424B5

Our common stock is quoted on The NASDAQ Global Select Market under the symbol “GPOR.” On February 11, 2013, the last reported sale price of our common stock on The NASDAQ Global Select Market was $38.68 per share.

The underwriters have an option to purchase a maximum of 1,162,500 additional shares of our common stock at the public offering price (less the underwriting discount) solely to cover over-allotments of shares.

Investing in our common stock involves risks. Please read “Risk Factors” beginning on page S-17 of this prospectus supplement for a description of various risks you should consider in evaluating an investment in the shares.

Delivery of the shares of common stock will be made on or about February 15, 2013.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus supplement or the accompanying prospectus to which it relates is truthful or complete. Any representation to the contrary is a criminal offense.

This document is in two parts. The first part is this prospectus supplement, which describes the specific terms of this offering. The second part, the accompanying prospectus, gives more general information, some of which may not apply to this offering. You should read the entire prospectus supplement, as well as the accompanying prospectus and the documents incorporated by reference that are described under “Where You Can Find More Information” in the accompanying prospectus and “Information Incorporated by Reference” in this prospectus supplement. In the event that the description of this offering varies between this prospectus supplement and the accompanying prospectus, you should rely on the information contained in this prospectus supplement.

You should rely only on the information contained or incorporated by reference in this prospectus supplement and the accompanying prospectus or to which we have referred you. We and the underwriters have not authorized any other person to provide you with additional or different information. We and the underwriters take no responsibility for, and can provide no assurance as to the reliability of, any information that others may give you. We and the underwriters are not making any offer to sell these securities in any jurisdiction where the offer to sell is not permitted. You should not assume that the information we have included in this prospectus supplement and the accompanying prospectus is accurate as of any date other than the date hereof or thereof, respectively, or that information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since those dates.

When used in this prospectus supplement, the terms “Gulfport,” the “Company,” “we,” “our” and “us” refer to Gulfport Energy Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires.

This prospectus supplement and the accompanying prospectus, including the documents incorporated by reference, may include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements, other than statements of historical facts, included in this prospectus supplement, the accompanying prospectus and the documents incorporated by reference that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and gas reserves and the present value thereof (including production activity for 2013), future capital expenditures (including the amount and nature thereof), drilling activity, production, expenses, business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, the pending acquisition of certain oil and natural gas interests described in this prospectus supplement, plans, references to future success, references 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 us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject to a number of risks and uncertainties, general economic, market or business conditions, the opportunities (or lack thereof) that may be presented to and pursued by us, competitive actions by other oil and gas companies, changes in laws or regulations, hurricanes and other natural disasters and other factors, many of which are beyond our control, including those discussed under the heading “Risk Factors” herein and those discussed in the documents we have incorporated by reference including our Annual Report on Form 10-K for the fiscal year ended December 31, 2011, our Quarterly Reports on Form 10-Q and any other reports filed subsequent to the filing of such reports. Consequently, all of the forward-looking statements made in this prospectus supplement, the accompanying prospectus and the documents incorporated by reference are qualified by these cautionary statements and we cannot assure you that the actual results or developments anticipated by us will be realized or, even if realized, that they will have the expected consequences to or effects on us, our 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.

PROSPECTUS SUPPLEMENT SUMMARY

This summary describes certain recent developments and highlights information contained elsewhere in or incorporated by reference into this prospectus supplement and the accompanying prospectus. This summary may not contain all the information that is important to you. We also advise you to read “Risk Factors” beginning on page S-17 for a description of various risks you should consider in evaluating an investment in the shares of our common stock.

The Company

Overview

We are an independent oil and natural gas exploration and production company focused on the exploration, exploitation, acquisition and production of crude oil, natural gas liquids and natural gas in the United States. Our corporate strategy is to internally identify prospects, acquire lands encompassing those prospects and evaluate those prospects using subsurface geology and geophysical data and exploratory drilling. Using this strategy, we have developed an oil and natural gas portfolio of proved reserves, as well as development and exploratory drilling opportunities on high potential conventional and unconventional oil and natural gas prospects. Our principal producing properties are located along the Louisiana Gulf Coast in the West Cote Blanche Bay, or WCBB, and Hackberry fields. During 2010, we acquired our initial acreage position in the Niobrara Formation of Northwestern Colorado. During 2011, we acquired our initial acreage position in the Utica Shale in Eastern Ohio and our first well in the Utica Shale was spud in February 2012. As of February 1, 2013, we had drilled 14 wells in the Utica Shale, three of which were producing. Of the remaining 11 wells, seven are projected to be producing by April 1, 2013 and the other four are projected to be producing by June 1, 2013 as the necessary gathering infrastructure is completed. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, a 21.4% equity interest in Diamondback Energy, Inc., or Diamondback, a NASDAQ Global Select Market listed company to which we contributed our Permian Basin oil and gas interests in October 2012 immediately prior to Diamondback’s initial public offering, or the Diamondback IPO (see “—Recent Developments—Contribution” below), and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs.

The following table presents certain information as of December 31, 2012 reflecting our net interest in our principal producing oil and natural gas properties along the Louisiana Gulf Coast, in the Utica Shale in Eastern Ohio, in the Niobrara Formation in Northwestern Colorado and in the Bakken Formation in Western North Dakota and Eastern Montana.


	NRI/WI(1)		Productive Wells(2)				Non-Productive Wells				Developed Acreage(3)				Proved Reserves
	NRI/WI(1)		Productive Wells(2)				Non-Productive Wells				Developed Acreage(3)				Gas		Oil		Total
Field	Percentages		Gross		Net		Gross		Net		Gross		Net		MBOE		MBOE		MBOE
West Cote Blanche Bay Field(4)		80.108/100		109		109		181		181		5,668		5,668		556		4,266		4,822
E. Hackberry Field(5)		80.309/100		41		41		96		96		3,931		3,931		151		1,900		2,051
W. Hackberry Field		83.333/100		3		3		23		23		1,192		1,192		3		95		98
Utica Shale(6)		40.641/50.0		2		1		—		—		2,441		1,800		4,886		1,702		6,588
Niobrara Formation		36.2/41.5		7		3		2		1		2,807		1,404		16		204		220
Bakken Formation(7)		2.7/2.9		8		0.2		—		—		1,862		163		10		82		92
Overrides/Royalty Non-operated		Various		208		0.4		2		0.06		—		—		6		2		8

Total				378		157.6		304		301.06		17,901		14,158		5,628		8,251		13,879

(1)

Net Revenue Interest (NRI)/Working Interest (WI) for producing wells.

(2)

Includes seven gross and net wells at WCBB that are producing intermittently.

(3)

Developed acres are acres spaced or assigned to productive wells. Approximately 11% of our acreage is developed acreage and has been perpetuated by production.

(4)

We have a 100% working interest (80.108% average NRI) from the surface to the base of the 13900 Sand which is located at 11,320 feet. Below the base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI).

(5)

NRI shown is for producing wells.

(6)

Does not give effect to our pending acquisition of approximately 22,000 net acres. See “—Recent Developments—February 2013 Utica Acreage Acquisition.”

(7)

NRI/WI is from wells that have been drilled or in which we have elected to participate.

The following is a description of our principal properties.

West Cote Blanche Bay

The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres.

In 2011, at our WCBB field, we recompleted 68 wells and drilled 21 wells for a total cost of approximately $42.4 million as of December 31, 2011. Of the 21 new wells drilled at WCBB in 2011, 19 were completed as producing wells, one was non-productive and one was waiting on completion. In 2012, we recompleted 61 existing wells. We also spud 31 wells, of which 27 were completed as producers and four were non-productive. Aggregate net production from the WCBB field during the three months ended December 31, 2012 was 293,906 barrels of oil equivalent, or BOE, or 3,195 BOE per day, 98% of which was from oil and 2% of which was from natural gas. During January 2013, our average daily net production at WCBB was approximately 3,054 BOE, 98% of which was from oil and 2% of which was from natural gas.

East Hackberry Field

The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 80.309% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. As of December 31, 2012, we held beneficial interests in approximately 4,512 acres, including the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. We have licensed approximately 54 square miles of 3-D seismic data covering a portion of the area and are reprocessing the data.

In 2011, at our East Hackberry field, we recompleted 24 wells and drilled 22 wells. Of the 22 new wells drilled at East Hackberry during 2011, 17 were completed as producing wells, two were non-productive and three were waiting on completion. In 2012, we recompleted 32 existing wells. We also spud 23 wells, of which 19 were completed as producing wells and three were non-productive and, at December 31, 2012, one was being drilled. Aggregate net production from the East Hackberry field during the three months ended December 31, 2012 was approximately 212,975 BOE, or 2,315 BOE per day, 98% of which was from oil and 2% of which was from natural gas. During January 2013, our average daily net production at East Hackberry was approximately 2,623 BOE, 97% of which was from oil and 3% of which was from natural gas.

West Hackberry Field

The West Hackberry field is located on land and is five miles west of Lake Calcasieu in Cameron Parish, Louisiana, approximately 85 miles west of Lafayette and 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 83.333% NRI) in 1,192 acres within the West Hackberry field. Our leases

at West Hackberry are located within two miles of one of the United States Department of Energy’s Strategic Petroleum Reserves.

At December 31, 2012, we were drilling one well at West Hackberry. Aggregate net production from the West Hackberry field during the three months ended December 31, 2012 was approximately 4,711 BOE, or 51 BOE per day. During January 2013, our average daily net production at West Hackberry was approximately 29 BOE, 100% of which was from oil.

Utica Shale (Eastern Ohio)

As of December 31, 2012, we had acquired leasehold interests in approximately 137,000 gross (106,000 net) acres in the Utica Shale in Eastern Ohio. We have entered into an agreement to acquire approximately 22,000 additional net acres in the Utica Shale. See “—Recent Developments—February 2013 Utica Acreage Acquisition.” We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of February 1, 2013, had drilled 14 wells, ten of which had been completed. As of February 1, 2013, three of these wells were producing. Of the 11 additional wells, seven are projected to be producing by April 1, 2013 and the other four wells are projected to be producing by June 1, 2013. The delays in bringing these additional wells on-line have primarily been associated with MarkWest Energy Partners, L.P.’s challenges in obtaining rights-of-way and acquiring necessary state and federal permitting. These rights-of-way and permits have now been obtained. In addition, 12 gross (one net) wells were drilled by another operator on our Utica Shale acreage during 2012.

At February 1, 2013, we had two rigs under contract on our Utica Shale acreage and expect to add a third rig later in the month. We currently intend to drill 50 wells on our Utica Shale acreage in 2013.

Aggregate net production from the Utica Shale during the three months ended December 31, 2012 was approximately 69,667 BOE, or 757 BOE per day, 35% of which was from oil and natural gas liquids, or NGLs, and 65% of which was from natural gas. During January 2013, our average daily net production from the Utica Shale was approximately 792 BOE, 41% of which was from oil and NGLs and 59% of which was from natural gas. The Wagner 1-28H well, our longest producing well in the Utica Shale, was assigned gross proved ultimate recovery reserves at December 31, 2012 of 65.8 thousand barrels of oil, or MBbls, and 10.0 billion cubic feet, or Bcf, of unshrunk natural gas by Ryder Scott Company, L.P. Adjusting for shrinkage and the extraction of NGLs, we estimate that this is equivalent to 1.8 million BOE, or MMBOE, of proved reserves.

Niobrara Formation (Northwestern Colorado)

Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and held leases for approximately 11,788 net acres as of December 31, 2012. In 2012, three gross (one net) wells, including one gross (.04 net) well drilled by another operator, were spud on our Niobrara Formation acreage, two of which were completed as producers and one of which was non-productive. Aggregate net production from our Niobrara Formation acreage during the three months ended December 31, 2012 was approximately 2,644 BOE, or 29 BOE per day, 100% of which was from oil. During January 2013, average daily net production from our Niobrara Formation acreage was approximately 43 BOE, 100% of which was from oil.

Bakken Formation

In the Bakken Formation, as of December 31, 2012, we held approximately 864 net acres, interests in nine wells and overriding royalty interests in certain existing and future wells. Aggregate net production from the Bakken Formation during the three months ended December 31, 2012 was approximately 7,355 BOE, or 80 BOE per day. During January 2013, our average daily net production from the Bakken Formation was approximately 73 BOE.

Permian Basin (West Texas)

In 2007, we acquired approximately 4,100 net acres in West Texas in the Permian Basin with production at the time of acquisition from 32 gross (16 net) wells, predominately from the Wolfcamp formation. Subsequently, we acquired approximately 14,100 additional net acres, which brought our total net acreage position in the Permian Basin to approximately 18,200 net acres as of September 30, 2012. From our initial acquisition in the

Permian Basin through August 1, 2012, 116 gross (52.7 net) wells were drilled on our leasehold in this area, primarily targeting the Wolfberry formation. We were not the operator of our Permian Basin acreage but were actively involved in the planning and execution of the drilling plans governed by a joint operating agreement with Diamondback O&G LLC (formerly known as Windsor Permian LLC), or Diamondback O&G, the operator in this field and an entity controlled by Wexford Capital L.P., or Wexford. An affiliate of Wexford owned approximately 9.5% of our outstanding common stock as of March 13, 2012, which ownership was reduced to less than 1% as of September 28, 2012. In 2011, 39 gross (17 net) wells were drilled and eight gross (four net) wells were recompleted on our Permian Basin acreage. As of December 31, 2011, 35 of the 39 wells had been completed and four wells were awaiting completion. From January 1, 2012 through the closing of the contribution of our Permian Basin acreage to Diamondback on October 11, 2012, 19 gross (8.3 net) wells, including our first horizontal well, were spud on our Permian Basin acreage, all of which were completed as producing wells. One gross (0.3 net) existing well was recompleted from January 1, 2012 to October 11, 2012. Aggregate net production from our Permian Basin acreage during the first eleven days of October 2012 was approximately 17,100 BOE, or 1,555 BOE per day, of which approximately 60% was oil, 28% was natural gas liquids and 12% was natural gas.

As discussed below under the heading “—Recent Developments—Contribution,” on October 11, 2012, we contributed to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin. At the closing of this contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and other items of Diamondback O&G referred to in the contribution agreement as of the date of this contribution. In January 2013, we received an additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. As of October 23, 2012, following the closing of the Diamondback IPO and the underwriters’ exercise in full of their option to purchase additional shares of common stock of Diamondback, we owned approximately 21.4% of Diamondback’s outstanding common stock. Following the Contribution, we account for our interest in Diamondback as an equity investment.

Our Equity Investments

Grizzly. We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by an entity controlled by Wexford. As of December 31, 2012, Grizzly had approximately 800,000 acres under lease in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of other existing oil sands projects. Our total net investment in Grizzly was approximately $165.0 million as of September 30, 2012. As of that date, Grizzly had drilled an aggregate of 232 core holes and seven water supply test wells, tested eleven separate lease blocks and conducted a seismic program. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order-in Council authorizing the Alberta Energy Resources Conservation Board, or ERCB, to issue the formal regulatory approval of Grizzly’s Algar Lake steam-assisted gravity drainage, or SAGD, project. During the second quarter of 2012, Grizzly finished SAGD well pair drilling at Algar Lake and began the process of completing those well pairs for SAGD injection and first production is expected in mid-2013. In the first quarter of 2012, Grizzly completed the acquisition of approximately 47,000 acres through the purchase of its May River property and has prepared a full field development plan under which the May River property will be developed in multiple phases with the goal of producing 70,000 barrels per day of bitumen by the year 2020. Grizzly is currently conducting a 25 well delineation program at May River, with 14 wells completed as of February 6, 2013. Following the 2012/2013 winter exploration program, it is expected that Grizzly’s May River property will have been explored to a sufficient level to support the filing of an initial 12,000 barrel per day SAGD project regulatory application. Grizzly’s other 2012 activities included the completion of the 2011/2012 core hole drilling and seismic program, submission of a SAGD project regulatory application for the development of a 12,000 barrel per day oil sands

project at Thickwood Hills and further development of its Algar Lake SAGD project, which included the fabrication and onsite construction of a central processing facility and the drilling of ten initial SAGD well pairs. The Thickwood Hills project is expected to consist of a plant site with two 6,000 barrel per day processing facilities, four SAGD well pads and up to 33 cycle steam stimulation well pads and associated facilities and infrastructure. Grizzly filed an environmental assessment for the Thickwood Hills project in November 2012 and expects to receive the applicable approvals within 12 to 18 months thereafter. Following receipt of the approvals, Grizzly anticipates the period leading to first production will be approximately 18 months. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN’s rail network. Grizzly expects that this arrangement will provide consistent access to Brent-based pricing from Grizzly’s Algar Lake project. Grizzly is also pursuing the design, permitting and construction of rail terminals in Northern Alberta and on the Lower Mississippi where, with scalable capacity to accommodate unit trains to ship and receive up to 100,000 barrels per day, Grizzly anticipates beginning to transport the company’s bitumen starting in the fourth quarter of 2013.

Tatex II. We own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. The remaining interests in Tatex II are owned by entities controlled by Wexford. Tatex II, a privately held entity, holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC, or APICO, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately two million acres which include the Phu Horm field. As of September 30, 2012, our net investment in Tatex II was $0.3 million. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. During the three months ended September 30, 2012, net gas production from the Phu Horm field was approximately 93 million cubic feet, or MMcf, of natural gas per day and condensate production was 426 barrels per day. Hess Corporation operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTT Exploration and Production Public Company Limited (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex II as a member of APICO) in the Phu Horm field is 0.7%. Since our ownership in the Phu Horm field is indirect and Tatex II’s investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information.

Tatex III. We also own a 17.9% ownership interest in Tatex Thailand III, LLC, or Tatex III. Approximately 68.7% of the remaining interests in Tatex III are owned by entities controlled by Wexford. Tatex III owns a concession covering approximately one million acres. During the nine months ended September 30, 2012, we paid $0.6 million in cash calls, bringing our total investment in Tatex III to $8.7 million. The first well was drilled on our concession in 2010 and was temporarily abandoned pending further scientific evaluation. Drilling of the second well concluded in March 2011. The second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced gas shows and carried a flare measuring up to 25 feet throughout drilling below the intermediate casing point of 9,695 feet. During testing, the well produced at rates as high as 16 MMcf per day of gas for short intervals, but would subsequently fall to a sustained rate of two MMcf per day of gas. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the application process for two more drilling locations. Tatex III currently expects to drill the first of these wells, located to the south of the TEW-E well, in 2013.

Other Investments. In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are required to support our operations. In the second quarter of 2012, we acquired a 50% equity interest in each of Stingray Pressure Pumping LLC, or Stingray Pressure, and Stingray Cementing LLC, or Stingray Cementing. Stingray Pressure and Stingray Cementing will provide well completion services. We also acquired a 50% equity interest in Blackhawk Midstream LLC, or

Blackhawk, which coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale acreage. In March 2012, we acquired a 50% equity interest in Timber Wolf Terminals LLC, or Timber Wolf, for $1.0 million. Timber Wolf will operate a crude/condensate terminal and sand transloading facility in Ohio. Also in March 2012, we acquired a 22.5% equity interest in Windsor Midstream LLC, or Midstream, for $7.0 million. Midstream owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011, we acquired a 25% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates drilling rigs and related equipment. In April 2012, we purchased an additional 15% equity interest for approximately $6.2 million, bringing our total ownership interest in Bison to 40%. Also in 2011, we acquired a 25% interest in Muskie Holdings LLC, or Muskie, which is engaged in the mining of hydraulic fracturing grade sand. The remaining equity interests in these entities are owned by affiliates of Wexford. In 2012, we invested approximately $30.0 million to $35.0 million in these entities.

Our Strengths

We believe that the following strengths will help us achieve our business goals:

•

Exposure to oil rich resource base. We have interests in some of the most prolific oil plays in North America, including the shallow waters of the Gulf of Mexico in Louisiana, the Canadian Oil Sands in Central Alberta, the Bakken Shale in North Dakota and, through our interest in Diamondback, the Permian Basin in West Texas. We have also acquired acreage positions in the Niobrara Shale of Western Colorado and the Utica Shale in Eastern Ohio. Our 2012 production was approximately 90% oil and 3% natural gas liquids, with the remaining production provided by natural gas. We expect that natural gas liquids and natural gas as a percentage of our production will increase as more Utica Shale production is brought on-line.

•

Inventory of low risk development and exploitation opportunities. We have identified a multi-year inventory of drilling locations that we believe provides attractive growth and return opportunities. We have focused our efforts on building an oil-weighted inventory of reserves because we anticipate that such inventory will provide, in the long-term, superior returns.

•

Experienced management and technical team with proven acquisition and operating capabilities. Our executive officers and technical personnel have an average of over 30 years of experience in the oil and natural gas exploration and production business. We believe that our drilling success rate of 95% over the six-year period from 2007 through 2012 is attributable to our team’s industry experience.

Our Business Strategy

Our business strategy is to continue to profitably grow our business through the following:

•

Grow production and reserves by developing our large oil-rich resource base. Through the conversion of our proved undeveloped, probable and possible reserves, we will seek to grow our production, reserves and cash flow. We target areas that are believed to have a large amount of oil in place, then seek to apply the available technology to extract additional oil from those regions with a large amount of original oil in place, including 3-D seismic and directional drilling in South Louisiana, horizontal drilling and hydraulic fracturing in the Utica Shale and SAGD to extract bitumen from oil sands in Canada.

•

Continue to pursue attractive acquisitions. We have grown and diversified our oil-rich reserve and resource base by making selective acquisitions. Over the last several years we have added interests in the Niobrara Formation, Utica Shale and the Canadian Oil Sands to our original asset base along the Louisiana Gulf Coast.

•

Financial flexibility. We seek to maintain a conservative financial position. By maintaining a conservative capital structure, we will seek to preserve our flexibility to pursue opportunities that fit our strengths and corporate strategy as those opportunities present themselves.

Recent Developments

Operational Update

For the fourth quarter of 2012, our net production was 540,558 barrels of oil, 366,258 thousand cubic feet, or Mcf, of natural gas and 289,728 gallons of NGLs, or 608,499 BOE. Our net production for the fourth quarter of 2012 by region was 293,906 BOE at WCBB, 217,686 BOE at Hackberry, 69,667 BOE in the Utica Shale, 17,100 BOE in the Permian Basin and an aggregate of 10,140 BOE in the Bakken Formation, Niobrara Formation and other areas. For 2012, we recorded net production of 2,323,373 barrels of oil, 1,107,744 Mcf of natural gas and 2,714,085 gallons of NGLs, or 2,572,618 BOE. Our realized prices for the fourth quarter of 2012, including transportation costs, were $101.89 per barrel of oil, $3.00 per Mcf of natural gas and $1.01 per gallon of NGLs, for a total equivalent of $92.80 per BOE. Our realized prices for the full-year 2012, including transportation costs, were $104.46 per barrel of oil, $2.91 per Mcf of natural gas and $0.98 per gallon of NGLs, for a total equivalent of $96.63 per BOE.

The following table presents our production volumes and average prices for the periods presented:


(Unaudited) Production Volumes:	4Q2012		4Q2011		2012		2011
Oil (MBbls)		541		618		2,323		2,128
Natural Gas (MMcf)		366		186		1,108		878
NGLs (MGal)		290		535		2,714		2,468
Oil equivalents (MBOE)		609		662		2,573		2,333

Average Realized Price:
Oil (per Bbl)	$	101.89	$	109.18	$	104.46	$	104.33
Natural Gas (per Mcf)	$	3.00	$	3.67	$	2.91	$	4.37
NGLs (per Gal)	$	1.01	$	1.39	$	0.98	$	1.25
Oil equivalents (BOE)(1)	$	92.80	$	104.11	$	96.63	$	98.13

(1)

See note 1 to the table under the heading “Summary Operating and Reserve Data” for information regarding the impact of our fixed price swaps on our average realized prices.

We estimate that our 2013 capital expenditures for exploration and production activities will be approximately $450.0 million to $500.0 million, after giving effect to our pending acquisition of additional acreage in the Utica Shale and excluding any amounts attributable to Grizzly. We expect that we will fund our capital development plans for 2013 from our operating cash flow, proceeds from our 2012 note and equity offerings, borrowings under our revolving credit facility and a portion of the net proceeds from this offering. Approximately 85% of the capital expenditures specified above are currently expected to be spent in the Utica Shale. Our actual costs may exceed these estimates and, if they do, there can be no assurance that we would be able to fund these additional costs. See “Risk Factors.”

February 2013 Utica Acreage Acquisition

On February 11, 2013, we entered into a purchase and sale agreement, or the PSA, with Windsor Ohio, LLC, or Windsor Ohio, which is an affiliate of Wexford, pursuant to which Windsor Ohio has agreed to sell, assign, transfer and convey to us approximately 22,000 net acres representing 100% of its right, title and interest in and to certain leasehold interests in the Utica Shale in Eastern Ohio. The purchase price is approximately $220.4 million, subject to certain adjustments. This acquisition excludes Windsor Ohio’s interest in 14 existing wells and 16 proposed future wells together with certain acreage surrounding these wells. We acquired our initial acreage in the Utica Shale in February 2011 and have subsequently acquired additional acreage in the area. Windsor Ohio participated with us in the acquisition of these leases. Through a prior transaction with Windsor

Ohio, as discussed below under the heading “—December 2012 Utica Acreage Acquisition,” we acquired approximately 37,000 net acres, which increased our working interest in the acreage to 77.7%. Through the current transaction, we are acquiring an additional approximately 16.2% interest in these leases, increasing our working interest in the acreage to 93.8%. All of the acreage included in this transaction is currently nonproducing and we are the operator of all of this acreage, subject to existing development and operating agreements between the parties.

Pending the completion of title review after the closing, approximately $33.6 million of the purchase price will be placed in an escrow account. The escrow account will terminate on May 1, 2013 and the escrow amount will be distributed to either us or Windsor Ohio based on any title benefits or title defects resulting from the title review. Pursuant to the PSA, we and Windsor Ohio have agreed to indemnify each other, our respective affiliates and their respective officers, directors, employees and agents from and against all losses that such indemnified parties incur arising from any breach of representations, warranties or covenants in the PSA and certain other matters. The transaction was approved by a special committee of our board of directors, who engaged independent counsel and financial advisors to assist with their review. The closing is subject to the satisfaction of a number of conditions, including the closing of this offering on terms reasonably satisfactory to us.

December 2012 Utica Acreage Acquisition

On December 17, 2012, we entered into a purchase and sale agreement with Windsor Ohio, pursuant to which Windsor Ohio agreed to sell, assign, transfer and convey to us approximately 30,000 net acres representing 50% of its right, title and interest at the time in and to certain leasehold interests in the Utica Shale in Eastern Ohio. On December 19, 2012, the parties amended that agreement to provide for our acquisition of approximately 7,000 additional net acres. The aggregate purchase price for these interests was approximately $372.0 million, subject to certain adjustments. Through this transaction, we acquired an approximately 27.5% interest in these leases, increasing our working interest in the acreage to 77.7%. The transaction closed on December 24, 2012. All of the acreage included in this transaction was nonproducing and we are the operator of all of this acreage, subject to existing development and operating agreements between the parties. Pending the completion of title review after the closing, approximately $53.9 million of the purchase price was placed in an escrow account. The escrow account will terminate on April 30, 2013 and the escrow amount will be distributed to either us or Windsor Ohio based on any title benefits or title defects resulting from the title review.

Contribution

On May 7, 2012, we entered into a contribution agreement with Diamondback. Under the terms of the contribution agreement, we agreed to contribute to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and gas interests in the Permian Basin. On October 11, 2012, we completed this contribution, which we refer to herein as the Contribution. At the closing of the Contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working capital, long-term debt and other items of Diamondback O&G referred to in the contribution agreement as of the date of the Contribution. In January 2013, we received an additional payment of $18.6 million as a result of this post-closing adjustment. Diamondback O&G is a wholly-owned subsidiary of Diamondback.

In connection with the Contribution, we and Diamondback entered into an investor rights agreement in which we have the right, for so long as we beneficially own more than 10% of Diamondback’s outstanding common stock, to designate one individual as a nominee to serve on Diamondback’s board of directors. Such nominee, if elected to Diamondback’s board, will also serve on each committee of the board so long as he or she satisfies the independence and other requirements for service on the applicable committee of the board. So long as we have the right to designate a nominee to Diamondback’s board and there is no nominee of ours actually serving as a Diamondback director, we will have the right to appoint one individual as an advisor to the board

who shall be entitled to attend board and committee meetings. We are also entitled to certain information rights and Diamondback granted us certain demand and “piggyback” registration rights obligating Diamondback to register with the Securities and Exchange Commission, or the SEC, any shares of Diamondback common stock that we own. Immediately upon completion of the Contribution, we owned a 35% equity interest in Diamondback, rather than leasehold interests in our Permian Basin acreage. Upon completion of the Diamondback IPO and the exercise in full by the underwriters of their over-allotment option to purchase additional shares of common stock of Diamondback, we owned approximately 21.4% of Diamondback’s outstanding common stock. Our investment in Diamondback is accounted for as an equity method investment.

Notes Offerings

On October 17, 2012, we issued $250.0 million in aggregate principal amount of 7.750% Senior Notes due 2020, or the October Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act under an indenture among us, our subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, which we refer to as the senior note indenture. The offering of the October Notes is referred to herein as the October Notes Offering. On December 21, 2012, we issued an additional $50.0 million in aggregate principal amount of 7.750% Senior Notes due 2020, or the December Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act, which offering we refer to herein as the December Notes Offering. The December Notes were issued as additional securities under the senior note indenture. The October Notes and the December Notes are referred to collectively herein as the Notes, and we refer to the October Notes Offering and the December Notes Offering collectively as the Notes Offerings.

Under the senior note indenture, interest on the Notes accrues at a rate of 7.750% per annum on the outstanding principal amount from October 17, 2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The Notes are our senior unsecured obligations and rank equally in the right of payment with all of our other senior indebtedness and senior in right of payment to any of our future subordinated indebtedness. All of our existing and future restricted subsidiaries that guarantee our secured revolving credit facility or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of our future unrestricted subsidiaries.

Equity Offering

On December 24, 2012, we issued and sold 11,750,000 shares of our common stock in an underwritten public offering, or the Equity Offering (including the partial exercise of an over-allotment option for 1,650,000 shares granted to the underwriters, which option was exercised to the extent of 750,000 shares). The underwriters subsequently exercised their option to purchase the remaining 900,000 additional shares of common stock subject to the over-allotment option in a second closing, which occurred on January 7, 2013. The net proceeds from the Equity Offering (including the net proceeds from the sale of the shares of common stock to the underwriters under their over-allotment option) were approximately $460.7 million. We used a portion of these net proceeds to fund the acquisition of approximately 37,000 net acres in the Utica Shale in Eastern Ohio, as described above under the caption “—December 2012 Utica Acreage Acquisition.” The remaining net proceeds will be used for general corporate purposes, including the funding of a portion of our 2013 capital development plan.

Senior Secured Credit Facility

Effective as of October 17, 2012, in connection with the completion of the October Notes Offering and the Contribution, our borrowing base under our senior secured credit facility was set at $45.0 million until the next borrowing base redetermination. Upon completion of the December Notes Offering, our borrowing base was

The Offering

Common stock offered by us

7,750,000 shares(1)

Underwriters’ option to purchase additional shares from us

1,162,500 shares

Common stock to be outstanding after this offering

76,177,386 shares(1)(2)

Use of proceeds

We estimate that the net proceeds from the sale of 7,750,000 shares of our common stock in this offering will be approximately $282.3 million, after deducting the underwriting discounts and commissions and estimated offering expenses, or approximately $324.7 million if the underwriters exercise the over- allotment option granted by us in full. We intend to use these net proceeds to fund the pending acquisition of additional acreage in the Utica Shale and for general corporate purposes, including the funding of a portion of our 2013 capital development plan. See “Use of Proceeds.”

NASDAQ Global Select Market symbol

GPOR

Dividend policy

We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. In addition, our existing credit facility and the senior note indenture limit our ability to pay dividends and make other distributions.

Risk factors

We are subject to a number of risks that you should carefully consider before deciding to invest in our common stock. These risks are discussed more fully in “Risk Factors.”

(1)

Assumes no exercise of the underwriters’ option to purchase additional shares.

(2)

The number of shares of common stock outstanding after the offering is based on 68,427,386 shares of common stock outstanding as of February 8, 2013, excluding 245,831 shares of restricted common stock awarded under our Amended and Restated 2005 Stock Incentive Plan but not yet vested. The number of shares outstanding does not include shares issuable upon the exercise of outstanding stock options held by our employees, officers and directors.

Summary Consolidated Historical and Pro Forma Financial Data

The following table summarizes our consolidated financial data as of and for each of the periods indicated. You should read the following summary financial data in conjunction with “Risk Factors,” “Use of Proceeds,” “Capitalization” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and the related notes included, as applicable, in this prospectus supplement and in our most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q incorporated by reference into this prospectus supplement and the accompanying prospectus. Our historical operating results presented below are not indicative of future results. The summary consolidated financial data as of and for each of the fiscal years ended December 31, 2011 and 2010 and the summary consolidated statements of operations and cash flow data for the fiscal year ended December 31, 2009 have been derived from our audited consolidated financial statements appearing in our most recent Annual Report on Form 10-K incorporated by reference into this prospectus supplement and the accompanying prospectus. The summary consolidated balance sheet data as of December 31, 2009 have been derived from our audited consolidated financial statements appearing in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009. The summary consolidated financial data as of and for the nine months ended September 30, 2012 and the summary consolidated statements of operations and cash flow data for the nine months ended September 30, 2011 have been derived from our unaudited consolidated financial statements appearing in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2012 incorporated by reference into this prospectus supplement and accompanying prospectus. The summary consolidated balance sheet data as of September 30, 2011 have been derived from our unaudited consolidated financial statements appearing in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2011. The unaudited pro forma financial data give effect to (a) the October Notes Offering or (b) the Diamondback contribution as if the identified transaction, alone, had occurred. The unaudited pro forma consolidated statement of operations data for the year ended December 31, 2011 and the nine months ended September 30, 2012 assume that each transaction occurred on January 1, 2011. The unaudited pro forma balance sheet data assume that each transaction occurred on September 30, 2012. The unaudited pro forma financial information is provided for illustrative purposes only and does not represent what our actual result of operations or our financial position would have been had the transactions occurred on the dates assumed nor is it indicative of our future results or financial position. Please see “Unaudited Pro Forma Consolidated Financial Statements” and related notes appearing in our Current Report on Form 8-K filed on December 18, 2012 incorporated by reference into this prospectus supplement and the accompanying prospectus for a presentation of the cumulative effect of these two transactions.


	Year Ended December 31,						Nine Months Ended September 30,				Pro Forma for the October Notes Offering				Pro Forma for the Contribution
	2011		2010		2009		2012		2011		Year Ended December 31, 2011		Nine Months Ended September 30, 2012		Year Ended December 31, 2011		Nine Months Ended September 30, 2012
Consolidated Statements of Operations Data:
Revenues	$	229,254,000	$	127,921,000	$	85,968,000	$	192,323,000	$	160,308,000	$	229,254,000	$	192,323,000	$	206,202,000	$	171,106,000
Costs and expenses:
Lease operating expenses		20,897,000		17,614,000		16,316,000		18,201,000		15,103,000		20,897,000		18,201,000		15,413,000		11,842,000
Production taxes		26,333,000		13,966,000		9,797,000		22,411,000		18,520,000		26,333,000		22,411,000		25,057,000		21,292,000
Depreciation, depletion and amortization		62,320,000		38,907,000		29,225,000		70,424,000		40,606,000		62,320,000		70,424,000		70,993,000		85,294,000
General and administrative		8,074,000		6,063,000		4,992,000		9,370,000		6,209,000		8,074,000		9,370,000		8,074,000		9,370,000
Accretion expense		666,000		617,000		582,000		529,000		491,000		666,000		529,000		634,000		498,000

		118,290,000		77,167,000		60,912,000		120,935,000		80,929,000		118,290,000		120,935,000		120,171,000		128,296,000

Income from Operations		110,964,000		50,754,000		25,056,000		71,388,000		79,379,000		110,964,000		71,388,000		86,031,000		42,810,000


	Year Ended December 31,									Nine Months Ended September 30,						Pro Forma for the October Notes Offering						Pro Forma for the Contribution
	2011			2010			2009			2012			2011			Year Ended December 31, 2011			Nine Months Ended September 30, 2012			Year Ended December 31, 2011			Nine Months Ended September 30, 2012

Other (Income) Expense:
Interest expense		1,400,000			2,761,000			2,309,000			1,630,000			1,163,000			21,013,000	(1)		15,778,000	(1)		1,400,000			1,630,000
Insurance proceeds		—			—			(1,050,000	)		—			—			—			—			—			—
Interest income		(186,000	)		(387,000	)		(564,000	)		(37,000	)		(139,000	)		(186,000	)		(37,000	)		(186,000	)		(37,000	)
Loss (gain) from equity method investments		1,418,000			977,000			706,000			1,793,000			906,000			1,418,000			1,793,000			290,000			(2,851,000	)

		2,632,000			3,351,000			1,401,000			3,386,000			1,930,000			22,245,000			17,534,000			1,504,000			(1,258,000	)

Income before Income Taxes		108,332,000			47,403,000			23,655,000			68,002,000			77,449,000			88,719,000			53,854,000			84,527,000			44,068,000
Income Tax Expense (Benefit)		(90,000	)		40,000			28,000			15,514,000			1,000			(90,000	)		10,562,000			(90,000	)		7,137,000

Net Income		108,422,000			47,363,000			23,627,000			52,488,000			77,448,000			88,809,000			43,292,000			84,617,000			36,931,000

Net Income Available to Common Stockholders	$	108,422,000		$	47,363,000		$	23,627,000		$	52,488,000		$	77,448,000		$	88,809,000		$	43,292,000		$	84,617,000		$	36,931,000

Net Income Per Common Share—Basic	$	2.22		$	1.08		$	0.55		$	0.94		$	1.63		$	1.82		$	0.78		$	1.74		$	0.66
Net Income Per Common Share—Diluted	$	2.20		$	1.07		$	0.55		$	0.93		$	1.61		$	1.80		$	0.77		$	1.72		$	0.66

Consolidated Cash Flow Information:
Net cash provided by (used in):
Operating activities	$	158,138,000		$	85,835,000		$	53,299,000		$	165,876,000		$	122,046,000
Investing activities	$	(323,248,000	)	$	(105,315,000	)	$	(39,246,000	)	$	(387,893,000	)	$	(230,205,000	)
Financing activities	$	256,539,000		$	20,224,000		$	(18,273,000	)	$	140,400,000		$	128,402,000


	At December 31,						At September 30,				Pro Forma for the October Notes Offering			Pro Forma for the Contribution
	2011		2010		2009		2012		2011		At September 30, 2012			At September 30, 2012
Consolidated Balance Sheet Data:
Total assets	$	691,158,000	$	319,693,000	$	227,344,000	$	970,609,000	$	553,437,000	$	1,075,944,000		$	959,811,000	(3)
Total debt, including current maturity	$	2,283,000	$	51,917,000	$	52,428,000	$	143,180,000	$	2,317,000	$	248,515,000	(2)	$	143,180,000
Total liabilities	$	58,808,000	$	108,637,000	$	102,293,000	$	289,982,000	$	75,752,000	$	395,317,000	(2)	$	285,378,000
Stockholders’ equity	$	632,350,000	$	211,056,000	$	125,051,000	$	680,627,000	$	477,685,000	$	680,627,000		$	674,433,000	(3)

(1)

Giving pro forma effect to the December Notes Offering, pro forma interest expense would have increased by $4,094,000 and $3,070,000 to $25,107,000 and $18,848,000 for the year ended December 31, 2011 and the nine months ended September 30, 2012, respectively.

(2)

Giving pro forma effect to the December Notes Offering, pro forma total debt, including current maturity, and pro forma total liabilities would have each increased by $50,500,000 to $299,015,000 and $445,817,000, respectively.

(3)

In January 2013, we received a payment of $18,550,000 from Diamondback in settlement of the post-closing purchase price adjustment. This payment increases our pro forma total assets and stockholders’ equity at September 30, 2012 to $978,361,000 and $692,983,000, respectively.

Summary Operating and Reserve Data

The following tables set forth production volumes, average prices and estimates of proved reserves for the periods presented. The estimates of our net proved reserves at December 31, 2012 were prepared by Netherland, Sewell & Associates, Inc., or NSAI, with respect to our WCBB, Hackberry and Niobrara fields (52% of our proved reserves at December 31, 2012) and by Ryder Scott Company L.P., or Ryder Scott, with respect to our Utica Shale acreage (47% of our proved reserves at December 31, 2012). The estimates of our net proved reserves at December 31, 2011 were prepared by NSAI with respect to our WCBB, Hackberry and Niobrara fields (33% of our proved reserves at December 31, 2011) and by Ryder Scott with respect to our Permian Basin acreage (67% of our proved reserves at December 31, 2011). The estimates of our net proved reserves at December 31, 2010 were prepared by NSAI with respect to our WCBB and Niobrara fields (22% of our proved reserves at December 31, 2010) and by Pinnacle Energy Services, LLC, or Pinnacle, with respect to our Permian Basin acreage (65% of our proved reserves at December 31, 2010). Our own personnel prepared the estimates of our net proved reserves with respect to our overriding royalty and non-operated interests at December 31, 2012 and 2011 (less than 1% of our proved reserves at December 31, 2012 and 2011) and with respect to our Hackberry fields, overriding royalty and non-operated interests at December 31, 2010. For additional information, you should refer to the reports of NSAI and Ryder Scott attached as Appendix A and Appendix B, respectively, to this prospectus supplement and to “Risk Factors,” “Business—Proved Oil and Natural Gas Reserves,” “Business—Production, Prices, and Production Costs,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” our audited consolidated financial statements and notes thereto and our unaudited consolidated financial statements and notes thereto included in our most recent Annual Report on Form 10-K and Quarterly Reports on Form 10-Q incorporated by reference into this prospectus supplement and the accompanying prospectus.


	Year Ended December 31,
	2012			2011			2010
Production Volumes
Oil (MBbls)		2,323			2,128			1,777
Gas (MMcf)		1,108			878			788
Natural gas liquids (MGal)		2,714			2,468			2,821
Oil equivalents (Mboe)		2,573			2,333			1,976
Average Prices
Oil (per Bbl)	$	104.46	(1)	$	104.33	(1)	$	68.29	(1)
Gas (per Mcf)	$	2.91		$	4.37		$	4.40
Natural gas liquids (per Gal)	$	0.98		$	1.25		$	1.00
Oil equivalents (per Boe)	$	96.63	(1)	$	98.13	(1)	$	64.61	(1)


	At December 31,
	2012				2011				2010
	Oil (MBbls)		Natural Gas (MMcf)		Oil (MBbls)		Natural Gas (MMcf)		Oil (MBbls)		Natural Gas (MMcf)
Estimated Proved Reserves
Proved developed		5,219		18,482		7,485		6,152		7,230		6,068
Proved undeveloped		3,032		15,289		9,260		9,576		12,474		10,090

Total(2)		8,251		33,771		16,745		15,728		19,704		16,158


	At December 31,
	2012		2011		2010
Total net proved oil and natural gas reserves (Mboe)(2)		13,879		19,367		22,397
PV-10 value (in millions)(3)	$	—	$	490.5	$	392.6
Standardized measure (in millions)(4)	$	—	$	376.7	$	315.5

(1)

Includes various derivative contracts at a weighted average price of:


January—December 2012	$	108.31
January—December 2011	$	86.96
January—December 2010	$	57.55

Excluding the net effect of the fixed price swaps, the average oil price for 2011 would have been $107.13 per barrel and $100.68 per barrel of oil equivalent. The total volume hedged for 2011 represented approximately 31% of our total sales volumes for the year. Excluding the net effect of the forward sales contracts, the average oil price for 2010 would have been $78.12 per barrel and $73.45 per barrel of oil equivalent. The total volume hedged for 2010 represented approximately 45% of our total sales volumes for the year. Excluding the net effect of the fixed price swaps, the average oil price for the year ended December 31, 2012 would have been $106.11 per barrel and $98.12 per barrel of oil equivalent. The total volume hedged for the year ended December 31, 2012 represented approximately 46% of our total sales volumes for the period.

(2)

Estimates of reserves as of year-end 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2012, 2011 and 2010, respectively, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2012, 2011 and 2010. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

(3)

Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves for the years ended December 31, 2011 and 2010. This information is not currently available for the year ended December 31, 2012. The estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our reserve reports for the years ended December 31, 2011 and 2010 is priced based on the 12-month unweighted arithmetic average of the first-day-of-the month price for the period January through December of the applicable year, using $96.16 per barrel and $4.12 per million British thermal units, or MMBtu, and $76.16 per barrel and $4.38 per MMBtu, respectively, and in each case adjusted by lease for transportation fees and regional price differentials.

PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation of

Investing in our common stock involves risks. You should carefully consider the following risks and all other information contained or incorporated by reference in this prospectus supplement, including our historical financial statements and related notes, before deciding to invest in our common stock. Our business, financial condition or results of operations could be materially and adversely affected by any of these risks or by additional risks not currently known to us or that we currently deem not material. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment. Information contained in this section may be considered “forward-looking statements”. See “Cautionary Note Regarding Forward-Looking Statements” for a discussion of certain qualifications regarding such statements.

The volatility of oil and natural gas prices due to factors beyond our control greatly affects our profitability.

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, during the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to herein as West Texas Intermediate, or WTI, has ranged from a low of $30.28 per barrel, or Bbl, in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per MMBtu in September 2009 to a

high of $13.31 per MMBtu in July 2008. During 2012, West Texas Intermediate prices ranged from $80.48 to $108.99 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.80 to $3.80 per MMBtu. On December 31, 2012, the West Texas Intermediate posted price for crude oil was $91.82 per barrel and the Henry Hub spot market price of natural gas was $3.44 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development results deteriorate, full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the United States mortgage market and a weak real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

Our success depends on finding, developing or acquiring additional reserves, which requires significant capital expenditures.

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other replacement activities or use third parties to accomplish these activities. We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. Historically, we have financed capital expenditures primarily with cash flow from operations, the issuance of equity securities and borrowings under our bank and other credit facilities. Our cash flow from operations and access to capital are subject to a number of variables, including:

We may not have sufficient resources to undertake our exploration, development and production activities or the acquisition of oil and natural gas reserves, our exploratory projects or other replacement activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for additional reserves could also increase.

Our failure to successfully identify, complete and integrate future acquisitions of properties or businesses could reduce our earnings and slow our growth.

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period to period, based on whether or not significant acquisitions are completed in particular periods.

If we are unable to complete capital projects in a timely manner, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

Delays related to capital spending programs involving engineering, procurement and construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays may arise as a result of unpredictable factors, many of which are beyond our control, including:

Any one or more of these factors could have a significant impact on our ongoing capital projects.

Our Canadian oil sands projects are complex undertakings and may not be completed at our estimated cost or at all.

During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. As of December 31, 2012, Grizzly had approximately 800,000 acres under lease in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of other existing oil sands projects. Our total net investment in Grizzly was approximately $165.0 million as of September 30, 2012. As of that date, Grizzly had drilled an aggregate of 232 core holes and seven water supply test wells, tested eleven separate lease blocks and conducted a seismic program. In March 2010, Grizzly filed an application for the

development of an 11,300 barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order-in Council authorizing the ERCB to issue the formal regulatory approval of Grizzly’s Algar Lake SAGD project. During the second quarter of 2012, Grizzly finished SAGD well pair drilling at Algar Lake and began the process of completing those well pairs for SAGD injection and first production is expected mid-2013. In the first quarter of 2012, Grizzly completed the acquisition of approximately 47,000 acres through the purchase of its May River property and has prepared a full field development plan under which the May River property will be developed in multiple phases with the goal of producing 70,000 barrels per day of bitumen by the year 2020. Grizzly is currently conducting a 25 well delineation program at May River, with 14 wells completed as of February 6, 2013. Following the 2012/2013 winter exploration program, it is expected that Grizzly’s May River property will have been explored to a sufficient level to support the filing of an initial 12,000 barrel per day SAGD project regulatory application. Grizzly’s other 2012 activities included the completion of the 2011/2012 core hole drilling and seismic program, submission of a SAGD project regulatory application for the development of a 12,000 barrel per day oil sands project at Thickwood Hills and further development of its Algar Lake SAGD project, which included the fabrication and onsite construction of a central processing facility and the drilling of ten initial SAGD well pairs. The Thickwood Hills project is expected to consist of a plant site with two 6,000 barrel per day processing facilities, four SAGD well pads and up to 33 cycle steam stimulation well pads and associated facilities and infrastructure. Grizzly filed an environmental assessment for the Thickwood Hills project in November 2012 and expects to receive the applicable approvals within 12 to 18 months thereafter. Following receipt of the approvals, Grizzly anticipates the period leading to first production will be approximately 18 months. These are complex projects and additional financing may be required. There can be no assurance that such financing, if required, could be obtained on commercially reasonable terms or at all.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict our operations.

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, we rely on independent third party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

We rely on a few key employees whose absence or loss could disrupt our operations resulting in a loss of revenues.

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services, particularly the loss of Mike Liddell, our Chairman of the Board, James D. Palm, our Chief Executive Officer, Michael G. Moore, our Chief Financial Officer, or our two geophysicists could disrupt our operations resulting in a loss of revenues. Our executives are not restricted from competing with us if they cease to be employed by us, except under certain limited circumstances prohibiting competition while making use of

our trade secrets. We are party to an employment agreement with each of these executive officers. As a practical matter, however, employment agreements may not assure the retention of our employees. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.

SEC rules that went into effect for fiscal years ending on or after December 31, 2009 could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules that went into effect for fiscal years ending on or after December 31, 2009 require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe.

Estimates of oil and natural gas reserves are uncertain and may vary substantially from actual production.

There are numerous uncertainties associated with estimating quantities of proved reserves and in projecting future rates of production and timing of expenditures. The reserve information herein represents estimates prepared by NSAI with respect to our WCBB, Hackberry and Niobrara fields at December 31, 2012 and 2011 and with respect to our WCBB and Niobrara fields at December 31, 2010, by Ryder Scott at December 31, 2012 with respect to our Utica Shale acreage, by Ryder Scott at December 31, 2011, and by Pinnacle at December 31, 2010, with respect to our Permian Basin acreage (which acreage has been contributed to Diamondback as described in “Summary—Recent Developments—Contribution”) and by our personnel with respect to our overriding royalty and non-operated interests at December 31, 2012 and 2011 and with respect to our Hackberry fields, overriding royalty and non-operated interests at December 31, 2010. Petroleum engineering is not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, future site restoration and abandonment costs, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, capital expenditures and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Estimates of reserves as of year-end 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2012, 2011 and 2010, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.

The present value of future net revenues from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net revenue from our proved reserves for 2012, 2011 and 2010 on an average price equal to the unweighted arithmetic average of prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2012, 2011 and 2010, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years. However, actual future net revenues from our oil and natural gas properties also will be affected by factors such as:

The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

As of December 31, 2012, approximately 40.2% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and may require successful drilling operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but these assumptions may not be accurate, and this may not occur.

There are numerous uncertainties in estimating quantities of bitumen reserves and resources in connection with our equity investment in Grizzly and the indicated level of reserves or recovery of bitumen may not be realized.

There are numerous uncertainties in estimating quantities of bitumen reserves and resources, and the indicated level of reserves or recovery of bitumen may not be realized. In general, estimates of economically recoverable bitumen reserves and the future net cash flow from such reserves are based upon a number of factors and assumptions made as of the date on which the reserve and resource estimates were determined, such as geological and engineering estimates which have uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially.

Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history may result in variations in the estimated reserves. Reserve and resource estimates may require revision based on actual production experience. Reserve and resources estimates are determined with reference to assumed oil prices and operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen. The actual gravity or quality of bitumen to be produced from Grizzly’s lands cannot be determined at this time.

The marketability of our production is dependent upon compressors, gathering lines, transportation barges and other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas lines and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be limited or denied. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. We are at particular risk with respect to oil and natural gas produced at our WCBB

field, which is our largest producing field. In October 2006, for example, a natural gas line in this field operated by our natural gas purchaser was ruptured by a third party contractor, requiring the field to be shut in for approximately seven weeks until the line could be repaired. Further, we are dependent on our oil purchaser to provide the barges necessary to transport our oil production from the WCBB field. In addition, we currently intend to focus a significant portion of our future exploration and development activity on our Utica Shale acreage. Historically, there has been no or only limited infrastructure in this area and the commencement of production from our initial wells on our Utica Shale acreage has been delayed due to challenges in obtaining rights-of-ways and acquiring necessary state and federal permitting. If we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter compression or other production related difficulties, we will be required to shut in or curtail production from the impacted field(s). Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations.

A substantial portion of our producing properties is located in Louisiana, making us vulnerable to risks associated with operating in this region.

Our largest field by production, WCBB, is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from this region caused by weather conditions such as fog or rain, hurricanes or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates we consider reasonable or that any particular types of coverage will be available.

Our identified drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

We have identified over 600 drilling locations on our Louisiana, Ohio and Western Colorado properties. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, oil and natural gas prices, inclement weather, costs, drilling results and regulatory changes. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect our business, financial condition or results of operations.

Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

Operating hazards and uninsured risks may result in substantial losses and could prevent us from realizing profits.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and repairs to resume operations.

In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we understand that insurance carriers are modifying or otherwise restricting insurance coverage or ceasing to provide certain types of insurance coverage in the Gulf Coast region. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest.

Prior to the drilling of an oil or gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact

our ability in the future to increase production and reserves. Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We acquire significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices for oil and natural gas, expected costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. Drilling results in our newer oil and liquids-rich shale plays may be more uncertain than in shale plays that are more developed and have longer established production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries will be ultimately successful when used in newly developed shale formations.

Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; therefore, the results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks and drilling results may not meet our expectations for reserves or production.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and consequently we are less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or natural gas and oil prices decline, the return on our investment in

these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and gas properties and the value of our undeveloped acreage could decline in the future.

We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.

We are not the operator of all of the properties in which we have an interest, and have limited ability to exercise influence over the operations of such non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others will depend upon a number of factors that will be largely outside of our control, including:

In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

Our undeveloped acreage in the Niobrara Formation must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. As of December 31, 2012, leases representing 45%, 17%, 2%, 12% and 24%, respectively, of our total Niobrara undeveloped acreage are scheduled to expire in 2013, 2014, 2015, 2016 and thereafter. None of our Utica acreage leases are scheduled to expire until 2015, at which time 36% of our total Utica undeveloped acreage as of December 31, 2012 will be subject to expiration, with 64% of such acreage expiring thereafter, although our Utica leases generally grant us the right to extend these leases for an additional five-year period. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire or obtain protection from sellers against such liabilities.

Acquiring oil and gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such

assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Our operations are subject to various governmental regulations which require compliance that can be burdensome and expensive.

Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations have continually imposed increasingly strict requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. See “Business—Regulation—Environmental Matters and Regulation” and “Business—Regulation—Other Regulation of the Oil and Natural Gas Industry” included in our most recent Annual Report on Form 10-K incorporated by reference herein for a description of the laws and regulations that affect us.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions. The Environmental Protection Agency, or EPA, however, has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.

Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act.

On April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule includes a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts, the results of which are expected between later in 2012 and 2014. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates.

Some states in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, in January 2012, the Ohio Department of Natural Resources issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio, to study the relationship between these wells and minor earthquakes reported in the area. The Texas Railroad Commission and Louisiana Department of Natural Resources recently adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to the requirements of federal Occupational Safety and Health Act (OSHA) to state regulators and on a public internet website. Effective August 26, 2011, Montana adopted hydraulic fracturing disclosure regulations under which well operators must provide information in drilling permit applications on the estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon completion of the well, well operators must provide the Montana Board of Oil and Gas Conservation with the volume and type of chemicals used, including the additive type, chemical ingredient names, and Chemical Abstracts Service, or CAS, number, subject to certain trade secret protections. On April 1, 2012, the North Dakota Industrial Commission enacted regulations requiring hydraulic fracturing well operators to disclose the hydraulic fluid composition, including the trade name, supplier, ingredients, CAS Number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. Colorado enacted rules requiring similar disclosures on January 30, 2012. Also, on May 4, 2012, the U.S. Department of Interior, or DOI, issued a draft rule that seeks to require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing

process; (ii) confirm its wells meet certain construction standards and (iii) establish site plans to manage flowback water. We plan to use hydraulic fracturing in connection with the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or offshore drilling, including legislation and regulation in the states in which we operate, could reduce the volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.

There has been increasing public controversy regarding hydraulic fracturing with regard to use of fracturing fluids, impacts on drinking water supplies, use of waters and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws. In this regard, in November 2012, we and other entities involved in our WCBB field operations received a government subpoena, to which we responded, for the production of documents and other information related primarily to a discharge of produced water that allegedly was identified

by the U.S. Coast Guard in March 2012. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves

The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress recently adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The legislation was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission, or CFTC, and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In its rulemaking under the new legislation, the CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. Although the CFTC has promulgated numerous final rules based on its proposals, it is not possible at this time to predict when the CFTC will finalize its proposed regulations or the effect of such regulations on our business. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators

attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President’s Fiscal Year 2013 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development, (iii) the repeal of the percentage depletion allowance for oil and gas properties, (iv) an extension of the amortization period for certain geological and geophysical expenditures and (iv) implementing certain international tax reforms. These proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial condition, results of operations and cash flows.

The adoption of climate change legislation by Congress could result in increased operating costs and reduced demand for the oil and natural gas we produce.

Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA, that the EPA has the authority to regulate carbon dioxide emissions from automobiles as “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an Endangerment Finding that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule, which purports to limit emissions of GHGs from motor vehicles manufactured in model years 2012-2016, in April 2010 and it became effective January 2011, although it does not require immediate reductions in GHG emissions. A recent rulemaking proposal by the EPA and the Department of Transportation’s National Highway Traffic Safety Administration seeks to expand the motor vehicle rule to include vehicles manufactured in model years 2017-2025. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective January 2011, although it remains subject of several pending lawsuits filed by industry groups. The Tailoring Rule establishes new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the Tailoring Rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the Tailoring Rule, which became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions by more than

75,000 tons per year. Phase III of the Tailoring Rule, which is expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process. Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. The proposed rule underwent an extended public comment process, which concluded on June 25, 2012. The EPA is also under a legal obligation pursuant to a consent decree with certain environmental groups to issue new source performance standards for refineries. The EPA has also adopted regulations imposing best available control technology requirements on the largest greenhouse gas stationary sources, regulations requiring reporting of greenhouse gas emissions from certain facilities, and it is considering additional regulation of greenhouse gases as “air pollutants.” As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938, or the NGA, exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission, or FERC. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from FERC’s jurisdiction under the NGA. However, the distinction

between FERC-regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. In addition, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of government regulation.

We depend upon a limited number of customers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil and natural gas we produce.

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate commerce. The oil and natural gas we produce in Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB is being sold in accordance with the Shell posted price for West Texas/New Mexico Intermediate crude plus or minus Platt’s trade month average P+ value, plus or minus the Platt’s HLS/WTI differential less $2.70 per barrel for transportation. During 2012, we sold 92% and 8% of our oil production to Shell and DiamondbackO&G, respectively, and 41%, 18% and 16% of our natural gas production to Noble Americas Gas, Hess and Chevron, respectively. During 2011, we sold 93% and 7% of our oil production to Shell and Diamondback O&G, respectively, and 22%, 27% and 50% of our natural gas production to Diamondback O&G, Chevron and Hilcorp Energy Company, respectively. During 2010, we sold 75% and 19% of our oil production to Shell and Diamondback O&G, respectively, and 50%, 32% and 10% of our natural gas production to Diamondback O&G, Chevron and Hilcorp Energy Company, respectively. Shell has agreed to purchase our Utica oil, and we have agreements in place with various purchasers for our Utica natural gas production. We may not continue to have ready access to suitable markets for our future oil and natural gas production.

Our method of accounting for oil and natural gas properties may result in impairment of asset value.

We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural gas reserves and the cost of the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil.

Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for 2012, 2011 and 2010, adjusted for any contract provisions or financial derivatives, if any, that hedge oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash writedown is required. A ceiling test impairment can give us a significant loss for a particular period. Once incurred, a write down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. If prices of oil, natural gas and natural gas liquids decrease, we may be required to further write down the value of our oil and gas properties. Future non-cash asset impairments could negatively affect our results of operations.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

We have entered into forward sales contracts and fixed price swaps and may in the future enter into additional contracts for a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas.

To mitigate the effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 through February 2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through July 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from August 2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average price of $107.29 per barrel. For the period from January 2013 through December 2013, we entered into fixed price swaps for 5,000 barrels of oil per day at a weighted average price of $100.90 per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. Under the 2012 contracts, we hedged approximately 46% of our 2012 production. Under the 2013 contracts, we have hedged approximately 23% to 24% of our estimated 2013 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contracts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “Derivatives and Hedging,” and related pronouncements.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Loss of our information and computer systems could adversely affect our business.

We are dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

Our substantial level of indebtedness could adversely affect our business, financial condition, results of operations and prospects.

As of December 31, 2012, we had total indebtedness (net of associated accrued discount and premium) of approximately $300.0 million, including $296.9 million attributable to the Notes, and borrowing base availability of $40.0 million under our secured revolving credit facility, under which no borrowings are outstanding.

Our outstanding indebtedness could have important consequences to you, including the following:

Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations and prospects.

In addition, if we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, or interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest. More specifically, the lenders under our secured revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or litigation.

We may not have sufficient funds to repay borrowings under our revolving credit facility if required as a result of a borrowing base redetermination.

In connection with the Contribution and the Notes Offerings, our borrowing base under our senior secured revolving credit facility was reduced to $40.0 million. The borrowing base is expected to be redetermined by the lenders on a semiannual basis. Additionally, the required lenders will be able to request one additional borrowing base redetermination in between scheduled redeterminations, and also have the right to redetermine the borrowing base upon the amendment, modification or termination of any swap contract or forward sales contract. In addition, our borrowing base will be reduced in connection with certain asset dispositions.

We repaid all borrowings outstanding under our secured revolving credit facility (approximately $141.0 million) with a portion of the proceeds from the October Notes Offering. We currently have no borrowings outstanding under our revolving credit facility, although we intend to reborrow under this facility in the future. If the outstanding borrowings under our secured revolving credit facility were to exceed the borrowing base as a result of any such recalculation, we would be required to eliminate this excess. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.

Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. Our business may not continue to generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash

flow, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional equity capital on terms that may be onerous or highly dilutive. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our secured revolving credit facility and the indenture governing the notes restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.

Despite our current leverage, we may still be able to incur substantially more indebtedness. This could further exacerbate the risks that we and our subsidiaries face.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, either under our senior secured credit facility or otherwise. The terms of our secured revolving credit facility and the indenture governing the Notes restrict our ability to incur additional indebtedness, but in each case do not completely prohibit us from doing so. In addition, the indenture governing the Notes allows us to issue additional notes under certain circumstances which will also be guaranteed by the guarantors. The indenture governing the Notes allows us to incur certain other additional secured debt and will allow our subsidiaries that do not guarantee the Notes to incur additional debt. In addition, the indenture governing the Notes does not prevent us from incurring other liabilities that do not constitute indebtedness. If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

Restrictive covenants in our secured revolving credit facility, in the indenture governing the notes and in future debt instruments may restrict our ability to pursue our business strategies.

Our secured revolving credit facility and the senior note indenture limit, and the terms of any future indebtedness may limit, our ability, among other things, to:

The restrictions contained in these agreements could limit our ability to plan for, or react to, market conditions, meet capital needs, make acquisitions or otherwise restrict our activities or business plans.

A breach of any of these restrictive covenants could result in default under the agreement governing our senior secured revolving credit facility. If default occurs, the lenders under our senior secured revolving credit facility may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be

immediately due and payable, which would result in an event of default under the senior note indenture. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay outstanding borrowings when due, the lenders under our senior secured revolving credit facility will also have the right to proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under our senior secured revolving credit facility and the notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.

If our quarterly revenues and operating results fluctuate significantly, the price of our common stock may be volatile.

Our revenues and operating results may in the future vary significantly from quarter to quarter. If our quarterly results fluctuate, it may cause our stock price to be volatile. We believe that a number of factors could cause these fluctuations, including:

Because of the factors listed above, among others, we believe that our quarterly revenues, expenses and operating results may vary significantly in the future and that period-to-period comparisons of our operating results are not necessarily meaningful. You should not rely on the results of one quarter as an indication of our future performance. It is also possible that in some future quarters, our operating results will fall below our expectations or the expectations of market analysts and investors. If we do not meet these expectations, the price of our common stock may decline significantly.

We do not currently pay dividends on our common stock and do not anticipate doing so in the future.

We have paid no cash dividends on our common stock, and we may not pay cash dividends on our common stock in the future. We intend to retain any earnings to fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, the terms of our credit agreement prohibit the payment of any dividends to the holders of our common stock.

As of December 31, 2011, we had a net operating loss, or NOL, carry forward of approximately $116.8 million for federal income tax purposes. Transfers of our stock in the future could result in an ownership change. In such a case, our ability to use the NOLs generated through the ownership change date could be limited. In general, the amount of NOLs we could use for any tax year after the date of the ownership change would be limited to the value of our stock (as of the ownership change date) multiplied by the long-term tax-exempt rate.

This offering and future sales of our common stock may depress our stock price.

We have registered a substantial number of shares of our common stock under a registration statement filed with the SEC. Sales of these shares of our common stock in the public market, including the shares sold in this offering, or the perception that these sales may occur, could cause the market price of our common stock to

decline. In addition, sales by certain of our stockholders of their shares could impair our ability to raise capital through the sale of common or preferred stock. As of February 8, 2013, there were 68,427,386 shares of our common stock issued and outstanding, excluding 245,831 shares of unvested restricted stock awarded under our Amended and Restated 2005 Stock Incentive Plan and 335,241 shares issuable upon exercise of outstanding options to purchase our common stock granted under our Amended and Restated 2005 Stock Incentive Plan.

We could issue preferred stock which could be entitled to dividend, liquidation and other special rights and preferences not shared by holders of our common stock or which could have anti-takeover effects.

We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of preferred stock may be issued from time to time in one or more series as our board of directors, by resolution or resolutions, may from time to time determine each such series to be distinctively designated. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions, if any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations of our certificate of incorporation and the Delaware General Corporation Law, or DGCL, our board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and qualifications, limitations and restrictions thereof, of each such series preferred stock. The issuance of any such preferred stock could materially adversely affect the rights of holders of our common stock and, therefore, could reduce the value of our common stock.

In addition, specific rights granted to future holders of preferred stock could be used to restrict our ability to merge with, or sell our assets to, a third party. The ability of our board of directors to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving control of the company by the current stockholders.

The existence of some provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult. See “Description of Our Capital Stock—Anti-takeover Effects of Provisions of Our Certificate of Incorporation and Our Bylaws” contained in the accompanying prospectus.

We estimate that our net proceeds from the sale of 7,750,000 shares of our common stock in this offering will be approximately $282.3 million, after deducting the underwriting discounts and commissions and estimated offering expenses, or approximately $324.7 million if the underwriters exercise the over-allotment option granted by us in full. We intend to use our net proceeds from this offering to fund the pending acquisition of additional acreage in the Utica Shale and for general corporate purposes, including the funding of a portion of our 2013 capital development plan.

The following table sets forth our unaudited cash and cash equivalents and capitalization as of September 30, 2012, on:

You should read this table in conjunction with the information contained in “Use of Proceeds,” and the information contained in our audited consolidated financial statements and notes thereto, our unaudited consolidated financial statements and notes thereto and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2011 and our Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, which are incorporated by reference herein.

Our common stock is listed and traded on The NASDAQ Global Select Market under the symbol “GPOR.” The following table includes the high and low sales prices for our common stock as reported on The NASDAQ Global Select Market for the periods presented.

The closing price of our common stock on The NASDAQ Global Select Market on February 11, 2013 was $38.68 per share.

The following is a general discussion of material U.S. federal income and estate tax consequences of the ownership and disposition of our common stock by a non-U.S. holder. This discussion deals only with common stock purchased in this offering that is held as a capital asset by a non-U.S. holder. Except as modified for estate tax purposes, the term “non-U.S. holder” means a beneficial owner of our common stock that is not, for U.S. federal income and estate tax purposes:

An individual may generally be treated as a resident of the United States in any calendar year for U.S. federal income tax purposes, by, among other ways, being present in the United States for at least 31 days in that calendar year and for an aggregate of at least 183 days during a three-year period ending in the current calendar year. For purposes of the 183-day calculation, all of the days present in the current year, one-third of the days present in the immediately preceding year and one-sixth of the days present in the second preceding year are counted. Residents are taxed for U.S. federal income tax purposes as if they were U.S. citizens.

This discussion is based upon provisions of the Code, and U.S. Treasury Regulations, administrative rulings and judicial decisions, all as of the date hereof. Those authorities may be changed, perhaps retroactively, so as to result in U.S. federal income and estate tax consequences different from those discussed below. This discussion does not address all aspects of U.S. federal income and estate taxation and does not deal with other U.S. federal tax laws (such as gift tax laws) or foreign, state, local or other tax considerations that may be relevant to non-U.S. holders in light of their personal circumstances. In addition, this discussion does not address tax considerations applicable to investors that may be subject to special treatment under the U.S. federal income tax laws, such as (without limitation):

If a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner generally will depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership (including an entity treated as a partnership for U.S. federal income tax purposes) holding our common stock, you should consult your tax advisor.

Investors considering the purchase of our common stock should consult their own tax advisors regarding the application of the U.S. federal income and estate and gift tax laws to their particular situation as well as the applicability and effect of any state, local or foreign tax laws or tax treaties.

We do not expect to pay any cash distributions on our common stock in the foreseeable future. However, in the event we do make such cash distributions, these distributions generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. If any such distribution exceeds our current and accumulated earnings and profits, the excess will be treated as a non-taxable return of capital to the extent of the non-U.S. holder’s tax basis in our common stock and thereafter as capital gain from the sale or exchange of such common stock. See “Gain on Disposition of Common Stock.” Dividends paid to a non-U.S. holder of our common stock that are not effectively connected with the non-U.S. holder’s conduct of a trade or business within the United States will be subject to U.S. withholding tax at a 30% rate, or if an income tax treaty applies, a lower rate specified by the treaty. In order to receive a reduced treaty rate, a non-U.S. holder must provide to the withholding agent Internal Revenue Service, or IRS, Form W-8BEN (or applicable substitute or successor form) properly certifying eligibility for the reduced rate.

Dividends that are effectively connected with a non-U.S. holder’s conduct of a trade or business in the United States and, if an income tax treaty so requires, are attributable to a permanent establishment maintained by the non-U.S. holder in the United States, are taxed on a net income basis at the regular graduated rates and in the manner applicable to United States persons (as defined under the Code). In that case, we will not have to withhold U.S. federal withholding tax if the non-U.S. holder complies with applicable certification and disclosure requirements (which may generally be met by providing an IRS Form W-8ECI). In addition, a “branch profits tax” may be imposed at a 30% rate (or a lower rate specified under an applicable income tax treaty) on dividends received by a foreign corporation that are effectively connected with its conduct of a trade or business in the United States.

A non-U.S. holder generally will not be subject to U.S. federal income tax on gain recognized on a disposition of our common stock unless:

Generally, a corporation is a USRPHC if the fair market value of its United States real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We have not determined whether we are currently a USRPHC for United States federal income tax purposes, but we believe we currently may be a USRPHC. If we are or become a USRPHC, a non-U.S holder nonetheless will not be subject to U.S. federal income tax or withholding in respect of any gain realized on a sale or other disposition of our common stock so long as (i) our common stock continues to be “regularly traded on an established securities market” for U.S. federal income tax purposes (as it currently is) and (ii) such non-U.S. holder does not actually or constructively own, at any time during the applicable period described in the third bullet point, above, more than 5% of our outstanding common stock. Accordingly, a non-U.S holder who actually or constructively owns more than 5% of our common stock would be subject to U.S. federal income tax and withholding in respect of any gain realized on any sale or other disposition of common stock (taxed in the same manner as gain that is effectively connected income, except that the branch profits tax would not apply). Non-U.S. holders should consult their own advisor about the consequences that could result if we are, or become, a USRPHC.

Dividends paid to you will generally be subject to information reporting and may be subject to U.S. backup withholding. You will be exempt from backup withholding if you properly provide a Form W-8BEN certifying under penalties of perjury that you are a non-U.S. holder or otherwise meet documentary evidence requirements for establishing that you are a non-U.S. holder, or you otherwise establish an exemption. Copies of the information returns reporting such dividends and the tax withheld with respect to such dividends also may be made available to the tax authorities in the country in which you reside.

The gross proceeds from the disposition of our common stock may be subject to information reporting and backup withholding. If you receive payments of the proceeds of a disposition of our common stock to or through a U.S. office of a broker, the payment will be subject to both U.S. backup withholding and information reporting unless you properly provide an IRS Form W-8BEN certifying under penalties of perjury that you are a non-U.S. person (and the payor does not have actual knowledge or reason to know that you are a United States person, as defined under the Code) or you otherwise establish an exemption. If you sell your common stock outside the United States through a non-U.S. office of a non-U.S. broker and the sales proceeds are paid to you outside the United States, then the U.S. backup withholding and information reporting requirements generally will not apply to that payment. However, U.S. information reporting, but not backup withholding, will generally apply to a payment of sales proceeds, even if that payment is made outside the United States, if you sell your common stock through a non-U.S. office of a broker that has certain relationships with the United States unless the broker has documentary evidence in its files that you are a non-U.S. person and certain other conditions are met, or you otherwise establish an exemption.

Backup withholding is not an additional tax. You may obtain a refund or credit of any amounts withheld under the backup withholding rules that exceed your U.S. federal income tax liability, if any, provided the required information is timely furnished to the IRS.

Sections 1471 through 1474 of the Code (provisions which are commonly referred to as “FATCA”) and the regulations and administrative guidance thereunder may require withholding at a rate of 30% of dividends paid on or after January 1, 2014 and the gross proceeds from the sale of our common stock paid on or after January 1, 2017 to (i) a foreign financial institution (whether such foreign financial institution is the beneficial owner or an

intermediary) unless such institution agrees to report and disclose, on an annual basis, information with respect to its U.S. account holders and meets certain other specified requirements or (ii) a non-financial foreign entity (whether such non-financial foreign entity is the beneficial owner or an intermediary) unless such entity certifies that it does not have any “substantial United States owners” or provides the name, address, and taxpayer identification number regarding the entity’s “substantial United States owners” and such entity meets certain other specified requirements. Accordingly, the entity through which our common stock is held will affect the determination of whether such withholding is required. You should consult your own tax advisors regarding this legislation and whether it may be relevant to your purchase, ownership, and disposition of our common stock.

Our common stock that is owned (or treated as owned) by an individual who is not a citizen or resident of the United States (as specially defined for United States federal estate tax purposes) at the time of death will be included in such individual’s gross estate for United States federal estate tax purposes, unless an applicable tax treaty provides otherwise, and, therefore, may be subject to United States federal estate tax.

THE FOREGOING DISCUSSION IS FOR GENERAL INFORMATION ONLY AND SHOULD NOT BE VIEWED AS TAX ADVICE. INVESTORS CONSIDERING THE PURCHASE OF OUR COMMON STOCK SHOULD CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME AND ESTATE AND GIFT TAX LAWS TO THEIR PARTICULAR SITUATION AS WELL AS THE APPLICABILITY AND EFFECT OF ANY STATE, LOCAL OR FOREIGN TAX LAWS OR TAX TREATIES.

Under the terms and subject to the conditions contained in an underwriting agreement dated February 11, 2013, we have agreed to sell to the underwriters named below, for whom Credit Suisse Securities (USA) LLC is acting as representative, the following respective numbers of shares of common stock:

The underwriting agreement provides that the underwriters are obligated to purchase all the shares of common stock in the offering if any are purchased, other than those shares covered by the over-allotment option described below.

We have granted to the underwriters a 30-day option to purchase on a pro rata basis up to 1,162,500 additional shares at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common stock.

The underwriters propose to offer the shares of common stock initially at the public offering price on the cover page of this prospectus supplement and to selling group members at that price less a selling concession of $0.8664 per share. After the initial public offering, the underwriters may change the public offering price and concession and discount to broker/dealers.

The following table summarizes the compensation and estimated expenses we will pay:

We estimate that our out of pocket expenses for this offering will be approximately $989,000.

We have agreed that, subject to certain exceptions, we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the Securities and Exchange Commission a registration statement under the Securities Act relating to, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse Securities (USA) LLC

for a period of 90 days after the date of this prospectus supplement. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse Securities (USA) LLC waives, in writing, such an extension. The foregoing sentence will not apply if, as of the expiration of the “lock-up” period, shares of our common stock are “actively-traded securities,” as defined in Regulation M.

Our officers and directors have agreed that, subject to certain exceptions, including, among others, the right of one of our officers to sell up to 100,000 shares of common stock, they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any of these transactions are to be settled by delivery of our common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse Securities (USA) LLC for a period of 90 days after the date of this prospectus supplement. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse Securities (USA) LLC waives, in writing, such an extension. The foregoing sentence will not apply if, as of the expiration of the “lock-up” period, shares of our common stock are “actively-traded securities,” as defined in Regulation M.

Credit Suisse Securities (USA) LLC, in its sole discretion, may release the common stock and other securities subject to the lock-up agreements described above in whole or in part at any time. When determining whether or not to release the common stock and other securities from lock-up agreements, Credit Suisse Securities (USA) LLC will consider, among other factors, our or the holder’s reasons for requesting the release and the number of shares of common stock or other securities for which the release is being requested.

We have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.

Our common stock is listed on The NASDAQ Global Select Market under the symbol “GPOR.”

In connection with the offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934, or the Exchange Act.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of our common stock. As a result the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on The NASDAQ Global Select Market or otherwise and, if commenced, may be discontinued at any time.

A prospectus in electronic format may be made available on the web sites maintained by the underwriters, or selling group members, if any, participating in this offering and the underwriters may distribute prospectuses electronically. The underwriters may agree to allocate a number of shares to selling group members for sale to their online brokerage account holders. Internet distributions will be allocated to selling group members that will make internet distributions on the same basis as other allocations.

Certain of the underwriters and their affiliates have performed investment and commercial banking and advisory services for us and our affiliates from time to time for which they have received customary fees and expenses. In particular, an affiliate of Credit Suisse Securities (USA) LLC acts as a lender under our senior secured credit facility, and Credit Suisse Securities (USA) LLC acted as an underwriter for the Diamondback IPO and the Equity Offering and an initial purchaser in the Notes Offerings. Additionally, Scotia Capital (USA) Inc., Capital One Southcoast, Inc., Johnson Rice & Company L.L.C., KeyBanc Capital Markets Inc., SunTrust Robinson Humphry, Inc., Wunderlich Securities, Inc., Sterne, Agee & Leach, Inc., RBC Capital Markets, LLC, Simmons & Company International and IBERIA Capital Partners L.L.C. each acted as an initial purchaser in one or both of our Notes Offerings and each of the underwriters acted as an underwriter in our Equity Offering. An affiliate of Scotia Capital (USA) Inc. acts as administrative agent, letter of credit issuer and sole lead manager and affiliates of each of Credit Suisse Securities (USA) LLC, IBERIA Capital Partners L.L.C. and KeyBanc Capital Markets Inc. are lenders under our senior secured credit facility. Capital One Southcoast Inc., Simmons & Company International, Sterne, Agee & Leach, Inc., SunTrust Robinson Humphrey, Inc., Wunderlich Securities, Inc. and an affiliate of Scotia Capital (USA) Inc. acted as underwriters in the Diamondback IPO. The underwriters and their affiliates may, from time to time, engage in transactions with and perform services for us in the ordinary course of their business. In the ordinary course of their various business activities, the underwriters and their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers and such investment and securities activities may involve our securities and/or instruments. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

The SEC allows us to “incorporate by reference” into this prospectus the information we provide in other documents filed by us with the SEC. The information incorporated by reference is an important part of this prospectus supplement. Any statement contained in a document that is incorporated by reference in this prospectus supplement is automatically updated and superseded if information contained in this prospectus supplement, or information that we later file with the SEC, modifies and replaces this information. We incorporate by reference the following documents that we have filed with the SEC:

In addition, all documents filed by us with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act (other than those furnished pursuant to Item 2.02 or Item 7.01 of Form 8-K, unless otherwise stated therein) after the date of this prospectus supplement and prior to the filing of a post-effective amendment that indicates that all securities offered hereby have been sold or that deregisters all securities remaining unsold, will be considered to be incorporated by reference into this prospectus supplement and to be a part of this prospectus supplement from the dates of the filing of such documents. Pursuant to General Instruction B of Form 8-K, any information submitted under Item 2.02, Results of Operations and Financial Condition, or Item 7.01, Regulation FD Disclosure, of Form 8-K is not deemed to be “filed” for the purpose of Section 18 of the Exchange Act, and we are not subject to the liabilities of Section 18 of the Exchange Act with respect to information submitted under Item 2.02 or Item 7.01 of Form 8-K. We are not incorporating by reference any information submitted under Item 2.02 or Item 7.01 of Form 8-K into any filing under the Securities Act or the Exchange Act or into this prospectus supplement, unless otherwise indicated on such Form 8-K.

You may get copies of this prospectus supplement or any of the incorporated documents (excluding exhibits, unless the exhibits are specifically incorporated) at no charge to you by writing to Gulfport Energy Corporation, Attention: Investor Relations, at 14313 North May Avenue, Suite 100, Oklahoma City, Oklahoma 73134, or calling (405) 242-4888.

Certain legal matters will be passed upon for the Company by Akin, Gump, Strauss, Hauer & Feld, L.L.P. The underwriters have been represented in connection with this offering by Cravath, Swaine & Moore LLP.

The audited consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting incorporated by reference in this prospectus supplement and elsewhere in the registration statement have been so incorporated by reference in reliance upon the reports of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing in giving said reports.

Information incorporated by reference into this prospectus supplement regarding estimates of our proved oil and natural gas reserves and the discounted present value of estimated future net revenue before income tax of our estimated proved reserves is based on reports included in our Annual Report on Form 10-K for the year ended December 31, 2011 and incorporated herein by reference, prepared by Netherland, Sewell & Associates, Inc., or NSAI, with respect to our WCBB, Hackberry and Niobrara fields at December 31, 2011 and 2010, and by Ryder Scott Company L.P., or Ryder Scott, with respect to the assets in the Permian Basin in West Texas at December 31, 2011 covered by such report. Information contained in this prospectus supplement regarding estimates of our proved reserves and the discounted present value of estimated future net revenue before income tax of our estimated proved reserves at December 31, 2012 is based on reports prepared by NSAI with respect to our WCBB, Hackberry and Niobrara fields and by Ryder Scott with respect to our Utica Shale acreage, which reports are attached to this prospectus supplement as Appendix A and Appendix B, respectively. All of such information has been so included herein in reliance upon the authority of such firms as experts in such matters.

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2012, to the Gulfport Energy Corporation (Gulfport) interest in certain oil and gas properties located in Colorado and Louisiana. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately 52 percent of all proved reserves owned by Gulfport. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Gulfport’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

We estimate the net reserves and future net revenue to the Gulfport interest in these properties, as of December 31, 2012, to be:

The oil reserves shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves. As requested, probable reserves that exist for these properties have not been included. No study was made to determine whether possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves

categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Gross revenue is Gulfport’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Gulfport’s share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2012. For oil volumes, the average Shell Trading (US) Company West Texas/New Mexico Intermediate posted price of $91.32 per barrel is adjusted by field for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $2.757 per MMBTU is adjusted by field for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $108.46 per barrel of oil and $2.872 per MCF of gas.

Operating costs used in this report are based on operating expense records of Gulfport, the operator of the properties, and include only direct lease- and field-level costs. As requested, these costs do not include the per-well overhead expenses allowed under joint operating agreements, nor do they include the headquarters general and administrative overhead expenses of Gulfport. Operating costs are held constant throughout the lives of the properties.

Capital costs used in this report were provided by Gulfport and are based on actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of Gulfport’s future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Abandonment costs used in this report are Gulfport’s estimates of the costs to abandon the wells and production facilities, net of any salvage value. Capital costs and abandonment costs are held constant to the date of expenditure.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Gulfport interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Gulfport receiving its net revenue interest share of estimated future gross gas production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the

reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A substantial portion of these reserves are for behind-pipe zones, non-producing zones, and undeveloped locations; such reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Gulfport, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects—such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations—by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

•

The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

•

The company’s historical record at completing development of comparable long-term projects;

•

The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

•

The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

•

The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Gulfport Energy Corporation (Gulfport) as of December 31, 2012. The subject properties are located in the state of Ohio. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 11, 2013, and presented herein, was prepared for public disclosure by Gulfport in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of Gulfport in the Ohio Utica Shale as of December 31, 2012.

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (Mbbl). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the state of Ohio. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$).

The estimated reserves and future net income amounts presented in this report, as of December 31, 2012, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report.

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software package Aries^TM System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used solely at the request of Gulfport. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, and development costs. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 60.9 percent and gas reserves account for the remaining 39.1 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Gulfport’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.”

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Gulfport’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Gulfport owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

Production information for the Utica Shale is very limited. Gulfport currently has 2 wells on production for which performance methods were used. Gulfport has interests in an additional 16 wells which have been drilled and are awaiting a pipeline connection. Of these 16 wells, 8 have been tested. Proved reserves were assigned to only those wells with test information, and assignments were limited to no more than 1 year at the peak production test rates.

All of the proved undeveloped reserves included herein were estimated by the analogy method. The data utilized from the analogues were considered sufficient for the purpose thereof.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Gulfport has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Gulfport with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, and development costs, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Gulfport. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Gulfport. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Gulfport furnished us with the above mentioned average prices in effect on December 31, 2012. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Gulfport. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Gulfport to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Operating costs for the leases and wells in this report are based on the operating expense reports of Gulfport and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by Gulfport. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Gulfport and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. Gulfport’s estimates of zero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott has not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Gulfport’s estimate.

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Gulfport’s plans to develop these reserves as of December 31, 2012. The implementation of Gulfport’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Gulfport’s management. As the result of our inquiries during the course of preparing this report, Gulfport has informed us that the development activities included herein have been subjected to and received the internal approvals required by Gulfport’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Gulfport. Additionally, Gulfport has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Gulfport were held constant throughout the life of the properties.

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or

a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to Gulfport. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Gulfport.

We have provided Gulfport with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Gulfport and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of the reserves, future production and income presented herein.

Mr. Griffin, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Griffin served in a number of engineering positions with Amoco Production Company. For more information regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott Company website at http://www.ryderscott.com/Experience/Employees.php.

Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 1975 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Griffin fulfills. Mr. Griffin attended an additional 15 hours of training during 2012 covering such topics as reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants.

Based on his educational background, professional training and more than 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher

portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

By this prospectus, we or selling security holders may offer and sell, from time to time in one or more offerings, our common stock and debt securities. We refer to our common stock and debt securities collectively as the “securities.”

This prospectus provides you with a general description of the securities and the general manner in which we or selling security holders will offer the securities. Each time we or selling security holders sell securities, we will provide a supplement to this prospectus that contains specific information about the offering. The supplement may also add, update or change information contained in this prospectus. You should carefully read this prospectus, all prospectus supplements and all other documents incorporated by reference in this prospectus before you invest in our securities.

Investing in our securities involves risks. See “Risk Factors” beginning on page 1.

Our common stock is listed on The NASDAQ Global Select Market under the symbol “GPOR.”

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

This prospectus is part of a “shelf” registration statement that we filed with the Securities and Exchange Commission, or SEC. Under this registration statement, we or selling security holders may sell any combination of the securities described in this prospectus from time to time in one or more offerings. This prospectus provides you with a general description of the securities we or selling security holders may offer. This prospectus does not contain all the information set forth in the registration statement as permitted by the rules of the SEC. Each time we or selling security holders sell securities, we will provide a supplement to this prospectus that will contain specific information about the terms of that offering. That prospectus supplement may also add, update or change information contained in this prospectus. Before purchasing any securities, you should carefully read both this prospectus and any applicable prospectus supplement, together with the additional information described in this prospectus under the headings “Where You Can Find More Information” and “Information Incorporated by Reference.”

You should rely only on the information contained in this prospectus and in any applicable prospectus supplement, including any information incorporated by reference. We have not authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. You should not assume that the information appearing in this prospectus, any prospectus supplement or any document incorporated by reference is accurate at any date other than as of the date of each such document. Our business, financial condition, results of operations and prospects may have changed since the date indicated on the cover page of such documents.

The distribution of this prospectus may be restricted by law in certain jurisdictions. You should inform yourself about and observe any of these restrictions. This prospectus does not constitute, and may not be used in connection with, an offer or solicitation by anyone in any jurisdiction in which the offer or solicitation is not authorized, or in which the person making the offer or solicitation is not qualified to do so, or to any person to whom it is unlawful to make the offer or solicitation.

When used in this prospectus or in any supplement to this prospectus, the terms “Gulfport,” the “Company,” “we,” “our” and “us” refer to Gulfport Energy Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires.

This prospectus and the documents incorporated by reference in this prospectus include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,” “should,” “could,” would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward-looking statements. All statements, other than statements of historical facts, included in this prospectus and the documents incorporated by reference in this prospectus that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, 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 us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate in the circumstances. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties, including those in any prospectus supplement and those discussed in the documents we have incorporated by reference. Consequently, all of the forward-looking statements made in this prospectus, and the documents incorporated by reference in this prospectus, are qualified by these cautionary statements and we cannot assure you that the actual results or developments anticipated by us will be realized or, even if realized, that they will have the expected consequences to or effects on us, our 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.

We are an independent oil and natural gas exploration and production company with our principal producing properties located along the Louisiana Gulf Coast in the West Cote Blanche Bay and Hackberry fields, and in West Texas in the Permian Basin. In 2010, we acquired an acreage position in the Niobrara Formation of Western Colorado. In May 2011, we also acquired certain leases in the Utica Shale in Ohio. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek to achieve reserve growth and increase our cash flow through our annual drilling programs.

Our principal executive offices are located at 14313 North May Avenue, Suite 100, Oklahoma City, Oklahoma 73134, and our telephone number is (405) 848-8807. Our website address is www.gulfportenergy.com. Information contained on our website does not constitute a part of this prospectus or any prospectus supplement.

You should carefully consider the factors contained in our annual report on Form 10-K for the fiscal year ended December 31, 2010 under the headings “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” and in any other filings we made with the SEC prior to the filing of this prospectus under the heading “Risk Factors” before investing in our securities. You should also consider similar information contained in any annual report on Form 10-K or other document filed by us with the SEC after the date of this prospectus before deciding to invest in our securities. We will also include in any prospectus supplement a description of any other risk factors applicable to an offering contemplated by such prospectus supplement.

Unless the applicable prospectus supplement indicates otherwise, we intend to use the net proceeds from the sale of the securities for general corporate purposes, including without limitation repaying or refinancing all or a portion of our existing short-term and long-term debt, making acquisitions of assets, businesses or securities, capital expenditures and for working capital. The precise amount and timing of the application of such proceeds will depend upon our funding requirements and the availability and cost of other capital. Pending any specific application of the net proceeds, we intend to invest our net proceeds in short-term, investment-grade securities, interest-bearing securities or guaranteed obligations of the United States or its agencies.

Unless the applicable prospectus supplement indicates otherwise, we will not receive any proceeds from the sale of securities by selling security holders.

The following table sets forth our ratios of earnings (deficit) to fixed charges for the periods indicated. We have calculated the ratio of earnings (deficit) to fixed charges by dividing the sum of income from continuing operations plus fixed charges by fixed charges. Fixed charges consist of interest expense.

The debt securities will be either senior debt securities or subordinated debt securities. The debt securities will be issued under one or more separate indentures between us and a trustee that is qualified to act under the Trust Indenture Act of 1939. The trustee for each series of debt securities will be identified in the applicable prospectus supplement. Any senior debt securities will be issued under a “senior indenture” and any subordinated debt securities will be issued under a “subordinated indenture.” Together, the senior indenture and the subordinated indenture are called “indentures.”

The following description is a summary of the material provisions of the indentures. It does not describe those agreements in their entirety. The forms of indentures are filed as exhibits to the registration statement of which this prospectus is a part. Any supplemental indentures will be filed by us from time to time by means of an exhibit to a Current Report on Form 8-K and will be available for inspection at the corporate trust office of the trustee, or as described below under “Where You Can Find More Information” and “Information Incorporated By Reference.” The indentures will be subject to, and governed by, the Trust Indenture Act of 1939. We will execute a supplemental indenture if and when we issue any debt securities. We urge you to read the indentures and any supplemental indenture because they, and not this description, define your rights as a holder of the debt securities.

Unless we state otherwise in the applicable prospectus supplement, the following is a description of the general terms of the debt securities that we may offer. If the terms of any series of debt securities differ from the terms described below, those terms will be described in the prospectus supplement relating to that series of debt securities.

The senior debt securities will rank equally with all of our other senior and unsubordinated debt. The subordinated debt securities will have a junior position to all of our senior debt. The debt securities may be our secured or unsecured obligations.

A prospectus supplement and a supplemental indenture relating to any series of debt securities being offered will include specific terms relating to the offering. These terms will include some or all of the following:

None of the indentures will limit the amount of debt securities that may be issued by us. Each indenture will allow debt securities to be issued up to the principal amount that may be authorized by us and may be in any currency or currency unit designated by us.

Debt securities of a series may be issued in registered, bearer, coupon or global form.

Unless the prospectus supplement for each issuance of debt securities states otherwise, the securities will be issued in denominations of $1,000 each or multiples thereof.

Under the subordinated indenture, payment of the principal, interest and any premium on the subordinated debt securities will generally be subordinated and junior in right of payment to the prior payment in full of all of our senior debt, whether existing at the date of the subordinated indenture or subsequently incurred. The subordinated indenture will provide that no payment of principal, interest or any premium on the subordinated debt securities may be made in the event:

The subordinated indenture will not limit the amount of senior debt that we may incur.

Unless we state otherwise in a prospectus supplement, “Senior Debt” will be defined in the subordinated indenture to include all notes or other unsecured evidences of indebtedness, including guarantees given by us, for money borrowed by us, including principal of and any interest or premium on such amounts, whether incurred on, before or after the date of the subordinated indenture, that is not expressed to be subordinate or junior in right of payment to any of our other indebtedness.

Each indenture generally will permit a consolidation or merger between us and another corporation. They also will permit the sale by us of all or substantially all of our property and assets. If this happens, the remaining or acquiring corporation will assume all of our responsibilities and liabilities under the indentures, including the payment of all amounts due on the debt securities and performance of the covenants in the indentures. However, we will consolidate or merge with or into any other corporation or sell all or substantially all of our assets only according to the terms and conditions of the indentures. The remaining or acquiring corporation will be substituted for us in the indentures with the same effect as if it had been an original party to the indentures. Thereafter, the successor corporation may exercise our rights and powers under any indenture, in our name or in its own name. Any act or proceeding required or permitted to be done by our board of directors or any of our officers may be done by the board or officers of the successor corporation. If we sell all or substantially all of our assets, we will be released from all our liabilities and obligations under any indenture and under the debt securities.

Under each indenture our rights and obligations and the rights of the holders may be modified with the consent of the holders of a majority in aggregate principal amount of the outstanding debt securities of each series affected by the modification. No modification of the principal or interest payment terms, and no modification reducing the percentage required for modifications, will be effective against any holder without its consent.

“Event of Default” when used in an indenture, could mean any of the following:

An event of default for a particular series of debt securities will not necessarily constitute an event of default for any other series of debt securities issued under an indenture. The trustee may withhold notice to the holders of debt securities of any default, except a default in the payment of principal or interest, if it considers the withholding of notice to be in the best interests of the holders.

If an event of default for any series of debt securities occurs and continues, the trustee or the holders of at least 25% in aggregate principal amount of the debt securities of the series may declare the entire principal of all the debt securities of that series to be due and payable immediately. If this happens, subject to certain conditions, the holders of a majority of the aggregate principal amount of the debt securities of that series can void the declaration.

Other than its duties in case of a default, a trustee is not obligated to exercise any of its rights or powers under any indenture at the request, order or direction of any holders, unless the holders offer the trustee reasonable indemnity. If they provide this reasonable indemnification, the holders of a majority in principal amount of any series of debt securities may direct the time, method and place of conducting any proceeding or any remedy available to the trustee, or exercising any power conferred upon the trustee, for any series of debt securities.

If there are any restrictive covenants applicable to a series of debt securities, we will describe them in the prospectus supplement for that series.

We will pay principal, interest and any premium on fully registered debt securities at designated places. We will make payment by check mailed to the persons in whose names the debt securities are registered on days specified in the indentures or any prospectus supplement. If we make debt securities payments in other forms, we will pay those payments at a place designated by us and specified in a prospectus supplement.

You may transfer or exchange fully registered debt securities at the corporate trust office of the trustee or at any other office or agency maintained by us for such purposes, without the payment of any service charge except for any tax or governmental charge.

We may issue one or more series of debt securities as permanent global debt securities deposited with a depository. Unless otherwise indicated in the prospectus supplement, the following is a summary of the depository arrangements applicable to debt securities issued in permanent global form and for which the Depositary Trust Company, which we refer to as DTC, acts as depository.

Each global debt security will be deposited with, or on behalf of, DTC, as depository, or its nominee, and registered in the name of a nominee of DTC. Except under the limited circumstances described below, global debt securities are not exchangeable for definitive certificated debt securities.

Ownership of beneficial interests in a global debt security is limited to institutions that have accounts with DTC or its nominee, or persons that may hold interests through those participants. In addition, ownership of beneficial interests by participants in a global debt security will be evidenced only by, and the transfer of that ownership interest will be effected only through, records maintained by DTC or its nominee for a global debt security. Ownership of beneficial interests in a global debt security by persons that hold those interests through participants will be evidenced only by, and the transfer of that ownership interest within that participant will be effected only through, records maintained by that participant. DTC has no knowledge of the actual beneficial owners of the debt securities. Beneficial owners will not receive written confirmation from DTC of their purchase, but beneficial owners are expected to receive written confirmations providing details of the transaction, as well as periodic statements of their holdings, from the participants through which the beneficial owners entered the transaction. The laws of some jurisdictions require that certain purchasers of securities take physical delivery of securities they purchase in definitive form. These laws may impair your ability to transfer beneficial interests in a global debt security.

We will make payment of principal of, and interest on, debt securities represented by a global debt security registered in the name of or held by DTC or its nominee to DTC or its nominee, as the case may be, as the registered owner and holder of the global debt security representing those debt securities. DTC has advised us that upon receipt of any payment of principal of, or interest on, a global debt security, DTC immediately will credit accounts of participants on its book-entry registration and transfer system with payments in amounts proportionate to their respective interests in the principal amount of that global debt security, as shown in the records of DTC. Payments by participants to owners of beneficial interests in a global debt security held through those participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers in bearer form or registered in “street name,” and will be the sole responsibility of those participants, subject to any statutory or regulatory requirements that may be in effect from time to time.

Neither we, any trustee nor any of our respective agents will be responsible for any aspect of the records of DTC, any nominee or any participant relating to, or payments made on account of, beneficial interests in a permanent global debt security or for maintaining, supervising or reviewing any of the records of DTC, any nominee or any participant relating to such beneficial interests.

A global debt security is exchangeable for definitive debt securities registered in the name of, and a transfer of a global debt security may be registered to, a person other than DTC or its nominee, only if:

Any global debt security that is exchangeable pursuant to the preceding sentence will be exchangeable in whole for definitive debt securities in registered form, of like tenor and of an equal aggregate principal amount as the global debt security, in denominations specified in the applicable prospectus supplement, if other than $1,000 and integral multiples of $1,000. The definitive debt securities will be registered by the registrar in the name or names instructed by DTC. We expect that these instructions may be based upon directions received by DTC from its participants with respect to ownership of beneficial interests in the global debt security.

Except as provided above, owners of the beneficial interests in a global debt security will not be entitled to receive physical delivery of debt securities in definitive form and will not be considered the holders of debt securities for any purpose under the indentures. No global debt security shall be exchangeable except for another global debt security of like denomination and tenor to be registered in the name of DTC or its nominee. Accordingly, each person owning a beneficial interest in a global debt security must rely on the procedures of DTC and, if that person is not a participant, on the procedures of the participant through which that person owns its interest, to exercise any rights of a holder under the global debt security or the indentures.

We understand that, under existing industry practices, in the event that we request any action of holders, or an owner of a beneficial interest in a global debt security desires to give or take any action that a holder is entitled to give or take under the debt securities or the indentures, DTC would authorize the participants holding the relevant beneficial interests to give or take that action and those participants would authorize beneficial owners owning through those participants to give or take that action or would otherwise act upon the instructions of beneficial owners owning through them.

We will be discharged from our obligations on the debt securities of any series at any time if we deposit with the trustee an amount sufficient to pay the principal, interest, any premium and any other sums due to the stated maturity date or a redemption date of the debt securities of the series. If this happens, the holders of the debt securities of the series will not be entitled to the benefits of the indenture except for registration of transfer and exchange of debt securities and replacement of lost, stolen or mutilated debt securities.

Under U.S. Federal income tax law as of the date of this prospectus, such a discharge should be treated as an exchange of the related debt securities. Each holder generally will be required to recognize gain or loss equal to the difference between the holder’s cost or other tax basis for the debt securities and the value of the holder’s interest in the trust. Holders might be required to include as income a different amount than would be includable without the discharge. Prospective investors are urged to consult their own tax advisers as to the consequences of such a discharge, including the applicability and effect of tax laws other than the U.S. Federal income tax laws.

Each indenture, as supplemented by any supplemental indenture, will contain provisions describing how meetings of the holders of debt securities of a series may be convened. A meeting may be called at any time by the trustee, and also, upon request, by us or the holders of at least 10% in principal amount of the outstanding debt securities of a series. A notice of the meeting must always be given in the manner described under “—Notices” below. Generally speaking, except for any consent that must be given by all holders of a series as described under “—Modification of Indentures” above, any resolution presented at a meeting of the holders of a series of debt securities may be adopted by the affirmative vote of the holders of a majority in principal amount of the outstanding debt securities of that series, unless the indenture allows the action to be voted upon to be taken with the approval of the holders of a different specific percentage of principal amount of outstanding debt securities of a series. In that case, the holders of outstanding debt securities of at least the specified percentage must vote in favor of the action. Any resolution passed or decision taken at any meeting of holders of debt securities of any series in accordance with the applicable indenture will be binding on all holders of debt securities of that series, unless, as discussed under “—Modification of Indentures” above, the action is only effective against holders that have approved it. The quorum at any meeting called to adopt a resolution, and at any reconvened meeting, will be holders holding or representing a majority in principal amount of the outstanding debt securities of a series.

Each indenture and the debt securities will be governed by and construed in accordance with the laws of the State of New York, except to the extent the Trust Indenture Act applies.

Notices to holders of debt securities will be given by mail to the addresses of such holders as they appear in the security register.

If the trustee serves as trustee under both the senior indenture and the subordinated indenture, the provisions of the indentures and the Trust Indenture Act governing trustee conflicts of interest will require the trustee to resign as trustee under either the subordinated indenture or the senior indenture upon the occurrence of any uncured event of default with respect to any series of senior debt securities. Also, any uncured event of default with respect to any series of subordinated debt securities will force the trustee to resign as trustee under either the senior indenture or the subordinated indenture. Any resignation will require the appointment of a successor trustee under the applicable indenture in accordance with the terms and conditions of such indenture.

The trustee may resign or be removed by us with respect to one or more series of debt securities and a successor trustee may be appointed to act with respect to any such series. The holders of a majority in aggregate principal amount of the debt securities of any series also may remove the trustee with respect to the debt securities of that series.

Each indenture will contain certain limitations on the right of the trustee thereunder, in the event that it becomes one of our creditors, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise.

The trustee will be required to submit an annual report to the holders of the debt securities regarding, among other things, the trustee’s eligibility to serve as such, the priority of the trustee’s claims regarding certain advances made by it, and any action taken by the trustee materially affecting the debt securities.

Each indenture will provide that, in addition to other certificates or opinions that may be specifically required by other provisions of an indenture, every application by us for action by the trustee will be accompanied by a certificate of certain of our officers and an opinion of counsel (who may be our counsel) stating that, in the opinion of the signers, all conditions precedent to that action have been complied with by us.

The following summary description of our capital stock is qualified in its entirety by reference to our certificate of incorporation and bylaws, each of which is incorporated by reference in this prospectus.

We are currently authorized to issue up to 100,000,000 shares of common stock, par value $0.01 per share, of which there were 47,480,032 shares outstanding as of July 1, 2011, excluding 186,455 shares of unvested restricted stock awarded under our Amended and Restated 2005 Stock Incentive Plan. Holders of our common stock are entitled to cast one vote for each share held of record on each matter submitted to a vote of stockholders. There is no cumulative voting for election of directors. Subject to the prior rights of any series of preferred stock which may from time to time be outstanding, if any, holders of our common stock are entitled to receive ratably dividends when, as and if declared by the board of directors out of funds legally available for such purpose and, upon the liquidation, dissolution or winding up of the company, are entitled to share ratably in all assets remaining after payment of liabilities and payment of accrued dividends and liquidation preferences on the preferred stock, if any. There are no redemption or sinking fund provisions that are applicable to our common stock. Subject only to the requirements of the DGCL, the board of directors may issue shares of our common stock without stockholder approval, at any time and from time to time, to such persons and for such consideration as the board of directors deems appropriate. Holders of our common stock have no preemptive rights and have no rights to convert their common stock into any other securities. The outstanding common stock is validly authorized and issued, fully paid and nonassessable.

We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of preferred stock may be issued from time to time in one or more series as the board of directors may from time to time determine, each of said series to be distinctively designated. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions thereof, if any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations of our certificate of incorporation and the DGCL, the board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and qualifications, limitations and restrictions thereof, of each such series of preferred stock.

The issuance of any such preferred stock could adversely affect the rights of the holders of our common stock and therefore, reduce the value of the common stock. The ability of the board of directors to issue preferred stock could discourage, delay, or prevent a takeover of us. See “Risk Factors.”

As of July 1, 2011, we had warrants to purchase 30,420 shares of common stock issued in connection with a private placement completed by us in March 2002. Each warrant has a term of ten years and a current exercise price of $1.19 per share of common stock subject to adjustment. We granted to holders of the warrants certain demand and piggyback registration rights with respect to shares of common stock issuable upon exercise of the warrants.

Anti-takeover Effects of Provisions of Our Certificate of Incorporation and Our Bylaws

Some provisions of our certificate of incorporation and our bylaws contain provisions that could make it more difficult to acquire us by means of a merger, tender offer, proxy contest or otherwise, or to remove our incumbent officers and directors. These provisions, summarized below, are expected to discourage coercive

takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection of our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging such proposals because negotiation of such proposals could result in an improvement of their terms.

Preferred stock. Our certificate of incorporation permits our board of directors to authorize and issue one or more series of preferred stock, which may render more difficult or discourage an attempt to change control of us by means of a merger, tender offer, proxy contest or otherwise. For example, if in the due exercise of its fiduciary obligations, the board of directors were to determine that a takeover proposal is not in our best interest, the board of directors could cause shares of preferred stock to be issued without stockholder approval in one or more private offerings or other transactions that might dilute the voting or other rights of the proposed acquirer or insurgent stockholder or stockholder group.

Stockholder meetings. Our bylaws provide that a special meeting of stockholders may be called only by the Chairman of the Board, the Chief Executive Officer or by a resolution adopted by a majority of the total number of directors the board of directors would have if there were no vacancies.

Requirements for advance notification of stockholder nominations and proposals. Our bylaws and certificate of incorporation establish advance notice procedures with respect to stockholder proposals and the nomination of candidates for election as directors, other than nominations made by or at the direction of the board of directors.

Stockholder Action By Written Consent. Our bylaws provide that, except as may otherwise be provided with respect to the rights of the holders of preferred stock, no action that is required or permitted to be taken by our stockholders at any annual or special meeting may be effected by written consent of stockholders in lieu of a meeting of stockholders, unless the action to be effected by written consent of stockholders and the taking of such action by such written consent have expressly been approved in advance by our board of directors. This provision, which may not be amended by our stockholders except by the affirmative vote of holders of at least 66-2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class, makes it difficult for stockholders to initiate or effect an action by written consent that is opposed by our board of directors.

Amendment of the bylaws. Under Delaware law, the power to adopt, amend, alter or repeal bylaws is conferred upon the stockholders. A corporation may, however, in its certificate of incorporation also confer upon the board of directors the power to adopt, amend or repeal its bylaws. Our certificate of incorporation and bylaws grant our board of directors the power to adopt, amend, alter or repeal our bylaws at any regular or special meeting of the board of director on the affirmative vote of a majority of the total number of directors the board of directors would have if there were no vacancies. Our stockholders may adopt, amend, alter or repeal our bylaws but only at any regular or special meeting of stockholders by an affirmative vote of holders of at least 66-2/3% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

The provisions of our certificate of incorporation and bylaws could have the effect of discouraging others from attempting hostile takeovers and, as a consequence, they may also inhibit temporary fluctuations in the market price of our common stock that often result from actual or rumored hostile takeover attempts. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish transactions which stockholders may otherwise deem to be in their best interests.

The transfer agent and registrar for our common stock is Computershare Trust Company, N.A.

We may, from time to time, sell, transfer or otherwise dispose of the securities offered by this prospectus or any applicable prospectus supplement on any stock exchange, market or trading facility on which such securities are traded or in private transactions. These dispositions may be at fixed prices, at prevailing market prices at the time of sale, at prices related to the prevailing market price, at varying prices determined at the time of sale or at negotiated prices.

We may use any one or more of the following methods when disposing of the offered securities:

If underwriters are used to sell the securities, we will enter into an underwriting agreement or similar agreement with them at the time of the sale to them. In that event, underwriters may receive compensation from us in the form of underwriting discounts or commissions and may also receive commissions from purchasers of the securities for whom they may act as agent.

To the extent required by applicable law, a prospectus supplement relating to the securities will set forth:

The securities may be offered to the public either through underwriting syndicates represented by one or more managing underwriters or directly by one or more of such firms. Unless otherwise set forth in an applicable prospectus supplement, the obligations of underwriters or dealers to purchase the securities will be subject to certain conditions precedent and the underwriters or dealers will be obligated to purchase all the securities if any are purchased. Any public offering price and any discounts or concessions allowed or reallowed or paid by underwriters or dealers to other dealers may be changed from time to time.

The securities may be sold directly by us or through agents designated by us from time to time. Any agent involved in the offer or sale of the securities in respect of which this prospectus and a prospectus supplement is delivered will be named, and any commissions payable by us to such agent will be set forth, in any required prospectus supplement. Unless otherwise indicated in the prospectus supplement, any such agent will be acting on a best efforts basis for the period of its appointment.

If so indicated in the prospectus supplement, we will authorize underwriters, dealers or agents to solicit offers from certain specified institutions to purchase securities from us at the public offering price set forth in the prospectus supplement pursuant to delayed delivery contracts providing for payment and delivery on a specified date in the future. Such contracts will be subject to any conditions set forth in the prospectus supplement and the prospectus supplement will set forth the commissions payable for solicitation of such contracts. The underwriters and other persons soliciting such contracts will have no responsibility for the validity or performance of any such contracts.

Underwriters, dealers and agents may be entitled under agreements entered into with us to be indemnified by us against certain civil liabilities, including liabilities under the Securities Act, or to contribution by us to payments which they may be required to make. The terms and conditions of such indemnification will be described in an applicable prospectus supplement. Underwriters, dealers and agents may be customers of, engage in transactions with or perform services for us in the ordinary course of business.

Any underwriters to whom securities are sold by us for public offering and sale may make a market in such securities, but such underwriters will not be obligated to do so and may discontinue any market making at any time without notice. No assurance can be given as to the liquidity of the trading market for any securities.

Certain persons participating in any offering of securities may engage in transactions that stabilize, maintain or otherwise affect the price of the securities offered. In connection with any such offering, the underwriters, dealers or agents, as the case may be, may purchase and sell securities in the open market. These transactions may include overallotment and stabilizing transactions and purchases to cover syndicate short positions created in connection with the offering. Stabilizing transactions consist of certain bids or purchases for the purpose of preventing or retarding a decline in the market price of the securities and syndicate short positions involve the sale by the underwriters, dealers or agents, as the case may be, of a greater number of securities than they are required to purchase from us in the offering. The underwriters may also impose a penalty bid, whereby selling concessions allowed to syndicate members or other broker-dealers for the securities sold for their account may be reclaimed by the syndicate if such securities are repurchased by the syndicate in stabilizing or covering transactions. These activities may stabilize, maintain or otherwise affect the market price of the securities, which may be higher than the price that might otherwise prevail in the open market, and if commenced, may be discontinued at any time. These transactions may be effected on The NASDAQ Global Select Market, in the over-the-counter market or otherwise. These activities will be described in more detail in the sections entitled “Plan of Distribution” or “Underwriting” in the applicable prospectus supplement.

Selling security holders may use this prospectus in connection with resales of securities they hold as described in the applicable prospectus supplement. The applicable prospectus supplement will identify the selling security holders, the terms of the securities and any material relationships we have with the selling security holders. Selling security holders may be deemed to be underwriters under the Securities Act in connection with the securities they resell and any profits on the sales may be deemed to be underwriting discounts and commissions under the Securities Act. Unless otherwise provided in a prospectus supplement, the selling security holders will receive all the proceeds from the sale of the securities.

We have filed with the SEC a registration statement on Form S-3 under the Securities Act covering the securities offered by this prospectus. This prospectus does not contain all of the information that you can find in that registration statement and its exhibits. Certain items are omitted from this prospectus in accordance with the rules and regulations of the SEC. For further information with respect to us and the securities offered by this prospectus, reference is made to the registration statement and the exhibits filed with the registration statement. Statements contained in this prospectus as to the contents of any contract or other document referred to are not necessarily complete and in each instance such statement is qualified by reference to each such contract or document filed with or incorporated by reference as part of the registration statement. We file reports, proxy and information statements and other information with the SEC. You may read any materials we have filed with the SEC free of charge at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of all or any part of these documents may be obtained from such office upon the payment of the fees prescribed by the SEC. The public may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains an Internet site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the site is http://www.sec.gov. The registration statement, including all exhibits thereto and amendments thereof, has been filed electronically with the SEC.

You can also find our SEC filings on our website at www.gulfportenergy.com. The information contained on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

The SEC allows us to “incorporate by reference” into this prospectus the information we provide in other documents filed by us with the SEC. The information incorporated by reference is an important part of this prospectus and any prospectus supplement. Any statement contained in a document that is incorporated by reference in this prospectus is automatically updated and superseded if information contained in this prospectus and any prospectus supplement, or information that we later file with the SEC, modifies and replaces this information. We incorporate by reference the following documents that we have filed with the SEC:

the Exchange Act, and we are not subject to the liabilities of Section 18 with respect to information submitted under Item 2.02 or Item 7.01 of Form 8-K. We are not incorporating by reference any information submitted under Item 2.02 or Item 7.01 of Form 8-K into any filing under the Securities Act or the Exchange Act or into this prospectus, unless otherwise indicated on such Form 8-K.

You may request a copy of this prospectus or any of the incorporated documents (excluding exhibits, unless the exhibits are specifically incorporated) at no charge to you by writing to Gulfport Energy Corporation, Attention: Investor Relations, at 14313 North May Avenue, Suite 100, Oklahoma City, Oklahoma 73134, or calling (405) 242-4888.

Unless otherwise indicated in the applicable prospectus supplement, the validity of the securities to be offered hereby offered by us and the selling stockholders will be passed upon by Akin, Gump, Strauss, Hauer & Feld, L.L.P. If legal matters in connection with offerings made by this prospectus are passed on by counsel for the underwriters, dealers or agents, if any, that counsel will be named in the applicable prospectus supplement.

The consolidated financial statements and management’s assessment of the effectiveness of internal control over financial reporting incorporated by reference in this prospectus and elsewhere in the registration statement have been so incorporated by reference in reliance upon the reports of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing in giving said reports.

Information incorporated by reference into this prospectus regarding estimates of our proved oil and natural gas reserves and the discounted present value of estimated future net revenue before income tax of our estimated proved reserves is based on reports included in our Annual Report on Form 10-K for the year ended December 31, 2010 and incorporated herein by reference, prepared by Netherland, Sewell & Associates, Inc., with respect to our West Cote Blanche Bay and Niobrara fields, and by Pinnacle Energy Services, LLC, with respect to our assets in the Permian Basin in West Texas. All of such information has been so included herein in reliance upon the authority of such firms as experts in such matters.



Title of Each Class of Securities To Be Registered	Amount To Be Registered(1)	Proposed Maximum Aggregate Price Per Share	Proposed Maximum Aggregate Offering Price(1)	Amount of Registration Fee(2)
Common Stock, par value $0.01 per share	8,912,500	$38.00	$338,675,000	$46,195.27


	Public Offering Price		Underwriting Discounts and Commissions		Proceeds to Us (Before Expenses)
Per Share	$	38.00	$	1.444	$	36.556
Total	$	294,500,000	$	11,191,000	$	283,309,000


IBERIA Capital Partners L.L.C.
	KeyBanc Capital Markets
		Simmons & Company International
			Stephens Inc.
	Stifel Nicolaus Weisel
Global Hunter Securities			Tuohy Brothers


	Page
PROSPECTUS SUPPLEMENT

ABOUT THIS PROSPECTUS SUPPLEMENT		S-ii
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		S-iii
PROSPECTUS SUPPLEMENT SUMMARY		S-1
RISK FACTORS		S-17
USE OF PROCEEDS		S-40
CAPITALIZATION		S-41
PRICE RANGE OF COMMON STOCK		S-42
MATERIAL U.S FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS		S-43
UNDERWRITING		S-47
INFORMATION INCORPORATED BY REFERENCE		S-50
LEGAL MATTERS		S-51
EXPERTS		S-51
RESERVE REPORT OF NETHERLAND, SEWELL & ASSOCIATES, INC.		A-1
RESERVE REPORT OF RYDER SCOTT COMPANY L.P.		B-1
	Page
PROSPECTUS

ABOUT THIS PROSPECTUS		ii
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS		iii
OUR COMPANY		1
RISK FACTORS		1
USE OF PROCEEDS		1
RATIO OF EARNINGS (DEFICIT) TO FIXED CHARGES		1
DESCRIPTION OF DEBT SECURITIES		2
DESCRIPTION OF CAPITAL STOCK		9
PLAN OF DISTRIBUTION		11
WHERE YOU CAN FIND MORE INFORMATION		13
INFORMATION INCORPORATED BY REFERENCE		13
LEGAL MATTERS		14
EXPERTS		14


	Year Ended December 31,
	2011		2010
Standardized measure of discounted future net cash flows	$	376,681,000	$	315,487,000
Add: Present value of future income tax discounted at 10%		113,791,000		77,117,000

PV-10 value	$	490,472,000	$	392,604,000


	As of September 30, 2012
	Actual			Pro Forma			Pro Forma As Adjusted
	(In thousands)
Cash and cash equivalents(1)	$	12,280		$	310,725		$	373,045

Long-term debt (including current maturities):
Revolving credit agreement	$	141,000		$	—		$	—
7.750% Senior Notes due 2020(2)		—			296,835			296,835
Building loans		2,180			2,180			2,180

Total		143,180			299,015			299,015

Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; 0 issued and outstanding		—			—			—
Stockholders’ equity:
Common stock—$.01 par value, 100,000,000 authorized, 55,717,702 issued and outstanding; 68,367,702 pro forma and 76,117,702 pro forma as adjusted		557			684			761
Paid-in-capital		608,010			1,067,653			1,349,896
Accumulated other comprehensive income (loss)		(4,975	)		(4,975	)		(4,975	)
Retained earnings (accumulated deficit)		77,035			70,841			70,841

Total stockholders’ equity		680,627			1,134,203			1,416,523

Total capitalization	$	823,807		$	1,433,218		$	1,715,538


	Price Range of Common Stock
	High		Low

2011
First Quarter		$36.38	$	20.00
Second Quarter		38.09		23.84
Third Quarter		37.49		22.00
Fourth Quarter		37.80		18.72

2012
First Quarter		$37.63	$	27.66
Second Quarter		29.66		15.79
Third Quarter		33.11		18.17
Fourth Quarter		40.73		28.94

2013
First Quarter (through February 11, 2013)		$42.75	$	37.57


Underwriter	Number of Shares
Credit Suisse Securities (USA) LLC		4,893,000
Capital One Southcoast, Inc.		245,000
Johnson Rice & Company L.L.C.		245,000
RBC Capital Markets, LLC		245,000
Scotia Capital (USA) Inc.		245,000
Sterne, Agree & Leach, Inc.		245,000
SunTrust Robinson Humphrey, Inc.		245,000
Wunderlich Securities, Inc.		245,000
C.K. Cooper & Company, Inc.		204,000
IBERIA Capital Partners L.L.C.		163,000
KeyBanc Capital Markets Inc.		163,000
Simmons & Company International		163,000
Stephens Inc.		163,000
Stifel, Nicolas & Company, Incorporated		122,000
Global Hunter Securities, LLC		82,000
Tuohy Brothers Investment Research, Inc.		82,000

Total		7,750,000


	Per Share				Total
	Without Over-allotment		With Over-allotment		Without Over-allotment		With Over-allotment
Underwriting Discounts and Commissions	$	1.444	$	1.444	$	11,191,000.00	$	12,869,650.00


	Net Reserves				Future Net Revenue (M$)
Category	Oil (MBBL)		Gas (MMCF)		Total		Present Worth at 10%
Proved Developed Producing		1,598.0		636.5		105,441.5		98,729.0
Proved Developed Non-Producing		2,883.2		2,401.8		176,655.7		139,017.3
Proved Undeveloped		1,983.2		1,322.6		125,827.2		104,987.6

Total Proved		6,464.4		4,361.0		407,924.4		342,733.9


Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699

By:		/s/ C.H. (Scott) Rees III
		C.H. (Scott) Rees III, P.E.
		Chairman and Chief Executive Officer



By:	/s/ Derek F. Newton	By:	/s/ Mike K. Norton	By:	/s/ John R. Cliver
	Derek F. Newton		Mike K. Norton		John R. Cliver
	Texas P.E. 97689		Texas P.G. 441		Louisiana P.E. 37090
	Vice President		Senior Vice President		Petroleum Engineer

Date Signed: January 11, 2013		Date Signed: January 11, 2013		Date Signed: January 11, 2013


		\s\ Don P. Griffin
		Don P. Griffin, P.E.
		TBPE License No. 64150
		Senior Vice President


	Proved
	Developed				Undeveloped		Total Proved
	Producing		Non-Producing		Undeveloped		Total Proved
*Net Remaining Reserves*
Oil/Condensate – Mbbl		153		457		947		1,557
Plant Products – Mbbl		43		0		101		145
Gas – MMCF		4,223		11,126		13,966		29,315

*Income Data ($M)*
Future Gross Revenue	$	28,082	$	74,468	$	129,773	$	232,323
Deductions		5,369		14,533		66,912		86,814

Future Net Income (FNI)	$	22,713	$	59,935	$	62,861	$	145,509
Discounted FNI @ 10%	$	15,909	$	42,751	$	31,348	$	90,008


	Discounted Future Net Income ($M) As of December 31, 2012
Discount Rate Percent	Total Proved
5	$	111,029
15	$	75,779
20	$	65,403
25	$	57,427


Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$94.71/Bbl	$84.88/Bbl
	NGLs	Mt. Belvieu	$43.24/Bbl	$69.75/Bbl
	Gas	Henry Hub	$2.76/MMBTU	$3.11/MCF