Response Letter

LOGO

14313 North May Avenue, Suite 100

Oklahoma City, Oklahoma 73134

August 2, 2013

VIA FACSIMILE AND EDGAR

United States Securities and Exchange Commission

The Division of Corporate Finance

100 F Street, N.E.

Washington, D.C. 20549-3561

Attn:

H. Roger Schwall, Assistant Director

Ronald Winfrey

Re:

Gulfport Energy Corporation

Form 10-K for the Fiscal Year ended December 31, 2012

Filed March 1, 2013

File No. 0-19514

Dear Messrs. Schwall and Winfrey:

Set forth below are the responses of Gulfport Energy Corporation, a Delaware corporation (the “Company”), to the comment letter of the staff (the “Staff”) of the Securities and Exchange Commission (the “Commission”) dated July 17, 2013 with respect to Form 10-K for the fiscal year ended December 31, 2012 filed March 1, 2013 (the “Form 10-K”).

For your convenience, we have set forth below each Staff comment followed by the Company’s response. Caption references and page numbers refer to the captions and pages contained in the Form 10-K, unless otherwise indicated.

Form 10-K for the Fiscal Year Ended December 31, 2012

Properties, page 43

Proved Oil and Natural Gas Reserves, page 43

Item 1202(a)(6) of Regulation S-K requires that a registrant who is disclosing material additions to its reserves estimates provide a general discussion of the technologies used to establish the appropriate level of certainty for reserves estimates from material properties included in the total reserves disclosed. Please amend your document to comply with that Item.

United States Securities and Exchange Commission

August 2, 2013

Page 2

Response:

Utica Shale

Gulfport added net reserves of 29,315 MMCF of natural gas and 1,702 MBBL of liquids from the Utica Shale in 2012 as determined by Ryder Scott. Reserves were determined by standard decline curve analysis (“DCA”) using daily production data and flowing tubing pressures. Life Indexes for these wells based upon their initial test rates and ultimate recoverable reserves by DCA were in excess of 1.5 in each case. Consequently, shut-in wells were assigned reserves based upon their initial test rates and a Life Index of not more than 1.0. The undeveloped locations were assigned reserves by the analogy method utilizing direct offsets not more than one location away. Untested shut-in wells were assigned no proven reserves.

Gulfport also added net reserves of 3,108 MBBL of oil and 1,526 MMCF of natural gas from its Southern Louisiana fields in 2012 as determined by Netherland Sewell. These reserves are attributable to infill, up-dip attic locations predominantly in oil sands for which the drive mechanism is natural water influx. These locations were determined based on structural maps from existing well control. Volumetric calculations for these reserves are based on these maps combined with parameters derived from petrophysical analysis and analogous in-field performance and statistics. These techniques represent standard industry techniques for determining reserves in Southern Louisiana fields that are deemed reliable based on prior field experience.

The Company respectfully proposes to include comparable information in its future filings where applicable.

Proved Undeveloped Reserves (PUDs), page 45

2.	You developed approximately 73 MBOE PUD reserves with the expenditure of $18 million for a unit cost of $247/BOE. If our calculations are correct, please explain to us the causes for this apparently high cost.

Response: The Company’s costs associated with the development of PUDs in 2012 were $38 BOE per unit, rather than $247 BOE per unit as calculated by the Staff, with the total cost of approximately $18.0 million to the Company. This expense relates to the development of 13 PUDs (with an aggregate of 468 MBOE of reserves) booked as such in the Company’s reserve report at December 31, 2011. Of these PUDs:

•

seven wells (drilled in 2012 in the Permian Basin at the cost of $7.8 million to the Company and having booked PUD reserves totaling 343 MBOE) were sold to Diamondback Energy Corporation (“Diamondback”) as part of the Company’s sale to Diamondback of all of its Permian Basin assets on October 11, 2012 and, as a result, were not converted by the Company to proved developed producing wells at December 31, 2012;

•

three wells (drilled by the Company in 2012 in its West Cote Blanche Bay (“WCBB”) field at the cost of $5.9 million) were targeting several zones per well, with only one zone per well having booked PUD reserves totaling 73 MBOE at December 31, 2011; and

•

the new reserves from the additional zones targeted by the Company when drilling the above-referenced three PUD wells at its WCBB field were included as a portion of the total 1,275 MBOE of extensions to proved undeveloped reserves, as disclosed on page 45 of the Form 10-K, rather than conversions of PUDs, at December 31, 2012.

United States Securities and Exchange Commission

August 2, 2013

Page 3

3.	We note your statement, “All PUD drilling locations are scheduled to be drilled prior to the end of 2016.” Please tell us the volume figures, if any, for your current PUD reserves that are scheduled for drilling more than five years after initial booking.

Response: The Company does not have any PUD reserves that are scheduled for drilling more than five years after the initial booking.

Notes to Consolidated Financial Statements, page F-9

Note 18 – Supplemental Information on Oil and Gas Exploration and Production Activities, page F-35

4.	Please expand your disclosure to provide supplemental information on oil and gas activities for your equity method investees to comply with the guidance in FASB ASC paragraphs 932-235-50-8 to 50-35A.

Response: The Company respectfully points out that reserve reports prepared in accordance with the Commission’s rules and regulations have never been prepared by Grizzly Oil Sands ULC (“Grizzly”) in Canada or by Tatex Thailand II, LLC and Tatex Thailand III, LLC in Thailand (the “Tatex Entities”) and, therefore, are not available to the Company. The Company owns only a small, minority equity interests in each of these entities. Diamondback, in which the Company had a 21.4% equity interest at December 31, 2012, as disclosed in the Form 10-K, and currently has a 13.5% equity interest, is a reporting company under the Securities Exchange Act of 1934, as amended. Diamondback’s reserves as of December 31, 2012 are disclosed in its Annual Report on Form 10-K, filed by Diamondback with the Commission on March 1, 2013, as amended on April 11, 2013. In its future filings with the Commission on Form 10-K, the Company will include the reserves attributable to the Company’s interest in Diamondback (as shown in Annex A attached hereto), and will also include the reserves attributable to the Company’s interest in Grizzly and the Tatex Entities if and when reserves prepared in accordance with the Commission’s rules and regulations become available for such entities. The Company does not currently expect that reserve reports complying with the Commission’s rules and regulations for the reserves held by Grizzly or the Tatex Entities will be available for 2013.

United States Securities and Exchange Commission

August 2, 2013

Page 4

Oil and Gas Reserves (Unaudited), page F-37

5.	FASB ASC Paragraph 932-235-50-5 requires “appropriate explanation of significant changes” for line items in the reconciliation of your disclosed proved reserves. Please amend your document to explain the details/circumstances of “extensions and discoveries” during 2012.

Response: The Company respectfully notes that 6,675 MBOE of the total 10,091 MBOE attributable to extensions and discoveries are from the discovery and development of the Company’s assets in the Utica Shale. The Company will include a disclosure to that effect in its future filings with the Commission.

Changes in Standardized Measure of Discounted Future Net Cash Flows…, page F-38

6.	FASB ASC Subparagraph 932-235-50-35(g) specifies the inclusion of “[p]reviously estimated development costs incurred during the period” in the determination of annual changes to the standardized measure. Please amend your document to comply with ASC 932.

Response: In response to the Staff’s comment, the Company provided additional disclosure under the heading “Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)” in Annex A attached hereto. The Company will include disclosure to that effect in its future filings with the Commission.

Exhibit 99.1, page 3

We note the statement, “[t]he technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards.” Item 1202(a)(7) of Regulation S-K requires the disclosure of “… the qualifications of the technical person primarily responsible for overseeing the preparation of the reserves estimates and, if the registrant represents that a third party conducted a reserves audit, disclose the qualifications of the technical person primarily responsible for overseeing such reserves audit.” Please file a third party report that discloses these qualifications, rather than cites a reference.

Response: The Company respectfully points out that it provided the following disclosure under the heading “Proved Oil and Natural Gas Reserves—Evaluation and Review of Reserves” on pages 43 and 44 of the Form 10-K:

“Our chief reserve engineer is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer with over 30 years of reservoir and operations experience and our geophysical staff has over 60 years combined industry experience.”

United States Securities and Exchange Commission

August 2, 2013

Page 5

In its future filings with the Commission requiring such disclosure, the Company will enhance its disclosure relating to the qualifications of the Company’s third party independent petroleum engineers and will provide disclosure regarding specific qualifications of the technical persons at the Company’s third party independent petroleum engineering firms who are responsible for preparing the Company’s reserve estimates.

The Company acknowledges that:

•

the Company is responsible for the adequacy and accuracy of the disclosure in the filing;

•

Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

•

the Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

If you have any questions with respect to the foregoing, please do not hesitate to call me at (405) 242-4408 or Seth Molay of Akin Gump Strauss Hauer & Feld LLP at (214) 969-4780.

Sincerely,

/s/ Michael G. Moore

Michael G. Moore

Vice President and Chief Financial Officer

cc:	Seth R. Molay, P.C.

Annex A

Capitalized Costs Related to Oil and Gas Producing Activities


	2012			2011

Company
Proven properties	$	984,795,000		$	897,130,000
Unproven properties		626,295,000			132,912,000

		1,611,090,000			1,030,042,000
Accumulated depreciation, depletion, amortization and impairment reserve		(661,442,000	)		(571,213,000	)

Net capitalized costs	$	949,648,000		$	458,829,000


Company’s share of equity investment in Diamondback Energy, Inc.
Proven properties	$	123,370,000		$	—
Unproven properties		25,947,000			—

		149,317,000			—
Accumulated depreciation, depletion, amortization and impairment reserve		(31,052,000	)		—

Net capitalized costs	$	118,265,000		$	—

Costs Incurred in Oil and Gas Property Acquisition and Development Activities


	2012		2011		2010

Company
Acquisition	$	513,904,000	$	119,522,000	$	17,627,000
Development of proved undeveloped properties		121,787,000		123,489,000		64,652,000
Exploratory		93,397,000		3,994,000		—
Recompletions		24,643,000		17,259,000		16,917,000
Capitalized asset retirement obligation		2,195,000		1,390,000		1,328,000

Total	$	755,926,000	$	265,654,000	$	100,524,000


Company’s share of equity investment in Diamondback Energy, Inc.
Acquisition	$	49,895,000	$	—	$	—
Development of proved undeveloped properties		22,740,000		—		—
Exploratory		3,755,000		—		—
Capitalized asset retirement obligation		203,000		—		—

Total	$	76,593,000	$	—	$	—

Results of Operations for Producing Activities


	2012			2011			2010

Company
Revenues	$	248,601,000		$	228,953,000		$	127,636,000
Production costs		(53,708,000	)		(47,230,000	)		(31,580,000	)
Depletion		(90,230,000	)		(61,965,000	)		(38,600,000	)

		104,663,000			119,758,000			57,456,000

Income tax expense (benefit)
Current		730,000			282,000			40,000
Deferred		25,633,000			(372,000	)		—

		26,363,000			(90,000	)		40,000

Results of operations from producing activities	$	78,300,000		$	119,848,000		$	57,416,000

Depletion per barrel of oil equivalent (BOE)	$	35.07		$	26.56		$	19.54


Results of operations from Company’s share of equity method investment in Diamondback Energy, Inc.
Revenues	$	16,042,000		$	—		$	—
Production costs		(4,474,000	)		—			—
Depletion		(5,515,000	)		—			—

		6,053,000			—			—
Income tax expense		2,158,000			—			—


Results of operations from producing activities	$	3,895,000		$	—		$	—

Oil and Gas Reserves (Unaudited)


	2012						2011						2010
	Oil			Gas			Oil			Gas			Oil			Gas
	(MBbls)			(MMcf)			(MBbls)			(MMcf)			(MBbls)			(MMcf)

Company
Proved Reserves
Beginning of the period		16,745			15,728			19,704			16,158			17,488			14,332
Purchases in oil and gas reserves in place		—			—			2			19			3,913			3,482
Extensions and discoveries		4,880			31,265			3,940			2,091			5,574			5,303
Sales of oil and gas reserves in place		(10,604	)		(11,757	)		—			—			—			—
Revisions of prior reserve estimates		(382	)		(357	)		(4,714	)		(1,662	)		(5,426	)		(6,171	)
Current production		(2,388	)		(1,108	)		(2,187	)		(878	)		(1,845	)		(788	)

End of period		8,251			33,771			16,745			15,728			19,704			16,158

Proved developed reserves		5,219			18,482			7,485			6,152			7,230			6,068

Proved undeveloped reserves		3,032			15,289			9,260			9,576			12,474			10,090


Company’s share of equity investment in Diamondback Energy, Inc.
Proved Reserves
Beginning of the period		4,954			4,398			—			—			—			—
Purchases in oil and gas reserves in place		2,083			2,292			—			—			—			—
Extensions and discoveries		851			804			—			—			—			—
Revisions of prior reserve estimates		(315	)		82			—			—			—			—
Current production		(201	)		(178	)		—			—			—			—

End of period		7,372			7,398			—			—			—			—

Proved undeveloped reserves		5,192			4,645			—			—			—			—

Proved developed reserves		2,180			2,753			—			—			—			—

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)


	Year ended December 31,
	2012			2011			2010

Company
Future cash flows	$	954,833,000		$	1,594,050,000		$	1,479,295,000
Future development and abandonment costs		(159,113,000	)		(306,810,000	)		(301,651,000	)
Future production costs		(147,024,000	)		(295,383,000	)		(305,814,000	)
Future production taxes		(89,175,000	)		(124,739,000	)		(136,323,000	)
Future income taxes		(114,867,000	)		(229,649,000	)		(159,171,000	)

Future net cash flows		444,654,000			637,469,000			576,336,000
10% discount to reflect timing of cash flows		(96,013,000	)		(260,788,000	)		(260,849,000	)

Standardized measure of discounted future net cash flows	$	348,641,000		$	376,681,000		$	315,487,000


Company’s share of equity investment in Diamondback Energy, Inc. standardized measure of discounted cash flows
Future cash flows	$	592,669,000		$	—		$	—
Future development and abandonment costs		(115,869,000	)		—			—
Future production costs		(165,553,000	)		—			—
Future production taxes		(30,122,000	)		—			—
Future income taxes		(71,669,000	)		—			—

Future net cash flows		209,456,000			—			—
10% discount to reflect timing of cash flows		(130,871,000	)

Standardized measure of discounted future net cash flows	$	78,585,000		$	—		$	—

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)


	Year ended December 31,
	2012			2011			2010

Company
Sales and transfers of oil and gas produced, net of production costs	$	(194,893,000	)	$	(181,723,000	)	$	(96,056,000	)
Net changes in prices, production costs, and development costs		108,941,000			136,071,000			122,147,000
Acquisition of oil and gas reserves in place		—			72,000			63,043,000
Extensions and discoveries		151,654,000			107,110,000			88,227,000
Previously estimated development costs incurred during the period		10,211,000			41,193,000			12,247,000
Revisions of previous quantity estimates, less related production costs		(10,504,000	)		(112,553,000	)		(89,155,000	)
Sales of reserves in place		(214,867,000	)		—			—
Accretion of discount		37,668,000			31,549,000			24,077,000
Net changes in income taxes		25,585,000			(36,674,000	)		(54,879,000	)
Change in production rates and other		58,165,000			76,149,000			5,062,000

Total change in standardized measure of discounted future net cash flows	$	(28,040,000	)	$	61,194,000		$	74,713,000


Company’s share of equity investment in Diamondback Energy, Inc. changes in standardized measure of discounted cash flows

Sales and transfers of oil and gas produced, net of production costs	$	(11,601,000	)	$	—		$	—
Net changes in prices, production costs, and development costs		(14,596,000	)		—			—
Acquisition of oil and gas reserves in place		23,090,000			—			—
Extensions and discoveries		16,969,000			—			—
Previously estimated development costs incurred during the period		19,014,000			—			—
Revisions of previous quantity estimates, less related production costs		(4,897,000	)		—			—
Sales of reserves in place		—			—			—
Accretion of discount		7,803,000			—			—
Net changes in income taxes		(26,866,000	)		—			—
Change in production rates and other		(8,358,000	)		—			—

Total change in standardized measure of discounted future net cash flows	$	558,000		$	—		$	—