2015

Ohio Pipeline Energy Network (OPEN) Texas Eastern Transmission Spectra Energy South 550 11/1/2015

Uniontown to Gas City Texas Eastern Transmission Spectra Energy Midwest 425 11/1/2015

WB Express Broad Run Columbia Gas Transmission NiSource Intra-Northeast 590 11/1/2015

Ohio to Louisiana Project Texas Gas Transmission Boardwalk Pipeline Partners South 625 6/1/2016

Zone 3 Capacity Enhancement Rockies Express Pipeline TallGrass REX Midwest 800 6/1/2016

OH Valley Connector Equitrans Pipeline EQT Midstream Partners Lebanon 400 7/1/2016

Gulf Markets Expansion Phase 1 Texas Eastern Transmission Spectra Energy South 250 11/1/2016


Utica Access Columbia Gas Transmission NiSource Intra-Northeast 200 11/1/2016

Rover Pipeline Rover Pipeline Energy Transfer Midwest 3,250 12/1/2016

Northern Supply Access Project Texas Gas Transmission Boardwalk Pipeline Partners South 584 4/1/2017

Rover Michigan Rover Pipeline Energy Transfer Midwest 1,300 6/1/2017

Adair Southwest Texas Eastern Transmission Spectra Energy South 200 11/1/2017

Broad Run Expansion Zone 3 to Zone 1 500L Tennessee Pipeline Kinder Morgan South 200 11/1/2017

Gulf Markets Expansion Phase 2 Texas Eastern Transmission Spectra Energy South 100 11/1/2017

Leach Express Columbia Gas Transmission NiSource South 1,500 11/1/2017

NEXUS Pipeline NEXUS Pipeline Spectra Energy Midwest 1,500 11/1/2017

Rayne Express Columbia Gulf Transmission NiSource South 251 11/1/2017

WB Express Broad Run Part 2 Columbia Gas Transmission NiSource Intra-Northeast 200 11/1/2017

Access South Texas Eastern Transmission Spectra Energy South 320 4/1/2018

Atlantic Coast PL Atlantic Coast Pipeline Dominion Resources Southeast 1,500 11/1/2018

Gulf Express Columbia Gulf Transmission NiSource South 1,006 11/1/2018

Mountain Valley Pipeline Mountain Valley Pipeline EQT/Nextera Southeast 2,000 11/1/2018

Mountaineer Express Columbia Gas Transmission NiSource South 2,200 11/1/2018

Clarington West Project Rockies Express Pipeline Generic Midwest 1,600 4/1/2022

Total 28,127




Overview

LNG Exports – Proposed Gulf Coast Projects

Project Name Sponsor Nominal Capacity

(MMtpa)

Nominal Capacity

(Bcf/d)FERC Status Development Status

Sabine Pass Cheniere 18 2.40 Approved Under construction

Cameron Sempra 12 1.60 Approved Under construction

Freeport Export Train 1-2 Freeport LNG 10 1.33 Approved Under construction

Freeport Export Train 3 Freeport LNG 5 0.67 Approved Under construction

Corpus Christi Train 1-2 Cheniere 9 1.20 Approved Under construction

Sabine Pass Train 5 Cheniere 4.5 0.60 Approved Under construction

Corpus Christi Train 3 Cheniere 4.5 0.60 Approved

Sabine Pass Train 6 Cheniere 4.5 0.60 Approved

Lake Charles Export Energy Transfer Equity 10 1.33 H2 15

Magnolia LNG LNG Ltd 8 1.07 2016

Golden Pass Export Golden Pass Products 15.6 2.08 2016

Delfin LNGFairwood Group /

Peninsula Group5 0.67 2016

Gulf LNG Energy Kinder Morgan/GE 10 1.33 2017

Source: Wood Mackenzie, “US FERC tracker – Q2 2015 ,” July 2015.




Appendix




Hedge Book (1)

Hedged Production

1) As of August 5, 2015. Counterparty has option to call 20,000 MMBtu/d for January 2016 – December 2016.

3Q15 4Q15 2015 2016 2017 2018 2019

Natural Gas Contract Summary:

Natural Gas Fixed Price Swaps (NYMEX)

Volume (BBtupd) 267 296 241 258 151 70 5

Weighted Average Price ($/MMBtu) $ 3.86 $ 3.87 $ 3.94 $ 3.67 $ 3.52 $ 3.35 $ 3.37

Natural Gas Fixed Price Swaptions (NYMEX)

Volume (BBtupd) - - - 20 - - -

Weighted Average Price ($/MMBtu) $ - $ - $ - $ 3.38 $ - $ - $ -

Total Potential Natural Gas Volumes (BBtupd) 267 296 241 278 151 70 5

Total Weighted Average Price ($/MMBtu) $ 3.86 $ 3.87 $ 3.94 $ 3.65 $ 3.52 $ 3.35 $ 3.37

Oil Contract Summary:

Oil Fixed Price Swaps (LLS)

Volume (Bblpd) 1,500 1,500 1,132 746 - - -

Weighted Average Price ($/Bbl) $ 63.03 $ 63.03 $ 62.86 $ 63.03 $ - $ - $ -

Oil Fixed Price Swaps (WTI)

Volume (Bblpd) 1,000 1,000 586 497 - - -

Weighted Average Price ($/Bbl) $ 61.40 $ 61.40 $ 61.40 $ 61.40 $ - $ - $ -

Total Crude Oil (Bblpd) 2,500 2,500 1,718 1,243 - - -

Total Weighted Average Price ($/Bbl) $ 62.38 $ 62.38 $ 62.36 $ 62.38 $ - $ - $ -

Basis Contract Summary:

MichCon

Volume (BBtupd) 40 40 34 40 - - -

Differential ($/MMBtu) $ 0.02 $ 0.02 $ 0.02 $ 0.02 $ - $ - $ -




Net Reserves as of December 31, 2014

Oil Gas NGL Total PV-10 ($MM)

(MMBbls) (Bcf) (MMBbls) (Bcfe) SEC (1)

Proved Developed Producing 3.5 344.1 12.4 439.4 $1,154

Proved Developed Non-Producing 2.2 1.1 - 14.4 $82

Proved Undeveloped 3.8 373.8 13.9 479.8 $605

Total Proved Reserves 9.5 719.0 26.3 933.6 $1,841

Probable Reserves 9.1 260.4 5.7 349.6 $578

Total Proved + Probable Reserves 18.6 979.4 32.0 1,283.2 $2,419

SEC 1P Net Present Value – 10%SEC Proved Reserve AllocationSEC Net Proved Reserves

2014 Proved Reserve Summary

1) Per Company reserve report for year ending 12/31/14.

PDP

47%

PDNP

2%

PUD

51%

Oil

6%NGL

17%

Gas

77%

PDP

68%

PDNP

3%

PUD

29%




Grizzly Oil Sands

• Gulfport has interest in a substantial position in the Canadian oil sands by way of a 24.9% interest in Grizzly Oil Sands ULC (“Grizzly”)

— Grizzly is effectively the last major private company in the oil sands without a joint venture partner

Note: Gulfport Energy Corporation owns 24.9% of Grizzly Oil Sands ULC. For important qualification and limitations relating to these oil sands reserves and resources, please see page 29 of this presentation1) GLJ Petroleum Consultants Ltd, as December 31, 2014

• Over 800,000 net acres in Athabasca and Peace River regions (nearly all 100% working interest)

• 67 million bbls of proved reserves, 193 million bbls of probable reserves, and approximately 3.0 billion bbls of 2P+Contingent Resources (1)

• Grizzly’s “ARMS” development model enables repeatable and scalable project development, reducing execution and financing risk

Grizzly Summary Grizzly Acreage




— Notes:

— Proved reserves are defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated Proved reserves.

— Probable reserves are defined in the COGE Handbook as those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

— Contingent Resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.

— Prospective Resources are defined in the COGE Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.

— Best Estimate as defined in the COGE Handbook is considered to be the best estimate of the quantity that will actually be recovered from the accumulation. If probabilistic methods are used, this term is a measure of central tendency of the uncertainty distribution (P50).

— Discovered Petroleum Initially-In-Place are defined in the COGE Handbook as that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production.

— Undiscovered Petroleum Initially-In-Place are defined in the COGE Handbook as that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered.

— It should be noted that reserves, Contingent Resources and Prospective Resources involve different risks associated with achieving commerciality. There is no certainty that it will be commercially viable for Grizzly to produce any portion of the Contingent Resources. There is no certainty that any portion of Grizzly’s Prospective Resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the Prospective Resources. Grizzly’s Prospective Resource estimates discussed in this press release have been risked for the chance of discovery but not for the chance of development and hence are considered by Grizzly as partially risked estimates.

Reserves and Resources Notes

Note: Gulfport Energy Corporation owns 24.9% of Grizzly Oil Sands ULC




Gulfport Energy Headquarters14313 North May Avenue, Suite 100

Oklahoma City, OK 73134www.gulfportenergy.com

Investor Relations (405) 242-4888

[email protected]



august 2015 -...

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