CORRESP

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 December 11, 2014 with respect to Form 10-K for the fiscal year ended December 31, 2013 filed February 28, 2014 (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.

Response: The Company respectfully points out that, based on its reading and interpretation of the Staff’s prior comments, the Company used its best efforts to be responsive to such comments in the Company’s prior response letters. The Company also notes that the Company needed additional clarification from the Staff with respect to several of the Staff’s comments included in the Staff’s December 11, 2014 comment letter. In an effort to clarify and resolve such comments, the Company held a conference call with the Staff on December 18, 2014 during which it sought guidance from the Staff with respect to the Staff’s comments that raised uncertainty from the Company’s perspective as to the nature, scope and/or format of the responses sought by the Staff. The Company believes that its responses below are consistent with its discussions with the Staff and adequately address the Staff’s comments, as clarified by the Staff during the parties’ conference call.

For example, indicate the composition of the December 31, 2009 estimate by showing the quantities of the total added in each of the fiscal years ended 2009, 2008, 2007, 2006, 2005, and so forth. You should rollforward each strata by showing subsequent conversions to developed status, sales of reserves not developed, reclassifications to unproved status, and identifying any other material adjustments for each period. Please submit the analysis outlined above. Please include comparable details on any PUD reserve conversions during 2014.

Response: In response to the Staff’s comment, the Company is providing the Staff supplementally with Schedule A, detailing the information requested by the Staff in Comment 2 above, covering the 2009 through 2013 fiscal years, stratifying for each year-end estimate the quantity of such reserves initially claimed in that period and each prior period and showing (for each strata) the conversions in each period, percentage that such conversions represent of the beginning of the reserve strata balance, specifying adjustments and distinguishing them by type, and reconciling each strata between the year-end estimates. Please note that such Schedule A is being furnished to the Staff under separate cover pursuant to Rule 12b-4 of the Securities Exchange Act of 1934, as amended, and under the Freedom of Information Act and is not being filed electronically as part of this letter.

Please submit a detailed explanation of how the projected development costs and drilling schedules for the first year utilized in compiling PUD reserve estimates at the end of each of the last five fiscal years compared to the approved capital expenditure budgets, operating plans and actual drilling schedules for such year, following the reserve declaration date. For example, explain how the projected development costs and development schedule for 2014 in the PUD reserve estimate as of December 31, 2013, compared to the approved capital expenditure budget, operating plan and actual drilling schedule for 2014.

Response: In response to the Staff’s comment, the Company hereby provides further detail regarding the Company’s procedures concerning the adoption of a development plan with respect to its PUD locations booked by the Company in its reserve report. In the fourth quarter of each year, the Company has historically prepared its capital expenditure budget for the subsequent year. As part of the annual budget process, the Company analyzes the factors and procedures previously discussed by the Company in its response to Comment 4(a) of the Staff’s September 30, 2014 comment letter included in the Company’s response letter dated November 7, 2014. Based on this analysis and the financial capacity of the Company, the Company determines the number of wells that it plans to drill on operated assets for the subsequent year. Further, the Company evaluates a multi-year outlook for developing the assets in each of its core areas, including its Southern Louisiana assets, which the Company has been continuously developing since 1997, and its Utica Shale assets, which the Company has been developing since it spud its first well on its Utica acreage in early 2012. The selected PUD locations are then incorporated in the Company’s budget and business plan, which is subsequently reviewed and approved first by the Company’s senior management and second by its Board of Directors. For assets operated by others, the Company works with the operator to determine a drilling schedule for the following year and the five-year plan with respect to the PUD locations determined by the operator. Based on these short-term and long-term considerations, the Company records proved undeveloped reserves only after a plan has been approved to complete the associated development drilling within five years. This

process is intended to ensure that PUD reserves are only claimed for locations where a final investment decision has been made either by the Company (in the case of operated acreage) or by the operator (in the case of non-operated acreage).

Notwithstanding the pre-approved development plan, during the year, the Company may periodically seek to re-optimize its development plan. When making these real time adjustments to the development plan, in Southern Louisiana, the Company considers, among other things, new data from recently completed wells which may increase the attractiveness of a yet-to-be-drilled well location, which the Company may then move ahead of the pre-approved PUD location in its drilling plan. In the Utica, changes in the commodity price outlook, availability of infrastructure, permitting delays and other similar real time considerations may result in a modification to the development plan. All PUD locations that have not been, or will not be, drilled within five years of the booking date are then removed from proved reserves. This analysis is undertaken as part of the Company’s year-end reserve preparation process.

The Company is providing the Staff supplementally with Schedule B, which details the information requested by the Staff with respect to the development costs and drilling schedules. Please note that Schedule B is being furnished to the Staff under separate cover pursuant to Rule 12b-4 of the Securities Exchange Act of 1934, as amended, and under the Freedom of Information Act and is not being filed electronically as part of this letter.

Please submit a schedule summarizing the locations associated with each reserve strata for each of the prior five fiscal years, showing the internal rates of return associated with PUD reserves developed, PUD reserves derecognized, PUD reserves retained and PUD reserves added during these periods, also indicating the corresponding statistics for non-PUD reserves developed each period.

It should be clear how the internal rates of return inherent in the various prospects retained at each reserve declaration date compared to the internal rates of return associated with both the PUD reserve locations and the non-PUD reserve locations drilled during the period, and to the internal rates of return associated with the PUD reserve locations that were de-recognized during the period.

Please identify and thoroughly describe any differences between the economic criteria governing your reserve booking procedures and those utilized in deciding whether to actually proceed with development. Please augment the analyses requested above as necessary to encompass any such differences.

Response: In response to the Staff’s comment and the telephonic conference call on December 18, 2014, the Company hereby provides the following additional detail regarding the Company’s criteria considered when booking PUD reserves. As discussed by the Company in its response to Comment 4(b) of the Staff’s September 30, 2014 comment letter included in the Company’s response letter dated November 7, 2014, the financial criteria the Company considers when determining whether to claim PUD reserves include achieving an internal rate of return above its cost of capital, the expected payback period and the Company’s commodity price outlook. The financial criteria are also weighed against the Company’s plan to develop the location and whether that location meets the requirements of a PUD location, as analyzed by the Company’s third-party reserve engineers. While executing on the Company’s development plan and moving from a multi-year outlook to intra-year decision making, many other non-financial factors are taken into account as the Company determines the well-drilling sequence. The following discussion provides additional information on how these factors impact the Company’s drilling schedule in the Utica Shale and Southern Louisiana.

The Utica Shale, which accounted for approximately 86.5% of the Company’s 2013 year-end PUD reserves, is an unconventional shale reservoir characterized by four-phase windows: dry natural gas, liquids-rich natural gas, condensate and oil. While the depth of the producing formation and the hydrocarbon production varies from phase window to phase window, within each window the producing formation is relatively homogeneous. As a result, within each phase window the estimated internal rate of return is frequently quite similar. When considering expected internal rates of return from one phase window to another, the commodity price outlook can have the most significant impact. As the commodity price outlook changes, such as a greater change in oil prices versus natural gas prices, the Company will vary its level of activity in one phase window versus another. Further, when analyzing the sequence of wells to be drilled, the Company has to consider multiple other operational factors. These operational factors include, among others:

The Company evaluates changes in these operational factors, along with any possible change in the commodity price outlook, in real time and re-optimizes its drilling schedule periodically, based on these considerations. The Company also reviews annually its multi-year development plan and revises its PUD locations accordingly to comply with the SEC guidelines. The Company believes that this multi-faceted approach to first selecting its drilling locations and then making real time adjustments to the sequence of the wells it drills when circumstances dictate will result in the highest recovery of hydrocarbons, and therefore internal rates of return, for the development of its Utica Shale acreage as a whole.

The Company’s Southern Louisiana assets, which accounted for approximately 13.5% of its 2013 year-end PUD reserves, are much different than its Utica Shale assets. The Company’s Southern Louisiana assets are salt dome structures whereby oil and natural gas are trapped in a complex system of fault bounded traps. For instance, there are over 100 distinct sandstone reservoirs in the Company’s West Cote Blanche Bay field and over 30 pays zones in its Hackberry fields. The Company’s Southern Louisiana assets have been producing for over 70 years, so the Company is utilizing the latest technology to find previously overlooked pockets of oil and natural gas hydrocarbons when it drills a well in Southern Louisiana. Based on the analysis of data for wells drilled by the Company since 1997, the Company believes that its wells generate a return in excess of its cost of capital. Therefore, the Company’s sequence of wells drilled in this area incorporates several considerations that are in addition to, or may be different from, its considerations in the Utica Shale. First, the Company seeks to drill wells that have more zones. In Southern Louisiana, the Company often targets wells with multiple zones of hydrocarbon pockets, or stacked pay, which the Company believes will improve its chance of success versus a well which may have fewer pockets of stacked pay. As a result, the Company tries to drill wells which have more potential pay zones. Second, each well the Company drills may provide it with additional geologic data, enabling it to re-interpret the data associated with another well not yet drilled. As this additional data is processed, the Company’s preference as to which well is drilled next on its drilling schedule may change. Third, the Company has periodically been drilling wells in less developed portions of its acreage in order to improve its understanding of the hydrocarbons in place in those areas. While these wells may not have the highest expected internal rate of return viewed in isolation, the Company believes the additional opportunity they may unlock makes these wells (drilled by the Company selectively) worth incorporating into its drilling schedule. The Company believes that these real time adjustments to its drilling plan will help the Company to maximize the recovery and returns of its Southern Louisiana assets.

Note 19 - Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited), page F-43

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, page F-46

Please provide us a schedule showing the particular wells associated with the development costs excluded from your ceiling test, the dates drilling of each well began and completed, the status of the well at the balance sheet date, and your estimate of any remaining costs to be incurred to complete development of the well. Please include an explanation of the specific delays in the completion and subsequent production of each well in this field.

Further, the examples provided in Rule 4-10(c)(3)(ii)(B) of Regulation S-X of a major development project include the installation of an offshore drilling platform from which development wells are to be drilled, and the installation of improved recovery programs. Please demonstrate why you believe the facts and circumstances encountered in the Utica Shale field are comparable to these examples, if this is your view. The reasons for any delay in booking reserves for wells drilled in your Utica Shale field should be clarified.

Response: As noted in its response to prior comment six, the Company applied Rule 4-10(c)(3)(ii)(B) and (C) of Regulation S-X by excluding work-in-progress costs for wells that had incurred costs as of December 31, 2013, but had no booked reserves as of that date, from its ceiling test calculation. The Company considers the development of its Utica Shale field a major development project according to Rule 4-10(c)(3)(ii)(B). The Utica Shale is an emerging play, the development of which has occurred in recent years due to new technologies in horizontal drilling and multistaged hydraulic fracturing techniques. First production from horizontal wells in the field did not occur until as recently as 2011. At the time the Company commenced drilling operations in the field in 2012, it had invested over $600 million to acquire undeveloped acreage in the play. This amount of capital investment was significant to the Company. As of December 31, 2014, the Company had invested an aggregate of over $1 billion to acquire undeveloped acreage in this emerging play. In addition, construction of the necessary infrastructure in the Utica Shale did not begin on a large scale basis until 2012, and the limited infrastructure has impacted the development of the play. Based on the significant capital invested by the Company to acquire undeveloped acreage in the Utica Shale, the lack of necessary infrastructure and the infancy of the play, the subsequent drilling activity in the play was considered a major development project by the Company.

Because of the emerging play status of the Utica Shale, the majority of the wells drilled in this field by the Company in 2013 were not booked as PUD locations and were not offsets to producing wells. The Company selected its drilling locations strategically based on existing infrastructure, the need to develop and hold its acreage and other factors. In addition, the Company’s technical staff has determined that it was beneficial to the ultimate performance of the wells to drill and complete a pad of two to four wells simultaneously, which delays first production until all wells on the pad are completed. Drilling and completing a pad of multiple wells takes several months from first spud date to first production date (all wells on the pad are put on production at the same date). The costs excluded as development costs were for wells in various stages of drilling and completion at December 31, 2013 and, due to the factors noted above, had no booked reserves at December 31, 2013.

The Company is providing the Staff supplementally with Schedule C, which details approximately 99% of the costs excluded from the ceiling test as development costs at December 31, 2013 (costs excluded on Schedule C are for wells not operated by the Company and in which the Company has an immaterial working interest). Please note that Schedule C is being furnished to the Staff under separate cover pursuant to Rule 12b-4 of the Securities Exchange Act of 1934, as amended, and under the Freedom of Information Act and is not being filed electronically as part of this letter. As noted in Schedule C, the majority of the wells were completed during the first nine months of 2014, and reserves were booked and the previously excluded costs were moved to the Company’s amortizable base upon commencement of production from the wells. As requested, Schedule C details the date drilling began, the completion date, the date of first production, the remaining costs to be incurred to complete development and well status as of December 31, 2013. As shown on Schedule C, the excluded costs were for wells that were not producing at December 31, 2013, had significant remaining costs to be incurred, had no test data available and, as a result, had no booked reserves at December 31, 2013.

Response: In response to the Staff’s comment, the Company reviewed the Form 10-K, including the financial statements and related notes contained therein, and determined that the incorrect reference to 341 MBOE was a typographical error that appeared only in Item 2—Properties under the heading “Proved Undeveloped Reserves” on page 45 of the Form 10-K and had no impact on any other disclosure made or assumptions used in any other part of the Form 10-K, including Note 19—“Supplemental Information on Oil and Gas Exploration and Production Activities (Unaudited).” As a result, the only two changes that the Company would need to make in the Form 10-K (neither of which the Company believes to be material) are: (i) to correct the reference in the second bullet of the first paragraph under the heading “Proved Undeveloped Reserves” from 341 MBOE to 2,731 MBOE with respect to the conversion of PUD reserves into proved developed reserves and (ii) to make a corresponding upward adjustment with respect to additions attributable to 2013 acquisitions and extensions in the Utica field referenced in the first bullet of the same paragraph from 8,331 MBOE to 10,720 MBOE. In response to the Staff’s comment, the Company reviewed its internal controls over financial reporting and believes that its internal controls are adequate and effective. The Company also notes that no error relating to this matter occurred in its financial statements. However, in an effort to minimize the possibility of typographical errors in its future filings with the Commission, the Company enhanced its disclosure controls and procedures by adding an additional layer of review and proofing to its current disclosure controls and procedures.

If you have any questions with respect to the foregoing, please do not hesitate to call me at (405) 242-4885 or Seth Molay of Akin Gump Strauss Hauer & Feld LLP at (214) 969-4780.

Sincerely,

/s/ Keri Crowell

Keri Crowell

Vice President and Controller