8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Date of report (Date of earliest event reported): December 7, 2010

GULFPORT ENERGY CORPORATION

(Exact Name of Registrant as Specified in Charter)

Delaware	000-19514	73-1521290
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification Number)
14313 North May Avenue, Suite 100, Oklahoma City, Oklahoma		73134
(Address of principal executive offices)		(Zip code)

(405) 848-8807

(Registrant’s telephone number, including area code)

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions:

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01. Regulation FD Disclosure.

Representatives of Gulfport Energy Corporation intend to make a presentation at the Capital One Southcoast Energy Conference in New Orleans, Louisiana on Wednesday, December 8, 2010, at 1:20 p.m. Central Time. A copy of the Company’s presentation is being furnished as Exhibit 99.1 to this Current Report on Form 8-K and has also been posted on the Company’s website at www.gulfportenergy.com.

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits

Exhibit Number	Description
99.1	Gulfport Energy Corporation’s presentation at the Capital One Southcoast Energy Conference in New Orleans, Louisiana on December 8, 2010.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	GULFPORT ENERGY CORPORATION
Date: December 7, 2010	By:	/S/    MICHAEL G. MOORE
		Michael G. Moore Chief Financial Officer

Exhibit Index

Exhibit Number	Description
99.1	Gulfport Energy Corporation’s presentation at the Capital One Southcoast Energy Conference in New Orleans, Louisiana on December 8, 2010.

EX-99.1

Exhibit 99.1

Exhibit 99.1

Gulfport Energy Corporation

Capital One Southcoast Energy Conference December 8, 2010

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 Securities Exchange 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 developments that Gulfport expects or anticipates will or may occur in the future, including statements relating to the proposed transactions, 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, business or weather conditions; the opportunities (or lack thereof) that may be presented to and pursued by Gulfport; 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. Specifically, Gulfport cannot assure you that the proposed 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 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 presentation 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-looking statements, whether as a result of new information, future results or otherwise.

Prior to 2010, the Securities and Exchange Commission generally permitted oil and gas companies, in their filings, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation 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 disclosure of probable and possible reserves. We have elected not to disclose our probable and possible reserves in our filings with the SEC. We use the terms “unrisked resource potential,” “unrisked resource,” “contingent resource,” or “EUR,” or other descriptions of volumes of hydrocarbons to describe volumes of resources potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines prohibit us 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 be applied 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 and accordingly 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 possible reserves.

2

Gulfport Today

Company Overview

Areas of Operation

Ticker:

Market Cap¹: $903 MM

45 MM Shares x $20.26 Per Share

Enterprise Value²: $949 MM

Canadian Oil Sands

Acreage: 131,901 Net Acres

Thailand

Acreage: 4,000,000 Gross Acres Reserves: 2.739 Net Bcf Gas

Niobrara Shale

Acreage: 24,468 Net Acres Reserves: 0.900 MMBOE

Permian

Acreage: 13,923 Net Acres Reserves: 11.579 MMBoe

Southern Louisiana

Acreage: 13,998 Net Acres Reserves: 8.264 MMBoe

Portfolio Highlights

20.8 MMBOE Net Proved Reserves

34.6 MMBOE Net Probable Reserves

513 MMBO Net Best Case Recoverable Resource

18.8 MMBOE Net Unbooked Reserve Potential in Permian

587.2 MMBOE Net Exploitable Oil-Rich Resource

Produced 1.68 MMBOE during 2009

Approximately 95% Oil & Liquids

Forecasted 2010 production of approximately 1.85 to 2.05 MMBOE

¹ Market capitalization calculated as of the close of the market on 12/5/10 at a price of $20.26 per share using 3Q’10 shares outstanding from the Company’s 3Q’10 financial statements

² Enterprise value calculated as of the close of the market on 12/5/10 at a price of $20.26 per share using 3Q’10 shares outstanding, short-term and long-term debt, and cash and cash equivalents from the Company’s 3Q’10 financial statements

3

Recent Financial & Operational Highlights

Strong production growth and healthy cash margins drove solid financial performance for Gulfport in 3Q’10

3Q’10 production of 5,728 BOEPD

13% sequential growth over 2Q’10

$24.0 million of EBITDA¹

20% sequential increase over 2Q’10

$23.4 million of operating cash flow¹

20% sequential increase over 2Q’10

$12.7 million of net income

22% sequential increase over 2Q’10

Began permitting a 60 square mile 3-D seismic survey in the Niobrara

– Expect to begin shooting in early 2011 Gulfport’s operator in Permian is actively securing availability of key services and vertically integrating operations

– Secured crews for 6-10 fracs per month

– Purchased two drilling rigs Continue to be focused on controlling lease operating expense

– Reported LOE of $7.71 per BOE in 3Q’10, a 9% sequential improvement from 2Q’10

Grizzly² has finalized plans for an active 2010/2011 winter drilling program

– 89 primary core hole locations

– 35 contingent core hole locations Grizzly² has received its supplemental information request (“SIR”) from Alberta regulators according to schedule

– No significant concerns or issues identified Entered into a new $100 million senior secured revolving credit facility with a September 30, 2013 maturity and an initial borrowing base of $50 million

[Graphic Appears Here]

¹ Please refer to Gulfport’s November 4, 2010, news release regarding financial and operating results for third quarter 2010 and for reconciliation of non-GAAP financial measures to GAAP financial measures

² Gulfport owns a 24.9999% interest in Grizzly Oil Sands, ULC

4

2011 Guidance

Year Ending 12/31/2011 Forecasted Production Oil Equivalent—BOE 2,200,000—2,400,000

Average Daily Oil Equivalent Midpoint—BOEPD 6,301

Projected Year-Over-Year Production Increase¹ 18%

Projected Operating Costs per BOE

Lease Operating Expense—$/BOE $8.00—$9.50 Production Taxes—$/BOE $8.50—$9.50 Depreciation, Depletion and Amortization—$/BOE $19.00—$21.00 General and Administrative—$/BOE $2.50—$3.50

Budgeted Capital Expenditures—In Millions:

West Cote Blanche Bay $35—$38 Hackberry $24—$26 Permian $26—$28 Niobrara $1—$2 Grizzly $24—$26 Total Budgeted Capital Expenditures $110—$120

Gulfport currently expects to spend $110 to $120 million of capital during 2011, which is to be entirely funded from within internally generated cash flow

¹ Based upon the midpoint of 2010 forecasted production of 1.95 MMBOE from guidance released on November 5, 2009 and the midpoint of 2011 forecasted production of 2.3 MMBOE.

5

GPOR vs. Peers

Share Total Debt Enterprise 2011 2011 Est. 2011 2011 Est.

Company Price¹ (9/30/10) Value¹ EBITDA Net Income² EV/EBITDA EV/Net Income² Total Deb/EV

SWIFT ENERGY CO $ 40.15 $ 472 $ 2,138 $ 378 $ 81 5.7 26.4 22% STONE ENERGY CORP $ 21.83 $ 525 $ 1,499 $ 438 $ 101 3.4 14.8 35% ENERGY XXI BERMUDA $ 26.08 $ 766 $ 2,688 $ 685 $ 97 3.9 27.7 28% W&T OFFSHORE INC $ 18.68 $ 450 $ 1,664 $ 466 $ 88 3.6 18.9 27%

Subgroup Average 4.1 21.9 28%

BRIGHAM EXPLORATION CO $ 26.99 $ 306 $ 3,145 $ 273 $ 103 11.5 30.5 10% WHITING PETROLEUM CORP $ 113.49 $ 700 $ 7,342 $ 1,202 $ 400 6.1 18.3 10% OASIS PETROLEUM INC $ 27.60 $ —$ 2,276 $ 195 $ 84 11.7 27.0 0%

Subgroup Average 9.8 25.3 6%

CONCHO RESOURCES INC $ 85.91 $ 727 $ 9,308 $ 1,151 $ 347 8.1 26.9 8% SM ENERGY CO $ 52.65 $ 275 $ 3,588 $ 640 $ 91 5.6 39.6 8% CARRIZO OIL & GAS INC $ 31.46 $ 584 $ 1,680 $ 228 $ 82 7.4 20.5 35% PETROLEUM DEVELOPMENT CORP $ 38.10 $ 302 $ 1,181 $ 192 $ 13 6.2 94.0 26% GMX RESOURCES INC $ 5.05 $ 259 $ 433 $ 87 $ 15 5.0 28.9 60%

Subgroup Average 6.4 42.0 27%

PETROQUEST ENERGY INC $ 7.44 $ 150 $ 565 $ 114 $ 28 5.0 20.3 27% ABRAXAS PETROLEUM CORP $ 4.34 $ 140 $ 470 $ 41 $ 11 11.3 41.2 30% RAM ENERGY RESOURCES INC $ 1.73 $ 247 $ 383 $ 56 $ 5 6.9 70.4 65%

Subgroup Average 7.7 43.9 40% Group Average 6.7 33.7 26% GULFPORT ENERGY CORP $ 20.26 $ 48 $ 949 $ 121 $ 75 7.8 12.6 5%

¹ Closing prices and enterprise values as of 12/5/10

² Bloomberg consensus estimates as of 12/5/10

6

Capturing Valuable Oil Resource

Large exploitable oil-rich resource base of 587 MMBOE + significant upside

20.8 MMBOE of proved reserves Includes 0.9 MMBO of proved reserves from the recent Niobrara acquisition

10.1 MMBOE of probable reserves at WCBB and Permian 100% third party engineered

24.5 MMBO of probable reserves net to Gulfport’s interest in Grizzly’s Algar Lake Related to Grizzly’s commercial development Algar Lake SAGD Project

18.8 MMBOE of unbooked reserve potential in the Permian 496 gross (188 net) unbooked potential drilling locations remaining¹

513 MMBO of best estimate contingent + prospective resource net to Gulfport’s interest in Grizzly Contingent resource assigned to ~35% of Grizzly’s acreage

Does not include significant upside potential encompassed by: Potential resource on the remaining 65% of oil sands acreage Potential for 20-acre down spacing in the Permian Niobrara upside

513 MMBO

18.8 74.2 24.5 MMBOE MMBOE

MMBO 19.9 10.1 30.9 MMBOE 0.9 20.8 MMBOE MMBOE

MMBOE MMBOE

Year-End Niobrara Net Proved Year-End Net Proved & Algar Lake Permian P1 +P2 + Niobrara Resource on Best 20-Acre 2009 Shale Reserves 2009 Probable Net Reserve Recent Resource Remaining Estimate Permian Net Proved Acquisition Net Probable Reserves Contingent Potential Acquisitions Unlocked by 65% of Oil Contingent + Downspacing Reserves Reserves Resource Remaining on Modern Sands Prospective Potential

40-Acre Units Technology Acreage Resource

7

West Cote Blanche Bay

Inventory¹

Net proved reserves of 5.29 MMBOE

– 27% of total company proved reserves

• Net probable reserves of 6.15 MMBOE

– 100% third party engineered

• 21 PUD locations, 79 probable locations, and hundreds of un-booked locations

• 5,668 net acres with >100 producing zones

Typical Well Economics

• Capital cost of approximately $1.5 MM

• Internal Rate of Return

– 55% ($65.00 Oil, $4.00 Gas)

– 78% ($75.00 Oil, $5.00 Gas)

– >100% ($85.00 Oil, $6.00 Gas)

Production²

• Average net production of 3,528 BOEPD

• ~ 62% of Gulfport’s total net production

• ~93% oil weighted production mix

– Priced as high quality HLS crude and sold at a premium to WTI before transportation

West Cote Blanche Bay Production Facilities

2010 Activities Update³

• Drilled and completed 20 wells year-to-date

• Currently plan to drill 24 wells during 2010

• Added infrastructure to accommodate increased production and boost efficiency

• Purchased a dock to vertically integrate

2011 Planned Act ivies

• Plan to drill 20 to 24 wells beginning in March and perform approximately 60 recompletions

• CAPEX: $35 to $38 million

¹ 12/31/09

² 3Q’10

³ As of November 5, 2010

8

Hackberry

Inventory¹

Proved reserves of 2.97 MMBOE

16 PUD locations, 11 permitted un-booked locations and a growing prospect inventory

Proprietary 42 square mile 3-D seismic survey

8,330 net acres with >30 producing zones

2011 Planned Activities

Plan to drill 7 to 10 wells and perform approximately 10 recompletions

– Rig to move from WCBB in mid-to-late December to begin work at Hackberry

– Includes plans to drill a well on joint exploration lands by March 2011

CAPEX: $24 to $26 million

Production²

Average net production of 1,385 BOEPD

~24% of Gulfport’s total net production

96% oil weighted production mix

2010 Activities Update³

Drilled and completed 6 wells year-to-date

Due to continued success at the field, Gulfport has expanded its 2010 drilling program at Hackberry to include a total of eight wells

¹ 12/31/09

² 3Q’10

³ As of November 5, 2010

9

[Graphic Appears Here]

Permian

Gross Estimated Ultimate Recovery

GPOR: 110-145 MBOE

Peers 3

CXO: 140-150 MBOE PXD: 120-150 MBOE

DVN: 150 MBOE

GPOR Leasehold Concho Leasehold Pioneer Leasehold Devon Leasehold

Inventory

Net proved reserves of 11.58 MMBOE¹

– 191 gross (96 net) PUD locations

Net probable reserves of 3.96 MMBOE¹

– 82 gross (41 net) probable locations

– 100% third party engineered

Potentially 496 gross (188 net) un-booked locations remaining on 40-acre spacing

Production²

Average net production of 704 BOEPD

~12% of Gulfport’s total net production

83% oil and NGL weighted production mix

Typical Well Cost

Capital cost of approximately $1.6 -1.8 MM

2010 Activities Update

Drilled 17 gross (7.75 net) wells year-to-date

Currently plan to drill 24 to 26 gross wells and perform a total of 10 gross recompletions during 2010

– 2 rigs drilling full time on Gulfport acreage

Increased position in play to 13,923 net acres

2011 Planned Activities

Plan to drill 29 to 31 gross wells running 2 to 3 rigs

CAPEX: $26 to $28 million

¹ 12/31/09

² 3Q’10

4 ³ CXO: 140-150 MBOE Gross; PXD: 120-150 MBOE Gross; DVN: 150 MBOE Gross As of November 5, 2010

10

Permian – Recent Transactions Imply Significant Value

Gulfport Energy Berry 1/1/10 Acq. Linn 3/29/10 Acq.

PDC 5/20/10 Acq.

Linn 7/1/10 Acq.

Energen 8/26/10 Acq.

Berry 10/29/10 Acq.

10 Miles

Buyer Deal Announced Purchase Price Acreage Production Proved $MM Net Acres BOEPD MMBOE

Berry Petroleum 10/25/2010 $180 9,300 1,200 N/A¹ Linn Energy 9/7/2010 $352 N/A 3,300 30 Energen 8/23/2010 $185 8,700 900 18 Linn Energy 7/1/2010 $90 N/A 950 7 Linn Energy 3/29/2010 $305 N/A 2,800 18 Berry Petroleum 1/11/2010 $126 6,886 1,300 11.2

Buyer Deal Announced Valuation $/Acre $/Flowing Barrel $/Proved Barrel

Berry Petroleum 10/25/2010 $19,355 $150,000 N/A Linn Energy 9/7/2010 N/A $107,000 $11.73 Energen 8/23/2010 $21,264 $206,000 $10.28 Linn Energy 7/1/2010 N/A $95,000 $12.86 Linn Energy 3/29/2010 N/A $109,000 $16.94 Berry Petroleum 1/11/2010 $18,298 $97,000 $11.25

Average $19,639 $127,333 $12.61

¹ 35 MMBOE of 2P reserves included in acquisition

11

Permian Deal Comps – Berry 10/25/10

Deal Announced: 10/25/2010 Purchase Price: $180 MM Acreage: 9,300 Net Acres Production: 1,200 BOEPD Reserves: 35 MMBOE of P2 Transaction Metrics:

$/Acre: $19,355

$/Flowing Barrel: $150,000

$/Proved: N/A

Gulfport owns ~3,300 net acres in the vicinity of this transaction

12

Permian Deal Comps – Energen 8/23/10

10 Miles

Deal Announced: 8/23/2010 Purchase Price: $185 MM Acreage: 8,700 Net Acres Production: 900 BOEPD Reserves: 18 MMBOE Transaction Metrics:

$/Acre: $21,264

$/Flowing Barrel: $206,000

$/Proved: $10.28

Gulfport owns ~4,300 net acres in the vicinity of this transaction

13

Permian Deal Comps – Linn Energy 7/1/10

Gulfport Energy

Linn 7/1/10 Acq.

Deal Announced: 7/1/2010 Purchase Price: $90 MM Acreage: N/A Production: 950 BOEPD Reserves: 7 MMBOE Transaction Metrics:

$/Acre: N/A

$/Flowing Barrel: $95,000

$/Proved: $12.86

Gulfport owns ~3,300 net acres in the vicinity of this transaction

14

Permian Deal Comps – Linn 3/29/10

Gulfport Energy

Linn 3/29/10 Acq.

Deal Announced: 3/23/2010 Purchase Price: $305 MM Acreage: N/A Production: 2,800 BOEPD Reserves: 18 MMBOE Transaction Metrics:

$/Acre: N/A

$/Flowing Barrel: $109,000

$/Proved: $16.94

Gulfport owns ~7,600 net acres in the vicinity of this transaction

10 Miles

15

Niobrara

Inventory¹

Proved reserves of 0.9 MMBOE

23 gross PUD locations on 24,468 net acres

3 producing wells and existing well control on acreage

75-150 MMBOE of gross original oil in place per section²

Typical Well Economics

Capital cost of approximately $1.4 MM per well

Gross EUR of approximately 120 MBOE per well

Differentials of approximately $9-$10 per barrel

2010 Activities Update

Currently in the process of permitting 60 square mile 3-D seismic survey over Craig Dome acreage

2011 Planned Activities

Shoot and process 3-D seismic survey over Craig Dome acreage during the first half of 2011

Interpret seismic and identify locations during 3Q’11

Drill three to five vertical wells in the 4Q’11

CAPEX: $1 to $2 million

Upside

Horizontal drilling potential

Potential to apply modern hydraulic fracturing technology

Down spacing potential

Potential to apply 3-D seismic to aid in well positioning

¹ 4/1/10

² Internal estimates

16

Niobrara—Acquisition Strategy

24,468 net acres focused near a number of structures on the uplift between the Piceance and Sandwash basins

75 to 150 MMBOE¹ of gross original oil in place per section

GPOR Leasehold Area

Significant oil in place in an area that historically has proven to be productive with the potential to unlock considerable resource by applying modern drilling and completion technology to increase recoveries

Historical recoveries per section have ranged from 0.01% to 1.1% and Gulfport internally estimates average recoveries to be 0.12%¹ using previous drilling and completion methods

A 1% increase in recoveries would increase gross recoverable resource by 0.75 to 1.5 MMBOE per section

¹Internal estimates

17

Niobrara – Development Plan

Well #1 (1987) Vertical, Slotted Liner CUM: 262 MBO 208 MMCFG

Craig Dome Prospect

8,630 Gross / 4,315 Net Acres 322 MBO & 215 MMCFG

Niobrara Shale

Buck Peak Field

4.73 MMBO & 7.7 BCFG Niobrara Shale

Well #2

Vertical, Unstimulated Open Hole EUR: 103 MBO

Completed 10/07

Well #3

Vertical, Unstimulated Open Hole EUR: 143 MBO

Completed 9/09

The Craig Dome Prospect will be the site of Gulfport’s initial development in the Niobrara

– Craig Dome has 11 Niobrara formation penetrations

– Planning a 60 square mile 3-D seismic survey over the acreage 23 PUD drilling locations

– Currently have two drilling permits in hand First Niobrara production came in 1987 from Well #1 which has cumulative production of 262 MBO

– This well was air drilled and was not artificially stimulated

Subsequently, two other wells (Well #2 & Well #3) were drilled to test the Niobrara and are expected to ultimately recover 103 MBO and 143 MBO, respectively

– Both wells were completed as open hole, natural completions with no stimulation

18

Grizzly¹ Asset Overview

House

- Current Alberta Oil Sands Leases (OSLS)

- Grizzly Properties Assigned Contingent Resource by GLJ

- Grizzly Properties Not Assigned Contingent Resource by GLJ

Grizzly Properties Assigned Contingent Resource by GLJ Lease Holdings 182,691 Acres Proved + Probable (2P) Reserves 98 MMbbls Best Estimate (P50) Contingent Resource 1,850 MMbbls Best Estimate (P50) Prospective Resource 202 MMbbls

Grizzly Properties Not Assigned Contingent Resource by GLJ Lease Holdings 340,175 Acres

Approximately 65% of Grizzly’s acreage was not assigned contingent resource by GLJ

19

Grizzly¹ Reserves & Resources

Grizzly Interest Proved + Best Estimate Best Estimate Discovered Undiscovered Recoverable Probable (2P) (P50) Contingent (P50) Prospective Bitumen Initially Bitumen Initially (Millions of Barrels) Reserves Resource Resource In Place In Place Algar Lake Project 98 51 28 437 81 Other Clastics — 1,600 94 12,296 558 Carbonate — 199 80 1,431 3,879 Total 98 1,850 202 14,164 4,518

Notes:

Probable reserves are defined in the Canadian Oil and Gas Evaluation Handbook (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.

¹ Gulfport Energy Corporation owns 24.9999% of Grizzly Oil Sands ULC

20

Grizzly¹ Thickwood Hills Area

Marathon Birchwood 35+ New Coreholes Planned for 2010-11 Drilling Season

10 Kilometers 6.2 Miles

GLJ did not evaluate Thickwood Hills pending results of the 2010-2011 drilling season

Grizzly has plans for 29 primary core holes plus an additional 23 contingent core hole locations

Sourthern Pacific has received approval for their 12,000 BOPD McKay SAGD Project and plan to drill 30 to 35 core holes during their 2010-2011 drilling program

Construction of the all-season road to the Southern Pacific McKay SAGD facility is underway

AOSC/PetroChina submitted their application for their 150,000 BOPD MacKay SAGD Project with the first production phase of 35,000 BOPD expected to begin producing in 2014

Marathon has plans to drill 35+ new core holes on their Birchwood Area north of Grizzly’s Thickwood Hills during the 2010-2011 drilling season (162 Total Locations Permitted)

Grizzly Thickwood Hills Area 2010-11 Proposed Core Holes

52 Primary & Contingent Locations

¹ Gulfport Energy Corporation owns 24.9999% of Grizzly Oil Sands ULC

21

Grizzly¹ Firebag River Area

New Imperial Oil Resources Firebag Area

30 Delineation Wells Drilled Since 2008

UTS – SilverBirch Energy 40-50 New Coreholes Planned for 2010-11 Drilling Season

5 Kilometers 3.1 Miles

Grizzly Oil Sands Firebag River Area Extensive Unexplored Bitumen Resource Potential

22.5 Meters

24.0 Meters

Oilsands Quest Wallace Creek Area

9 New Delineation Wells Drilled in 2010 with 20+ Meters of pay Found Additional Wells Planned for 2010-11 Season

GLJ did not evaluate Firebag River pending results of the 2010-2011 drilling season

Grizzly has plans for 20 primary cores holes plus an additional 11 contingent core hole locations

UTS-SilverBirch Energy will drill 40 to 50 new core holes the 2010-2011 drilling season to the north of Grizzly’s Firebag River

Additional core hole drilling possible to the south of Grizzly’s Firebag River by Oilsands Quest

Grizzly Firebag River Area 2010-11 Proposed Core Holes

31 Primary & Contingent Locations

22

¹ Gulfport Energy Corporation owns 24.9999% of Grizzly Oil Sands ULC

Grizzly¹ Algar Lake Area

5 Kilometers 3.1 Miles

Grizzly Algar Lake SAGD Project

Application filed in March 2010

Design capacity of 11,300 BOPD

Grizzly Algar Lake Area

GLJ assigned 98 MMbbls of Proved + Probable (2P) Reserves, 51 MMbbls of Best Estimate (P50) Contingent Resource and 28 MMbbls of Best Estimate (P50) Prospective Resource

Grizzly has plans for 20 primary core hole loctions

In April 2010 JACOS filed their application for an expansion of facilities to 35,000 BOPD with first production at the end of 2014.

Connacher completed construction on its 10,000 BOPD Algar SAGD Project, its second in the area, during the first half of 2010 and is currently ramping up production

Connacher has plans to expand its Great Divide SAGD Project to 44,000 BOPD beginning in 2012

¹ Gulfport Energy Corporation owns 24.9999% of Grizzly Oil Sands ULC

23

Grizzly¹ Algar Lake SAGD Project

Grizzly has submitted its regulatory application for a 11,300 BOPD oil sands project at Algar Lake

– The project is expected to operate at an average capacity of 10,000 BOPD over a design life of 30 years

– Grizzly plans to develop Algar Lake utilizing a proven method of in-situ extraction called Steam Assisted Gravity Drainage (SAGD)

Development plan and capital requirements:

– The Stage 1 development of Grizzly’s Algar Lake Project contemplates two plant phases and ten well pairs on each of four well pads

– Upon approval, Grizzly intends to construct the first phase consisting of one modular central processing facility, ten well pairs on one well pad and associated roads and pipelines

– The second plant phase is expected to be developed two years subsequent to approval and include a second modular central processing facility and an additional ten well pairs and well pad

– The first two phases are estimated to carry a gross initial capital cost of ~$240 million and, in order to maintain consistent production, an additional pad will be required for each phase every five years at an estimated gross cost of ~$35 million

Why Develop Algar Lake First?

Low Geologic Risk – Will be developing the same type McMurray Channel sands as found in nearby JACOS & Connacher producing SAGD projects (Ave. Porosity: 33%, Ave Oil Saturation: 80%)

Proximity to Infrastructure – Nearby access to the Highway 63 road and pipeline corridor. Existing natural gas and electric transmission lines within the vicinity initial project area

Timeline: Grizzly expects regulatory approval within 12 to 18 months of application submission followed by a construction period of 18 months leading up to first production

¹ Gulfport Energy Corporation owns 24.9999% of Grizzly Oil Sands ULC

24

Grizzly¹ SAGD Approach – Unique Design, Proven Process

Proven Plant Process

Boiler feedwater by mechanical vapor recompression

Conventional package boiler, gas-fired

Self generating power with gas-fired cogeneration

Standard oil and produced water processing equipment

Designed to meet 10% water make-up guidelines

Production trucked to local markets

Unique modular plant design

5,000 BOPD modular central plant

One pad of 10 well pairs initially

All equipment on pre-fabricated modules

All modules close coupled (no pipe racks)

Field construction target is 90 days

Designed to be portable to reduce reserve life index

High level of process automation

¹ Gulfport Energy Corporation owns 24.9999% of Grizzly Oil Sands ULC

25

Key Investment Considerations

OILY TODAY

Gulfport has a diverse portfolio of oil-weighted assets

Active most prolific in Southern oil producing Louisiana basins and the Permian, two of America’s

Niobrara acquisition adds additional oily inventory

Grizzly provides exposure to over a half billion barrels of oil resource net to Gulfport’s interest

Moving toward first production at Algar Lake within 30 to 36 months

Historically a 95% oil and liquids weighted production profile

&

GROWING

Gulfport’s large captured resource and high rate of return opportunities are expected to drive growth for the foreseeable future

Multi-year drilling inventory exploitable from cash flow

Forecasted production growth of 16%¹ in 2010

First oil sands project projected to come online within 30 to 36 months, with each subsequent project bringing the potential for significant reserve and production growth

Track record of opportunistic acquisitions provides additional upside

¹ Based upon average daily oil equivalent production for 2009 of 1.68 MMBOE and the average daily oil equivalent midpoint for 2010 estimated production of 1.95 MMBOE

26

Appendix A

27

Hedged Production

Gulfport Energy Corporation Fixed Price Contracts 2010 & 2011

Weighted Average Barrels Per Month Daily Price Day

October-10 $58.24 2,300 November-10 $58.24 2,300 December-10 $58.24 2,300 January-11 $86.96 2,000 February-11 $86.96 2,000 March-11 $86.96 2,000 April-11 $86.96 2,000 May-11 $86.96 2,000 June-11 $86.96 2,000 July-11 $86.96 2,000 August-11 $86.96 2,000 September-11 $86.96 2,000 October-11 $86.96 2,000 November-11 $86.96 2,000 December-11 $86.96 2,000

2010 2011

Q4 Q1 Q2 Q3 Q4 Total

Fixed Price Contracts

Volume (Bbl) 211,600 180,000 182,000 184,000 184,000 730,000 Weighted Average Price (Bbl) $ 58.24 $ 86.96 $ 86.96 $ 86.96 $ 86.96 $ 86.96

28

Canadian Oil Sands Comparable Trading Analysis

Land Production Reserves & Resources Oil Sands EV /

Current 2P + Best Total Bitumen 2P Contingent

Market Cap EV Acreage Production Reserves Resources Reserve Total Acreage 2P Reserves Recoverable [$ mm, f.d.] [$ mm] [Acres] BOPD [MMbbls] [MMbbls] Evaluator [$ / acre] $ /bbl $ /bbl

Athabasca Oil Sands PUB $5,614 $4,377 1,800,000 N/A 114 8,888 GLJ, D&M, $2,432 $38.39 $0.49 excluding Carbonates 114 5,794 McDaniel $38.39 $0.76

Connacher PUB $512 $1,326 98,000 13,000 223 725 GLJ $13,529 $5.95 $1.83

MEG Energy PUB $7,945 $7,505 537,600 27,500 1,691 5,414 GLJ $13,959 $4.44 $1.39

OSUM PRV $1,204 $950 80,512 N/A 320 2,464 GLJ $11,802 $2.97 $0.39 excluding Carbonates 320 463 $2.97 $2.05

Laracina PRV $1,778 $1,728 181,767 N/A 36 4,292 GLJ $9,508 $48.01 $0.40 excluding Carbonates 36 1,794 $48.01 $0.96

Average 10,246 $0.90

Average excluding Carbonates N/A $1.40

Information is sourced from company disclosures, press releases, broker research, and media reports

Comparable trading analysis presented inclusive and exclusive of carbonate resources

No proven commercial technology currently in existence to recover carbonate resources

29

Canadian Oil Sands Historical Transactions

Transaction Contingent

Announcement Transaction Value Value Production 2P Reserves Resources Reserve $/ Contingent Acquiror Seller Target Date US $mm Net Acres US $/acre BOPD MMbbls MMbbls Evaluator $ / 2P Resource

PTTEP Statoil 40% of Kai KosDehseh 11/23/2010 $2,280 102,800 $22,179 N/A N/A 1,240 GLJ & McDaniel N/A $1.84

Candian Natural Resources Enerplus Kirby 9/21/2010 $405 43,360 $9,340 N/A N/A 497 GLJ $0.81 Athabasca OilSands Excelsior Company 9/13/2010 $144 26,607 $5,412 N/A N/A 183 McDaniel N/A $0.79 Total E&P Canada UTS Energy 20% of Fort Hills 7/7/2010 $731 9,340 $78,218 N/A N/A 678 Sproule N/A $1.08 Public MEG IPO Christina Lake, Surmont, Growth Properties 7/6/2010 $5,945 537,600 $11,058 24,500 1,691 5,414 GLJ $3.52 $1.10 Canada Pension Plan Investment BoaLaricina Energy $250MM Company Financing 7/6/2010 $1,368 excluding Carbonates N/A N/A 2,020 $0.68 including Carbonates 181,841 $7,525 N/A 36 4,585 GLJ $38.01 $0.30 BP Value Creation 75% WI in VC Terre De Grace 3/15/2010 $883 138,750 $6,364 N/A N/A 1,000 McDaniel N/A $0.88 Devon Energy (Midpoint Estimate) BP 50% of Kirby Lease 3/11/2010 $635 53,120 $11,950 N/A N/A 625 N/A N/A $1.02 Public Athabasca IPO Athabasca OilSands 2/26/2010 $5,151 excluding Carbonates N/A N/A 5,330 $0.97 including Carbonates 1,570,933 $3,279 N/A 114 7,146 GLJ, D&M $45.19 $0.72 PetroChina Athabasca OilSands 60% of Company (Mackay & Dover) 8/31/2009 $1,737 201,744 $8,610 N/A N/A 2,848 GLJ, D&M N/A $0.61

Average (Excluding Carbonates) N/A $0.90 Average (Including Carbonates) $18,143 $0.81

Information is sourced from company disclosures, press releases, broker research, and media reports

Historical transactions presented inclusive and exclusive of carbonate resources

No proven commercial technology currently in existence to recover carbonate resources

30

Thailand

In 2005, Gulfport gained exposure to a natural gas play in northeast Thailand through an indirect equity investment in APICO

Third party engineers Gaffney Cline credit wells producing in the Phu Horm gas field with ~ ¹/2 TCF¹ of proved reserves Net to Gulfport’s interest, total proved reserves are estimated to be 2.7 Bcf of natural gas

Exploratory potential of four, 1-million acre concession blocks provides significant upside

APICO has identified several high-quality exploration targets

Gross production in the Phu Horm gas field, of which Gulfport indirectly owns 0.7%, averaged 86.4 MMcf per day of natural gas and 445 Bbls per day of condensate during the first quarter of 2010 Long-term gas sales contract in place with Thai government in place, locking in favorable pricing

Pricing tied to Singapore Medium Sulfur Fuel Oil (MSFO)

In 2008, Tatex III was formed to explore and develop the 1-million acre Concession Block L16/50

Gulfport indirectly owns an 18% interest in Tatex III

Tatex III shot the largest onshore 3-D seismic survey in SE Asia over L16/50 during 2009

Tatex III is currently drilling the first of two or more exploratory wells on Concession Block L16/50

¹ Third party report issued on 12/31/08

31

Appendix B

Oil Sands Activity Overview

32

Algar Lake – Activity Update

Grizzly Oil Sands Algar Lake SAGD Project Application Filed in March 2010 With a Design Capacity of 11,300 BOPD

Grizzly Plans Continued Delineation of the Algar Lake Lease Area in the 2010-11 Drilling Season.

JACOS Hangingstone SAGD Project

1st Production 1999 – Cumulative Production – 21.7 MMBO –Averages 7,500 BOPD

In April 2010 JACOS Filed their Application with Alberta ERCB for an Expansion of Facilities to 35,000 BOPD with 1st Production at the end of 2014.

Connacher Great Divide SAGD Project

Pod 1 1st Production Dec. 2007 – Cumulative Production – 5.0 MMBO

– Est. Average for 2010—8500 BOPD

Algar 10,000 BOPD SAGD Project – Construction Complete – 1st Steam in May/June 2010 Future Great Divide Expansion Plans to 44,000 BOPD to Start in 2012

33

West Athabasca Trend Overview

Sunshine Oilsands West Ells 10000 BOPD SAGD

Project Area

Grizzly Oil Sands West Ells (North) Area Lands Adjoining the Sunshine West Ells SAGD Project

Athabasca – PetroChina

Dover SAGD Project Area

Total Dover Area Resources – 7.66 Billion Bbls OBIP / 3.313 Billion Bbls. Contingent Resource – Best Case (from GLJ)

Athabasca Oil Sands Corp (AOSC) West Dover Wabiskaw / McMurray Clastics & Leduc Reef Areas W.Dover Clastics – 4.9 Billion Bbls OBIP* 2.0 Billion Contingent Resource* Leduc Carbonates – 6.2 Billion Bbls OBIP* 1.4 Billion Contingent Resource* * Best Case Estimate from GLJ

Grizzly Oil Sands West Ells Area Lands Adjoining the AOSC West Dover Sand & Leduc Reef Plays

Grizzly Oil Sands Birchwood Area Adjoining AOSC/PetroChina (North) MacKay Areas

Grizzly Oil Sands Thickwood Hills Area Potential Trends Adjoining STP McKay

ConocoPhillips Project AreasCNPC

BP – Value Creation JV Terra de Grace SAGD Project Area

1 Billion Barrels Recoverable Resource

Grizzly Oil Sands Silvertip Future SAGD Project Area

Grizzly Oil Sands Dover Area Possible Unexplored Sand Trend Extension

Athabasca – PetroChina MacKay (North) Area

Southern Pacific Resource (STP) McKay SAGD & McKay South Project Areas Total 2P Reserves + Best Est. Contingent Resource 708 MMBO Exploitable in Place / 284 MMBO Recoverable (from GLJ)

Athabasca – PetroChina

MacKay SAGD Project Area Total MacKay Area Resources –3.59 Billion Bbls OBIP / 1.43 Bill. Bbls. of Contingent Resource –Best Case (from GLJ)

¹ Wabiskaw -McMurray Net Sand Bitumen Isopach > 10m

34

Thickwood Hills – Activity Update

In May of 2009, Southern Pacific submitted their application for a 12,000 barrel per day project on their McKay acreage

Southern Pacific acquired the remaining 20% interest in their McKay project from their partner in March of 2010 for $33 million, or $8,150 per acre In December of 2009, Athabasca Oil Sands submitted an application for a 150,000 barrel per day project on their MacKay JV with PetroChina

Internal mapping of Grizzly’s Thickwood Hills area shows similar sand trends to those present in Southern Pacific’s McKay project and Athabasca Oil Sands’ MacKay JV with PetroChina Grizzly stands to benefit from new infrastructure moving into the area as a result of recent activity

35

West Ells North – Activity Update

On Mach 31, 2010 Sunshine Oilsands submitted a project application for the development of a 10,000 barrel per day SAGD project on their West Ells leases

Grizzly’s West Ells North leases consist of three sections located directly adjacent to Sunshine’s West Ells SAGD project area According to Sunshine’s internal mapping and reservoir parameters provided in their West Ells Project application to the Alberta regulators, Grizzly estimates there to be 223 MMBO OBIP² at Grizzly’s West Ells North lease Based on Sunshine’s mapping, there is oil in place of a thickness and size commensurate with the development of a commercial SAGD project at Grizzly’s West Ells North lease

Grizzly’s West Ells leases are also located around the Athabasca Oil Sands Dover Area SAGD Project joint venture with PetroChina and the Athabasca Oil Sands Leduc carbonate play Grizzly is currently planning an aggressive exploration drilling program for the 2010/2011 winter drilling season

¹ Figure 2.2 -22 of Sunshine Oilsands West Ells SAGD Project application, annotated to show Grizzly’s West Ells North lease

² Grizzly internal estimate of Grizzly West Ells (north lease) using Sunshine mapping & reservoir parameters and using an 18.0 meter average thickness

36

Silvertip – Activity Update

Net Bitumen Pay > 10m—Wabiskaw / McMurray Shoreface Sands³ C.I. = 5 meters

Grizzly¹ acquired a 40% interest in 62.5 sections in Canada during October 2009, adding a total of 15,688 net acres to their position

Net to Gulfport, the acquisition added 3,922 acres

Combining the two areas provides enough scale to support a major SAGD project at Silvertip similar to Algar Lake McMurray Channel Sands in these areas have similar reservoir characteristics to those found in the planned Grizzly¹ Algar Lake project, as well as many currently operating SAGD thermal in-situ projects in the Athabasca oil sands region Large defined resource in the Wabiskaw is geologically similar (deltaic vs. channel sand) to that found on the acreage included in the Athabasca -PetroChina deal Highly prospective acreage with 32 sections located near potential Chevron and Total SAGD projects and in direct vicinity of the AOSC—PetroChina joint venture Two high quality reservoirs within a 50 meter gross McMurray section

19 core holes Net pay bitumen saturation:

64 miles of proprietary 65% to 95%

2-D seismic Porosity: 27% to 37%

New Pod Total O.B.I.P

Gross Estimate of Exploitable Net Bitumen Pay (>10 meters) in MMBO³

McMurray Wabiskaw/McMurray Total O.B.I.P Channel Sand Shoreface Sands MMBO

Grizzly Oil Sands Silvertip Area 154.4 469.0 623.4

Grizzly Oil Sands Newly Acquired Acreage 143.8 159.8 303.6

Grizzly Silvertip & Newly Acquired Acreage 298.2 628.8 927.0

Grizzly Silvertip Area (100% WI) & Grizzly Newly Acquired Acreage (40% WI) Net Estimate of Exploitable Net Bitumen Pay (>10 meters) in MMBO³

McMurray Wabiskaw/McMurray Total O.B.I.P Channel Sand Shoreface Sands MMBO

Grizzly Oil Sands (100%) 211.9 532.9 744.8

Gulfport Energy (~25%) 53.0 133.2 186.2

Grizzly Oil Sands¹ Silvertip Project Area 100% Owned Oil Sand Leases

Grizzly Oil Sands¹ Newly Acquired Acreage 40% Owned Oil Sand Leases

Net Bitumen Pay > 10m McMurray Channel Sands³ C.I. = 5 meters

¹ Gulfport owns an approximate 25% interest in Grizzly Oil Sands, ULC

³ Isopach map and OOIP estimates are the products of Grizzly’s internally generated estimates and assumptions

37

Firebag River – Activity Update

New Imperial Oil Resources Firebag Area

30 Delineation Wells Drilled Since 2008

Grizzly Oil Sands Firebag River Area Extensive Unexplored Bitumen Resource Potential

During the 2009/2010 winter drilling season, Oilsands Quest drilled two core holes directly offsetting Grizzly’s Firebag River Area that found significant thickness:

The two core holes found 24 and 22.5 meters of sand thickness, respectively Grizzly believes this suggests there to be pay of a thickness that would be commensurate with a developable project directly offsetting our Firebag River acreage

Oilsands Quest Wallace Creek Area 9 New Delineation Wells Drilled in 2010 with 20+ Meters of pay Found

¹ Map Sourced from Oilsands Quest March 2010 presentation

38

Saleski – Activity Update

Grizzly Oil Sands Saleski Area Grosmont Bitumen Resource Potential Offsetting the Laricina Energy Saleski Solvent Cyclic SAGD (SC-SAGD) Pilot & the OSUM Saleski Underground Mining Proposed Project

Laricina Pilot

OSUM Saleski Area – Proposed Underground Mining Scheme to Access Grosmont Carbonate Bitumen with SAGD from Tunnels Constructed Below Pay Zones at a Depth of 300 meters

*OSUM Grosmont Porosity Map & Resource Estimate from March 23, 2010 Presentation to the Canadian Society of Petroleum Geologists (Webcast Archive)

Possible Tunnel Locations (3 to 4 Miles in Length)

Laricina Energy’s Saleski Pilot Project Area Recently Approved Solvent Cyclic SAGD Thermal Process to Recover Bitumen from the Grosmont Carbonates with 2.3 Billion bbls of Recoverable Resource and a Potential Production rate of 270,000 BOPD (from GLJ Report July 1, 2009)

(from Nov. 16, 2009 Laricina Presentation)

39

Liege-Harper – Activity Update

Sunshine Oilsands Harper Area Approved (December 2009) Application for a Single Well Cyclic Steam Pilot in the Grosmont (C Zone)

Athabasca Oil Sands / Zama Ventures Grosmont Area

Laricina Energy Burnt Lake Area

Carbonates with a Potential Production rate of 45,000 BOPD (from GLJ Report July 1, 2009) (from Nov. 16, 2009 Laricina Presentation)

Shell Grosmont

Area (North End)

Suncor Energy Grosmont Frontier Area

Grizzly Oil Sands Liege-Harper Area Extensive Unexplored Bitumen Resource Potential

Isopach Map of Grosmont C + D Zones Bitumen Porosity >15m

¹ Isopach Map of Grosmont C + D Zones Bitumen Porosity >15m

40