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raw/filings/0000077877/2005/0000077877-06-000037/item13.txt

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+Item 13. Certain Relationships and Related Transactions 
+During the year ended December 31, 2005, there was no transaction or
+series of transactions to which we were or are a party in which the amount
+involved exceeded or exceeds $60,000 and in which any director, executive
+officer, holder of more than 5% of our common stock or any member of the
+immediate family of any of the foregoing persons had or will have a direct or
+indirect material interest.

raw/filings/0000077877/2012/0000077877-13-000017/filing_metadata.csv

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+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000077877,PDCE,"PDC ENERGY, INC.",10-K,2013-02-27,2012-12-31,2013-02-27T13:47:47.000Z,0000077877-13-000017,pdce-10kxfy12.htm,10-K,27980980,1,0,https://www.sec.gov/Archives/edgar/data/77877/000007787713000017/pdce-10kxfy12.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787713000017/,2012,2012,1

raw/filings/0000077877/2012/0000077877-13-000017/item13.txt

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+ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE 
+Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2013 Annual Stockholders' meeting and is incorporated by reference in this report.

raw/filings/0000077877/2012/0000077877-13-000017/item9a.txt

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+ITEM 9A. CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Controls and Procedures 
+As of December 31, 2012 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2012 . 
+Changes in Internal Control over Financial Reporting 
+During the fourth quarter of 2012 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

raw/filings/0000077877/2012/0000077877-13-000017/rpt_disclosure.txt

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+TRANSACTIONS WITH RELATED PERSONS 
+Related Transactions 
+From January 1, 2013 to the
+present, there was no transaction or series of transactions, nor is there any currently proposed transaction involving an amount exceeding $120,000 in which the Company is a participant and/or in which any Director, executive officer, known holder
+of more than five percent of the Company’s voting securities, or any member of the immediate family of any of the foregoing persons had or will have a direct or indirect material interest for which disclosure is required under SEC Rule S-K 404.
+Policies and Procedures With Respect to Transactions with Related Persons 
+The Board has adopted a written policy for the review, approval and ratification of transactions that involve related
+parties and potential conflicts of interest. The related party transaction policy applies to each Director and executive officer of the Company, any nominee for election as a Director, any security holder who is known to own more than five percent
+of the Company’s voting securities, any immediate family member of any of the foregoing persons and any corporation, firm or association in which one or more of the Company’s Directors are directors or officers, or have a substantial
+financial interest. 
+24 
+Table of Contents 
+Under our related-party transaction policy, a related person transaction is
+a transaction or arrangement involving a related person in which the Company is a participant or that would require disclosure in the Company’s filings with the SEC as a transaction with a related person. The related person must disclose to the
+Audit Committee any potential related person transactions and must disclose all material facts with respect to such transaction and relationship. All related person transactions will be reviewed by the Audit Committee. In determining whether to
+approve or ratify a transaction, the Audit Committee will consider the relevant facts and circumstances of the transaction, which may include factors such as the relationship of the related person with the Company, the materiality or significance of
+the transaction to the Company and the business purpose and reasonableness of the transaction, whether the transaction is comparable to a transaction that could be available to the Company on an arms-length basis and the impact of the transaction on
+the Company’s business and operations.

raw/filings/0000874499/2001/0001060830-02-000041/filing_metadata.csv

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+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2002-04-01,2001-12-31,2002-04-01T05:00:00.000Z,0001060830-02-000041,gulfportenergy10k2001.txt,,173966,0,0,https://www.sec.gov/Archives/edgar/data/874499/000106083002000041/gulfportenergy10k2001.txt,https://www.sec.gov/Archives/edgar/data/874499/000106083002000041/,2001,2001,1

raw/filings/0000874499/2001/0001060830-02-000041/item1.txt

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+Item 1. Business
+Description of Business
+Gulfport is an independent oil and gas exploration and production
+company with properties located in the Louisiana Gulf Coast. Gulfport has a
+market enterprise value of approximately $50.9 million dollars and generated
+EBITDA of $9.6 million dollars for the twelve months ended December 31, 2001. As
+of December 31, 2001, the Company had 29 MMBOE proved reserves with a present
+value (10%) of estimated future net reserves of $130 million dollars.
+Gulfport is actively pursuing further development of its properties in
+order to fully exploit its reserves. The Company has a substantial portfolio of
+low risk developmental projects for the next several years providing the
+opportunity to increase production and cash flow. Gulfport's developmental
+program is designed to reach the Company's high impact, higher potential rate of
+return prospects through the penetration of several producing horizons.
+Additionally, Gulfport owns 3-D seismic data, which along with the
+Company's technical expertise, will be used to identify exploratory prospects
+and test undrilled fault blocks in existing fields.
+Background
+Gulfport is the successor of WRT Energy Corporation ("WRT"). WRT filed for
+bankruptcy in February 1996. Gulfport emerged as the reorganized company in July
+1997.
+4
+Principal Oil and Gas Properties
+Gulfport owns interests in a number of producing oil and gas properties
+located along the Louisiana Gulf Coast. The following is a map showing the
+locations of Gulfport's principal oil and gas properties.
+(MAP OMITTED)
+Gulfport serves as the operator of substantially all of the properties in
+which it holds a working interest with the exception of the Texaco ("Texaco" or
+"ChevronTexaco") well and deep rights at West Cote Blanche Bay. During 2001
+Chevron acquired Texaco. The following table presents certain information as of
+January 1, 2002 reflecting Gulfport's net interest in its producing oil and gas
+properties.
+Net Proved Reserves
+Shut-in As of 1/1/02
+-------------------
+Field NRI/WI Active Wells wells(1) Acreage(2) Gas Oil Total
+-------------- ------------ -----------
+Percentages Gross Net Gross Net Gross Net MBOE MBOE MBOE
+---------------------------------------------------------------------------------------------------------
+E Hackberry 78.7/100 17 17 73 73 3,147 3,147 590 3,392 3,982
+W Hackberry 87.5/100 2 2 25 25 592 592 47 248 295
+West Cote
+Blanche Bay (3) 78.7/100 48 47 296 296 4,590 4,590 3,384 20,906 24,290
+Overrides/Royalty Various 12 1 6 1 403 403 100 277 377
+------------------------------------------------------------------------
+TOTAL 79 67 400 395 8,732 8,732 4,121 24,823 28,944
+========================================================================
+(1) The following wells produce on an intermittent basis: East Hackberry -
+4; West Hackberry - 1; and West Cote Blanche Bay - 6.All of Gulfport's
+acreage is Developed Acreage.
+(2) Includes 1 producing well and 3 shut-in wells attributable to depths
+below the Rob "C" Marker ("Deep Rights"). Gulfport has a 7.45%
+non-operated working interest (5.84% NRI) in the Deep Rights. The Deep
+Rights are operated by ChevronTexaco Corporation.
+(3) In the future, Gulfport will have to plug and abandon almost 400
+wellbores. Gulfport's strategy to meet this obligation is to plug at
+least twenty wells a year at WCBB, three at Hackberry and to invest in
+plugging escrow accounts. The Company continually deposits money in
+the West Cote Blanche Bay Escrow Account, which currently has a
+balance of approximately $2.3 million dollars. Additionally, Gulfport
+has a $200,000 letter of credit dedicated to the plugging operations
+at East Hackberry.
+All of the oil and gas leases in which Gulfport owns an interest have been
+perpetuated by production. The operator may surrender the leases at any time by
+notice to the lessors, or by the cessation of production.
+East Hackberry Field
+(Map Omitted)
+Location and Land
+The East Hackberry Field is located along the western shore of Lake
+Calcasieu in Cameron Parish, Louisiana approximately 80 miles west of Lafayette
+5
+and 15 miles inland from the Gulf of Mexico. In February 1994, Gulfport
+purchased a 100% working interest (approximately 79% average NRI) in certain
+producing oil and gas properties situated in the East Hackberry Field. The
+purchase included two separate lease blocks, the Erwin Heirs Block which is
+located on land originally developed by Gulf Oil Company (now ChevronTexaco
+Corporation), and the adjacent State Lease 50 Block which is located primarily
+in the shallow waters of Lake Calcasieu, originally developed by Texaco. The two
+lease blocks together contain 3,147 acres.
+In September 1994, Gulfport sold an overriding royalty interest equal to a
+50% working interest in certain producing oil and gas wells situated in the East
+Hackberry Field to Milam Royalty Corporation a subsidiary of J. P. Morgan and
+Company. In April 1999, Gulfport purchased the overriding royalty interest back
+from the then current owner, Queen Sand Resources, Inc. giving Gulfport a 100%
+working interest in the field.
+Geology
+The Hackberry Field is a major salt intrusive feature, elliptical in shape
+as opposed to a classic "dome," divided into East and West field entities by a
+saddle. Structurally, Gulfport's East Hackberry acreage is located on the
+eastern end of the Hackberry salt ridge. There are over 30 pay zones at this
+field. The salt intrusion trapped Oligocene through Lower Miocene rocks in a
+series of complex, steeply dipping fault blocks. The Camerina sand series is a
+prolific producer with 1-2 MMBL per well of oil potential. Gulfport's wells
+currently produce from perforations found between 5,100' and 12,200'.
+Area History and Production
+The East Hackberry field was discovered in 1926 by Gulf Oil Company (now
+ChevronTexaco Corporation) by a gravitational anomaly survey. The massive
+shallow salt stock presented an easily recognizable gravity anomaly indicating a
+productive field. Initial production began in 1927 and has continued to the
+present. The estimated cumulative oil and condensate production through 2002
+was 111 million barrels of oil with casinghead gas production being 60 billion
+cubic feet of gas. There have been a total of 170 wells drilled on Gulfport's
+portion of the field with 17 having current daily production; three produce
+intermittently; 73 wells are shut-in and 4 wells have been converted to salt
+water disposal wells. The remaining 73 wells have been plugged and abandoned.
+During 2001, daily net production averaged 305 barrels of oil with a limited
+amount of net gas production.
+Facilities
+Gulfport has land-based production and processing facilities located at
+the East Hackberry Field. The facility is comprised of two dehydrating units and
+four disposal pumps. Gulfport also has a field office that serves both the East
+and West Hackberry fields. Due to the high cost of gas, Gulfport converted the
+Erwin Heirs Block from gas lift to other lifting methods in 2000 and returned
+the rental compressors. Gulfport reactivated three pumping units from inventory
+and purchased an additional surface unit and two electric submersible pumps.
+2001 Activity
+Gulfport began a program to periodically test shut-in wells on the State
+Lease 50 portion of the East Hackberry Field. Additionally, Gulfport
+reactivated a satellite tank battery at the State Lease 50 portion of East
+Hackberry. The Company also conducted several remedial operations that included
+6
+repairing holes in tubing and casing, replaced parted tubing and cleaned out
+salt water disposal wells.
+West Hackberry Field
+Location and Land
+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. In November 1992, Gulfport
+purchased a 100% working interest (approximately 80% average NRI, subsequently
+increased to approximately 87.5% NRI) in 592 acres within the West Hackberry
+Field.
+Gulfport's leases at West Hackberry are located within two miles of one of
+the United States' Department of Energy's Strategic Petroleum Reserves. The
+West Hackberry storage facility occupies 525 acres and has capacity to store 222
+million barrels of oil in underground salt caverns.
+Geology
+Structurally, Gulfport's West Hackberry acreage is located on the western
+end of the Hackberry salt ridge. (See graphic above.) There are over 30 pay
+zones at this field. West Hackberry consists of a series of fault-bounded traps
+in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt
+Ridge. Recoveries from these thick, porous, water-drive reservoirs have
+resulted in per well cumulatives of almost 700 BOE.
+Area History and Production
+The first discovery well at West Hackberry was drilled in 1938 and was
+developed by Superior Oil Company (now Exxon-Mobil Corporation) between 1938 and
+1988. The estimated cumulative oil and condensate production through 2001 was
+170 million barrels of oil with casinghead gas production of 120 billion cubic
+feet of gas. There have been 36 wells drilled to date on Gulfport's portion of
+West Hackberry and currently 2 are producing, 25 are shut-in and 1 well has been
+converted to a saltwater disposal well. The remaining 8 wells have been plugged
+and abandoned. During 2001, daily net production averaged 40 barrels of oil and
+a limited amount of gas.
+Facilities
+Gulfport has land-based production and processing facilities located at
+the West Hackberry field. Gulfport has two dehydrating units and one disposal
+pump. During 2000, due to the high cost of gas, Gulfport converted the West
+Hackberry field from gas lift to other lifting methods. The Company reactivated
+two pumping units from inventory and sold a company owned compressor. Gulfport
+maintains a field office that serves both the East and West Hackberry fields.
+2001 Activity
+Gulfport conducted several remedial operations that included repairing
+holes in tubing and casing and replacing parted tubing.
+West Cote Blanche Bay Field
+(Map Omitted) (Type Log Omitted)
+7
+Location and Land
+The West Cote Blanche Bay (WCBB) Field lies approximately five miles off
+the coast of Louisiana primarily in St. Mary Parish in a shallow bay, with water
+depths averaging eight to ten feet. Gulfport originally acquired from Texaco a
+6.25% working interest in all zones in the WCBB field in July 1988. In April
+1995, Gulfport completed the purchase of an additional 43.75% working interest
+in the WCBB field from an affiliate of Benton Oil and Gas Company and two
+affiliates of Tenneco, Inc. as to those rights lying above the base of the Rob
+"C" marker, located at approximately 10,500'. The sellers retained their
+interests in all depths below the base of the Rob "C" marker. In July, 1997
+Gulfport acquired the remaining 50% working interest in the WCBB field in depths
+above the Rob "C" marker from Texaco and became the operator of the shallow
+rights in the field. In 1999 Gulfport exercised a preferential right to
+purchase an additional 1.00% working interest in the rights below the Rob "C"
+marker. Currently Gulfport owns a 100% working interest (78.66% NRI) and is
+the operator in the depths above the Rob "C" marker and owns a 7.45%
+non-operated working interest (5.84% NRI) in depths below the Rob "C" marker.
+Texaco is the operator below the base of the Rob "C" marker. Gulfport's
+leasehold at WCBB covers a portion of Louisiana State Lease 340 and contains
+4,590 acres.
+Geology
+WCBB overlies one of the largest salt dome structures on the Gulf Coast.
+The field is characterized by a piercement salt dome, which created traps from
+the Pleistocene through the Miocene. The relative movements affected deposition
+and created a complex system of fault traps. The compensating fault sets
+generally trend NW-SE and are intersected by sets having a major radial
+component. Later-stage movement caused extension over the dome and a large
+graben system was formed.
+There are over 100 distinct sandstone reservoirs recognized throughout
+most of the field and nearly 200 major and minor discrete intervals have been
+tested. Within the over 800 wellbores that have been drilled to date in the
+field, over 4,000 potential zones have been penetrated. These sands are highly
+porous and permeable reservoirs primarily with a strong water drive.
+Area History and Production
+Texaco drilled the discovery well in 1940 based on a seismic and
+gravitational anomaly. WCBB was subsequently developed on an even 160-acre
+pattern for much of the remainder of the decade. Developmental drilling
+continued and reached its peek in the 1970's when over 300 of the over 800 total
+wells were drilled in the field. Of the over 800 wells drilled, only 80 were dry
+holes and many of these were capable of hydrocarbon production. As a result, the
+field has an historic success rate of over 90% for all wells drilled. The
+cumulative gross production for the average producer in the field was 237 MBO,
+with over 100 of those wells (14% of total wells) producing in excess of 500
+MBO. As of January 1, 2002, field cumulative gross production was 191 MMBO and
+232.5 BCF of gas.
+There have been 871 wells drilled in WCBB. Of these, 48 are currently
+producing, 303 are shut-in and five have been converted to salt water disposal
+wells. The balance of the wells (or 515) have been plugged and abandoned.
+During 2001, Gulfport's net current daily production averaged 1,280 barrels of
+oil, 399 MCF of gas and 11,881 barrels of water at WCBB.
+In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100
+shot points per mile that processed out 100 fold. In 1993, an undershoot survey
+around the crest and production facilities was added. Gulfport owns the rights
+8
+to the seismic data. In December of 1999 Gulfport completed the reprocessing
+of the seismic data and its technical staff developed prospects from the data.
+The reprocessed data will enable Gulfport to identify prospects in areas of the
+field that would otherwise remain obscure.
+Facilities
+Gulfport owns and operates a production facility at WCBB. The platform
+for the production facility stretches over a mile and is equipped with a 30 MMCF
+capacity dehydrating system and three 225 horsepower triplex saltwater disposal
+pumps. The Company has an ongoing program to modernize and service the
+production facilities at WCBB. During 2001, Gulfport installed two new gas
+compressors totaling 3,000 horsepower into full time service at the field
+replacing three outdated inefficient compressors. The new compressors increased
+efficiency and, together with a new header valve the Company installed at one of
+the tank batteries, reduced gas usage in the field by 50%. Other work performed
+on the facility during 2001 included repairing or replacing flow lines and gas
+lift lines. Gulfport also back flowed and cleaned sand from the five saltwater
+disposal wells at West Cote Blanche Bay, which allows the wells to handle a
+higher volume of water. The Company generates cash flow by handling other
+companies' gas and oil and disposing of their saltwater through the facility for
+a fee. In 2001, Gulfport earned an average of $33,524 a month from third party
+facility charges.
+2001 Activity
+During April 2001, Gulfport finished the seven well drilling program it
+had commenced in January of 2001. The Company successfully drilled, completed
+and is currently producing six intermediate depth wells, with total depths
+averaging approximately 9,000' and one shallow well, with a total depth of
+2,500'. These wells found significant oil and gas deposits in multiple targets
+ranging from relatively low risk proven undeveloped objectives to higher
+potential exploratory targets. Gulfport feels that by taking most future wells
+to a depth of 9,000' there will be an increased chance of converting reserves
+currently classified as possible and probable to proved.
+Gulfport continued to meet its plugging obligation and plugged 26 wells at
+WCBB during 2001 at an average cost of $18,400 per well. The Company has plugged
+90 wells at WCBB since it began its plugging program in 1997.
+2002 Field Activity
+West Cote Blanche Bay
+In 2002, Gulfport continues to use the reprocessed 3-D seismic data to
+identify and confirm intermediate and shallow prospects at WCBB. The Company
+plans to begin a ten well drilling program in the second quarter of 2002. The
+ten well program will consist of eight developmental intermediate depth wells,
+one developmental shallow horizontal well and one exploratory shallow well. The
+Company anticipates that these wells will access significant oil and gas
+deposits with most of the wells having multiple targets ranging from relatively
+low risk proven undeveloped objectives to higher potential exploratory targets.
+Gulfport also anticipates several recompletions and workovers and will continue
+to fulfill its plugging obligations during 2002.
+East & West Hackberry
+Gulfport will continue testing shut-in wells and putting them on permanent
+or intermittent production as results warrant. The Company also plans several
+recompletion projects for the Erwin and State Lease 50 portion of East
+9
+Hackberry. Gulfport is in the process of generating projects in the West
+Hackberry field.
+Texaco Operated Well
+In June of 1999, Gulfport executed a sublease in favor of Texaco of an
+approximate 72 acre block below the base of the 8 Sand, located at approximately
+9,060 feet, at WCBB and reserved a 25% back-in working interest after the
+proceeds of the well totaled $1,000,000. The well paid out in December 1999.
+Overriding Royalty Interests
+Gulfport also owns overriding royalty interests in an additional 14
+producing oil and gas wells lying in four fields.
+When Gulfport sold its interest in the Bayou Penchant Field to Castex
+Energy 1996 Limited Partnership effective April 1, 1998, Gulfport retained a 10%
+overriding royalty interest in this field. The Bayou Penchant field is located
+in Terrebonne Parish, Louisiana and the 2001 average daily gross production from
+five producing wells was 1,250 gross MCF of gas.
+Gulfport also owns a 2.5% overriding royalty interest in three producing
+wells at the Napoleonville Field retained when Gulfport sold its interest to
+Plymouth Operating Company in 1998. The Napoleonville field is located in
+Assumption Parish, Louisiana and averaged 150 gross barrels of oil per day in
+2001.
+Additionally, Gulfport owns a net profits interest in one producing well
+and all the leasehold rights in the South Atchafalaya Bay Field located in St.
+Mary Parish, Louisiana. This well was placed on production in late 1999. This
+interest provided over $21,000 in net revenue to Gulfport in 2001.
+The land occupied by a warehouse owned by Gulfport in Lafayette, LA covers
+approximately one acre. The mineral rights underlying the building were
+included in a unit drilled by Newfield Exploration Company. In April 2000,
+effective June 1999, Gulfport backed into a working interest in the Gladys
+Garber #1 well. During 2001, the well generated over $62,000 net to Gulfport's
+interest.
+Fee Minerals and Surface Interest
+Gulfport owns 230 net acres of fee minerals and surface interest adjacent
+to its West Hackberry Field in Cameron Parish, Louisiana. This property
+currently contains six producing wells.
+Castex Energy 1996 Limited Partnership
+Castex Back-In
+Gulfport sold its interest in the Bayou Penchant, Bayou Pigeon, Deer Island
+and Golden Meadow fields to Castex Energy 1996 Limited Partnership effective
+April 1, 1998 subject to a 25% reversionary interest in the partnership after
+Castex had received 100% of the initial investment. Castex informed Gulfport
+that the investment had paid out effective September 1, 2001. In lieu of a 25%
+interest in the partnership, Gulfport elected to take a proportionately reduced
+25% working interest in the properties. The Company now owns the following
+working interest in the subject fields:
+10
+Field Parish Working Interest
+Bayou Penchant Terrebonne 3.125%
+Bayou Pigeon Iberia 6.250%
+Deer Island Terrebonne 6.250%
+Golden Meadow Lafourche 3.125%
+In addition to the producing wells and associated leasehold rights,
+Gulfport has prepaid the drilling and completion costs of three new wells.
+Other Interests
+Litigation Trust
+Gulfport owns a 12% interest in the Trust (the "Litigation Trust") that was
+established in WRT's bankruptcy to pursue litigation connected with WRT.
+The Litigation Trust filed approximately 400 preference actions and
+several substantive actions alleging fraud, malpractice and other wrongdoings.
+At this time, Gulfport cannot estimate what the potential future recovery from
+the litigation will be.
+Oil and Gas Marketing
+Gulfport sells its oil and gas at the wellhead and does not refine
+petroleum products. Other than normal production facilities, Gulfport does not
+own an interest in any bulk storage facilities or pipelines. As is customary in
+the industry, Gulfport sells its production in any one area to relatively few
+purchasers, including transmission companies that have pipelines near Gulfport's
+producing wells. Gas purchase contracts are generally on a short-term "spot
+market" basis and usually contain provisions by which the prices and delivery
+quantities for future deliveries will be determined. The majority of Gulfport's
+crude oil production in 2001 was sold on contracts based on the average closing
+price on NYMEX for each trading day during the month of delivery.
+During 2001, oil sales to Gulfmark Energy Inc. accounted for 86% of
+Gulfport's oil sales. Gulfport had no other purchasers that accounted for
+greater than 10% of it's oil sales. Gulfport had no gas purchasers that
+accounted for more than 10% of it's total sales.
+Competition and Markets
+Availability of Markets. The availability of a ready market for any oil
+and/or gas produced by Gulfport depends on numerous factors beyond the control
+of 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 gas production and federal regulation of gas sold
+in interstate commerce. Oil and gas produced by Gulfport in Louisiana is sold to
+various purchasers who service the areas where Gulfport's wells are located.
+Gulfport's wells are not subject to any agreements that would prevent Gulfport
+from either selling its production on the spot market or committing such gas to
+a long-term contract; however, there can be no assurance that Gulfport will
+continue to have ready access to suitable markets for its future oil and gas
+production.
+Impact of Energy Price Changes. Oil and gas prices can be extremely
+volatile and are subject to substantial seasonal, political and other
+fluctuations. The prices at which oil and gas produced by Gulfport may be sold
+11
+is uncertain and it is possible that under some market conditions the production
+and sale of oil and gas from some or all of its properties may not be
+economical. The availability of a ready market for oil and gas and the prices
+obtained for such oil and gas, depend upon numerous factors beyond the control
+of Gulfport, including competition from other oil and gas suppliers and national
+and international economic and political developments. Because of all of the
+factors influencing the price of oil and gas, it is impossible to accurately
+predict future prices.
+Environmental Regulation
+Operations of Gulfport are subject to numerous federal, state and local
+laws and regulations governing environmental protection. Over the last several
+years, state and federal environmental laws and regulations have become more
+stringent and may continue to become more stringent in the future. These laws
+and regulations may affect Gulfport's operations and costs as a result of their
+affect on oil and gas development, exploration, and production operations. It is
+not anticipated that Gulfport will be required in the near future to expend
+amounts that are material in relation to its total capital expenditures program
+by reason of environmental laws and regulations, but inasmuch as such laws and
+regulations are frequently changed, Gulfport is unable to predict the ultimate
+cost of compliance.
+Operational Hazards and Insurance
+Gulfport's operations are subject to all of the risks normally incident to
+the production of oil and gas, including blowouts, cratering, pipe failure,
+casing collapse, oil spills and fires, each of which could result in severe
+damage to or destruction of oil and gas wells, production facilities or other
+property, or injury to persons. The energy business is also subject to
+environmental hazards, such as oil spills, gas leaks, and ruptures and discharge
+of toxic substances or gases that could expose Gulfport to substantial liability
+due to pollution and other environmental damage. Although Gulfport maintains
+insurance coverage considered to be customary in the industry for a company its
+size, it is not fully insured against certain of these risks, either because
+such insurance is not available or because of high premium costs. The occurrence
+of a significant event that is not fully insured against could have a material
+adverse effect on Gulfport's financial position.
+Headquarters and Other Facilities
+Gulfport leases office space in Oklahoma City, Oklahoma under a lease
+covering approximately 7,000 square feet. The monthly rent is approximately
+$13,000.
+In 1996, Gulfport purchased a building in Lafayette, Louisiana to be used
+as Gulfport's Louisiana headquarters. The 16 year-old building contains 12,480
+total square feet with 8,180 square feet of finished office area and 6,300
+square feet of clear span warehouse area. The mortgage balance was
+approximately $163,000 as of January 1, 2002 with an estimated fair market value
+of $350,000. This building allows Gulfport to provide office space for
+Louisiana personnel, have access to meeting space close to the fields and to
+maintain a corporate presence in Louisiana.
+Employees
+At December 31, 2001 Gulfport had 13 employees. A Louisiana well
+servicing company serves as contract operator of the fields and provides all
+necessary field personnel.
+12

raw/filings/0000874499/2001/0001060830-02-000041/item13.txt

@@ -0,0 +1,8 @@
+Item 13. Certain Relationships and Related Transactions
+In March 2001, a company that shares common ownership with Gulfport
+acquired a majority of the oil and natural gas properties of a mid-continent
+exploration and production company. Subsequent to the acquisition, Gulfport
+began providing administrative services to effectively manage the day-to-day
+operations of this acquisition and in turn receives an administrative service
+fee for such services.
+26

raw/filings/0000874499/2001/0001060830-02-000041/rp_note.txt

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+13. RELATED PARTY TRANSACTIONS
+In the ordinary course of business, the Company conducts business
+activities with a substantial number of its shareholders.
+DLB Oil & Gas, Inc. ("DLB") and Wexford Management LLC ("Wexford") were,
+along with Gulfport, co-proponents in a 1997 plan of reorganization. During
+April of 1998, DLB distributed all of its shares in the Company to its
+shareholders prior to DLB's acquisition by Chesapeake Energy Corporation. As a
+result of this distribution, Charles Davidson, Mike Liddell and Mark Liddell
+collectively received 37.5% of the Company's stock. As of December 31, 2001,
+Wexford and its affiliates owned approximately 17.7% of Gulfport's issued
+outstanding stock. Charles Davidson, Mike Liddell and the Estate of Mark Liddell
+own collectively 55.8% of the Company's outstanding stock as of December 31,
+2001.
+Administrative Service Agreement
+Pursuant to the terms and conditions of an Administrative Services
+Agreement, DLB agreed to make available to the Company personnel, services,
+facilities, supplies, and equipment as needed, including executive and
+managerial, accounting, auditing and tax, engineering, geological and
+geophysical, legal, land and administrative and clerical services. The initial
+term was one year beginning on the date of the Administrative Services
+Agreement. The Administrative Services Agreement was to continue for successive
+one-year periods unless terminated by either party. On April 28, 1998, in
+connection with the acquisition of DLB, Inc. by Chesapeake Energy Corporation,
+the obligations of DLB under the Administrative Services Agreement were assigned
+to DLB Equities, L.L.C.
+Gulfport paid fees under this agreement totaling $21,000 in 1999 and
+believes that such fees are comparable to those that would have been charged by
+an independent third party. Effective June of 1999, this Administrative Service
+Agreement was terminated.
+Stockholder Credit Facility
+On August 18, 1998, Gulfport entered into a $3,000,000 revolving credit
+facility with Liddell Investments, L.L.C., Liddell Holdings, L.L.C., CD
+Holdings, L.L.C. and Wexford Entities (collectively "Affiliated Stockholders").
+Borrowing under the Stockholder Credit Facility was due on August 17, 1999 and
+bore interest at LIBOR plus 3%. Pursuant to the facility agreement, Gulfport
+paid the eligible Affiliated Stockholders an aggregate commitment fee equal to
+$60,000. Gulfport repaid $2,000,000 of principal under the Amended ING Credit
+Agreement with borrowings under the Stockholder Credit Facility. The remaining
+$1,000,000 was used for working capital and general corporate purposes. The
+Affiliated Stockholders paid the subscription price for 1,200,000 shares
+pursuant to their Basic Subscription Privilege in the Rights Offering through
+F-16
+GULFPORT ENERGY CORPORATION
+NOTES TO FINANCIAL STATEMENTS
+DECEMBER 31, 2001, 2000 AND 1999
+CONTINUED
+the forgiveness of the amount owed to them under this stockholder credit
+facility.
+On August 5, 1999, Gulfport entered into a $3,255,000 revolving credit
+facility with the "Affiliated Stockholders". Borrowing under this agreement was
+due on August 1, 2000, and bore interest at LIBOR plus 3%. Pursuant to the terms
+of the agreement, Gulfport paid aggregate commitment fees equal to $65,000 or 2%
+of the related borrowings in stock. This debt was extinguished through the
+issuance of 4,040,011 shares of common stock to the Affiliated Stockholders in
+the Regulation D Offering in August 1999, and through the payment of additional
+funds totaling $208,000.

raw/filings/0000874499/2001/0001060830-02-000041/rpt_disclosure.txt

@@ -0,0 +1,8 @@
+Item 13. Certain Relationships and Related Transactions
+In March 2001, a company that shares common ownership with Gulfport
+acquired a majority of the oil and natural gas properties of a mid-continent
+exploration and production company. Subsequent to the acquisition, Gulfport
+began providing administrative services to effectively manage the day-to-day
+operations of this acquisition and in turn receives an administrative service
+fee for such services.
+26

raw/filings/0000874499/2007/0001193125-08-058618/filing_metadata.csv

@@ -0,0 +1,2 @@
+cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing
+0000874499,GPOR,GULFPORT ENERGY CORP,10-K,2008-03-17,2007-12-31,2008-03-17T17:59:04.000Z,0001193125-08-058618,d10k.htm,FORM 10-K,1199888,0,0,https://www.sec.gov/Archives/edgar/data/874499/000119312508058618/d10k.htm,https://www.sec.gov/Archives/edgar/data/874499/000119312508058618/,2007,2007,1

raw/filings/0000874499/2007/0001193125-08-058618/item1.txt

@@ -0,0 +1,470 @@
+ITEM 1. DESCRIPTION OF BUSINESS 
+General 
+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, or WCBB, and Hackberry fields. We have also recently acquired strategic assets in West Texas in the Permian Basin. 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.
+In 2007, at our WCBB field, we drilled 26 wells and recompleted 60 existing wells for a total cost of $57.9 million as of
+December 31, 2007. Of our 26 new wells drilled at WCBB in 2007, 22 were completed as producing wells and four were non-productive. As of March 1, 2008, we had drilled two new wells at WCBB, both of which are producing and had recompleted
+14 wells during 2008. During 2008, we intend to drill a total of eight to ten wells, recomplete 44 wells and conduct other activities at our WCBB field for an estimated aggregate cost of $21 to $23 million. In December 2007, production at WCBB was
+105,922 net barrels of oil equivalent, or BOE, or an average of 3,417 BOE per day, 93% of which was from oil and 7% of which was from natural gas. In February 2008, our average net daily production at WCBB was 3,622 BOE, 95% of which was from oil
+and 5% of which was from natural gas. 
+In 2007, at our East Hackberry field, we drilled nine wells in Lake Calcasieu and three wells on
+land and recompleted two existing wells for a total cost of $62.4 million as of December 31, 2007. Of the 12 wells drilled during 2007, ten were completed as producing wells and two were non-productive. As of March 1, 2008 at East
+Hackberry, we had drilled one additional well in Lake Calcasieu, which is now producing, and had recompleted three existing wells. We intend to drill three to five additional land wells, recomplete one additional well and conduct other activities in
+2008 for an aggregate estimated cost of $17 to $19 million. In December 2007, net production at East Hackberry was 26,850 BOE, or an average of 867 BOE per day, 70% of which was from oil and 30% of which was from natural gas. In February 2008, our
+average net daily production at East Hackberry was 735 BOE, 80% of which was from oil and 20% of which was from natural gas. 
+On
+December 20, 2007, we completed the acquisition of strategic assets in West Texas in the Permian Basin for approximately $85 million, with an effective date of November 1, 2007. Through this transaction, Gulfport acquired 4,100 net acres
+with production at the time of acquisition of approximately 800 net BOE a day from 32 gross wells, predominately from the Wolfcamp formation. Existing production is approximately 64% oil, 23% natural gas liquids and 13% natural gas. At
+December 31, 2007, Pinnacle Energy Services LLC, an independent petroleum engineering firm, estimated that proved reserves net to our interest in these assets were approximately 6.6 million BOE, of which 19.5% were classified as proved
+developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 92 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally
+characterized as long-lived, with predictable production profiles. We expect that approximately 17 to 22 net wells will be drilled on this acreage in 2008. The wells are expected to be drilled to approximately 10,200 feet at an estimated average
+gross completed well cost of $1.7 million. 
+During the third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings
+Inc., purchased a 24.9999% interest in Grizzly Oils Sands ULC, or Grizzly, a Canadian unlimited liability company. The remaining interests in Grizzly are owned by entities controlled by Wexford Capital LLC, or Wexford, an affiliate of ours. During
+2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. As of March 1, 2008, Grizzly had approximately 511,000 acres under lease. Grizzly
+drilled 62 core holes during the 2006/2007 winter delineation drilling season and tested three separate lease blocks. Future plans currently include acquiring additional leases, drilling approximately 55 to 60 additional core holes and a seismic
+program during the 2007/2008 winter drilling 
+2 
+Table of Contents 
+Index to Financial Statements 
+season and initial planning for the construction of a 10,000 barrel per day steam assisted gravity drainage facility, or SAGD, that could lead to initial
+production in 2011. Permitting for this initial SAGD facility is expected to commence later in 2008. 
+During 2005, we purchased a 23.5%
+ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, 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 three million acres which includes the Phu Horm Field. 
+As of December 31, 2007, we had 29.2 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future
+net revenues, discounted at 10%, or PV-10, of approximately $821million and associated standardized measure of discounted future net cash flows of approximately $668.3 million. See Item 2. “Properties—Proved Oil and Natural Gas
+Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. 
+Principal Oil and Natural Gas Properties 
+The following table presents certain information as of
+December 31, 2007 reflecting our net interest in our principal producing oil and natural gas properties along the Louisiana Gulf Coast and in the Permian Basin in West Texas. 
+Proved Reserves 
+Field 
+NRI/WI (1) 
+Producing 
+Wells (2) 
+Non-Producing 
+Wells 
+Developed 
+Acreage (3) 
+Gas 
+Oil 
+Total 
+Percentages 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Mboe 
+Mboe 
+Mboe 
+West Cote Blanche Bay (4) 
+78.665/100 
+111 
+111 
+166 
+166 
+5,668 
+5,668 
+15,891 
+15,135 
+17,783 
+E. Hackberry (5) 
+79.424/100 
+12 
+12 
+82 
+82 
+3,265 
+3,265 
+2,776 
+4,119 
+4,582 
+W. Hackberry 
+87.5/100 
+3 
+3 
+24 
+24 
+592 
+592 
+— 
+158 
+158 
+Permian 
+37.5/50 
+32 
+16 
+— 
+— 
+2,560 
+1,280 
+5,587 
+5,699 
+6,630 
+Overrides/Royalty Non-operated 
+Various 
+18 
+0.8 
+16 
+0.7 
+4,956 
+586 
+5 
+4 
+5 
+Total 
+176 
+142.8 
+288 
+272.7 
+17,041 
+11,391 
+24,259 
+25,115 
+29,158 
+(1) 
+Net Revenue Interest (NRI)/Working Interest (WI). 
+(2) 
+Includes 30 gross and net wells at WCBB that are producing intermittently. 
+(3) 
+Developed acres are acres spaced or assigned to productive wells. Approximately 87% of our acreage is developed acreage and has been perpetuated by production. We have 1,100 and
+2,820 net undeveloped acres in the East Hackberry field and the Permian Basin, respectively. 
+(4) 
+We have a 100% working interest (78.665% 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) 
+Does not include an additional 3,233 acres under an option we exercised which will increase our acreage position significantly to approximately 7,598 acres. State approval was
+obtained on February 27, 2008, and we are working with the state to finalize the leases. 
+3 
+Table of Contents 
+Index to Financial Statements 
+West Cote Blanche Bay Field 
+Location and Land 
+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 (78.665% 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. 
+Area History and Production 
+Texaco, now Chevron Corporation, drilled the discovery well in this
+field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells
+were drilled in the field. Of the 900 wells drilled as of December 31, 2007, 809 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in
+1997 through December 31, 2007, we drilled 120 new wells, 14 of which were non-productive, for an 88% success rate. As of December 31, 2007, estimated field cumulative gross production was 187.4 MMBOE and 235.5 billion cubic feet, or Bcf,
+of gas. Of the 900 wells drilled in WCBB as of December 31, 2007, 81 were producing, 166 were shut-in, 30 were producing intermittently and five were being used as salt water disposal wells. The other 618 wells have been plugged and abandoned.
+In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an
+undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The
+reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. 
+Geology 
+WCBB overlies one of the largest salt dome
+structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The
+compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults)
+was formed. 
+There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor
+discrete intervals have been tested. Within the 900 wellbores that had been drilled in the field as of December 31, 2007, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a
+strong water drive. 
+WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB
+are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been,
+and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of
+crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the
+mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an 
+4 
+Table of Contents 
+Index to Financial Statements 
+effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position
+within a particular zone. Our inventory of prospects includes 111 PUD wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2019. 
+Facilities 
+We own and operate a production facility at WCBB that includes four production tank
+batteries, six natural gas compressors, a dehydration unit and a salt water disposal system. 
+Recent and Future Activity 
+In 2007, we drilled 26 wells and recompleted 60 existing wells at WCBB. Of these 26 new wells, 22 were completed as producers, and four were
+non-productive. As of March 1, 2008, we had drilled two new wells, both of which are producing, and had recompleted 14 wells during 2008. Of the 22 wells completed in 2007, ten were considered deep wells. The 22 productive wells, with total
+depths ranging from 6,107 to 10,464 feet, have approximately 2,716 feet of aggregate apparent net pay. The other four wells were non-productive, including one exploratory well that was drilled to satisfy our drilling commitment with the State of
+Louisiana to hold the non-productive portions of WCBB. We anticipate drilling a total of eight to ten wells and recompleting 44 wells at WCBB during 2008. 
+Production Status 
+In December 2007, production at WCBB was 105,922 net BOE, or an average of 3,417 BOE per day, 93% of
+which was from oil and 7% of which was from natural gas. In February 2008, our average net daily production at WCBB was 3,622 BOE, 95% of which was from oil and 5% of which was from natural gas. 
+East Hackberry Field 
+Location and Land 
+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 79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold beneficial interests in approximately 4,365 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. In addition, we exercised our option to acquire an additional 3,233 acres at the Hackberry field. The option will
+increase our acreage position significantly to approximately 7,598 acres. State approval was obtained on February 27, 2008, and we are working with the state to finalize the leases. 
+Area History and Production 
+The East Hackberry field was discovered in 1926 by Gulf Oil Company, now
+Chevron Corporation, by a gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated
+cumulative oil and condensate production through 2007 was over 263,000 barrels of oil and 330 Bcf of casinghead gas production. There have been a total of 182 wells drilled on our portion of the field. As of December 31, 2007, 12 wells had
+daily production, 82 were shut-in and two had been converted to salt water disposal wells. The remaining 86 wells had been plugged and abandoned. 
+5 
+Table of Contents 
+Index to Financial Statements 
+Geology 
+The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern
+end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps
+for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. 
+Facilities 
+We have a field office that serves both the East and West Hackberry fields. In addition, we completed installation of a new production barge at the East
+Hackberry field in the second quarter of 2007. The barge is designed to have the ability to process on a per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high pressure natural gas, 6.5 Mmcf of low pressure natural gas and 10,000
+barrels of salt water. 
+Recent and Future Activity 
+During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry. Given that drilling activities at the East Hackberry field prior to our acquisition of the field in 1997 were undertaken
+without the benefit of modern seismic information, we believe that this 3-D seismic data will enhance our probability of drilling success. We continue to evaluate the 3-D seismic data to identify additional drilling locations. During 2007 at East
+Hackberry, we drilled nine wells in Lake Calcasieu and three wells on land and recompleted two existing wells. Of the 12 wells drilling during 2007, ten were completed as producing wells and two were non-productive. As of March 1, 2008 at East
+Hackberry, we had drilled one additional well in Lake Calcasieu, which is now producing, and had recompleted three existing wells. We intend to drill three to five additional land wells and recomplete one additional well at East Hackberry during
+2008. Drilling activity in this field during 2008 will target measured depths of up to 13,000 feet using directional drilling techniques. 
+Production
+Status 
+In December 2007, net production at East Hackberry was 26,850 BOE, or an average of 867 BOE per day, 70% of which was from oil
+and 30% of which was from natural gas. In February 2008, our average net daily production at East Hackberry was 735 BOE, 80% of which was from oil and 20% of which was from natural gas. 
+West Hackberry Field 
+Location and Land 
+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 87.5% NRI) in 592 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. 
+Area History 
+The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between
+1938 and 1988. The estimated cumulative oil and condensate production through 2007 was 227 MBOE and 140 Bcf of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 24 are shut-in and
+one has been converted to a saltwater disposal well. The remaining eight wells have been plugged and abandoned. 
+6 
+Table of Contents 
+Index to Financial Statements 
+Geology 
+Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and
+Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. 
+Production Status 
+In December 2007, net production at West Hackberry was 641 BOE, or 21 BOE per day.
+In February 2008, our average net daily production at West Hackberry was 21 BOE. 
+Facilities 
+We have land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both the East and West
+Hackberry fields. 
+Permian Basin (West Texas) 
+Location and Land 
+We acquired approximately 4,100 net acres in West Texas (near Midland) in the Permian Basin on
+December 20, 2007, effective date as of November 1, 2007, from ExL Petroleum, LP and certain other sellers. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major
+producing basins in the United States. The terrain in the Permian Bain is semi-arid mesquite-mixed grassland steppe. 
+Area History 
+The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a
+long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was
+not until the use of 3-D seismic in the 1990s that the greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300
+feet to pick up the upper part of the Wolfcamp formation. Henry Petroleum, a private firm, owned interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry decided to drill completely
+through the Wolfcamp section as Devonian wells. Henry mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry’s Wolfcamp team formed
+their own private company, ExL Petroleum, and began replicating Henry’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled
+us to participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. Currently, we hold interests in thirty-two gross producing wells. 
+Geology 
+The Wolfcamp/Spraberry play, which we refer
+to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The Wolfcamp is characterized by an approximately 2,000
+feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin Platform. 
+7 
+Table of Contents 
+Index to Financial Statements 
+Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% from the
+Spraberry section, consisting of approximately 64% oil, 23% natural gas liquids, and 13% natural gas. Pinnacle Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2007, proved reserves net to our
+interest in these assets were approximately 6.6 million BOE, of which 19.5% were classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 92 gross well locations on 40-acre
+units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally characterized as long-lived, with predictable production profiles. Wells to be drilled will be approximately 10,200 feet at an estimated average
+gross completed well cost of $1.7 million. The gross estimated ultimate recovery, or EUR, as estimated by Pinnacle Energy Services, LLC, is expected to average gross 146,000 BOE per well with an average net revenue interest in the field of
+approximately 75%. We have a 50% working interest and approximately 37.5% net revenue interest in the field. 
+Production Status 
+At the date of acquisition, there was production of approximately 800 net BOE a day from 32 gross, producing wells. During February 2008, average net
+production to Gulfport was 531 BOE a day. 
+Facilities 
+There are typical land oil and gas processing facilities in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent and Future Activity 
+We have identified 178
+gross future development drilling locations. We expect approximately 17 to 22 net wells to be drilled in 2008. The wells are expected to be drilled to approximately 10,200 feet at an estimated average gross completed well cost of $1.7 million.
+Additional Properties 
+Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana as described in the following table:
+Field 
+Parish 
+Acreage Working 
+Interest 
+Overriding Royalty 
+Interests 
+Producing 
+Wells 
+Non-Producing 
+Wells 
+Bayou Long 
+Iberia 
+3.125 
+% 
+0 
+% 
+0 
+0 
+Bayou Penchant 
+Terrebonne 
+3.125 
+% 
+0 
+% 
+2 
+5 
+Bayou Pigeon 
+Iberia 
+6.250 
+% 
+0 
+% 
+5 
+5 
+Deer Island 
+Terrebonne 
+6.250 
+% 
+0 
+% 
+0 
+6 
+Golden Meadow 
+Lafourche 
+3.125 
+% 
+0 
+% 
+0 
+1 
+Napoleonville 
+Assumption 
+0 
+% 
+2.5 
+% 
+3 
+0 
+Thailand . During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC,
+or Tatex, at a cost of $2,400,000. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, 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 three million acres which includes the Phu Horm Field. During the year ended December 31, 2007, we paid $88,000 in cash calls,
+bringing our total investment in Tatex (including previous investments) to $3,553,000. Our investment is accounted for on the equity method. Tatex accounts for its investment in APICO using the cost method. In December 2006, first gas sales were
+achieved at the Phu Horm field located in northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet per day. Current net production is approximately 100 Mcf per day. Hess Corporation operates the field
+with a 
+8 
+Table of Contents 
+Index to Financial Statements 
+35% interest. Other interest owners include APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest (through
+Tatex as a member of APICO) in the Phu Horm field is 0.7%. Proved reserves from the Phu Horm field, net to our interest, are 3.5 BCF of gas and 10,000 barrels of oil. Due to the fact that our ownership in the Phu Horm field is indirect and
+Tatex’s investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. 
+Williston Basin . During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by entities controlled by Wexford. In 2005 and 2006, Bakken acquired leases on
+undeveloped acreage in the Williston Basin areas of western North Dakota and eastern Montana. At December 31, 2007, our net investment in Bakken was $2,468,000. We are currently participating in the drilling of nine wells and have interests in
+eight producing wells with an average working interest of 1.55%. 
+Marquiss Field . In February 2005, but effective as of
+December 1, 2004, we acquired our interest in the Marquiss field, an approximately 9,500 net acre coalbed methane play in Campbell County, Wyoming, for $375,000. As of December 31, 2006, the Marquiss field included a total of 162 wells,
+all of which were shut-in as a result of the economic status of the field as a result of a decline in natural gas prices for this field. The wells (when on line) produced from multiple horizons with additional upside potential from deeper coals and
+operational efficiencies. Our interest in the Marquiss field was sold in February 2007 for $500,000. 
+Grizzly Oil Sands . During the
+third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and 2007, Grizzly acquired
+leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 511,000 acres under lease and our total net investment in Grizzly was $27,801,000 at
+December 31, 2007. Grizzly drilled 62 core holes during the 2006/2007 winter delineation drilling season and tested three separate lease blocks using up to four different rigs. Future plans currently include acquiring additional leases,
+drilling approximately 55 to 60 additional core holes and a seismic program during the 2007/2008 winter drilling season and initial planning for the construction of a 10,000 barrel per day SAGD facility that could lead to initial production in 2011.
+Gross capital expenditures for such a production facility are currently estimated to be approximately $325 million. 
+Competition and Markets
+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. 
+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 is being sold in accordance with the posted price for West Texas/New Mexico Intermediate crude plus Platt’s trade month
+average P+ value, plus or minus the Platt’s WII/LLS differential less $3.70 per barrel for transportation. During 2007, we sold 99% of our oil production to Shell and 69% of our natural gas production to Chevron and 23% of our natural gas
+production to Hilcorp Energy Company and during 2006, we sold 100% of our oil production to Shell and 96% 
+9 
+Table of Contents 
+Index to Financial Statements 
+of our natural gas production to Chevron. During 2005, we sold 99% of our oil production to Shell and 88% of our natural gas production to Chevron. There can
+be no assurance, however, that we will continue to have ready access to suitable markets for our future oil and natural gas production. 
+Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The prices at which the oil and natural gas we produce may be sold is uncertain and it is possible that under
+some market conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is impossible to accurately predict future
+prices. 
+To mitigate the effects of commodity price fluctuations, during 2007, we entered into forward sales contracts for the sale of
+3,000 barrels of production per day for the month of June 2007 at a weighted average daily price of $70.15 per barrel before transportation costs. For the period of July 2007 through December 2007, we entered into forward sales contracts for the
+sale of 3,500 barrels of production per day at a weighted average daily price of $70.29 per barrel before transportation costs. In addition, we have entered into agreements to sell 3,500 barrels of production per day for the months of January
+through May 2008 at a weighted average daily price of $70.29 per barrel before transportation costs. For the month of June 2008, we have agreements to sell 3,500 barrels of production per day at a weighted average daily price of $71.69 per barrel
+before transportation costs. For the month of July 2008, we have agreements to sell 3,000 barrels of production per day at a weighted average daily price of $81.37 per barrel before transportation costs. For August 2008, we have agreements to sell
+3,000 barrels of production per day at a weighted average daily price of $82.44 per barrel before transportation costs. For the periods of September 2008 through December 2008, we have entered into forward sales contracts for the sale of 3,000
+barrels of production per day in each such period at weighted average daily prices of $82.20 per barrel before transportation costs. Under these agreements we have committed to deliver approximately 60% of our estimated production for January
+through December 2008. For the period of January through December 2009, we entered into agreements to sell 2,500 barrels of production per day at a weighted average daily price of $84.62 per barrel before transportation costs. 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. These contracts require physical delivery of production quantities and are exempted from the provisions
+of SFAS 133 as normal sales of production. In addition, these arrangements may limit the benefit to us of increases in the price of oil. 
+Regulation
+Regulation of Gas and Oil Production 
+Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry
+is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently,
+affects our profitability. 
+We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast
+and West Texas. These states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations
+governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. 
+Environmental Regulation 
+Our oil and natural gas
+exploration, development and production operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous
+governmental agencies, such as the U.S. Environmental Protection Agency, or EPA, issue regulations to implement and enforce such laws, which often require difficult 
+10 
+Table of Contents 
+Index to Financial Statements 
+and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to
+comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and
+production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or
+former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations. The strict liability nature of such laws and regulations could impose liability upon us regardless
+of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations
+and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with current applicable environmental laws and regulations and we have not experienced any material adverse
+effect from compliance with these environmental requirements; this trend, however, may not continue in the future. 
+Waste Handling .
+The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the
+generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more
+stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that
+are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes
+or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous
+wastes.” 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We
+believe that we are in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our
+operations require them under such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural
+gas exploration and production wastes could increase our costs to manage and dispose of such wastes. 
+Comprehensive Environmental
+Response, Compensation and Liability Act . The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law, generally imposes joint and several liability, without regard to fault or
+legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner
+or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance. Under CERCLA and comparable state statutes, such persons may be subject to strict joint and several
+liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners
+and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials, that, if released, would be subject to
+CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous
+substances” have been deposited. 
+11 
+Table of Contents 
+Index to Financial Statements 
+Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the
+Clean Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other gas and oil wastes, into state
+waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These proscriptions also prohibit certain activity in wetlands
+unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be
+associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. We believe that we have obtained or applied for and are in substantial compliance with all permits required under the Clean Water Act.
+Sanctions for failure to comply with Clean Water Act requirement include administrative, civil and criminal penalties, as well as injunctive obligations. 
+Air Emissions . The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The
+EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for our
+facilities’ operations, and existing facilities may be required to incur capital costs to remain in compliance. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state
+regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial
+compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas
+projects. 
+Operational Hazards and Insurance 
+Our operations are subject to all of the risks normally incident to the production of oil and natural gas, including blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which could result in severe damage to or
+destruction of oil and natural gas wells, production facilities or other property, or injury to persons. The energy business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharge of toxic substances or
+gases that could expose us to substantial liability due to pollution and other environmental damage and consequences thereof, including personal injuries and property damage. We currently maintain insurance covering some, but not all of these risks.
+The occurrence of a significant event that is not fully insured against could have a material adverse effect on our financial position. 
+Headquarters
+and Other Facilities 
+We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate
+headquarters. We lease a portion of this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This building contains approximately
+6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for
+its use. 
+Employees 
+At
+December 31, 2007, we had 70 employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the
+estimated time they spent working for those affiliates. In addition, in the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For the years ended December 31, 2007 and 2006, expenses reimbursed
+to us under these arrangements were 
+12 
+Table of Contents 
+Index to Financial Statements 
+$11,153,000 and $12,738,000, respectively, and are reflected as a reduction in our general and administrative expenses. A Louisiana well servicing company
+provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. 
+Available Information 
+Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished
+pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with,
+or furnished to, the Securities and Exchange Commission, or SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be
+considered part of this report or any other filing that we make with the SEC.

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+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive Information Statement, which will be filed with the Securities and Exchange
+Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).

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+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+Evaluation of
+Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to
+be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and
+procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding
+required disclosures. 
+As of December 31, 2007, an evaluation was performed under the supervision and with the participation of
+management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of
+1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2007, our disclosure controls and procedures are effective. 
+Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that
+occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. 
+Management’s Report on Internal Control Over Financial Reporting 
+Management is responsible for the fair presentation
+of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the
+Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the
+preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal
+control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. 
+Management conducted
+an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its
+evaluation under the framework in Internal Control—Integrated Framework, management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was
+effective as of December 31, 2007. 
+Grant Thornton LLP, the independent registered public accounting firm that audited our financial
+statements for the year ended December 31, 2007 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2007, as stated in their accompanying report. 
+/s/ James D. Palm 
+/s/ Michael G. Moore 
+Name: 
+James D. Palm 
+Name: 
+Michael G. Moore 
+Title: 
+Chief Executive Officer 
+Title: 
+Chief Financial Officer 
+48 
+Table of Contents 
+Index to Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Gulfport Energy Corporation: 
+We have audited internal control over
+financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
+Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over
+financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we
+plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial
+reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the
+circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a
+process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s
+internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the
+company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company
+are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the
+company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial
+reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance
+with the policies or procedures may deteriorate. 
+In our opinion, the Company maintained, in all material respects, effective internal control over
+financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by COSO. 
+We
+have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2007 and 2006, and the related consolidated statements of
+operations, stockholders’ equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2007 and our report dated March 17, 2008 expressed an unqualified opinion. 
+/s/ GRANT THORNTON LLP 
+Oklahoma City, Oklahoma 
+March 17, 2008

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+Certain Relationships and Related Transactions 
+Administrative Services Agreements 
+We are a party to administrative service agreements with Diamondback Energy Services LLC,
+which we refer to as Diamondback, Great White Energy Services LLC, which we refer to as Great White, Caliber Development Company, LLC, which we refer to as Caliber, Stampede Investments LLC, which we refer to as Stampede, and Grizzly Oil Sands ULC,
+which we refer to as Grizzly, which agreements were entered into effective as of September 29, 2006, July 26, 2006, February 9, 2005, November 1, 2007 and November 15, 2007, respectively. Under these
+agreements, our services include accounting, human resources, legal and technical support. The services provided to these entities and the fees for such services can be amended by mutual agreement of the parties to these agreements. Each
+administrative services agreement has a three-year term, and upon expiration of that term the agreement will continue on a month-to-month basis until cancelled by either party to such agreement with at least 30 days prior written notice. Each
+administrative services agreement is terminable (1) by the counterparty at any time with at least 30 days prior written notice to us and (2) by either party if the other party is in material breach and such breach has not been cured within
+30 days of receipt of written notice of such breach. Each of Diamondback, Great White, Caliber, Stampede and Grizzly reimbursed us for our dedicated employee time and related general and administrative costs based on the proportionate amount of time
+our employees spent performing services for such entity. We were reimbursed approximately $17,000, $754,000, $1,249,000, $123,000 and $953,000 by Diamondback, Great White, Caliber, Stampede and Grizzly, respectively, for services provided under
+these agreements during the year ended December 31, 2007. Each of Diamondback, Great White, Caliber, Stampede and Grizzly is controlled by Wexford Capital LLC. Charles Davidson, who beneficial owned approximately 35.7% of our outstanding common
+stock as of April 23, 2008, is the Chairman and Chief Investment Officer of Wexford Capital LLC. Our Chairman of the Board, Mike Liddell, is also the Chairman of the Board of Diamondback Energy Services, Inc., a subsidiary of Diamondback. Two
+of our directors, Scott Streller and Donald L. Dillingham, are also director nominees of Diamondback Energy Services, Inc. 
+We provide office space,
+furniture, telecommunications and computer and other information technology support to certain employees of Windsor Energy Resources LLC, or Windsor. Windsor has agreed to reimburse us for such services based on the number of employees we office and
+nature of services provided by us to such employees, which can vary from time to time. Windsor is controlled by Wexford Capital LLC. 
+Two of our petroleum
+engineers are providing services relating to evaluation of potential investments to Wexford Capital LLC and geological evaluations, seismic review and similar services to Tatex Thailand II, LLC, or Tatex II, and Tatex Thailand III LLC, or Tatex III.
+Wexford Capital LLC, Tatex II and Tatex III, respectively, have agreed to reimburse us based on the amount, scope and nature of services provided by our petroleum engineers to such entities, which can vary from time to time. Tatex II and Tatex III
+are controlled by Wexford Capital LLC. 
+We provide certain general and administrative services to Floran Technologies LLC, or Floran. We are reimbursed for
+our dedicated employee time and related general and administrative costs based on the proportionate amount of time our employees spent performing such services. For the year ended December 31, 2007, we were reimbursed approximately $61,000 by
+Floran and were owed an additional $31,000 for such services at that date. 
+Services Provided to Us by Our Affiliates 
+We contract with Athena Construction, L.L.C. to provide barge services in our West
+Cote Blanche Bay, or WCBB, and Hackberry fields located along the Louisiana Gulf Coast. In January 31, 2006, Athena was acquired by an entity controlled by Wexford Capital LLC. For the year ended December 31, 2007, we paid Athena
+$5,902,000 and owed an additional $1,561,000 for such services at that date. 
+26 
+Table of Contents 
+In February 2005, but effective as of December 1, 2004, we acquired an interest in the Marquiss field, an
+approximately 9,500 net acre coalbed methane play in Campbell County, Wyoming. Windsor Energy Group, LLC, an entity controlled by Wexford Capital LLC, was the operator of this field. For the year ended December 31, 2007, we paid Windsor Energy
+Group $363,000 and owed an additional $440,000 related to reimbursement for services provided. Our interest in the Marquiss field was sold in February 2007. 
+Packers & Service Tools, Inc., which we refer to as Packers, performs services for us at our WCBB and Hackberry fields. For the year ended December 31, 2007, we paid Packers $1,406,000 and owed an additional $425,000 related
+to these services at that date. Packers is an entity controlled by Wexford Capital LLC. 
+Diamondback Completions LLC, which we refer to as Completions,
+performs services for us at our WCBB and Hackberry fields. For the year ended December 31, 2007, we paid Completions $278,000 and owed an additional $241,000 related to these services at that date. Completions is an entity controlled by Wexford
+Capital LLC. 
+Great White Towing LLC, which we refer to as Towing, performs services for us at our WCBB field. For the year ended December 31, 2007,
+we paid Towing $95,000 and owed an additional $50,000 related to these services at that date. Towing is an entity controlled by Wexford Capital LLC. 
+Effective March 1, 2008, Windsor provides tax planning, preparation of supporting tax schedules and consultation services to us, based on agreed upon fee structure. The scope of such services can be modified upon mutual agreement of
+the parties. Windsor is controlled by Wexford Capital LLC. 
+Caliber provides building maintenance services for our headquarters in Oklahoma City, Oklahoma.
+For the year ended December 31, 2007, we paid Caliber $14,000 and owed an additional $3,000 related to these services at that date. Caliber is an entity controlled by Wexford Capital LLC. 
+Our Investments in Affiliates and Related Agreements 
+During 2005, we purchased a 23.5% ownership interest in Tatex II at a
+cost of $2,400,000. The remaining interests in Tatex II are owned by other entities controlled by Wexford Capital LLC. Tatex II, a privately-owned 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 three million acres which includes the Phu Horm Field. During 2007, we paid $88,000 in cash calls in respect of our
+investment in Tatex II. 
+During 2008, we purchased a 5% ownership interest in Tatex III at a cost of $850,000. Approximately 68.7% of the remaining
+interests in Tatex III are owned by other entities and individuals affiliated with Wexford Capital LLC. 
+During 2005, we purchased a 20% ownership interest
+in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by other entities controlled by Wexford Capital LLC. In 2006, Bakken acquired leases on undeveloped acreage in the Williston Basin areas of western North Dakota and
+eastern Montana, which we refer to as the contract area. During 2007, we paid $127,000 in respect of our interest in Bakken. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our
+20% interest in Bakken. 
+In addition, effective January 1, 2008, we entered into an area of mutual interest agreement with Bakken and Windsor Dakota
+LLC, or Windsor Dakota, to jointly acquire oil and gas leases on certain lands located in North Dakota and Montana for the purpose of exploring, exploiting and producing oil and gas from the Bakken Shale. The agreement provides that each party must
+offer the other party the right to participate in such acquisition in proportion to its participating interest, which is 20% for us and 80% for Bakken and Windsor Dakota, collectively. The parties also agreed, subject to certain exceptions, to share
+third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, we, Bakken, Windsor Dakota and Windsor Energy Group, L.L.C., as the
+operator, also entered into the exploration agreement, effective as of January 1, 2008, pursuant to which we, Bakken and Windsor Dakota agreed to jointly evaluate, explore, exploit and develop the contract area, and 
+27 
+Table of Contents 
+Windsor Energy Group, L.L.C. agreed to act as the operator under the terms of a joint operating agreement, effective as of March 4, 2008. In the event
+Gulfport has greater than a 50% interest in a prospect, as defined in the exploration agreement, the parties agreed to support Gulfport as the operator. The parties agreed to pay Windsor Energy Group, L.L.C. for its services as the operator with
+respect to the contract area as provided in the joint operating agreement. 
+During the third quarter of 2006, we purchased, through our wholly owned
+subsidiary Grizzly Holdings, Inc., a 24.9999% interest in Grizzly, a Canadian unlimited liability company, for approximately $8,200,000. The remaining interests in Grizzly are owned by other entities controlled by Wexford Capital LLC. During 2006,
+Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of other existing oil sands projects. Grizzly has commenced drilling of core holes for feasibility of oil production in three
+separate lease blocks but has not commenced development of operations. As of December 31, 2007, our net investment in Grizzly was $27,801,000. 
+At
+December 31, 2007, our wholly owned subsidiary, Grizzly Holdings Inc., owed Grizzly approximately $151,000 for shares issued in 2007. 
+Option and Purchase Agreement and Related Agreements 
+On November 30, 2007, we entered into an option agreement with
+Windsor Permian LLC, an entity controlled by Wexford Capital LLC, which we refer to as Windsor Permian. Under the option agreement, we were granted the right to participate on a 50/50 basis with Windsor Permian in the acquisition of certain
+strategic assets in Upton County, Texas in the Permian Basin. We paid Windsor Permian $8.5 million for the option, which amount was applied to our portion of the purchase price for the acquisition. On December 12, 2007, we exercised the option
+and on December 18, 2007, the purchase agreement was amended to, among other things, add Gulfport as a buyer under the purchase agreement. On December 20, 2007, the acquisition was closed, effective as of November 1, 2007. We and
+Windsor Permian also agreed to share equally all third-party costs and expenses incurred by each of us in connection with the transaction, none of which had been paid as of December 31, 2007. 
+In addition, effective as of November 1, 2007, we and Windsor Permian entered into an area of mutual interest agreement to jointly acquire oil and gas leases in the
+Permian Basin. The agreement provides that each party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain exceptions, to share third-party costs and expenses in proportion
+to their respective participating interests and pay certain other fees as provided in the agreement. On March 20, 2008, in connection with this agreement, we received a six-month option to acquire a direct, undivided interest of up to 25% in
+Windsor Permian’s oil and gas interests acquired on February 29, 2008 in Midland County, Texas. The option price is the sum of (i) the option percentage of the acquisition consideration paid by Windsor Permian to a third party in
+connection with the acquisitions of these assets, subject to certain exceptions, (ii) a fee equal to 1% of our purchase price, (iii) the option percentage of the sum of all third-party costs and expenses incurred by Windsor Permian in
+connection with the acquisition of these assets, subject to certain exceptions, (iv) the option percentage of all capital costs and lease operating expenses incurred subsequent to Windsor Permian’s acquisition of these assets and prior to
+the date of the option exercise by Gulfport, subject to certain exceptions, and (v) interest, at 8% per annum, on the amounts set forth in items (i), (iii) and (iv) calculated from the time of accrual to the closing date of the
+option. 
+In connection with the Area of Mutual Interest Agreement, we, Windsor Permian and Windsor Energy Group, L.L.C., as the operator, entered into the
+joint development agreement, effective as of November 1, 2007, pursuant to which we and Windsor Permian agreed to develop certain jointly held oil and gas leases in the Permian Basin, and Windsor Energy Group, L.L.C. agreed to act as the
+operator under the terms of the joint operating agreement, effective as of November 1, 2007. In the event either party has greater than a 50% interest in a prospect, as defined in the development agreement, the majority party may designate the
+operator of its choice. The parties agreed to pay Windsor Energy Group, L.L.C. for its services as the operator with respect to the contract area as provided in the joint operating agreement. 
+28 
+Table of Contents

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+ITEM 1. 
+DESCRIPTION OF BUSINESS 
+General 
+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, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, and
+in the Bakken Shale, 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. 
+In 2008, at our WCBB field, we drilled eight wells and recompleted 48 existing wells for a total cost of approximately $31.0 million as of
+December 31, 2008. Of our eight new wells drilled at WCBB in 2008, seven were completed as producing wells and one was non-productive. During 2009, we currently anticipate drilling four wells and recompleting 20 wells at our WCBB field for an
+estimated aggregate cost of $7.5 to $8.5 million. In December 2008, production at WCBB was 109,292 net barrels of oil equivalent, or BOE, or an average of 3,526 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From
+January 1, 2009 through March 9, 2009, our average net daily production at WCBB was 3,037 BOE, 99% of which was from oil and 1% of which was from natural gas. 
+In 2008, at our East Hackberry field, we drilled five wells and recompleted seven existing wells for a total cost of approximately $18.0 million as of December 31, 2008. All five wells drilled during 2008 were
+completed as producing wells. During 2009, we currently anticipate drilling four land wells and recompleting three wells for an aggregate estimated cost of $4.5 to $5.5 million. In December 2008, net production at East Hackberry was 12,243 BOE, or
+an average of 395 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From January 1, 2009 through March 9, 2009, our average net daily production at East Hackberry was 439 BOE, 95% of which was from oil and 5% of
+which was from natural gas. 
+On December 20, 2007, we completed the acquisition of strategic assets in West Texas in the Permian Basin
+for approximately $83.8 million, with an effective date of November 1, 2007. Through this transaction, we acquired 4,100 net acres with production at the time of acquisition of approximately 800 net BOE a day from 32 gross wells, predominately
+from the Wolfcamp formation. In 2008, 31 gross (15.5 net) wells were drilled on this acreage, including one gross well spud in 2007 and completed in 2008 and one Henry Petroleum operated well for a total cost of approximately $33.9 million. As of
+March 1, 2009, 29 of the 31 wells had been completed and the other two wells were awaiting completion. We currently anticipate drilling three gross (1.5 net) wells on this acreage in 2009 for an estimated average completed gross well cost of
+$1.34 million. In December 2008, net production from our Permian acreage was 26,943 BOE, or an average of 869 BOE per day, 84% of which was from oil and natural gas liquids and 16% of which was from natural gas. From January 1, 2009 through
+March 9, 2009, our average daily net production from our Permian acreage was 725 BOE per day, 83% of which was from oil and natural gas liquids and 17% of which was from natural gas. 
+During the third quarter of 2006, we, through our wholly owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly. The remaining
+interests in Grizzly are owned by entities controlled by Wexford Capital LLC, or Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development
+projects. Grizzly has approximately 511,000 acres under lease and our total net investment in Grizzly was $21.9 million at December 31, 2008. During the 2006/2007 and 2007/2008 winter delineation drilling seasons, Grizzly drilled an aggregate
+of 117 core holes, tested five separate lease blocks using up to four different rigs and undertook a seismic program. Grizzly’s 2009 plans currently include drilling 15 additional core holes, which were completed in the first quarter of 2009
+for approximately $4.3 million. 
+2 
+Table of Contents 
+During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining
+interests in Tatex are owned by entities controlled by Wexford. Tatex, 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 three million acres which includes the Phu Horm Field. 
+During
+2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by entities controlled by Wexford. In 2006, Bakken acquired leases for undeveloped acreage in the Williston Basin area of
+western North Dakota and eastern Montana. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. As of December 31, 2008, we had participated, or
+committed to participate, in 53 gross wells in the Williston Basin with an average working interest of 2.52%. In December 2008, net production from this acreage was 8,692 BOE, or an average of 280 BOE per day. From January 1, 2009 through
+March 9, 2009, our average net daily production from this acreage was 271 BOE and was 100% oil. Plans for 2009 currently include drilling approximately 0.5 net wells for an estimated net cost of $2.5 million. 
+As of December 31, 2008, we had 25.5 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future
+net revenues, discounted at 10%, or PV-10, of approximately $126.2 million and associated standardized measure of discounted future net cash flows of approximately $126.2 million. See Item 2. “Properties—Proved Oil and Natural Gas
+Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. 
+Principal Oil and Natural Gas Properties 
+The following table presents certain information as of
+December 31, 2008 reflecting our net interest in our principal producing oil and natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas and in the Williston Basin. 
+Proved Reserves 
+Field 
+NRI/WI (1) 
+Producing 
+Wells (2) 
+Non-Producing 
+Wells 
+Developed 
+Acreage (3) 
+Gas 
+Oil 
+Total 
+Percentages 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Mboe 
+Mboe 
+Mboe 
+West Cote Blanche Bay (4) 
+80.335/100 
+107 
+107 
+158 
+158 
+5,668 
+5,668 
+2,009 
+11,391 
+13,400 
+E. Hackberry (5) 
+79.424/100 
+18 
+18 
+80 
+80 
+3,291 
+3,291 
+282 
+2,441 
+2,723 
+W. Hackberry 
+87.5/100 
+3 
+3 
+24 
+24 
+592 
+592 
+— 
+132 
+132 
+Permian 
+38.075/49.48 
+61 
+30.5 
+— 
+— 
+8,075 
+4,150 
+1,367 
+7,028 
+8,395 
+Bakken (6) 
+2.285/2.181 
+38 
+0.8 
+— 
+— 
+8,153 
+891 
+47 
+776 
+823 
+Overrides/Royalty Non-operated 
+Various 
+9 
+.5 
+17 
+.8 
+4,956 
+586 
+1 
+3 
+4 
+Total 
+236 
+159.8 
+279 
+262.8 
+30,735 
+15,178 
+3,706 
+21,771 
+25,477 
+(1) 
+Net Revenue Interest (NRI)/Working Interest (WI). 
+(2) 
+Includes 30 gross and net wells at WCBB that are producing intermittently. 
+(3) 
+Developed acres are acres spaced or assigned to productive wells. Approximately 42% of our acreage is developed acreage and has been perpetuated by production.
+(4) 
+We have a 100% working interest (80.335% 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) 
+NRI/WI is from wells that have been drilled or in which we have elected to participate. 
+3 
+Table of Contents 
+West Cote Blanche Bay Field 
+Location and Land 
+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 (80.335% 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. 
+Area History and Production 
+Texaco, now Chevron Corporation, drilled the discovery well in this
+field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells
+were drilled in the field. Of the 908 wells drilled as of December 31, 2008, 816 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in
+1997 through December 31, 2008, we drilled 128 new wells, 15 of which were non-productive, for an 88% success rate. As of December 31, 2008, estimated field cumulative gross production was 188.6 MMBOE and 235.9 billion cubic feet, or Bcf,
+of gas. Of the 908 wells drilled in WCBB as of December 31, 2008, 77 were producing, 158 were shut-in, 30 were producing intermittently and five were being used as salt water disposal wells. The other 638 wells have been plugged and abandoned.
+In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an
+undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The
+reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. 
+Geology 
+WCBB overlies one of the largest salt dome
+structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The
+compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults)
+was formed. 
+There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor
+discrete intervals have been tested. Within the 908 wellbores that had been drilled in the field as of December 31, 2008, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a
+strong water drive. 
+WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB
+are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been,
+and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of
+crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the
+mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to
+wells 
+4 
+Table of Contents 
+that produced from a sub-optimal position within a particular zone. Our inventory of prospects at WCBB as of December 31, 2008 included 81 PUD wells.
+The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2019. 
+Facilities 
+We own and operate a production facility at WCBB that includes four production tank batteries, six natural gas compressors, a dehydration unit and a salt
+water disposal system. 
+Recent and Future Activity 
+In 2008, we drilled eight wells and recompleted 48 existing wells at WCBB. Of these eight new wells, seven were completed as producers, and one was non-productive. As of March 1, 2009, we had recompleted seven
+wells during 2009. Of the eight wells drilled in 2008, all eight were considered deep wells. The seven productive wells, with total depths ranging from 6,900 to 9,600 feet, have approximately 824 feet of aggregate apparent net pay. We currently
+anticipate drilling four wells and recompleting 20 wells at WCBB during 2009. 
+Production Status 
+In December 2008, production at WCBB was 109,292 net BOE, or an average of 3,526 BOE per day, 98% of which was from oil and 2% of which was from natural
+gas. From January 1, 2009 through March 9, 2009, our average net daily production at WCBB was 3,037 BOE, 99% of which was from oil and 1% of which was from natural gas. 
+East Hackberry Field 
+Location and Land 
+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 79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold beneficial interests in approximately 7,233 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. 
+Area History and
+Production 
+The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly
+survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through
+2008 was over 409,701 barrels of oil and 330 Bcf of casinghead gas production. A total of 187 wells have been drilled on our portion of the field. As of December 31, 2008, 18 wells had daily production, 80 were shut-in and two had been
+converted to salt water disposal wells. The remaining 86 wells had been plugged and abandoned. 
+Geology 
+The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field
+entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault
+blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. 
+5 
+Table of Contents 
+Facilities 
+We have a field office that serves both the East and West Hackberry fields. In addition, we completed installation of a new production barge at the East Hackberry field in the second quarter of 2007. The barge is designed to have the
+ability to process on a per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high pressure natural gas, 6.5 Mmcf of low pressure natural gas and 10,000 barrels of salt water. 
+Recent and Future Activity 
+During 2005, we completed a proprietary 42 square mile 3-D seismic survey
+at East Hackberry. Given that drilling activities at the East Hackberry field prior to our acquisition of the field in 1997 were undertaken without the benefit of modern seismic information, we believe that this 3-D seismic data will enhance our
+probability of drilling success. We continue to evaluate the 3-D seismic data to identify additional drilling locations. During 2008 at East Hackberry, we drilled four land wells and one well on water and recompleted seven existing wells. All of the
+five wells drilled during 2008 were completed as producing wells. As of March 1, 2009, we had recompleted three wells during 2009. We currently intend to drill four land wells and have recompleted three wells at East Hackberry during 2009.
+Production Status 
+In December 2008,
+net production at East Hackberry was 12,243 BOE, or an average of 395 BOE per day, 98% of which was from oil and 2% of which was from natural gas. From January 1, 2009 through March 9, 2009, our average net daily production at East
+Hackberry was 439 BOE, 95% of which was from oil and 5% of which was from natural gas. Production has increased since year end as a result of mechanical well enhancements. 
+West Hackberry Field 
+Location and Land 
+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 87.5% NRI) in 592 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. 
+Area History 
+The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between
+1938 and 1988. The estimated cumulative oil and condensate production through 2008 was 242 MBOE and 140 Bcf of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 24 are shut-in and
+one has been converted to a saltwater disposal well. The remaining eight wells have been plugged and abandoned. 
+Geology 
+Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West
+Hackberry consists of a series of fault-bounded traps in the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production
+of almost 700 MBOE. 
+Production Status 
+In December 2008, net production at West Hackberry was 763 BOE, or 25 BOE per day. From January 1, 2009 through March 9, 2009, our average net daily production at West Hackberry was 34 BOE and was 100% oil. 
+6 
+Table of Contents 
+Facilities 
+We have land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both the East and West Hackberry fields. 
+Permian Basin (West Texas) 
+Location and Land 
+We acquired approximately 4,100 net acres in West Texas (near Midland) in the Permian Basin on December 20, 2007, effective date as of
+November 1, 2007, from ExL Petroleum, LP and certain other sellers. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. The
+terrain in the Permian Basin is semi-arid mesquite-mixed grassland steppe. Windsor Energy is the operator of this field. 
+Area History 
+The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a
+long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was
+not until the use of 3-D seismic in the 1990s that the greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300
+feet to pick up the upper part of the Wolfcamp formation. Henry Petroleum, a private firm, owned interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill
+completely through the Wolfcamp section as Devonian wells. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry
+Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize
+approximately 15% of their acreage position which enabled us to participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. Currently, we hold
+interests in 61 gross producing wells. 
+Geology 
+The Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The
+Wolfcamp is characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin
+Platform. 
+Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% from the Spraberry section. Pinnacle
+Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2008, proved reserves net to our interest in these assets were approximately 8.4 million BOE, of which 25% were classified as proved
+developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 115 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally
+characterized as long-lived, with predictable production profiles. The gross estimated ultimate recovery, or EUR, as estimated by Pinnacle Energy Services, LLC, is expected to average gross 145,000 BOE per well or approximately 55,000 BOE net to our
+interest. 
+7 
+Table of Contents 
+Production Status 
+In December 2008, net production from the Permian field was 26,943 BOE or an average of 869 BOE per day, 59% of which was oil, 25% was natural gas liquids and 16% was natural gas. From January 1, 2009 through
+March 9, 2009, our average daily net production from our Permian acreage was 725 BOE per day, 83% of which was from oil and natural gas liquids and 17% of which was from natural gas. As a result of the cessation of drilling, fracing and
+recompletion activities, production has decreased since year end due to normal production declines. 
+Facilities 
+There are typical land oil and gas processing facilities in the Permian Basin. Our facilities located at well locations include storage tank batteries,
+oil/gas/water separation equipment and pumping units. 
+Recent and Future Activity 
+In 2008, 31 gross (15.5 net) wells were drilled in our Permian acreage, including one gross well spud in 2007 and completed in 2008 and one Henry
+Petroleum operated well. We have identified 147 gross future development drilling locations. We currently expect an estimated three gross (1.5 net) wells to be drilled on our acreage in 2009. The wells are expected to be drilled to approximately
+10,200 feet at an estimated average completed gross well cost of $1.34 million. 
+Bakken 
+Location and Land 
+Bakken is located in the Williston
+Basin areas of western North Dakota and eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken are owned by entities controlled by Wexford. Beginning in 2005, Bakken
+acquired leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of its undeveloped acreage. Effective January 1, 2008, we acquired a direct, undivided 20%
+interest in Bakken’s assets in redemption of our 20% interest in Bakken. As a result, we currently hold interests in approximately 17,801 net acres, which includes approximately 4,600 acres in Mountrail Country, in the Bakken play. 
+As of December 31, 2008, we had participated, or committed to participate, in 53 gross wells in the Williston Basin with an average working
+interest of 2.52%. Windsor Energy, the operator of our acreage, drilled and completed the first two Windsor operated wells in 2008. We own working interests of approximately 15.5% and 3.9%, respectively, in these two wells. 
+Production Status 
+In December 2008, net production
+from the Bakken field was 8,692 BOE, or an average of 280 BOE per day, 100% of which was oil. From January 1, 2009 through March 9, 2009, our average net daily production from this acreage was 271 BOE and was 100% oil. 
+Facilities 
+There are typical land oil and gas
+processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+8 
+Table of Contents 
+Recent and future activities 
+In 2008, 37 gross (0.95 net) wells were drilled in our Bakken acreage including both those operated by Windsor and other non-operated wells. We have identified 31 gross future development drilling locations. We
+currently expect an estimated 0.5 net wells to be drilled on our Bakken acreage in 2009. The wells are expected to be drilled to approximately 14,500 total measured depth, or TMD, feet at an estimated average gross completed well cost of $4.7
+million. 
+Additional Properties 
+Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana as described in the following table:
+Field 
+Parish 
+Acreage Working 
+Interest 
+Overriding Royalty 
+Interests 
+Producing 
+Wells 
+Non-Producing 
+Wells 
+Bayou Long 
+Iberia 
+3.125 
+% 
+0 
+% 
+0 
+0 
+Bayou Penchant 
+Terrebonne 
+3.125 
+% 
+0 
+% 
+2 
+5 
+Bayou Pigeon 
+Iberia 
+6.250 
+% 
+0 
+% 
+4 
+5 
+Deer Island 
+Terrebonne 
+6.250 
+% 
+0 
+% 
+0 
+6 
+Golden Meadow 
+Lafourche 
+3.125 
+% 
+0 
+% 
+0 
+1 
+Napoleonville 
+Assumption 
+0 
+% 
+2.5 
+% 
+3 
+0 
+Thailand . During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC,
+or Tatex, at a cost of $2.4 million. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, 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 three million acres which includes the Phu Horm Field. During the year ended December 31, 2008, we paid $50,000 in cash calls
+and received $912,000 in distributions, bringing our total investment in Tatex (including previous investments) to $2.7 million. Our investment is accounted for on the equity method. Tatex accounts for its investment in APICO using the cost method.
+In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet per day. Current net production is approximately 90 Mcf per
+day. Hess Corporation operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex as a member of APICO) in the Phu Horm
+field is 0.7%. Estimated proved reserves from the Phu Horm field as of December 31, 2007, net to our interest, are 3.5 BCF of gas and 19,000 barrels of oil. Due to the fact that our ownership in the Phu Horm field is indirect and Tatex’s
+investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. 
+Grizzly
+Oil Sands . During the third quarter of 2006, we, through our wholly-owned subsidiary Grizzly Holdings Inc., purchased a 24.9999% interest in Grizzly. The remaining interests in Grizzly are owned by entities controlled by Wexford. During 2006 and
+2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 511,000 acres under lease and our total net investment in Grizzly was $21.9
+million at December 31, 2008. During the 2006/2007 and 2007/2008 winter delineation drilling seasons, Grizzly drilled an aggregate of 117 core holes, tested five separate lease blocks and undertook a seismic program. Grizzly’s 2009 plans
+currently include drilling approximately 15 additional core holes, which were completed in the first quarter 2009. 
+Competition and Markets
+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 
+9 
+Table of Contents 
+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. 
+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, other than the production sold under forward sales contracts, 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 trade month average differential less $3.45 per barrel for transportation. During 2008, we sold 87% of our oil production to Shell and 11% to Windsor Energy Group LLC, or Windsor, the operator
+of the Permian wells, 100% of our natural gas liquids production to Windsor, and 60%, 22%, and 16% of our natural gas production to Chevron, Windsor, and Hilcorp Energy Company, respectively. During 2007, we sold 99% of our oil production to Shell
+and 69% of our natural gas production to Chevron and 23% of our natural gas production to Hilcorp Energy Company and during 2006, we sold 100% of our oil production to Shell and 96% of our natural gas production to Chevron. There can be no
+assurance, however, that we will continue to have ready access to suitable markets for our future oil and natural gas production. 
+Oil and
+natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The prices at which the oil and natural gas we produce may be sold is uncertain and it is possible that under some market
+conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is impossible to accurately predict future prices.
+To mitigate the effects of commodity price fluctuations, during 2008, we were party to forward sales contracts for the sale of 3,500
+barrels of WCBB production per day at a weighted average daily price of $78.56 per barrel before transportation costs. We delivered approximately 73% of our 2008 production under these agreements. For the period January through December 2009, we had
+entered into agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel before transportation costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0
+million in cash. Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August
+2009. We have also entered into 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, for the period September 2009 to December 2009. For
+the period January 2010 through February 2010, we have entered into 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. For the period
+March 2010 through December 2010, we have entered into forward sales contracts for the sale of 2,000 barrels of WCBB production per day at a weighted average daily price of $57.35 per barrel, before transportation costs. Under these contracts, we
+have committed to deliver approximately 50% of our estimated 2009 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.
+Since these contracts require physical delivery of production quantities, they normally would be exempted from the provisions of SFAS 133 as normal sales of production. However, as a result of the early termination of the contracts in December 2008,
+we will not be able to apply this election on new contracts and they will be accounted for at fair value until we re-establish a history of physical delivery without early termination. In addition, these arrangements may limit the benefit to us of
+increases in the price of oil. 
+10 
+Table of Contents 
+Regulation 
+Regulation of Gas and Oil Production 
+Oil and natural gas operations such as ours are subject to various types of
+legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements
+carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. 
+We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast, West Texas and the Williston Basin.
+These states regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation
+matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. 
+Environmental Regulation 
+Our oil and natural gas
+exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the
+U.S. Environmental Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to
+comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and
+production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or
+former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict liability nature of such laws and
+regulations could impose liability upon us regardless of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport,
+disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable
+environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. 
+Waste Handling . The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect
+oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the
+individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas
+are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or
+the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time to
+re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” 
+Administrative,
+civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste 
+11 
+Table of Contents 
+handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under
+such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production
+wastes could increase our costs to manage and dispose of such wastes. 
+Comprehensive Environmental Response, Compensation and Liability
+Act . The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law, generally imposes joint and several liability, without regard to fault or legality of conduct, on classes of
+persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the
+time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance. Under CERCLA and comparable state statutes, such persons may be subject to strict joint and several liability for the costs of cleaning up
+the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims
+for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes.
+Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.
+Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, the Oil Pollution
+Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other gas and oil wastes, into state waters or waters of the United
+States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws and regulations also prohibit certain activity in wetlands unless authorized by a
+permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the
+treatment of wastewater or developing and implementing storm water pollution prevention plans. We believe that we have obtained or applied for and are in substantial compliance with all permits required under the Clean Water Act. Sanctions for
+failure to comply with Clean Water Act requirement include administrative, civil and criminal penalties, as well as injunctive obligations. 
+Air Emissions . The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and
+continues to develop, stringent regulations governing emissions of air pollutants at specified sources. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for our facilities’ operations,
+and existing facilities may be required to incur capital costs to remain in compliance. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose
+administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air
+emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. Our air emissions may
+also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide and methane, which are emitted in the course of oil and natural gas exploration and production. 
+Operational Hazards and Insurance 
+Our operations are
+subject to all of the risks normally incident to the production of oil and natural gas, including, but not limited to, blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which 
+12 
+Table of Contents 
+could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or injury or death to persons and
+wildlife. The energy business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharge of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental
+damage and consequences thereof, including personal injuries and property damage. We currently maintain insurance covering some, but not all of these risks. The occurrence of a significant event that is not fully insured against could have a
+material adverse effect on our financial position. 
+Headquarters and Other Facilities 
+We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease a portion of
+this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This building contains approximately 6,200 square feet of finished office
+area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for its use. 
+Employees 
+At December 31, 2008, we had 37
+employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the estimated time they spent working for
+those affiliates. In addition, in the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For the years ended December 31, 2008 and 2007, expenses reimbursed to us under these arrangements were
+$1.4 million and $11.2 million, respectively, and are reflected as a reduction in our general and administrative expenses. A Louisiana well servicing company provides all necessary field personnel needed to operate the WCBB and the Hackberry fields.
+Available Information 
+Our annual
+report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor
+Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange Commission, or SEC. Information contained on our website, or on
+other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. 
+13 
+Table of Contents

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+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and Exchange
+Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).

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+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+Evaluation of
+Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to
+be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and
+procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding
+required disclosures. 
+As of December 31, 2008, an evaluation was performed under the supervision and with the participation of
+management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act
+of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2008, our disclosure controls and procedures are effective. 
+Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that
+occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. 
+Management’s Report on Internal Control Over Financial Reporting 
+Management is responsible for the fair presentation
+of the consolidated financial statements of Gulfport Energy Corporation. Management is also responsible for establishing and maintaining a system of internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the
+Securities Exchange Act of 1934, as amended. These internal controls are designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the
+preparation of financial statements are reasonable. There are inherent limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal
+control system can only provide reasonable, not absolute, assurance with respect to reporting financial information. 
+Management conducted
+an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its
+evaluation under the framework in Internal Control—Integrated Framework, management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was
+effective as of December 31, 2008. 
+Grant Thornton LLP, the independent registered public accounting firm that audited our financial
+statements for the year ended December 31, 2008 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2008, as stated in their accompanying report. 
+/s/ James D. Palm 
+/s/ Michael G. Moore 
+Name: 
+James D. Palm 
+Name: 
+Michael G. Moore 
+Title: 
+Chief Executive Officer 
+Title: 
+Chief Financial Officer 
+48 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Gulfport Energy Corporation:
+We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of
+December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is
+responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over
+Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 
+We
+conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control
+over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and
+operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
+preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the
+maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation
+of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and
+(3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
+effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of
+December 31, 2008, based on criteria established in Internal Control—Integrated Framework issued by COSO. 
+We have also audited, in
+accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries as of December 31, 2008 and 2007, and the related consolidated
+statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2008 and our report dated March 16, 2009 expressed an unqualified opinion.
+/s/ GRANT THORNTON LLP 
+Oklahoma City, Oklahoma 
+March 16, 2009

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+Certain Relationships and Related Transactions 
+Administrative Services Agreements 
+We are or have been a party to administrative service
+agreements with Caliber Development Company, LLC, which we refer to as Caliber, Great White Energy Services LLC, which we refer to as Great White, Diamondback Energy Services LLC, which we refer to as Diamondback, and Stampede Investments LLC, which
+we refer to as Stampede Investments, which agreements were entered into effective as of February 9, 2005, July 22, 2006, September 26, 2006 and November 1, 2007, respectively. Under these agreements, our services
+include accounting, human resources, legal and technical support. The services provided and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements has a three-year term, and upon
+expiration of that term the agreements will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. Each administrative service agreement is terminable (1) by the counterparty at any time
+with at least 30 days prior written notice to us and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. Each of Caliber, Great White,
+Diamondback and Stampede Investments reimbursed us for our dedicated employee time and related general and administrative costs based on the proportionate amount of time our employees spent performing services for such entity. We were reimbursed
+approximately $60,000, $83,000, $10,000 and $0 by Caliber, Great White, Diamondback and Stampede Investments, respectively, for services provided under these agreements during the year ended December 31, 2008. Our administrative services
+agreements with Caliber and Diamondback were each terminated effective December 10, 2008. Each of Caliber, Great White and Stampede Investments is, and Diamondback was, controlled by Wexford Capital LLC. Charles Davidson, who beneficially owned
+approximately 36% of our outstanding common stock as of April 1, 2009, is the Chairman and Chief Investment Officer of Wexford Capital LLC. Our Chairman of the Board, Mike Liddell, served as the Chairman of the Board of Diamondback Energy
+Services, Inc., a subsidiary of Diamondback until December 2008. As of December 2008, Diamondback is no longer controlled by Wexford Capital LLC and is no longer an affiliate of ours. 
+We are also a party to administrative service agreements with Stampede Farms LLC, which we refer to as Stampede Farms, Grizzly Oil Sands ULC, which we refer to as Grizzly, and Everest Operations Management LLC, which
+we refer to as Everest, which agreements were each entered into effective March 1, 2008. Under these agreements, our services include professional and technical support. Under our agreements with Stampede Farms and Everest, we also provided
+office space during 2008. The services provided under these agreements and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements has a two-year term, and upon expiration of that
+term such agreement will continue on a month-to-month basis until cancelled by either party to such agreement with at least 60 days prior written notice. Each administrative service agreement is terminable (1) by the counterparty at any time
+with at least 30 days prior written notice to us and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. We were reimbursed approximately
+$159,000, $368,000 and $154,000 by Stampede Farms, Grizzly and Everest, respectively, for services provided under these agreements during the year ended December 31, 2008. We were also reimbursed approximately $20,000 and 26,000 by Stampede
+Farms and Everest, respectively, for office space under these agreements for the year ended December 31, 2008. Each of Stampede Farms, Grizzly and Everest is controlled by Wexford Capital LLC. 
+28 
+Table of Contents 
+Effective July 1, 2008, we entered into an acquisition team agreement with Everest to identify and evaluate
+potential oil and gas properties in which we and Everest or its affiliates may wish to invest. Pursuant to this agreement, Gulfport and Everest each agreed to form an acquisition team. Upon a successful closing of an acquisition or divestiture, the
+party whose acquisition team identified the acquisition or divestiture is entitled to receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share
+of the acquisition or divestiture consideration. The agreement has a one year term unless earlier terminated by either party upon 30 days notice. 
+We
+provide professional support, office space, furniture, telecommunications and computer and other information technology support to Windsor Energy Resources LLC, or Windsor, and Everest. Both Windsor and Everest have agreed to reimburse us for such
+services based on the number of employees we office and nature of services provided by us to each respective company, which can vary from time to time. We were reimbursed an aggregate of approximately $469,000 for the above services provided to
+Windsor and Everest for the year ended December 31, 2008. Both Windsor and Everest are controlled by Wexford Capital LLC. 
+From time to time, various
+members of our scientific staff provide services relating to evaluation of potential investments to Wexford Capital LLC and geological evaluations, seismic review and similar services to Tatex Thailand II, LLC, or Tatex II, and Tatex Thailand III
+LLC, or Tatex III. Wexford Capital LLC, Tatex II and Tatex III, respectively, have agreed to reimburse us based on the amount, scope and nature of services provided by our staff to such entities. Tatex II and Tatex III are controlled by Wexford
+Capital LLC. 
+We provide certain general and administrative services to Floran Technologies LLC, or Floran. We are reimbursed for our dedicated employee
+time and related general and administrative costs based on the proportionate amount of time our employees spent performing such services. For the year ended December 31, 2008, we were reimbursed approximately $46,000 by Floran and were owed an
+additional $16,000 for such services at that date. 
+Services Provided to Us by Our Affiliates 
+We contract with Athena Construction, L.L.C., which we refer to as Athena, to provide barge services in our West Cote Blanche Bay, or WCBB, and Hackberry fields located
+along the Louisiana Gulf Coast. For the year ended December 31, 2008, we paid Athena $3,888,000 and owed an additional $759,000 for such services at that date. Athena is controlled by Wexford Capital LLC. 
+Windsor Energy Group operates our Permian Basin wells in West Texas. For the year ended December 31, 2008, we paid Windsor Energy Group $39,137,000 and owed an
+additional $3,724,000 for such services at that date. Windsor Energy Group is controlled by Wexford Capital LLC. 
+Packers & Service Tools, Inc.,
+which we refer to as Packers, performs services for us at our WCBB and Hackberry fields. For the year ended December 31, 2008, we paid Packers $1,966,000 owed an additional $465,000 related to these services at that date. Packers was controlled
+by Wexford Capital LLC until November 18, 2008. On that date, Packers ceased to be an affiliate of ours. 
+Diamondback Completions LLC, which we refer
+to as Completions, performs services for us at our WCBB and Hackberry fields. For the year ended December 31, 2008, we paid Completions $444,000 and owed an additional $24,000 related to these services at that date. Completions were controlled
+by Wexford Capital LLC until November 18, 2008. On that date, Completions ceased to be an affiliate of ours. 
+Great White Towing LLC, which we refer
+to as Towing, performs services for us at our WCBB field. For the year ended December 31, 2008, we paid Towing $269,000 and owed an additional $222,000 related to these services at that date. Towing is an entity controlled by Wexford Capital
+LLC. 
+29 
+Table of Contents 
+Effective March 1, 2008, Windsor provides tax planning, preparation of supporting tax schedules and consultation
+services to us, based on agreed upon fee structure. The scope of such services can be modified upon mutual agreement of the parties. Windsor is controlled by Wexford Capital LLC. 
+Caliber provides building maintenance services for our headquarters in Oklahoma City, Oklahoma. For the year ended December 31, 2008, we paid Caliber $20,000 and owed an additional $2,000 at that date. Caliber is
+an entity controlled by Wexford Capital LLC. 
+Our Investments in Affiliates and Related Agreements 
+During 2005, we purchased a 23.5% ownership interest in Tatex II at a cost of $2,400,000. The remaining interests in Tatex II are owned by other entities controlled by
+Wexford Capital LLC. Tatex II, a privately-owned 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 three million acres which includes the Phu Horm Field. During 2008, we paid $50,000 and received $912,000 in distributions in respect of our investment in Tatex II. 
+During the first quarter of 2008, we purchased a 5% ownership interest in Tatex III at a cost of $850,000. Approximately 68.7% of the remaining interests in Tatex III
+are owned by other entities and individuals affiliated with Wexford Capital LLC. During 2008, we paid $35,000 in cash calls in respect of our investment in Tatex III. 
+During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken, with the remaining interests in Bakken owned by other entities controlled by Wexford Capital LLC. In 2006, Bakken acquired leases
+on undeveloped acreage in the Williston Basin areas of western North Dakota and eastern Montana, which we refer to as the contract area. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in
+redemption of our 20% interest in Bakken. 
+Effective January 1, 2008, we entered into an area of mutual interest agreement with Bakken and Windsor
+Dakota LLC, or Windsor Dakota, to jointly acquire oil and gas leases on certain lands located in North Dakota and Montana for the purpose of exploring, exploiting and producing oil and gas from the Bakken Shale. The agreement provides that each
+party must offer the other party the right to participate in such acquisition in proportion to its participating interest, which is 20% for us and 80% for Bakken and Windsor Dakota, collectively. The parties also agreed, subject to certain
+exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, we, Bakken, Windsor Dakota and Windsor Energy
+Group, L.L.C., as the operator, also entered into an exploration agreement, effective as of January 1, 2008, pursuant to which we, Bakken and Windsor Dakota agreed to jointly evaluate, explore, exploit and develop the contract area, and Windsor
+Energy Group, L.L.C. agreed to act as the operator under the terms of a joint operating agreement. In the event Gulfport has greater than a 50% interest in a prospect, as defined in the exploration agreement, the parties agreed to support Gulfport
+as the operator. The parties agreed to pay Windsor Energy Group, L.L.C. for its services as the operator with respect to the contract area as provided in the joint operating agreement. 
+During the third quarter of 2006, we purchased, through our wholly owned subsidiary Grizzly Holdings, Inc., a 24.9999% interest in Grizzly, a Canadian unlimited liability company, for approximately $8,200,000. The
+remaining interests in Grizzly are owned by other entities controlled by Wexford Capital LLC. During 2006, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects.
+Grizzly has commenced drilling of core holes for feasability of oil production in five separate lease blocks but has not commenced development of operations. As of December 31, 2008, our net investment in Grizzly was $21,881,000. 
+We, through our wholly owned subsidiary Grizzly Holdings Inc., entered into a loan agreement with Grizzly effective January 1, 2008, under which Grizzly may borrow
+funds from us. Borrowed funds bear interest at 
+30 
+Table of Contents 
+LIBOR plus 4%. Interest is paid on a paid-in-kind basis by increasing the outstanding balance of the loan. The loan matures on December 31, 2012. We
+loaned Grizzly approximately $10,519,000 during the year ended December 31, 2008. The Company recognized interest income of approximately $410,000 for the year ended December 31, 2008 under this loan agreement. The note balance was
+decreased by approximately $1,776,000 as a result of a currency translation loss for the year ended December 31, 2008. 
+Option and Purchase Agreement and Related Agreements 
+On November 30, 2007, we entered into an option
+agreement with Windsor Permian LLC, an entity controlled by Wexford Capital LLC, which we refer to as Windsor Permian. Under the option agreement, we were granted the right to participate on a 50/50 basis with Windsor Permian in the acquisition of
+certain strategic assets in Upton County, Texas in the Permian Basin. On December 12, 2007, we exercised the option and on December 18, 2007, the purchase agreement was amended to, among other things, add Gulfport as a buyer under the
+purchase agreement. On December 20, 2007, the acquisition was closed, effective as of November 1, 2007. We and Windsor Permian also agreed to share equally all third-party costs and expenses incurred by each of us in connection with the
+transaction. 
+In addition, effective as of November 1, 2007, we and Windsor Permian entered into an area of mutual interest agreement to jointly
+acquire oil and gas leases in the Permian Basin. The agreement provides that each party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain exceptions, to share third-party
+costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. On March 20, 2008, in connection with this agreement, we received a six-month option to acquire a direct,
+undivided interest of up to 25% in Windsor Permian’s oil and gas interests acquired on February 29, 2008 in Midland County, Texas. The option price is the sum of (i) the option percentage of the acquisition consideration paid by
+Windsor Permian to a third party in connection with the acquisitions of these assets, subject to certain exceptions, (ii) a fee equal to 1% of our purchase price, (iii) the option percentage of the sum of all third-party costs and expenses
+incurred by Windsor Permian in connection with the acquisition of these assets, subject to certain exceptions, (iv) the option percentage of all capital costs and lease operating expenses incurred subsequent to Windsor Permian’s
+acquisition of these assets and prior to the date of the option exercise by Gulfport, subject to certain exceptions, and (v) interest, at 8% per annum, on the amounts set forth in items (i), (iii) and (iv) calculated from the
+time of accrual to the closing date of the option. 
+In connection with the area of mutual interest agreement, we, Windsor Permian and Windsor Energy Group,
+L.L.C., as the operator, entered into the joint development agreement, effective as of November 1, 2007, pursuant to which we and Windsor Permian agreed to develop certain jointly held oil and gas leases in the Permian Basin, and Windsor Energy
+Group, L.L.C. agreed to act as the operator under the terms of the joint operating agreement, effective as of November 1, 2007. In the event either party has greater than a 50% interest in a prospect, as defined in the development agreement,
+the majority party may designate the operator of its choice. The parties agreed to pay Windsor Energy Group, L.L.C. for its services as the operator with respect to the contract area as provided in the joint operating agreement. 
+31 
+Table of Contents

raw/filings/0000874499/2009/0001193125-10-055121/filing_metadata.csv

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+ITEM 1. 
+DESCRIPTION OF BUSINESS 
+General 
+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, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. We also hold a significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil
+Sands ULC, or Grizzly, 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. 
+In 2009, at our WCBB field, we recompleted 56 wells and drilled 11 wells for a total cost of approximately $19.6 million as of
+December 31, 2009. Of our 11 new wells drilled at WCBB in 2009, 10 were completed as producing wells and one was non-productive. During 2010, we currently anticipate drilling 20 wells and recompleting 40 wells at our WCBB field for an estimated
+aggregate cost of $33.0 to $36.0 million. In December 2009, production at WCBB was 116,637 net barrels of oil equivalent, or BOE, or an average of 3,762 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From
+January 1, 2010 through February 28, 2010, our average net daily production at WCBB was 3,432 BOE, 98% of which was from oil and 2% of which was from natural gas. 
+In 2009, at our East Hackberry field, we recompleted five wells and drilled six wells for a total cost of approximately $11.0 million as of
+December 31, 2009. All wells drilled during 2009 were completed as producing wells. During 2010, we currently anticipate drilling three wells and recompleting five wells for an aggregate estimated cost of $6.0 to $7.0 million. In December 2009,
+net production at East Hackberry was 13,284 BOE, or an average of 429 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average net daily production at East
+Hackberry was 814 BOE, 96% of which was from oil and 4% of which was from natural gas. 
+In December 2009, net production at
+West Hackberry was 1,202 BOE, or an average of 39 BOE per day, 100% of which was from oil. From January 1, 2010 through February 28, 2010, our average net daily production at West Hackberry was 44 BOE, 100% of which was from oil.
+Effective November 1, 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 wells, predominately from the Wolfcamp formation. In 2008, 31 gross (15.5 net) wells were drilled on this acreage. In 2009, we acquired an additional 4,095 net acres, bringing our total net acreage position
+in the Permian Basin to approximately 8,200 net acres. During the year ended December 31, 2009, we drilled four gross wells and recompleted three gross wells on this acreage. As of March 1, 2010, three of the four wells had been completed
+and the other well was awaiting completion. We currently anticipate drilling 24 to 26 gross (12 to 13 net) wells on this acreage in 2010 for an estimated aggregate cost of $15.0 to $17.0 million. In December 2009, net production from our Permian
+acreage was 17,030 BOE, or an average of 549 BOE per day, 82% of which was from oil and natural gas liquids and 18% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average daily net production from our
+Permian acreage was 507 BOE per day, 82% of which was from oil and natural gas liquids and 18% of which was from natural gas. 
+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. During 2006 and 2007,
+Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 527,000 acres under lease and our total net investment in Grizzly was
+approximately $41.0 million, including a note receivable of $15.9 million, at December 31, 2009. During the 2006/2007, 2007/2008 and 2008/2009 winter delineation drilling seasons, Grizzly drilled an aggregate of 131 core holes and one
+water supply test well, tested five
+2 
+Table of Contents 
+Index to Financial Statements 
+separate lease blocks and conducted a seismic program. Grizzly recently filed an application in Alberta, Canada for the development of an 11,300 barrel per day oil sand project at Algar Lake, and
+its currently contemplated 2010 activities relate primarily to initial preparations for this facility. 
+During 2005, we
+purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining interests in Tatex are owned by entities controlled by Wexford Capital, LP, or Wexford. Affiliates of Wexford beneficially own approximately 36% of our
+outstanding common stock. Tatex, 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 three million acres which includes the Phu Horm Field. 
+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 one million acres. During 2009, the operator conducted a
+3-D seismic survey on this concession. During 2010, we expect to participate in the drilling of two wells. 
+During 2005, we
+purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. In 2006, Bakken acquired leases for undeveloped acreage in the Williston Basin area of western North Dakota and eastern Montana. Effective January 1, 2008, we acquired a
+direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 net BOEPD of production for approximately $13.0 million, with an
+effective date of April 1, 2009. During September 2009, we sold approximately 5,721 net acres for $5.8 million with an effective date of July 1, 2009. As of December 31, 2009, we held approximately 900 net acres and
+interests in 28 wells, as well as certain wells that might be drilled in the future. 
+In December 2009, net production from
+our remaining Bakken acreage was 2,092 BOE, or an average of 67 BOE per day, 97% of which was from oil and natural gas liquids and 3% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average daily net
+production from our Bakken acreage was 66 BOE per day, 95% of which was from oil and 5% of which was from natural gas. 
+As of
+December 31, 2009, we had 19.9 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $263 million and associated standardized
+measure of discounted future net cash flows of approximately $240.8 million. See Item 2. “Properties—Proved Oil and Natural Gas Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our
+standardized measure of discounted future net cash flows to PV-10. 
+Principal Oil and Natural Gas Properties 
+The following table presents certain information as of December 31, 2009 reflecting our net interest in our principal producing oil and
+natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas and in the Williston Basin. 
+Proved Reserves 
+Field 
+NRI/WI (1) 
+Productive 
+Wells (2) 
+Non-Productive 
+Wells 
+Developed 
+Acreage (3) 
+Gas 
+Oil 
+Total 
+Percentages 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Mboe 
+Mboe 
+Mboe 
+West Cote Blanche Bay Field (4) 
+80.108/100 
+95 
+95 
+181 
+181 
+5,668 
+5,668 
+262 
+5,028 
+5,290 
+E. Hackberry Field (5) 
+79.424/100 
+18 
+18 
+86 
+86 
+3,291 
+3,291 
+308 
+2,490 
+2,798 
+W. Hackberry Field 
+87.5/100 
+3 
+3 
+24 
+24 
+592 
+592 
+— 
+172 
+172 
+Permian Basin 
+38.075/49.48 
+64 
+32 
+— 
+— 
+8,157 
+4,078 
+1,816 
+9,763 
+11,579 
+Williston Basin (6) 
+3.08/4.10 
+4 
+1 
+— 
+— 
+2,560 
+127 
+2 
+32 
+34 
+Overrides/Royalty Non-operated 
+Various 
+32 
+1 
+17 
+2 
+— 
+— 
+1 
+3 
+4 
+Total 
+216 
+150 
+308 
+293 
+20,268 
+13,756 
+2,389 
+17,488 
+19,877 
+3 
+Table of Contents 
+Index to Financial Statements 
+(1) 
+Net Revenue Interest (NRI)/Working Interest (WI). 
+(2) 
+Includes nine gross and net wells at WCBB that are producing intermittently. 
+(3) 
+Developed acres are acres spaced or assigned to productive wells. Approximately 68% 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) 
+NRI/WI is from wells that have been drilled or in which we have elected to participate. 
+West Cote Blanche Bay Field 
+Location and Land 
+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. 
+Area History and Production 
+Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940
+based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in
+the field. Of the 919 wells drilled as of December 31, 2009, 826 were completed as producing wells. As a result, the field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in 1997 through
+December 31, 2009, we drilled 139 new wells, 16 of which were non-productive, for an 88% success rate. As of December 31, 2009, estimated field cumulative gross production was 190.1 MMBOE and 236.1 billion cubic feet, or Bcf, of gas. Of
+the 919 wells drilled in WCBB as of December 31, 2009, 86 were producing, 181 were shut-in, nine were producing intermittently and five were being used as salt water disposal wells. The other 638 wells have been plugged and abandoned.
+In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In
+1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the
+data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced seismic data processing.
+Geology 
+WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected
+deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large
+graben system (a downthrown area bounded by normal faults) was formed. 
+There are over 100 distinct sandstone reservoirs
+recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 919 wellbores that had been drilled in the field as of December 31, 2009, over 4,000 potential zones have been penetrated.
+These sands are highly porous and permeable reservoirs primarily with a strong water drive. 
+4 
+Table of Contents 
+Index to Financial Statements 
+WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped,
+or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of
+these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does
+introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new
+wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort to more efficiently drain each reservoir. The vast majority of the PUD targets
+are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. Our inventory of prospects at WCBB as of December 31, 2009 included 21 PUD wells. The drilling schedule used in the reserve report anticipates that
+all of those wells will be drilled by 2012. 
+Facilities 
+We own and operate a production facility at WCBB that includes four production tank batteries, six natural gas compressors, a dehydration unit and a salt water disposal system. 
+Recent and Future Activity 
+In 2009, we recompleted 56 wells and drilled 11 wells at WCBB. Of these 11 new wells, 10 were completed as producers, and one was non-productive. As of February 28, 2010, we had recompleted eight wells during 2010. Of the 11 wells
+drilled in 2009, none were considered deep wells. The ten productive wells, with total depths ranging from 2,500 to 10,325 feet, have approximately 1,077 feet of aggregate apparent net pay. We currently anticipate drilling 20 wells and recompleting
+40 wells at WCBB during 2010. 
+Production Status 
+In December 2009, production at WCBB was 116,637 net BOE, or an average of 3,762 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From January 1, 2010 through
+February 28, 2010, our average net daily production at WCBB was 3,432 BOE, 98% of which was from oil and 2% of which was from natural gas. 
+East Hackberry Field 
+Location and Land 
+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
+79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold beneficial interests in approximately 7,738 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. 
+Area History and Production 
+The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The massive
+shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through 2009 was over
+597,172 barrels of oil and 330 Bcf of casinghead gas production. A total of 193 wells have been drilled on our portion of the field. As of December 31, 2009, 18 wells had daily production, 86 were shut-in and two had been converted to salt
+water disposal wells. The remaining 87 wells had been plugged and abandoned. 
+5 
+Table of Contents 
+Index to Financial Statements 
+Geology 
+The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry
+acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks.
+These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. 
+Facilities 
+We have a field office that serves both the East and West Hackberry fields. In addition, we
+completed installation of a new production barge at the East Hackberry field in the second quarter of 2007. The barge is designed to have the ability to process on a per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high pressure
+natural gas, 6.5 Mmcf of low pressure natural gas and 10,000 barrels of salt water. 
+Recent and Future Activity 
+During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry, the first modern seismic program undertaken at
+this field. We believe that this 3-D seismic data enhances our probability of drilling success, and we continue to evaluate the 3-D seismic data to identify additional drilling locations. During 2009 at East Hackberry, we recompleted five wells and
+drilled four land wells and two wells on water. All of the six wells drilled during 2009 were completed as producing wells. As of February 28, 2010, we had not recompleted or drilled any wells during 2010. We currently intend to drill three
+land wells and recomplete five wells at East Hackberry during 2010. 
+Production Status 
+In December 2009, net production at East Hackberry was 13,284 BOE, or an average of 429 BOE per day, 96% of which was from oil and 4% of
+which was from natural gas. From January 1, 2010 through February 28, 2010, our average net daily production at East Hackberry was 814 BOE, 96% of which was from oil and 4% of which was from natural gas. Production has increased as a
+result of the successful drilling and completion of four wells during the fourth quarter of 2009. 
+West Hackberry Field 
+Location and Land 
+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 87.5% NRI)
+in 592 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. 
+Area History 
+The first
+discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2009 was 261 MBOE and 140 Bcf
+of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 24 are shut-in and one has been converted to a saltwater disposal well. The remaining eight wells have been plugged and
+abandoned. 
+6 
+Table of Contents 
+Index to Financial Statements 
+Geology 
+Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in
+the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. 
+Production Status 
+In
+December 2009, net production at West Hackberry was 1,202 BOE, or 39 BOE per day. From January 1, 2010 through February 28, 2010, our average net daily production at West Hackberry was 44 BOE and was 100% oil. 
+Facilities 
+We have
+land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both the East and West Hackberry fields. 
+Permian Basin (West Texas) 
+Location and Land 
+We acquired approximately 4,100 net acres in West Texas (near Midland) in the Permian Basin on December 20, 2007, effective date as of
+November 1, 2007, from ExL Petroleum, LP and certain other sellers. Subsequently, we acquired an additional 4,095 net acres, bringing our total acreage position to approximately 8,200 net acres as of December 31, 2009. The Permian Basin
+area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. The terrain in the Permian Basin is semi-arid mesquite-mixed grassland steppe. Windsor Energy is
+the operator of this field. 
+Area History 
+The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a long-established reservoir in West Texas, first found
+in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was not until the use of 3-D seismic in the 1990s that the
+greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 feet to pick up the upper part of the Wolfcamp
+formation. Henry Petroleum, a private firm, owned interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section as Devonian
+wells. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private
+company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled us to
+participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. As of December 31, 2009, we hold interests in 64 gross producing wells.
+Geology 
+The
+Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The Wolfcamp is
+characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin Platform.
+7 
+Table of Contents 
+Index to Financial Statements 
+Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20%
+from the Spraberry section. Pinnacle Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2009, proved reserves net to our interest in these assets were approximately 11.6 million BOE, of
+which 12% were classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 191 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry
+formations, which are generally characterized as long-lived, with predictable production profiles. 
+Production Status 
+In December 2009, net production from the Permian field was 17,030 BOE, or an average of 549 BOE per day, 82% of which was from oil and
+natural gas liquids, and 18% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average daily net production from our Permian acreage was 507 BOE per day, 82% of which was from oil and natural gas liquids
+and 18% of which was from natural gas. As a result of the reduction of drilling, fracing and recompletion activities, production has decreased since year end due to normal production declines. 
+Facilities 
+There are
+typical land oil and gas processing facilities in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent and Future Activity 
+In 2009, four gross (two net) wells were drilled in our Permian acreage. We have identified 191 gross future development drilling locations. We currently expect an estimated 24 to 26 gross (12 to 13 net) wells to be drilled on our acreage
+in 2010. The wells are expected to be drilled to approximately 10,200 feet. 
+Bakken 
+Location and Land 
+The
+Bakken Shale is located in the Williston Basin areas of western North Dakota and eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken were owned by entities
+controlled by Wexford. Beginning in 2005, Bakken acquired leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of its undeveloped acreage. Effective
+January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 net BOEPD of production for
+approximately $13.0 million, with an effective date of April 1, 2009. During September 2009, we sold approximately 5,721 net acres for approximately $5.8 million with an effective date of July 1, 2009. As of December 31, 2009, we held
+approximately 900 net acres and interests in 28 wells, as well as interests in certain wells that might be drilled in the future. 
+Production Status 
+In December 2009, net production from our Bakken acreage was 2,092 BOE, or an average of 67
+BOE per day, 97% of which was from oil and natural gas liquids and 3% of which was from natural gas. From January 1, 2010 through February 28, 2010, our average net daily production from this acreage was 66 BOE, of which 95% was from oil
+and 5% was from natural gas liquids. 
+8 
+Table of Contents 
+Index to Financial Statements 
+Facilities 
+There are typical land oil and gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping
+units. 
+Recent and future activities 
+As a result of the sale transactions described above, we have no activities currently scheduled for 2010 in the Williston Basin. 
+Additional Properties 
+Louisiana . In addition to our interests in
+the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana as described in the following table: 
+Field 
+Parish 
+Acreage Working 
+Interest 
+Overriding Royalty 
+Interests 
+Producing 
+Wells 
+Non-Producing 
+Wells 
+Bayou Long 
+Iberia 
+3.125 
+% 
+0 
+% 
+0 
+0 
+Bayou Penchant 
+Terrebonne 
+3.125 
+% 
+0 
+% 
+1 
+6 
+Bayou Pigeon 
+Iberia 
+6.250 
+% 
+0 
+% 
+4 
+5 
+Deer Island 
+Terrebonne 
+6.250 
+% 
+0 
+% 
+0 
+6 
+Golden Meadow 
+Lafourche 
+3.125 
+% 
+0 
+% 
+0 
+1 
+Napoleonville 
+Assumption 
+0 
+% 
+2.5 
+% 
+3 
+0 
+Thailand . During
+2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex, at a cost of $2.4 million. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, 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 three million acres which includes the Phu Horm Field.
+During the year ended December 31, 2009 we paid $320,000 in cash calls and received $517,000 in distributions, bringing our total investment in Tatex (including previous investments) to $2.5 million. Our investment is accounted for on the
+equity method. Tatex accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm’s initial gross production was approximately
+60 million cubic feet per day. For December 2009, net gas production was approximately 83 MMcf per day and condensate production was 452 Bbl’s per day. Hess Corporation operates the field with a 35% interest. Other interest owners include
+APICO (35% interest), PTTEP (20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex as a member of APICO) in the Phu Horm field is 0.7%. Estimated proved reserves from the Phu Horm field as of December 31, 2008,
+net to our interest, are 2.739 BCF of gas. Due to the fact that our ownership in the Phu Horm field is indirect and Tatex’s investment in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve
+information. 
+During the first quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III,
+at a cost of $850,000. In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3,385,000 bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining
+interests in Tatex III are owned by entities controlled by Wexford. During the year ended December 31, 2009, we paid $428,000 in cash calls, bringing our total investment in Tatex III to $4,482,000. Currently, we plan to participate in the
+drilling of two wells during 2010. 
+Grizzly Oil Sands . 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. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the
+9 
+Table of Contents 
+Index to Financial Statements 
+Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 527,000 acres under lease and our total net investment in Grizzly was approximately
+$41.0 million, including a note receivable of $15.9 million, at December 31, 2009. During the 2006/2007, 2007/2008 and 2008/2009 winter delineation drilling seasons, Grizzly drilled an aggregate of 131 core holes and one water supply
+test well, tested five separate lease blocks and conducted a seismic program. Grizzly recently filed an application in Alberta, Canada for the development of an 11,300 barrel per day oil sand project at Algar Lake, and its currently contemplated
+2010 activities relate primarily to initial preparations for the facility. 
+Competition and Markets 
+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.
+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 demand for oil and natural gas and the level 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, other than the production sold under forward sales contracts, 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 trade month average differential less $3.45 per barrel for
+transportation. During 2009, we sold 92% and 7% of our oil production to Shell and Windsor Energy Group, the operator of our Permian wells, respectively, and 45%, 38%, and 16% of our natural gas production to Windsor Energy Group, Chevron and
+Hilcorp Energy Company, respectively. During 2008, we sold 87% of our oil production to Shell and 11% to Windsor Energy Group, 100% of our natural gas liquids production to Windsor Energy Group, and 60%, 22%, and 16% of our natural gas production to
+Chevron, Windsor Energy Group, and Hilcorp Energy Company, respectively. During 2007, we sold 99% of our oil production to Shell and 69% and 23% of our natural gas production to Chevron and Hilcorp, respectively. We may not continue to have ready
+access to suitable markets for our future oil and natural gas production. 
+Oil and natural gas prices can be extremely
+volatile and are subject to substantial seasonal, political and other fluctuations. The prices at which the oil and natural gas we produce may be sold is uncertain and it is possible that under some market conditions the production and sale of oil
+and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is impossible to accurately predict future prices. 
+To mitigate the effects of commodity price fluctuations, during 2009, we were party to forward sales contracts for the sale of 825,000
+barrels of WCBB production at a weighted average price of $55.01 per barrel before transportation costs. We delivered approximately 49% of our 2009 production under these agreements. Initially, for the period January through December 2009, we had
+entered into agreements to sell 3,000 barrels of WCBB production per day at a weighted average daily price of $89.06 per barrel before transportation costs. In December 2008, we terminated these 2009 forward sales contracts in exchange for $39.0
+million in cash. Subsequently, we entered into forward sales contracts for the sale of 3,000 barrels of WCBB production per day at a weighted average daily price of $55.17 per barrel, before transportation costs, for the period April 2009 to August
+2009. We also entered into 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, for the period September
+10 
+Table of Contents 
+Index to Financial Statements 
+2009 to December 2009. In 2009, we terminated forward sales contracts for the months of March and May 2009 for an aggregate of approximately $2.0 million. For the period January 2010 through
+February 2010 we entered into 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. For the period March 2010 through December 2010, we
+have entered into 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. Under these contracts, we have committed to deliver approximately
+45% of our estimated 2010 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 contacts are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and Hedging, ” and related pronouncements.
+Regulation 
+Regulation of
+Gas and Oil Production 
+Oil and natural gas operations such as ours are subject to various types of legislation, regulation
+and other legal requirements enacted by governmental authorities. This legislation and regulation affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties
+for failure to comply. The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. 
+We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast, West Texas and the Williston Basin. These states regulate the production and sale of oil
+and natural gas, including requirements for obtaining drilling permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and
+natural gas resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. 
+Environmental Regulation 
+Our oil and natural gas exploration, development
+and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental
+Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws
+and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production
+activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former
+operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The strict liability nature of such laws and regulations
+could impose liability upon us regardless of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup
+requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and
+regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future. 
+Waste Handling . The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes and regulations promulgated
+thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and
+11 
+Table of Contents 
+Index to Financial Statements 
+cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more
+stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that
+are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes
+or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous
+wastes.” 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling
+requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations
+require them under such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural gas
+exploration and production wastes could increase our costs to manage and dispose of such wastes. 
+Comprehensive
+Environmental Response, Compensation and Liability Act . The Comprehensive Environmental Response, Compensation and Liability Act, also known as CERCLA or the “Superfund” law, generally imposes joint and several liability, without
+regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated
+facility, a former owner or operator of the facility at the time of contamination and those persons that disposed or arranged for the disposal of the hazardous substance. Under CERCLA and comparable state statutes, such persons may be subject to
+strict joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for
+neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released,
+would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such
+“hazardous substances” have been released. 
+Water Discharges . The Federal Water Pollution Control Act of
+1972, as amended, also known as the Clean Water Act, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and
+other gas and oil wastes, into state waters or waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws and regulations
+also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits
+for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. We believe that we have obtained or applied for and are in substantial compliance with all
+permits required under the Clean Water Act. Sanctions for failure to comply with Clean Water Act requirement include administrative, civil and criminal penalties, as well as injunctive obligations. 
+Air Emissions . The federal Clean Air Act, and comparable state laws and regulations, regulate emissions of various air pollutants
+through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. Some of our new facilities will be required
+to obtain permits before work can begin, permits may be required for our facilities’ operations, and existing facilities may be required to incur capital costs to remain in compliance. These laws and regulations may increase the costs of
+compliance for some facilities we own or
+12 
+Table of Contents 
+Index to Financial Statements 
+operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act
+and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or
+renewing permits has the potential to delay the development of oil and natural gas projects. Our air emissions may also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide and methane, which are
+emitted in the course of oil and natural gas exploration and production. 
+Operational Hazards and Insurance 
+Our operations are subject to all of the risks normally incident to the production of oil and natural gas, including, but not limited to,
+blowouts, cratering, pipe failure, casing collapse, oil spills and fires, each of which could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or injury or death to persons and
+wildlife. The energy business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharge of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental
+damage and consequences thereof, including personal injuries and property damage. We currently maintain insurance covering some, but not all of these risks. The occurrence of a significant event that is not fully insured against could have a
+material adverse effect on our financial position. 
+Headquarters and Other Facilities 
+We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease a
+portion of this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This building contains approximately 6,200 square feet of
+finished office area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for its use. 
+Employees 
+At
+December 31, 2009, we had 40 employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the
+estimated time they spent working for those affiliates. In addition, in the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For the years ended December 31, 2009 and 2008, expenses reimbursed
+to us under these arrangements were $0.6 million and $1.4 million, respectively, and are reflected as a reduction in our general and administrative expenses. A Louisiana well servicing company provides all necessary field personnel needed to operate
+the WCBB and the Hackberry fields. 
+Available Information 
+Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange
+Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the Securities and Exchange
+Commission, or SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other
+filing that we make with the SEC. 
+13 
+Table of Contents 
+Index to Financial Statements

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+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive
+proxy statement, which will be filed with the Securities and Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not
+incorporated by reference).

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+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure
+that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The
+disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely
+decisions regarding required disclosures. 
+As of December 31, 2009, an evaluation was performed under the supervision and
+with the participation of management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under
+the Securities Exchange Act of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2009, our disclosure controls and procedures are effective.
+Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over
+financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. 
+51 
+Table of Contents 
+Index to Financial Statements 
+Management’s Report on Internal Control Over Financial Reporting 
+Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is
+also responsible for establishing and maintaining a system of internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are designed to
+provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent limitations in the
+effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with respect to reporting
+financial information. 
+Management conducted an evaluation of the effectiveness of our internal control over financial
+reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal Control—Integrated
+Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2009. 
+Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended
+December 31, 2009 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2009, as stated in their accompanying report. 
+/s/ James D. Palm 
+/s/ Michael G. Moore 
+Name: 
+James D. Palm 
+Name: 
+Michael G. Moore 
+Title: 
+Chief Executive Officer 
+Title: 
+Chief Financial Officer 
+52 
+Table of Contents 
+Index to Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Gulfport
+Energy Corporation: 
+We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the
+“Company”) as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The
+Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s
+Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable
+assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
+weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a
+reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed to provide reasonable
+assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting
+includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
+assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with
+authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material
+effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect
+misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
+deteriorate. 
+In our opinion, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control
+over financial reporting as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by COSO. 
+We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries as
+of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2009 and our report
+dated March 12, 2010 expressed an unqualified opinion. 
+/s/ GRANT THORNTON LLP 
+Oklahoma City, Oklahoma 
+March 12, 2010

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+Certain Relationships and Related Transactions 
+Administrative Services Agreements 
+We are a party to an administrative service agreement with Great White Energy Services LLC, which we refer to as Great White, which agreement was entered
+into effective as of July 22, 2006. Under this agreement, our services include accounting, human resources, legal and technical support. The services provided and the fees for such services can be amended by mutual agreement of the parties.
+This administrative service agreement has a three-year term, and upon expiration of that term the agreement will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. This administrative
+service agreement is terminable (1) by the counterparty at any time with at least 30 days prior written notice to us and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of
+receipt of written notice of such breach. Great White reimbursed us for our dedicated employee time and related general and administrative costs based on the proportionate amount of time our employees spent performing services for such entity. We
+were reimbursed approximately $61,000 by Great White for services provided under this agreement during the year ended December 31, 2009. Great White is controlled by Wexford Capital LP. Charles Davidson, who beneficially owned approximately 36%
+of our outstanding common stock as of April 1, 2010, is the Chairman and Chief Investment Officer of Wexford Capital LP. 
+We are also a
+party to administrative service agreements with Stampede Farms LLC, which we refer to as Stampede Farms, Grizzly Oil Sands ULC, which we refer to as Grizzly, and Everest Operations Management LLC, which we refer to as Everest, which agreements were
+each entered into effective March 1, 2008. Under these agreements, our services include professional and technical support. Under our agreements with Stampede Farms and Everest, we also provide office space. The services provided under these
+agreements and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements has a two-year term, and upon expiration of that term such agreement will continue on a month-to-month basis
+until cancelled by either party to such agreement with at least 60 days prior written notice. Each administrative service agreement is terminable (1) by the counterparty at any time with at least 30 days prior written notice to us and
+(2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. We were reimbursed approximately $0, $20,000 and $508,000 by Stampede Farms, Grizzly and
+Everest, respectively, for services provided under these agreements during the year ended December 31, 2009. We were also reimbursed approximately $2,000 and $1,000 by Stampede Farms and Everest, respectively, for office space under these
+agreements for the year ended December 31, 2009. Each of Stampede Farms, Grizzly and Everest is controlled by Wexford Capital LP. 
+Effective July 1, 2008, we entered into an acquisition team agreement with Everest to identify and evaluate potential oil and gas properties in
+which we and Everest or its affiliates may wish to invest. Pursuant to this agreement, Gulfport and Everest each agreed to form an acquisition team. Upon a successful closing of an acquisition or divestiture, the party whose acquisition team
+identified the acquisition or divestiture is entitled to receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share of the acquisition or
+divestiture consideration. The agreement has a one year term unless earlier terminated by either party upon 30 days notice. 
+From time to
+time, two of our petroleum engineers provide services relating to evaluation of potential investments to Wexford Capital LLC and geological evaluations, seismic review and similar services to Tatex Thailand II, LLC, or Tatex II, and Tatex Thailand
+III LLC, or Tatex III. Wexford Capital LLC, Tatex II and Tatex III, respectively, have agreed to reimburse us based on the amount, scope and nature of services provided by our petroleum engineers to such entities. Each of Tatex II and Tatex III is
+controlled by Wexford Capital LP. 
+Services Provided to Us by Our Affiliates 
+We contract with Athena Construction, L.L.C., which we refer to as Athena, to provide barge services in our West Cote Blanche Bay, or WCBB, and Hackberry
+fields located along the Louisiana Gulf Coast. For the year 
+30 
+Table of Contents 
+ended December 31, 2009, we paid Athena $1,918,000 and owed an additional $836,000 for such services at that date. Athena is controlled by Wexford Capital LP. 
+Windsor Energy Group operates our Permian Basin wells in West Texas. For the year ended December 31, 2009, we paid Windsor Energy Group $7,158,000
+and owed an additional $1,631,000 for such services at that date. Windsor Energy Group is controlled by Wexford Capital LP. 
+Effective
+March 1, 2008, Everest provides tax planning, preparation of supporting tax schedules and consultation services to us, based on agreed upon fee structure. The scope of such services can be modified upon mutual agreement of the parties. Everest
+is controlled by Wexford Capital LP. 
+Caliber Development Company, LLC, or Caliber, provides building maintenance services for our
+headquarters in Oklahoma City, Oklahoma. For the year ended December 31, 2009, we paid Caliber $17,000 and owed an additional $0 at that date. Caliber is an entity controlled by Wexford Capital LP. 
+Our Investments in Affiliates and Related Agreements 
+During 2005, we purchased a 23.5% ownership interest in Tatex II at a cost of $2,400,000. The remaining interests in Tatex II are owned by other entities
+controlled by Wexford Capital LP. Tatex II, a privately-owned 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 three million acres which includes the Phu Horm Field. During 2009, we paid $320,000 in cash calls and received $517,000 in distributions in respect of our investment in Tatex II. 
+During the first quarter of 2008, we purchased a 5% ownership interest in Tatex III at a cost of $850,000. In December 2009, we purchased an additional
+approximately 12.9% ownership interest at a cost of approximately $3,385,000 bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining interests in Tatex III are owned by other entities and individuals
+affiliated with Wexford Capital LP. During 2009, we paid $428,000 in cash calls in respect of our investment in Tatex III. 
+During 2005, we
+purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken, with the remaining interests in Bakken owned by other entities controlled by Wexford Capital LP. In 2006, Bakken acquired leases on undeveloped acreage in the Williston Basin
+areas of western North Dakota and eastern Montana, which we refer to as the contract area. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. During 2009,
+we sold approximately 18,000 net acres in the Bakken Shale and approximately 190 net BOEPD of production for approximately $18.8 million. 
+Effective January 1, 2008, we entered into an area of mutual interest agreement with Bakken and Windsor Dakota LLC, or Windsor Dakota, to jointly
+acquire oil and gas leases on certain lands located in North Dakota and Montana for the purpose of exploring, exploiting and producing oil and gas from the Bakken Shale. The agreement provides that each party must offer the other party the right to
+participate in such acquisition in proportion to its participating interest, which is 20% for us and 80% for Bakken and Windsor Dakota, collectively. The parties also agreed, subject to certain exceptions, to share third-party costs and expenses in
+proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, we, Bakken, Windsor Dakota and Windsor Energy Group, L.L.C., as the operator, also entered into an
+exploration agreement, effective as of January 1, 2008, pursuant to which we, Bakken and Windsor Dakota agreed to jointly evaluate, explore, exploit and develop the contract area, and Windsor Energy Group, L.L.C. agreed to act as the operator
+under the terms of a joint operating agreement. In the event Gulfport has greater than a 50% interest in a prospect, as defined in the exploration agreement, the parties agreed to support Gulfport as the operator. The parties agreed to pay Windsor
+Energy Group, L.L.C. for its services as the operator with respect to the contract area as provided in the joint operating agreement. 
+31 
+Table of Contents 
+During the third quarter of 2006, we purchased, through our wholly owned subsidiary Grizzly Holdings, Inc.,
+a 24.9999% interest in Grizzly, a Canadian unlimited liability company, for approximately $8,200,000. The remaining interests in Grizzly are owned by other entities controlled by Wexford Capital LP. During 2006 and 2007, Grizzly acquired leases in
+the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 527,000 acres under lease and, at December 31, 2009, our net investment in Grizzly was approximately
+$41,000,000, including a note receivable of $15,900,000 as discussed in the following paragraph. 
+We, through our wholly owned subsidiary
+Grizzly Holdings Inc., entered into a loan agreement with Grizzly effective January 1, 2008, under which Grizzly may borrow funds from us. Borrowed funds bear interest at LIBOR plus 4%. Interest is paid on a paid-in-kind basis by increasing the
+outstanding balance of the loan. The loan matures on December 31, 2012. We loaned Grizzly approximately $4,377,000 during the year ended December 31, 2009. The Company recognized interest income of approximately $547,000 for the year ended
+December 31, 2009 under this loan agreement. The note balance was increased by approximately $1,843,000 as a result of a currency translation gain for the year ended December 31, 2009. 
+Option and Purchase Agreement and Related Agreements 
+On November 30, 2007, we entered into an option agreement with Windsor Permian LLC, an entity controlled by Wexford Capital LLC, which we refer to as
+Windsor Permian. Under the option agreement, we were granted the right to participate on a 50/50 basis with Windsor Permian in the acquisition of certain strategic assets in Upton County, Texas in the Permian Basin. On December 12, 2007, we
+exercised the option and on December 18, 2007, the purchase agreement was amended to, among other things, add Gulfport as a buyer under the purchase agreement. On December 20, 2007, the acquisition was closed, effective as of
+November 1, 2007. We and Windsor Permian also agreed to share equally all third-party costs and expenses incurred by each of us in connection with the transaction. 
+In addition, effective as of November 1, 2007, we and Windsor Permian entered into an area of mutual interest agreement to jointly acquire oil and
+gas leases in the Permian Basin. The agreement provides that each party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain exceptions, to share third-party costs and
+expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. 
+In connection
+with the area of mutual interest agreement, we, Windsor Permian and Windsor Energy Group, L.L.C., as the operator, entered into the joint development agreement, effective as of November 1, 2007, pursuant to which we and Windsor Permian agreed
+to develop certain jointly held oil and gas leases in the Permian Basin, and Windsor Energy Group, L.L.C. agreed to act as the operator under the terms of the joint operating agreement, effective as of November 1, 2007. In the event either
+party has greater than a 50% interest in a prospect, as defined in the development agreement, the majority party may designate the operator of its choice. The parties agreed to pay Windsor Energy Group, L.L.C. for its services as the operator with
+respect to the contract area as provided in the joint operating agreement. 
+32 
+Table of Contents

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+ITEM 1. 
+DESCRIPTION OF BUSINESS 
+General
+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, or WCBB, 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. We also hold a
+significant acreage position in the Alberta oil sands in Canada through our interest in Grizzly Oil Sands ULC, or Grizzly, 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. 
+In 2010, at our WCBB field, we
+recompleted 72 wells and drilled 23 wells for a total cost of approximately $40.9 million as of December 31, 2010. All 23 new wells drilled at WCBB in 2010 were completed as producing wells. During 2011, we currently anticipate drilling 20 to
+24 wells and recompleting 60 wells at our WCBB field for an estimated aggregate cost of $36.0 to $38.0 million. In the fourth quarter of 2010, production at WCBB was 293,372 net barrels of oil equivalent, or BOE, or an average of 3,189 BOE per day,
+97% of which was from oil and 3% of which was from natural gas. From January 1, 2011 through February 28, 2011, our average net daily production at WCBB was 2,721 BOE, 97% of which was from oil and 3% of which was from natural gas.
+In 2010, at our East Hackberry field, we recompleted ten wells and drilled eight wells for a total cost of approximately
+$20.0 million as of December 31, 2010. All wells drilled during 2010 were completed as producing wells. During 2011, we currently anticipate drilling seven to ten wells and recompleting five wells for an aggregate estimated cost of $24.0 to
+$26.0 million. In the fourth quarter of 2010, net production at East Hackberry was 157,349 BOE, or an average of 1,710 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1, 2011 through February 28,
+2011, our average net daily production at East Hackberry was 1,899 BOE, 93% of which was from oil and 7% of which was from natural gas. 
+In the fourth quarter of 2010, net production at West Hackberry was 3,121 BOE, or an average of 34 BOE per day, 100% of which was from oil. From January 1, 2011 through February 28, 2011, our
+average net daily production at West Hackberry was 35 BOE, 100% of which was from oil. 
+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 10,600 additional net acres, which brought
+our total net acreage position in the Permian Basin to approximately 14,700 net acres. During the year ended December 31, 2010, 25 gross (11 net) wells were drilled and four gross (two net) wells were recompleted on this acreage. As of
+March 1, 2011, 24 of the 25 wells had been completed and one well was awaiting completion. We currently anticipate that 40 to 42 gross (19 to 20 net) wells will be drilled and ten gross (five net) wells will be recompleted on this acreage in
+2011 for an estimated aggregate net cost of $37.0 to $39.0 million. In the fourth quarter of 2010, net production from our Permian acreage was 72,791 BOE, or an average of 791 BOE per day, 84% of which was from oil and natural gas liquids and 16% of
+which was from natural gas. From January 1, 2011 through February 28, 2011, our average daily net production from our Permian acreage was 787 BOE, 87% of which was from oil and natural gas liquids and 13% of which was from natural gas.
+Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Colorado and held leases for
+19,172 net acres as of March 1, 2011. During the year ended December 31, 2010, we recompleted one gross (0.4 net) well on this acreage. In the fourth quarter of 2010, net production at Niobrara was 3,380 BOE, or an average of 37 BOE per day,
+100% of which was from oil. From January 1, 2011 through February 28, 2011, our average net daily production at Niobrara was 36 BOE, 100% of which was from oil. We are in the process of permitting a 60 square mile 3-D seismic survey and
+expect to begin shooting in mid-2011. 
+2 
+Table of Contents 
+As of December 31, 2010, we held approximately 900 net acres in the Williston Basin of
+western North Dakota and eastern Montana with interests in five wells and an overriding royalty interest in wells drilled prior to our sale, wells drilled subsequent to our sale and wells that might be drilled in the future. In the fourth quarter of
+2010, our net production from this acreage was 6,522 BOE, or an average of 71 BOE per day, 95% of which was from oil and natural gas liquids and 5% of which was from natural gas. From January 1, 2011 through February 28, 2011, our average
+daily net production from our Bakken acreage was 64 BOE, 93% of which was from oil and 7% of which was from natural gas. 
+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 Capital LP, or Wexford. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles of
+other existing oil sands projects. Grizzly has approximately 534,000 acres under lease and our total net investment in Grizzly was approximately $46.5 million, including a note receivable of $20.0 million, at December 31, 2010. To date, Grizzly
+has drilled an aggregate of 199 core holes and three water supply test wells, tested nine separate lease blocks and conducted a seismic program. In March 2010, Grizzly filed an application in Alberta, Canada for the development of an 11,300 barrel
+per day oil sand SAGD facility at Algar Lake. Grizzly expects regulatory approval by mid-2011, followed by an anticipated construction period of 18 months leading to first production. Grizzly recently received the supplemental information request,
+or SIR, pertaining to its Algar Lake project application from the Alberta regulatory agencies. This is the standard process by which the Alberta regulatory agencies request additional information on all oil sands project applications. The SIR was
+received in a timeframe consistent with anticipated timeline for project approval. The engineering and procurement contract for Grizzly’s proposed steam assisted gravity drainage, or SAGD, facility at Algar Lake has been awarded to SNC-Lavin.
+Work on the detailed engineering design is underway out of Grizzly’s Calgary office and the detailed design of the project is expected to be complete by April 2011. Grizzly’s currently contemplated 2011 activities include the completion of
+the 2010/2011 core hole drilling activity, seismic program and the initial preparations for the Algar Lake SAGD facility. 
+We
+own a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, 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 includes the Phu Horm Field. 
+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 2010, Tatex completed a 3-D seismic survey on this concession. The first well drilled on our concession in 2010
+was temporarily abandoned pending further scientific evaluation. A 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. Tatex III is currently in the process of completing the well. 
+As of December 31, 2010, we had 22.4 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of
+estimated future net revenues, discounted at 10%, or PV-10, of approximately $392.6 million and associated standardized measure of discounted future net cash flows of approximately $315.5 million. See Item 2. “Properties—Proved Oil
+and Natural Gas Reserves” for our definition of PV-10, a non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. 
+3 
+Table of Contents 
+Principal Oil and Natural Gas Properties 
+The following table presents certain information as of December 31, 2010 reflecting our net interest in our principal producing oil
+and natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas, in the Niobrara Formation in western Colorado and in the Williston Basin in western North Dakota and eastern Montana. 
+Proved Reserves 
+Field 
+NRI/WI (1) 
+Productive 
+Wells (2) 
+Non-Productive 
+Wells 
+Developed 
+Acreage (3) 
+Gas 
+Oil 
+Total 
+Percentages 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+Mboe 
+Mboe 
+Mboe 
+West Cote Blanche Bay Field (4) 
+80.108/100 
+93 
+93 
+179 
+179 
+5,668 
+5,668 
+386 
+4,133 
+4,519 
+E. Hackberry Field (5) 
+79.424/100 
+27 
+27 
+74 
+74 
+3,291 
+3,291 
+291 
+2,561 
+2,852 
+W. Hackberry Field 
+87.5/100 
+3 
+3 
+22 
+22 
+592 
+592 
+— 
+146 
+146 
+Permian Basin 
+37.38/49.05 
+82 
+40 
+— 
+— 
+15,888 
+7,124 
+1,988 
+12,465 
+14,453 
+Niobrara Formation 
+36.4/44.04 
+4 
+2 
+1 
+0.4 
+2,240 
+628 
+23 
+339 
+362 
+Williston Basin (6) 
+3.2/3.9 
+5 
+0.2 
+— 
+— 
+2,560 
+127 
+5 
+58 
+63 
+Overrides/Royalty Non-operated 
+Various 
+77 
+0.2 
+2 
+— 
+— 
+— 
+— 
+2 
+2 
+Total 
+291 
+165.4 
+278 
+275.4 
+30,239 
+17,430 
+2,693 
+19,704 
+22,397 
+(1) 
+Net Revenue Interest (NRI)/Working Interest (WI). 
+(2) 
+Includes nine gross and net wells at WCBB that are producing intermittently. 
+(3) 
+Developed acres are acres spaced or assigned to productive wells. Approximately 36% 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) 
+NRI/WI is from wells that have been drilled or in which we have elected to participate. 
+West Cote Blanche Bay Field 
+Location and Land 
+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. 
+Area History and Production 
+Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the
+remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 973 wells drilled as of December 31, 2010, 880 were completed as producing wells. As a result, the
+field has a historic success rate of 90% for all wells drilled. From the date of our acquisition of WCBB in 1997 through December 31, 2010, we drilled 162 new wells, 146 of which were productive, for a 90% success rate. As of December 31,
+2010, estimated field cumulative gross production was 191.3 MMBOE and 236.4 billion cubic feet, or Bcf, of gas. Of the 973 wells drilled in WCBB as of December 31, 2010, 84 were producing, 179 were shut-in, nine were producing intermittently
+and five were being used as salt water disposal wells. The other 696 wells have been plugged and abandoned. 
+4 
+Table of Contents 
+In 1991, Texaco conducted a 70 square mile 3-D seismic survey with 1,100 shot points per
+mile that processed out 100 fold. In 1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December 1999, we completed the reprocessing of the seismic data and our technical
+staff developed prospects from the data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the first half of 2005, we again reprocessed the seismic data using advanced
+seismic data processing. 
+Geology 
+WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The
+relative movements affected deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension
+over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. 
+There are over 100 distinct
+sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 973 wells that had been drilled in the field as of December 31, 2010, over 4,000 potential zones have
+been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. 
+WCBB is a
+structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a
+structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The
+tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This,
+in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an effort
+to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. Our inventory of prospects at WCBB as of December 31, 2010 included
+29 PUD wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2013. 
+Facilities
+We own and operate a production facility at WCBB that includes four production tank batteries, eight natural gas
+compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. 
+Recent and Future Activity
+In 2010, we recompleted 72 gross and net wells and drilled 23 gross and net wells at WCBB. All 23 new wells were completed
+as producers. As of March 11, 2011, we had drilled two wells and recompleted twelve wells during 2011. Of the 23 wells drilled in 2010, 17 were considered deep wells. The 23 productive wells, with total depths ranging from 1,800 to 9,560 feet,
+have approximately 2,063 feet of aggregate apparent net pay. We currently anticipate drilling 20 to 24 gross and net wells and recompleting 60 gross and net wells at WCBB during 2011. 
+Production Status 
+In the fourth quarter of 2010, production at WCBB was
+293,372 net BOE, or an average of 3,189 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From January 1, 2011 through February 28, 2011, our average net daily production at WCBB was 2,721 BOE, 97% of which was
+from oil and 
+5 
+Table of Contents 
+3% of which was from natural gas. The decrease in production was due to operating inefficiencies with wells, machinery and equipment resulting from the sub-freezing weather conditions during
+January and February 2011 in Southern Louisiana. 
+East Hackberry Field 
+Location and Land 
+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 79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry
+field. We hold beneficial interests in approximately 4,870 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 also hold
+2,868 net acres subject to a two-year exploration agreement we entered into with an active gulf coast operator. We are the designated operator under the agreement and will participate in proposed wells with at least a 70% working interest. We have
+licensed approximately 54 square miles of 3-D seismic data covering a portion of the area and are reprocessing the data. 
+Area History and
+Production 
+The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a
+gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and
+condensate production through 2010 was over 1,015 MBOE and 330 Bcf of casinghead gas production. A total of 201 wells have been drilled on our portion of the field. As of December 31, 2010, 27 wells had daily production, 74 were shut-in and two
+had been converted to salt water disposal wells. The remaining 98 wells had been plugged and abandoned. 
+Geology 
+The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and
+west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply
+dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. 
+Facilities 
+We have a
+field office that serves both the East and West Hackberry fields. In addition, we completed installation of a new production barge at the East Hackberry field in the second quarter of 2007. The barge is designed to have the ability to process on a
+per day basis approximately 5,000 barrels of liquid, 30 Mmcf of high pressure natural gas, 6.5 Mmcf of low pressure natural gas and 10,000 barrels of salt water. 
+Recent and Future Activity 
+During 2005, we completed a proprietary 42
+square mile 3-D seismic survey at East Hackberry, the first modern seismic program undertaken at this field. We believe that this 3-D seismic data enhances our probability of drilling success, and we continue to evaluate the 3-D seismic data to
+identify additional drilling locations. During 2010 at East Hackberry, we recompleted ten gross and net wells and drilled six gross and net land wells and two gross and net wells on water. All of the eight wells drilled during 2010 were completed as
+producing wells. As of March 11, 2011, we had recompleted three wells during 2011, drilled one well and were in the process of drilling two additional wells. We currently intend to drill seven to ten gross and net wells and recomplete five
+gross and net wells at East Hackberry during 2011. 
+6 
+Table of Contents 
+Production Status 
+In the fourth quarter of 2010, net production at East Hackberry was 157,349 BOE, or an average of 1,710 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1,
+2011 through February 28, 2011, our average net daily production at East Hackberry was 1,899 BOE, 93% of which was from oil and 7% of which was from natural gas. The increase in production in 2011 is a result of our 2011 drilling activities.
+West Hackberry Field 
+Location and Land 
+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 87.5%
+NRI) in 592 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. 
+Area History 
+The first
+discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2010 was 274 MBOE and 140 Bcf
+of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, three are producing, 22 are shut-in and one has been converted to a saltwater disposal well. The remaining ten wells have been plugged and
+abandoned. 
+Geology 
+Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in
+the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. 
+Production Status 
+In
+the fourth quarter of 2010, net production at West Hackberry was 3,121 BOE, or an average of 34 BOE per day. From January 1, 2011 through February 28, 2011, our average net daily production at West Hackberry was 35 BOE and was 100% oil.
+Facilities 
+We have land-based production and processing facilities located at the West Hackberry field and maintain a field office that serves both
+the East and West Hackberry fields. 
+Permian Basin (West Texas) 
+Location and Land 
+We acquired approximately 4,100 net acres and 32 gross
+(16 net) producing wells in West Texas (near Midland) in the Permian Basin effective November 1, 2007. Subsequently, we acquired 10,600 additional net acres, which brought our total net acreage position in the Permian Basin to approximately
+14,700 net acres as of December 31, 2010. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing basins in the United States. The terrain in the Permian
+Basin is semi-arid mesquite-mixed grassland steppe. Windsor Energy LLC, an entity controlled by Wexford, is the operator of this field. 
+7 
+Table of Contents 
+Area History 
+The Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a long-established reservoir in West Texas, first found
+in the 1950s as wells aiming for deeper targets occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was not until the use of 3-D seismic in the 1990s that the
+greater extent of the Wolfcamp prospects was revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 feet to pick up the upper part of the Wolfcamp
+formation. Henry Petroleum, a private firm, owned interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section as Devonian
+wells. Henry Petroleum mapped the trend and began acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private
+company, ExL Petroleum, and began replicating Henry Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled us to
+participate in this play. Recent advancements in enhanced recovery techniques continue to make the basin an active play for exploration and production companies. As of December 31, 2010, we held interests in 82 gross (40 net) producing wells.
+Geology 
+The
+Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging Wolfcamp carbonate play. The Wolfcamp is
+characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir rock within the section is generally found in close proximity to the Central Basin Platform.
+Wolfberry well reserves are typically approximately 80% from the Wolfcamp section and 20% from the Spraberry section.
+Pinnacle Energy Services, LLC, an independent petroleum engineering firm, has estimated that at December 31, 2010, proved reserves net to our interest in these assets were approximately 14.5 million BOE, of which 16% were classified as
+proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 226 gross well locations on 40-acre units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally
+characterized as long-lived, with predictable production profiles. 
+Production Status 
+In the fourth quarter of 2010, net production from the Permian field was 72,791 BOE, or an average of 791 BOE per day, 84% of which was
+from oil and natural gas liquids, and 16% of which was from natural gas. From January 1, 2011 through February 28, 2011, our average daily net production from our Permian acreage was 787 BOE, 87% of which was from oil and natural gas
+liquids and 13% of which was from natural gas. The slight production decrease was the result of the unusual sub-freezing weather conditions during January and February 2011. 
+Facilities 
+There are typical land oil and gas processing facilities in the
+Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent and Future Activity 
+In 2010, 25 gross (11 net) wells were drilled in our Permian acreage. As of March 11, 2011, four gross (two net) wells had been recompleted and five gross (2.5 net wells) have been drilled
+on this acreage, three of which were waiting on completion and two were currently drilling. We have identified 226 gross future development drilling locations. We currently expect an estimated 40 to 42 gross (19 to 20 net) wells to be drilled
+on our acreage in 2011. The wells are expected to be drilled to approximately 10,200 feet. 
+8 
+Table of Contents 
+Niobrara Formation (Western Colorado) 
+Location and Land 
+Effective as of April 1, 2010, we acquired
+leasehold interests in the Niobrara Formation in western Colorado, and held leases for 19,172 acres as of March 1, 2011. We are the operator on the acreage. 
+Area History 
+The Niobrara Formation is a shale oil rock formation located
+in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 – 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara formation has emerged as
+another potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara has a history of producing through conventional technology with some of the earliest production
+dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara historically due to the low porosity and low permeability of the formation. Because of this, conventional production has been very localized and
+limited in area extent. We believe the Niobrara can be produced on a more widespread basis using today’s horizontal multi-stage fracture stimulation technology where the Niobrara is thermally mature. 
+Geology 
+The Niobrara
+Formation oil play in northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales, calcareous shales and marlstones. It is the fractured
+marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the areas production. These fractured carbonate reservoirs are associated with anticlinal, synclinal and monoclinal folds, and
+fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect oil generation. The producing intervals are geologically equivalent
+to the Niobrara reservoirs of the DJ and Powder River Basins which are currently emerging as a major crude resource play. 
+Production
+Status 
+In the fourth quarter of 2010, net production from our Niobrara acreage was 3,380 BOE, or an average of 37 BOE per
+day, 100% of which was from oil. From January 1, 2011 through February 28, 2011, our average daily net production from our Niobrara acreage was 36 BOE, 100% of which was from oil. 
+Facilities 
+There are typical land oil and gas processing facilities in the
+Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent and Future Activity 
+We recompleted one well at Niobrara during
+2010. We are in the process of permitting a 60 square mile 3-D seismic survey over our Craig Dome prospect and expect to begin shooting in mid-2011. We currently intend to drill four to five gross wells at Niobrara during 2011. 
+9 
+Table of Contents 
+Bakken 
+Location and Land 
+The Bakken Shale is located in the Williston Basin areas
+of western North Dakota and eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining interests in Bakken were owned by entities controlled by Wexford. Beginning in 2005, Bakken acquired
+leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of its undeveloped acreage. Effective January 1, 2008, we acquired a direct, undivided 20% interest
+in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190 net BOEPD of production for approximately $13.0 million, with an effective date of April 1, 2009.
+During September 2009, we sold approximately 5,721 net acres for approximately $5.8 million with an effective date of July 1, 2009. As of December 31, 2010, we held approximately 900 net acres, interests in five wells and an overriding
+royalty interest in wells drilled prior to our sale, wells drilled subsequent to our sale and wells that might be drilled in the future. 
+Production Status 
+In
+the fourth quarter of 2010, net production from our Bakken acreage was 6,522 BOE, or an average of 71 BOE per day, 95% of which was from oil and natural gas liquids and 5% of which was from natural gas. From January 1, 2011 through
+February 28, 2011, our average net daily production from this acreage was 64 BOE, of which 93% was from oil and 7% was from natural gas. 
+Facilities 
+There are
+typical land oil and gas processing facilities in the Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent and future activities 
+One gross well was drilled on our acreage in 2010. We have no activities currently scheduled for 2011 in the Williston Basin. 
+Additional Properties 
+Louisiana . In addition to our interests in
+the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana as described in the following table: 
+Field 
+Parish 
+Acreage Working 
+Interest 
+Overriding Royalty 
+Interests 
+Producing 
+Wells 
+Non-Producing 
+Wells 
+Bayou Long 
+Iberia 
+3.125 
+% 
+0 
+% 
+0 
+0 
+Bayou Penchant 
+Terrebonne 
+3.125 
+% 
+0 
+% 
+1 
+2 
+Bayou Pigeon 
+Iberia 
+6.250 
+% 
+0 
+% 
+0 
+0 
+Deer Island 
+Terrebonne 
+6.250 
+% 
+0 
+% 
+0 
+0 
+Golden Meadow 
+Lafourche 
+3.125 
+% 
+0 
+% 
+0 
+0 
+Napoleonville 
+Assumption 
+0 
+% 
+2.5 
+% 
+3 
+0 
+Thailand .
+During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex, at a cost of $2.4 million. The remaining interests in Tatex are owned by entities controlled by Wexford. Tatex, 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 includes
+the Phu Horm Field. During 
+10 
+Table of Contents 
+the year ended December 31, 2010, we received $565,000 in distributions, reducing our total investment in Tatex to $1.9 million. Our investment is accounted for on the equity method. Tatex
+accounts for its investment in APICO using the cost method. In December 2006, first gas sales were achieved at the Phu Horm field located in northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet
+per day. For December 2010, net gas production was approximately 98 MMcf per day and condensate production was 477 barrels per day. Hess Corporation operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTTEP
+(20% interest) and ExxonMobil (10% interest). Our gross working interest (through Tatex as a member of APICO) in the Phu Horm field is 0.7%. Due to the fact that our ownership in the Phu Horm field is indirect and Tatex’s investment in APICO is
+accounted for by the cost method, these reserves are not included in our year-end reserve information. 
+During the first
+quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III, at a cost of $850,000. In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3.4 million
+bringing our total ownership interest to approximately 17.9%. 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. Tatex III
+recently completed a 3-D seismic survey on this concession. During the year ended December 31, 2010, we paid $402,000 in cash calls, bringing our total investment in Tatex III to $4.7 million. The first well drilled on our concession in 2010
+was temporarily abandoned pending further scientific evaluation. A 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. Tatex III is currently in the process of completing the well. 
+Grizzly Oil Sands . 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. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray within a few miles from other existing oil sands projects. Grizzly has approximately
+534,000 acres under lease and our total net investment in Grizzly was approximately $46.5 million, including a note receivable of $20.0 million, at December 31, 2010. To date, Grizzly has drilled an aggregate of 199 core holes and three water
+supply test wells, tested nine separate lease blocks and conducted a seismic program. In connection with its 2010/2011 winter drilling program, Grizzly plans to drill a total of 71 core hole locations, 68 of which have been drilled to date. Upon the
+completion of the 2010/2011 drilling season, Grizzly will have drilled 32 locations at Thickwood Hills, 14 locations at Firebag River, 17 locations at Algar Lake, and eight total locations at Athabasca Rapids and Horse River. In March 2010, Grizzly
+filed an application in Alberta, Canada for the development of an 11,300 barrel per day SAGD facility at Algar Lake. Grizzly expects regulatory approval by mid-2011, followed by an anticipated construction period of 18 months leading to first
+production. Grizzly recently received the supplemental information request, or SIR, pertaining to its Algar Lake project application from the Alberta regulatory agencies. This is the standard process by which the Alberta regulatory agencies request
+additional information on all oil sands project applications. The SIR was received in a timeframe consistent with anticipated timeline for project approval. The engineering and procurement contract for Grizzly’s proposed steam assisted gravity
+drainage facility at Algar Lake has been awarded to SNC-Lavin. Work on the detailed engineering design is underway out of Grizzly’s Calgary office and the detailed design of the project is expected to be complete by April 2011. Grizzly’s
+currently contemplated 2011 activities include the completion of the 2010/2011 core hole drilling activity and the initial preparations for the Algar Lake SAGD facility. 
+Competition and Markets 
+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 
+11 
+Table of Contents 
+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. 
+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 demand for oil and natural gas and the level 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, other than the production sold under forward sales contracts,
+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 trade month average differential less $2.70 per
+barrel for transportation. During 2010, we sold 75% and 19% of our oil production to Shell and Windsor Energy Group, the operator of our Permian wells, respectively, and 50%, 32%, and 10% of our natural gas production to Windsor Energy Group,
+Chevron and Hilcorp Energy Company, respectively. During 2009, we sold 92% and 7% of our oil production to Shell and Windsor Energy Group, the operator of our Permian wells, respectively, and 45%, 38%, and 16% of our natural gas production to
+Windsor Energy Group, Chevron and Hilcorp Energy Company, respectively. During 2008, we sold 87% of our oil production to Shell and 11% to Windsor Energy Group, 100% of our natural gas liquids production to Windsor Energy Group, and 60%, 22%, and
+16% of our natural gas production to Chevron, Windsor Energy Group, and Hilcorp Energy Company, respectively. We may not continue to have ready access to suitable markets for our future oil and natural gas production. 
+Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The price
+at which the oil and natural gas we produce may be sold is uncertain and it is possible that under some market conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the
+factors influencing the price of oil and natural gas, it is impossible to accurately predict future prices. 
+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. We delivered approximately 45% of our 2010 production under these agreements. 
+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,
+before transportation costs and differentials, for the period January 2011 through December 2011. Under the 2011 contracts, we have committed to deliver approximately 30% to 33% of our estimated 2011 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. These forward sales contacts 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. 
+Regulation 
+Regulation of Gas and Oil Production 
+Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation
+affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our
+cost of doing business and, consequently, affects our profitability. 
+12 
+Table of Contents 
+We own interests in a number of producing oil and natural gas properties located along the
+Louisiana Gulf Coast, West Texas and the Niobrara Formation. The states in which our fields are located in regulate the production and sale of oil and natural gas, including requirements for obtaining drilling permits, the method of developing new
+fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas resources could affect the rate of production and may include maximum daily production
+allowables for wells on a market demand or conservation basis. 
+Environmental Regulation 
+Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the
+discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, or EPA, issue regulations which often require difficult and costly
+compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences,
+restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying
+within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or
+revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relate to our owned or operated facilities. The
+strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly
+pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that
+we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.
+Waste Handling . The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and
+regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and
+non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Although most wastes associated with the exploration,
+development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent requirements of non-hazardous waste
+provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future
+regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Any such changes in the laws and regulations
+could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal
+penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits,
+registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe that the current costs of managing our wastes as they are presently classified to be significant, any
+legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes. 
+Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as CERCLA or the “Superfund” law, and analogous state
+laws, generally 
+13 
+Table of Contents 
+imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a
+“hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or
+arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject to strict and joint and several liability for the costs of removing or
+remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health
+studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our
+operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of
+the costs to clean up sites at which such “hazardous substances” have been released. 
+Water Discharges . The
+Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act”, the Oil Pollution Act and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the
+unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance
+with the terms of a permit issued by the EPA or the state. Spill prevention, control and countermeasure, or SPCC, plan requirements under federal law require appropriate containment terms and similar structures to help prevent the contamination of
+navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also
+adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or
+developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for
+discharges or operations that may impact groundwater conditions. 
+The Oil Pollution Act, or OPA, is the primary federal law
+for oil spill liability. OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore
+facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects
+owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.
+Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well
+as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. 
+Air
+Emissions . The Federal Clean Air Act, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and
+continues to develop, stringent regulations governing emissions of air pollutants at specified sources. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for our facilities’ operations,
+and existing facilities may be required to incur capital costs to remain in compliance. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose
+administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air
+emissions regulations 
+14 
+Table of Contents 
+and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas
+projects. Our operations may also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide and methane, which are emitted in the course of oil and natural gas exploration and production. 
+Operational Hazards and Insurance 
+The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high pressure formations which could lead to
+environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to
+property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. 
+In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our
+properties for operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of certain wells, oil pollution, third
+party liability, workers compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery. Additionally, our insurance is subject to exclusion and limitations, and there is
+no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could cause a significant disruption to our business. For example, we experienced
+production interruptions in 2005 and 2006 from Hurricanes Katrina and Rita and, in 2008, from Hurricanes Gustav and Ike. A loss not fully covered by insurance could have a material adverse affect on our financial position, results of operations and
+cash flows. 
+Currently, we have general liability insurance coverage with an annual aggregate limit of up to $21.0 million
+which includes environmental impairment coverage for the effects of onshore and offshore pollution on third parties arising from our operations. For our offshore West Cote Blanche Bay properties, we also have a $25.0 million property physical damage
+policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to $10.0 million for damages arising as a result of a named windstorm. In the event
+of a loss under this policy, we have up to $6.6 million of business interruption coverage available after a 90 day waiting period. All of our insurance coverage includes deductibles of up to $500,000 per occurrence ($1.5 million in the case of a
+named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of insurance, policy terms and limits annually each May. Future insurance coverage for
+our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be
+given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage. 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. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial
+condition and results of operations. 
+At the depths and in the areas in which we operate, and in light of the vertical and
+directional drilling that we undertake, we typically do not encounter high pressures or extreme drilling conditions. Accordingly, we typically do not carry a control of well policy, although we currently have such coverage in place for two specific
+wells we are drilling this year. We also require all of our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and
+subcontractors hired by the service provider. 
+We have prepared and have in place spill prevention control and countermeasure
+plans for each of our principal facilities at WCBB in response to federal and state requirements. The plans are reviewed annually and 
+15 
+Table of Contents 
+updated as necessary. As required by applicable regulations, our facilities are built with oil containment features and we own certain oil containment equipment, such as oil boom to surround
+drill sites and production facilities if needed. In addition, we have a national emergency response company on retainer. This company specializes in the clean up of hydrocarbons as a result of spills, blow-outs and natural disasters. This emergency
+response company has been involved in the clean up efforts of some of the largest oil spills along the Gulf Coast and is on call to us 24 hours a day when its services are needed. It reports that it currently owns over 164 response vehicles, 65
+response vessels, 116 response trailers equipped with decontaminant supplies, personal protective equipment and other equipment used in responding to oil spills, two storage barge sets, allowing for storage of up to 248 barrels of recovered oil
+each, and over 20 roll-off boxes and vacuum boxes. We pay this company a retainer plus additional amounts when it provides us with clean up services. Our aggregate payments for the retainer and clean up services during 2009 and 2010 were
+approximately $139,000. While this company has been able to meet our service needs when required from time to time in the past, it is possible that its ability to provide services to us in the future, if and when needed, could be hindered or delayed
+in the event of a widespread disaster. However, in light of the depths and the areas in which we operate, and the necessity for gas lift to produce our WCBB wells due to low reservoir pressure at our WCBB field, we believe other companies would be
+available to us in the event our primary remediation company was unable to perform. 
+Headquarters and Other Facilities 
+We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease
+a portion of this office space to certain of our affiliates. We also own an approximately 12,500 square foot building in Lafayette, Louisiana that is leased to an unrelated third party. This building contains approximately 6,200 square feet of
+finished office area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for its use. 
+Employees 
+At
+December 31, 2010, we had 45 employees. Certain of our employees perform management and administrative services for affiliated companies. We are reimbursed by these affiliates for the salaries and benefits of these individuals based on the
+estimated time they spent working for those affiliates. In addition, in the past, we have also received 100% of the COPAS overhead charges billed to these affiliated companies. For the years ended December 31, 2009 and 2008, expenses reimbursed
+to us under these arrangements were $0.6 million and $1.4 million, respectively, and are reflected as a reduction in our general and administrative expenses. No amounts were reimbursed to us under these arrangements in 2010. A Louisiana well
+servicing company provides all necessary field personnel needed to operate the WCBB and the Hackberry fields. 
+Available Information
+Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those
+reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such material is
+electronically filed with, or furnished to, the Securities and Exchange Commission, or SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual report on
+Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. 
+16 
+Table of Contents

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+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and
+Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).

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+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief
+Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded,
+processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including
+our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. 
+As of December 31, 2010, an evaluation was performed under the supervision and with the participation of management, including our Chief Executive Officer and Vice President and Chief Financial
+Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President
+and Chief Financial Officer have concluded that as of December 31, 2010, our disclosure controls and procedures are effective. 
+Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial reporting that occurred during our last fiscal quarter that have
+materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. 
+57 
+Table of Contents 
+Management’s Report on Internal Control Over Financial Reporting 
+Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is
+also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are
+designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent
+limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with
+respect to reporting financial information. 
+Management conducted an evaluation of the effectiveness of our internal control
+over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal
+Control—Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2010.
+Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year
+ended December 31, 2010 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2010, as stated in their accompanying report. 
+/s/ James D. Palm 
+/s/ Michael G. Moore 
+Name: 
+James D. Palm 
+Name: 
+Michael G. Moore 
+Title: 
+Chief Executive Officer 
+Title: 
+Chief Financial Officer 
+58 
+Table of Contents 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Gulfport
+Energy Corporation: 
+We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the
+“Company”) as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The
+Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s
+Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable
+assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
+weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a
+reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed to provide reasonable
+assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting
+includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable
+assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with
+authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material
+effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect
+misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may
+deteriorate. 
+In our opinion, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control
+over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries as
+of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2010 and our report
+dated March 14, 2011 expressed an unqualified opinion. 
+/s/ GRANT THORNTON LLP 
+Oklahoma City, Oklahoma 
+March 14, 2011

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+Certain Relationships and Related Transactions 
+Review and Approval of Related Party Transactions 
+The Audit Committee, as provided in its charter, reviews and approves related party transactions. The Company does not have a formal set of standards to be substantively applied to each transaction
+reviewed by the Audit Committee. Instead of a formalized policy, related party transactions are reviewed and judgment is applied to determine whether such transactions are in the best interests of the Company. Further, the Company’s Code of
+Business Conduct and Ethics governs various compliance areas, including conflicts of interest and fair dealings, which are considered in the process of the review and approval of related party transactions. 
+The Company’s policy that all of its employees and directors, as well as their family members, must avoid any activity that is or has the appearance
+of conflicting with the Company’s business interest. This policy is a written policy included in the Company’s Code of Business Conduct and Ethics posted on its website. Each director and executive officer is instructed to always inform
+the designated compliance officer when confronted with any situation that may be perceived as a conflict of interest. Only the board of directors or a committee consisting solely of independent directors may grant waivers of the provisions of the
+Code of Business Conduct and Ethics for the Company’s executive officers and directors. In addition, at least annually, each director and executive officer completes a detailed questionnaire specifying any business relationship that may give
+rise to a conflict of interest. 
+Further, under the Audit Committee Charter, the Audit Committee is responsible for reviewing and monitoring
+compliance with our Code of Business Conduct and Ethics and recommending any warranted changes to the board of directors. In addition, the board of directors and, pursuant to its written charter, the Audit Committee, reviews and approves all
+relationships and transactions in which the Company and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their family members,
+have a direct or indirect material interest. The board of directors and the Audit Committee approve only those transactions that, in light of known circumstances, are consistent, or are not inconsistent with, the Company’s best interests, as
+they determine in the good faith exercise of their discretion. 
+Administrative Services Agreements
+We are a party to an administrative service agreement with Great White Energy Services LLC, which we refer to as Great White, which
+agreement was entered into effective as of July 22, 2006. Under this agreement, our services include accounting, human resources, legal and technical support. The services provided and the fees for such services can be amended by mutual
+agreement of the parties. This administrative service agreement had an initial three-year term, and upon expiration of that term the agreement has continued on a month-to-month basis. This administrative service agreement is terminable by either
+party at any time with at least 30 days prior written notice. Great White reimburses us for our dedicated employee time and related general and administrative costs based on the proportionate amount of time our employees spent performing services
+for such entity. Our services under this agreement ceased in January 2007, and we were not reimbursed any amounts by Great White for services provided under this agreement during the year ended December 31, 2010. However, Great White owes
+continuing indemnification obligations to us in connection with the pending Cudd litigation described in more detail in our Annual Report on Form 10-K. Great White paid us $67,000 in 2010 as reimbursement for our attorneys fees and expenses in
+connection with such litigation. Great White is controlled by Wexford Capital LP. Charles Davidson, who beneficially owned approximately 18.0% of our outstanding common stock as of April 15, 2011, is the Chairman and Chief Investment Officer of
+Wexford Capital LP. Mike Liddell, our Chairman of the Board, is also Chairman of the Board of Great White. 
+We are also a party to
+administrative service agreements with Stampede Farms LLC, which we refer to as Stampede Farms, Grizzly Oil Sands ULC, which we refer to as Grizzly, Everest Operations Management LLC, 
+32 
+Table of Contents 
+which we refer to as Everest, and Tatex Thailand III, LLC, which we refer to as Tatex III, which agreements were each entered into effective March 1, 2008. Under these agreements, our
+services include professional and technical support. The services provided under these agreements and the fees for such services can be amended by mutual agreement of the parties. Each of these administrative service agreements had an initial
+two-year term, and has continued thereafter on a month-to-month basis. Each agreement may be cancelled by either party to such agreement with at least 60 days prior written notice and is also terminable (1) by the counterparty at any time with
+at least 30 days prior written notice to us and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. We did not provide services under any of
+these agreements in 2010 and received no reimbursements thereunder. Each of Stampede Farms, Grizzly, Everest and Tatex III is controlled by Wexford Capital LP. Our administrative service agreement with Grizzly was terminated effective
+December 31, 2010. 
+Effective July 1, 2008, we entered into an acquisition team agreement with Everest to identify and evaluate
+potential oil and gas properties in which we and Everest or its affiliates may wish to invest. Pursuant to this agreement, Gulfport and Everest each agreed to form an acquisition team. Upon a successful closing of an acquisition or divestiture, the
+party whose acquisition team identified the acquisition or divestiture is entitled to receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share
+of the acquisition or divestiture consideration. The agreement has a one year term unless earlier terminated by either party upon 30 days notice. 
+From time to time, two of our petroleum engineers provide services relating to evaluation of potential investments to Wexford Capital LLC and geological evaluations, seismic review and similar services to
+Tatex Thailand II, LLC, or Tatex II, and Tatex III. Wexford Capital LLC, Tatex II and Tatex III, respectively, have agreed to reimburse us based on the amount, scope and nature of services provided by our petroleum engineers to such entities. Each
+of Tatex II and Tatex III is controlled by Wexford Capital LP. We did not provide any services under these arrangements in 2010. 
+Services Provided to Us by Our Affiliates 
+We contract with Athena Construction, L.L.C., which we refer to as Athena, to provide barge
+services in our West Cote Blanche Bay, or WCBB, and Hackberry fields located along the Louisiana Gulf Coast. For the year ended December 31, 2010, we paid Athena $3,036,000 and owed an additional $791,000 for such services at that date. Athena
+is controlled by Wexford Capital LP. 
+Windsor Energy Group operates our Permian Basin wells in West Texas. For the year ended
+December 31, 2010, we paid Windsor Energy Group $32,641,000 and owed an additional $5,871,000 for such services at that date. Mike Liddell, our Chairman of the Board, is also Chairman of the Board of Windsor Energy Group, L.L.C. Windsor Energy
+Group is controlled by Wexford Capital LP. 
+Effective March 1, 2008, Everest provides tax planning, preparation of supporting tax
+schedules and consultation services to us, based on agreed upon fee structure. The scope of such services can be modified upon mutual agreement of the parties. Everest is controlled by Wexford Capital LP. We paid Everest $10,000 for these services
+in 2010. 
+Caliber Development Company, LLC, or Caliber, provides building maintenance services for our headquarters in Oklahoma City,
+Oklahoma. For the year ended December 31, 2010, we paid Caliber $18,000 and owed an additional $3,000 at that date. Mike Liddell, our Chairman of the Board, is Chief Executive Officer of Caliber. Caliber is an entity controlled by Wexford
+Capital LP. 
+Great White Directional Services LLC, which we refer to as Directional, performs directional drilling services for us at our WCBB
+and Hackberry fields. For the year ended December 31, 2010, we paid Directional 
+33 
+Table of Contents 
+approximately $2,755,000 and owed an additional $952,000 for such services at that date. Directional is an entity controlled by Wexford Capital LP. 
+Great White Pressure Control, which we refer as Pressure Control, performs services for us at our WCBB field. At December 31, 2010, we owed $80,000
+to Pressure Control for such services at that date. No amounts were paid to Pressure Control in 2010. Pressure Control is an entity controlled by Wexford Capital LP. 
+Black Fin P&A, LLC, which we refer to as Black Fin, performs plugging and abandonment services for us at our WCBB field. For the year ended December 31, 2010, we paid $826,000 to Black Fin for
+such services at that date. No additional amounts were owed to Black Fin at December 31, 2010. Black Fin is an entity controlled by Wexford Capital LP. 
+Our Investments in Affiliates and Related Agreements 
+During
+2005, we purchased a 23.5% ownership interest in Tatex II at a cost of $2,400,000. The remaining interests in Tatex II are owned by other entities controlled by Wexford Capital LP. Tatex II, a privately-owned 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 three million acres which includes the Phu Horm Field.
+During 2010, we received $565,000 in distributions, reducing our total investment in Tatex II (including previous investments) to $1,907,000. 
+During the first quarter of 2008, we purchased a 5% ownership interest in Tatex III at a cost of $850,000. In December 2009, we purchased an additional
+approximately 12.9% ownership interest at a cost of approximately $3,385,000 bringing our total ownership interest to approximately 17.9%. Approximately 68.7% of the remaining interests in Tatex III are owned by other entities and individuals
+affiliated with Wexford Capital LP. During 2010, we paid $402,000 in capital calls, bringing our total investment in Tatex III to $4,660,000. 
+During the third quarter of 2006, we purchased, through our wholly owned subsidiary Grizzly Holdings, Inc., a 24.9999% interest in Grizzly, a Canadian
+unlimited liability company, for approximately $8,200,000. The remaining interests in Grizzly are owned by other entities controlled by Wexford Capital LP. During 2006 and 2007, Grizzly acquired leases in the Athabasca region located in the Alberta
+Province near Fort McMurray near other oil sands development projects. Grizzly has approximately 534,000 acres under lease and, at December 31, 2010, our net investment in Grizzly was approximately $46,460,000, including a note receivable of
+$20,006,000 as discussed in the following paragraph. 
+We, through our wholly owned subsidiary Grizzly Holdings Inc., entered into a loan
+agreement with Grizzly effective January 1, 2008, under which Grizzly may borrow funds from us. Borrowed funds bear interest at LIBOR plus 4% and had an original maturity date of December 31, 2012. Effective April 1, 2010, the loan
+agreement was amended to modify the interest rate to 0.69% and change the maturity date to December 31, 2011. Effective October 15, 2010, the loan agreement was further amended to change the maturity date to the original maturity date of
+December 31, 2012. Interest is paid on a paid-in-kind basis by increasing the outstanding balance of the loan. We loaned Grizzly approximately $2,877,000 during the year ended December 31, 2010. The Company recognized interest income of
+approximately $267,000 for the year ended December 31, 2010 under this loan agreement. The note balance was increased by approximately $942,000 as a result of a currency translation gain for the year ended December 31, 2010. 
+Area of Mutual Interest and Related Agreements 
+Effective as of November 1, 2007, we and Windsor Permian entered into an area of mutual interest agreement to jointly acquire oil and gas leases in the Permian Basin. The agreement provides that each
+party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain 
+34 
+Table of Contents 
+exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. 
+In connection with the area of mutual interest agreement, we, Windsor Permian and Windsor Energy Group, L.L.C., as the operator, entered into the joint
+development agreement, effective as of November 1, 2007, pursuant to which we and Windsor Permian agreed to develop certain jointly held oil and gas leases in the Permian Basin, and Windsor Energy Group, L.L.C. agreed to act as the operator
+under the terms of the joint operating agreement, effective as of November 1, 2007. In the event either party has greater than a 50% interest in a prospect, as defined in the development agreement, the majority party may designate the operator
+of its choice. The parties agreed to pay Windsor Energy Group, L.L.C. for its services as the operator with respect to the contract area as provided in the joint operating agreement. 
+Effective January 1, 2008, we entered into an area of mutual interest agreement with Bakken and Windsor Dakota LLC, or Windsor Dakota, to jointly acquire oil and gas leases on certain lands located
+in North Dakota and Montana for the purpose of exploring, exploiting and producing oil and gas from the Bakken Shale. The agreement provides that each party must offer the other party the right to participate in such acquisition in proportion to its
+participating interest, which is 20% for us and 80% for Bakken and Windsor Dakota, collectively. The parties also agreed, subject to certain exceptions, to share third-party costs and expenses in proportion to their respective participating
+interests and pay certain other fees as provided in the agreement. In connection with this agreement, we, Bakken, Windsor Dakota and Windsor Energy Group, L.L.C., as the operator, also entered into an exploration agreement, effective as of
+January 1, 2008, pursuant to which we, Bakken and Windsor Dakota agreed to jointly evaluate, explore, exploit and develop the contract area, and Windsor Energy Group, L.L.C. agreed to act as the operator under the terms of a joint operating
+agreement. In the event Gulfport has greater than a 50% interest in a prospect, as defined in the exploration agreement, the parties agreed to support Gulfport as the operator. The parties agreed to pay Windsor Energy Group, L.L.C. for its services
+as the operator with respect to the contract area as provided in the joint operating agreement. 
+Effective April 1, 2010, we entered into
+an area of mutual interest agreement with Windsor Niobrara LLC, which we refer to as Windsor Niobrara, to jointly acquire oil and gas leases on certain lands located in Northwest Colorado for the purpose of exploring, exploiting and producing oil
+and gas from the Niobrara Formation. The agreement provides that each party must offer the other party the right to participate in such acquisitions on a 50/50 basis. The parties also agreed, subject to certain exceptions, to share third-party costs
+and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. In connection with this agreement, we and Windsor Niobrara also entered into a development agreement, effective as of
+April 1, 2010, pursuant to which we and Windsor Niobrara agreed to jointly develop the contract area, and we agreed to act as the operator under the terms of a joint operating agreement. Windsor Niobrara is controlled by Wexford Capital LP.
+Utica Agreement 
+In February 2011, we entered into an agreement to acquire certain leasehold interests in 27,500 gross (13,750 net) acres located in the Utica Shale in Ohio. The agreement also grants us an exclusive right
+of first refusal for a period of six months on certain additional tracts leased by the seller. Windsor Energy Group, L.L.C., directly or through one or more of its affiliates, has agreed to participate with us on a 50/50 basis in the acquisition of
+all of the leases described above. We will be the operator on this acreage in the Utica Shale. The purchase price for our 50% interest in the initial acreage is approximately $31.6 million, subject to certain closing adjustments. This transaction is
+expected to close in mid-May 2011. Windsor Energy Group, L.L.C. is controlled by Wexford Capital LP. 
+35 
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+ITEM 1. 
+BUSINESS 
+General 
+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, or WCBB, and Hackberry fields, and in West Texas in the Permian Basin. During 2010, we acquired our initial acreage position in the Niobrara Formation of northwestern Colorado and, during 2011, we
+acquired our initial acreage position in the Utica Shale in Eastern 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. 
+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 the fourth quarter of 2011, production at WCBB was 362,996 net barrels of oil equivalent, or BOE, or an average of 3,946 BOE per day, 96% of which was from
+oil and 4% of which was from natural gas. From January 1, 2012 through January 31, 2012, our average net daily production at WCBB was 3,705 BOE, 96% of which was from oil and 4% of which was from natural gas. During 2012, we currently
+anticipate drilling 22 to 24 wells and recompleting 60 wells at our WCBB field for an estimated aggregate cost of $36.0 million to $38.0 million. 
+In 2011, at our East Hackberry field, we recompleted 24 wells and drilled 22 wells for a total cost of approximately $51.9 million as of December 31, 2011. 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 the fourth quarter of 2011, net production at East Hackberry was 190,930 BOE, or an average of 2,075 BOE per day, 97% of
+which was from oil and 3% of which was from natural gas. From January 1, 2012 through January 31, 2012, our average net daily production at East Hackberry was 2,220 BOE, 99% of which was from oil and 1% of which was from natural gas.
+During 2012, we currently anticipate drilling 10 to 12 wells and recompleting 10 wells for an aggregate estimated cost of $24.0 million to $26.0 million. 
+In the fourth quarter of 2011, net production at West Hackberry was 3,279 BOE, or an average of 36 BOE per day, 100% of which was from oil. From January 1, 2012 through January 31, 2012, our
+average net daily production at West Hackberry was 37 BOE, 100% of which was from oil. 
+In 2011, 39 gross (17 net) wells were
+drilled and eight gross (four net) wells were recompleted on our Permian Basin acreage for a total net cost of $38.4 million. As of December 31, 2011, 35 of the 39 wells had been completed and four wells were awaiting completion. In the fourth
+quarter of 2011, net production from our Permian Basin acreage was 93,760 BOE, or an average of 1,019 BOE per day, of which approximately 74% was from oil, 13% was from natural gas liquids and 13% was from natural gas. From January 1, 2012
+through January 31, 2012, our average daily net production from our Permian Basin acreage was 1,032 BOE, of which 72% was from oil, 16% was from natural gas liquids and 12% was from natural gas. We currently anticipate that 23 to 25 gross (11.5
+to 12.5 net) wells will be drilled and five gross (2.5 net) wells will be recompleted on this acreage in 2012 for an estimated aggregate net cost of $23.0 million to $25.0 million. In an effort to facilitate the development of our Permian Basin and
+other domestic acreage, we acquired a 25% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates four drilling rigs. The remaining 75% equity interest is owned by entities controlled by Wexford Capital LP, or
+Wexford. An affiliate of Wexford owned approximately 13.3% of our outstanding common stock as of February 20, 2012. We have also purchased a 25% interest in Muskie Holdings LLC, or Muskie, which holds certain rights in a lease covering land in
+Wisconsin for mining oil and natural gas fracture grade sand. Muskie is controlled by Wexford. 
+2 
+Table of Contents 
+Index to Financial Statements 
+Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara
+Formation in northwestern Colorado and held leases for approximately 15,000 net acres as of December 31, 2011. During the year ended December 31, 2011, we drilled three gross (1.5 net) wells on this acreage. In the fourth quarter of 2011,
+net production from our Niobrara acreage was 3,390 BOE, or an average of 37 BOE per day, 100% of which was from oil. From January 1, 2012 through January 31, 2012, our average net daily production from our Niobrara acreage was 41 BOE, 100%
+of which was from oil. In the Niobrara Formation, we have completed a 60 square mile 3-D seismic survey, have received a processed version of the seismic and are selecting future drilling locations. During 2012, we currently anticipate drilling five
+to seven gross wells in the Niobrara Formation for approximately $5.0 million to $6.0 million. 
+As of December 31, 2011,
+we held approximately 800 net acres in the Williston Basin of western North Dakota and eastern Montana with interests in six wells and an overriding royalty interest in wells drilled prior to our 2009 sale of certain of our Bakken acreage and
+production from such acreage, wells drilled subsequent to such sale and wells that might be drilled in the future. In the fourth quarter of 2011, our net production from this acreage was 7,167 BOE, or an average of 78 BOE per day, of which 91% was
+from oil, 6% was from natural gas and 3% was from natural gas liquids. From January 1, 2012 through January 31, 2012, our average daily net production from our Bakken acreage was 71 BOE, of which 92% was from oil and 8% was from natural
+gas. 
+As of December 31, 2011, we had acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in
+the Utica Shale in Eastern Ohio. As of February 20, 2012, we had closed on additional acquisitions bringing our leasehold interests to approximately 107,000 gross (53,500 net) acres. We intend to continue to pursue opportunities in this area
+and have commitments with various future closing dates that could increase our acreage position in the Utica Shale to an aggregate of approximately 125,000 gross (62,500 net) leasehold acres. We recently spud our first well on our Utica Shale
+acreage. 
+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, 2011, Grizzly had approximately 754,000 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. As of December 31, 2011, Grizzly had drilled an aggregate of 203 core holes and four water supply test wells, tested nine 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 (ERCB) to issue the formal regulatory approval of Grizzly’s Algar Lake SAGD project. Grizzly’s currently contemplated 2012 activities include the completion of the 2011/2012 core hole drilling and seismic program,
+submission of a SAGD project regulatory application for Thickwood Hills and the development of its Algar Lake SAGD project, which includes the fabrication and onsite construction of a central processing facility and the drilling of ten initial SAGD
+well pairs. 
+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 includes the Phu Horm Field. 
+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. In 2009, Tatex III completed a 3-D seismic survey on this concession. 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 million cubic feet per day of 
+3 
+Table of Contents 
+Index to Financial Statements 
+gas for short intervals, but would subsequently fall to a sustained rate of 2 million cubic feet per day. 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, located to the south of the TEW-E well, late this year or early 2013. 
+As of December 31, 2011, we had
+19.4 million barrels of oil equivalent, or MMBOE, of proved reserves with a present value of estimated future net revenues, discounted at 10%, or PV-10, of approximately $490.5 million and associated standardized measure of discounted future
+net cash flows of approximately $376.7 million, excluding reserves attributable to our interests in Grizzly, Tatex II and Tatex III. See Item 2. “Properties—Proved Oil and Natural Gas Reserves” for our definition of PV-10, a
+non-GAAP financial measure, and a reconciliation of our standardized measure of discounted future net cash flows to PV-10. 
+Principal Oil
+and Natural Gas Properties 
+The following table presents certain information as of December 31, 2011 reflecting our
+net interest in our principal producing oil and natural gas properties along the Louisiana Gulf Coast, in the Permian Basin in West Texas, in the Niobrara Formation in northwestern Colorado and in the Williston Basin in western North Dakota and
+eastern Montana. 
+Proved Reserves 
+Field 
+NRI/WI (1) 
+Productive 
+Wells (2) 
+Non-Productive 
+Wells 
+Developed 
+Acreage (3) 
+Gas 
+Oil 
+Total 
+Percentages 
+Gross 
+Net 
+Gross 
+Net 
+Gross 
+Net 
+MBOE 
+MBOE 
+MBOE 
+West Cote Blanche Bay Field (4) 
+80.108/100 
+95 
+95 
+189 
+189 
+5,668 
+5,668 
+352 
+3,617 
+3,969 
+E. Hackberry Field (5) 
+79.424/100 
+30 
+30 
+93 
+93 
+3,291 
+3,291 
+226 
+1,606 
+1,832 
+W. Hackberry Field 
+87.5/100 
+2 
+2 
+23 
+23 
+592 
+592 
+— 
+76 
+76 
+Permian Basin 
+35.4/46.87 
+121 
+57 
+— 
+— 
+8,880 
+4,119 
+2,008 
+10,877 
+12,885 
+Niobrara Formation 
+39.7/47.9 
+6 
+3 
+2 
+1 
+3,954 
+1,977 
+26 
+500 
+526 
+Williston Basin (6) 
+2.8/3.3 
+6 
+.2 
+— 
+— 
+1,708 
+132 
+7 
+67 
+74 
+Overrides/Royalty Non-operated 
+Various 
+133 
+.2 
+— 
+— 
+— 
+— 
+3 
+2 
+5 
+Total 
+393 
+187.4 
+307 
+306 
+24,093 
+15,779 
+2,622 
+16,745 
+19,367 
+(1) 
+Net Revenue Interest (NRI)/Working Interest (WI). 
+(2) 
+Includes six gross and net wells at WCBB that are producing intermittently. 
+(3) 
+Developed acres are acres spaced or assigned to productive wells. Approximately 36% 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) 
+NRI/WI is from wells that have been drilled or in which we have elected to participate. 
+4 
+Table of Contents 
+Index to Financial Statements 
+West Cote Blanche Bay Field 
+Location and Land 
+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. 
+Area History and Production 
+Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the
+remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 994 wells drilled as of December 31, 2011, 900 were completed as producing wells. As a result, the
+field has a historic success rate of 91% for all wells drilled. From the date of our acquisition of WCBB in 1997 through December 31, 2011, we drilled 183 new wells, 166 of which were productive, for a 91% success rate. As of December 31,
+2011, estimated field cumulative gross production was 192.6 MMBOE and 236.6 billion cubic feet, or Bcf, of gas. Of the 994 wells drilled in WCBB as of December 31, 2011, 89 were producing, 189 were shut-in, six were producing intermittently and
+five were being used as salt water disposal wells. The other 705 wells have been plugged and abandoned. 
+In 1991, Texaco
+conducted a 70 square mile 3-D seismic survey with 1,100 shot points per mile that processed out 100 fold. In 1993, an undershoot survey around the crest and production facilities was completed. We own the rights to the seismic data. In December
+1999, we completed the reprocessing of the seismic data and our technical staff developed prospects from the data. The reprocessed data has enabled us to identify prospects in areas of the field that would have otherwise remained obscure. During the
+first half of 2005, we again reprocessed the seismic data using advanced seismic data processing. 
+Geology 
+WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which
+created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets
+having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) was formed. 
+There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 994 wells that had been drilled in
+the field as of December 31, 2011, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive. 
+WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to
+faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells
+drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault
+before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn, can result in lower than expected or no reserves for that zone. The new wellbores eliminate the mechanical risk
+associated with trying to produce the zone from an old existing wellbore, while the wellbore locations are selected in an 
+5 
+Table of Contents 
+Index to Financial Statements 
+effort to more efficiently drain each reservoir. The vast majority of the PUD targets are up-dip offsets to wells that produced from a sub-optimal position within a particular zone. Our inventory
+of prospects at WCBB as of December 31, 2011 included 24 PUD wells. The drilling schedule used in the reserve report anticipates that all of those wells will be drilled by 2015. 
+Facilities 
+We own and operate a production facility at WCBB that includes
+four production tank batteries, eight natural gas compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system. 
+Recent and Future Activity 
+In 2011, we recompleted 68 gross and net wells
+and drilled 21 gross and net wells at WCBB. Nineteen of the new wells were completed as producers, one was non-productive and one was waiting on completion. As of February 20, 2012, we had drilled three wells, were in the process of drilling
+two additional wells and recompleted six wells during 2012. Of the 21 wells drilled in 2011, 18 were considered deep wells. The 19 productive wells, with total depths ranging from 2,500 to 10,748 feet, have approximately 1,855 feet of aggregate
+apparent net pay. We currently anticipate drilling 22 to 24 gross and net wells and recompleting 60 gross and net wells at WCBB during 2012. 
+Production Status 
+In
+the fourth quarter of 2011, our production at WCBB was 362,996 net BOE, or an average of 3,946 BOE per day, 96% of which was from oil and 4% of which was from natural gas. From January 1, 2012 through January 31, 2012, our average net
+daily production at WCBB was 3,705 BOE, 96% of which was from oil and 4% of which was from natural gas. The decrease in production was due to normal production declines. 
+East Hackberry Field 
+Location and Land 
+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 79.424% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. We hold beneficial interests in approximately 3,291 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 also hold 2,868 net acres subject to a two-year exploration agreement we entered into with an
+active gulf coast operator. We are the designated operator under the agreement and will participate in proposed wells with at least a 70% working interest. We have licensed approximately 54 square miles of 3-D seismic data covering a portion of the
+area and are reprocessing the data. 
+Area History and Production 
+The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The
+massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through 2011 was
+over 1,625 MBOE and 330 Bcf of casinghead gas production. A total of 223 wells have been drilled on our portion of the field. As of December 31, 2011, 30 wells had daily production, 93 were shut-in and two had been converted to salt water
+disposal wells. The remaining 98 wells had been plugged and abandoned. 
+6 
+Table of Contents 
+Index to Financial Statements 
+Geology 
+The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry
+acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks.
+These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet. 
+Facilities 
+We have a field office that serves both the East and West
+Hackberry fields. In addition, we own and operate two production facilities at East Hackberry that include a land based tank battery, production barge, three natural gas compressors, dehydration units and salt water disposal systems. 
+Recent and Future Activity 
+During 2005, we completed a proprietary 42 square mile 3-D seismic survey at East Hackberry, the first modern seismic program undertaken at this field. We believe that this 3-D seismic data enhances our
+probability of drilling success, and we continue to evaluate the 3-D seismic data to identify additional drilling locations. During 2011 at East Hackberry, we recompleted 24 gross and net wells and drilled 13 gross and net land wells and nine gross
+and net wells on water. Seventeen of the 22 wells drilled during 2011 were completed as producing wells, two were non-productive and three were waiting on completion. As of February 20, 2012, we had recompleted two wells during 2012, drilled
+two wells and were in the process of drilling two additional wells. We currently intend to drill 10 to 12 gross and net wells and recomplete 10 gross and net wells at East Hackberry during 2012. 
+Production Status 
+In
+the fourth quarter of 2011, our net production at East Hackberry was 190,930 BOE, or an average of 2,075 BOE per day, 97% of which was from oil and 3% of which was from natural gas. From January 1, 2012 through January 31, 2012, our
+average net daily production at East Hackberry was 2,220 BOE, 99% of which was from oil and 1% of which was from natural gas. The increase in production in 2012 is a result of our 2012 drilling activities. 
+West Hackberry Field 
+Location and
+Land 
+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 87.5% NRI) in 592 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. 
+Area History 
+The first discovery well at West Hackberry was drilled in 1938 and the field was developed by Superior Oil Company, now ExxonMobil
+Corporation, between 1938 and 1988. The estimated cumulative oil and condensate production through 2011 was 286 MBOE and 140 Bcf of natural gas. There have been 36 wells drilled to date on our portion of West Hackberry. Currently, two are producing,
+23 are shut-in and one has been converted to a saltwater disposal well. The remaining 10 wells have been plugged and abandoned. 
+7 
+Table of Contents 
+Index to Financial Statements 
+Geology 
+Structurally, our West Hackberry acreage is located on the western end of the Hackberry salt ridge. There are over 30 pay zones at this field. West Hackberry consists of a series of fault-bounded traps in
+the Oligocene-age Vincent and Keough sands associated with the Hackberry Salt Ridge. Recoveries from these thick, porous, water-drive reservoirs have resulted in per well cumulative production of almost 700 MBOE. 
+Production Status 
+In
+the fourth quarter of 2011, our net production at West Hackberry was 3,279 BOE, or an average of 36 BOE per day. From January 1, 2012 through January 31, 2012, our average net daily production at West Hackberry was 37 BOE and was 100% oil.
+Facilities 
+We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system.
+Permian Basin (West Texas) 
+Location and Land 
+We
+acquired approximately 4,100 net acres and 32 gross (16 net) producing wells in West Texas (near Midland) in the Permian Basin effective November 1, 2007. Subsequently, we acquired approximately 11,200 additional net acres, which brought our
+total net acreage position in the Permian Basin to approximately 15,300 net acres as of December 31, 2011. The Permian Basin area covers a significant portion of western Texas and eastern New Mexico and is considered one of the major producing
+basins in the United States. The terrain in the Permian Basin is semi-arid mesquite-mixed grassland steppe. Windsor Permian LLC, or Windsor, an entity controlled by Wexford, is the operator of this field. 
+Area History 
+The
+Permian Basin formed as an area of rapid Mississippian-Pennsylvanian subsidence in the foreland of the Ouachita Foldbelt. The Wolfcamp play was a long-established reservoir in West Texas, first found in the 1950s as wells aiming for deeper targets
+occasionally intersected slump blocks or reef facies with reservoir properties. Exploration with 2-D seismic located additional fields, but it was not until the use of 3-D seismic in the 1990s that the greater extent of the Wolfcamp prospects was
+revealed. During the late 1990s, Arco began a drilling program targeting the Spraberry formation at 10,000 feet and then drilled another 200 to 300 feet to pick up the upper part of the Wolfcamp formation. Henry Petroleum, a private firm, owned
+interest in the Pegusas field in Midland and Upton counties. While drilling in the same area as the Arco project, Henry Petroleum decided to drill completely through the Wolfcamp section as Devonian wells. Henry Petroleum mapped the trend and began
+acquiring acreage and drilling wells using multiple slick-water fracs across the entire Wolfcamp interval. In 2005, former members of Henry Petroleum’s Wolfcamp team formed their own private company, ExL Petroleum, and began replicating Henry
+Petroleum’s program. After ExL had drilled 32 productive Wolfcamp/Spraberry wells through late 2007, they decided to monetize approximately 15% of their acreage position which enabled us to participate in this play. Recent advancements in
+enhanced recovery techniques continue to make the basin an active play for exploration and production companies. As of December 31, 2011, we held interests in 121 gross (57 net) producing wells. 
+Geology 
+The
+Wolfcamp/Spraberry play, which we refer to as Wolfberry, of the Midland Basin lies in the area where the historically productive Spraberry trend geographically overlaps the productive area of the emerging
+8 
+Table of Contents 
+Index to Financial Statements 
+Wolfcamp carbonate play. The Wolfcamp is characterized by an approximately 2,000 feet section of organic rich basin floor debris flows shed from the Central Basin Platform. The best reservoir
+rock within the section is generally found in close proximity to the Central Basin Platform. 
+Wolfberry well reserves are
+typically approximately 80% from the Wolfcamp section and 20% from the Spraberry section. Ryder Scott Company L.P., or Ryder Scott, an independent petroleum engineering firm, has estimated that at December 31, 2011, proved reserves net to our
+interest in these assets were approximately 12.9 million BOE, of which 23% were classified as proved developed producing, or PDP. Proved undeveloped, or PUD, reserves included in this estimate were from 252 gross well locations on 40-acre
+units. The proved reserves are located in the Wolfcamp and Spraberry formations, which are generally characterized as long-lived, with predictable production profiles. 
+Production Status 
+In the fourth quarter of 2011, our net production from
+the Permian Basin field was 93,760 BOE, or an average of 1,019 BOE per day, of which 74% was from oil, 13% was from natural gas liquids and 13% was from natural gas. From January 1, 2012 through January 31, 2012, our average daily net
+production from our Permian Basin acreage was 1,032 BOE, 88% of which was from oil and natural gas liquids and 12% of which was from natural gas. 
+Facilities 
+There are typical land oil and natural gas processing
+facilities in the Permian Basin. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent and Future Activity 
+In 2011, 39 gross (17 net) wells were
+drilled in our Permian Basin acreage. From January 1, 2012 to February 20, 2012, two gross (one net) wells had been drilled on this acreage and were waiting on completion and at February 20, 2012 one gross (0.5 net) additional
+well was being drilled. We have identified 252 gross future development drilling locations. We currently expect an estimated 23 to 25 gross (11.5 to 12.5 net) wells to be drilled on our acreage in 2012. The wells are expected to be drilled to
+approximately 11,200 feet. In an effort to facilitate the drilling of these and future wells, in 2011 we acquired a 25% equity interest in Bison Drilling and Field Services LLC, or Bison, which owns and operates four drilling rigs. We acquired our
+interest in Bison from Windsor Permian LLC, or Windsor. Windsor is the operator of our Permian Basin properties and is controlled by Wexford. An affiliate of Wexford owned approximately 13.3% of our outstanding common stock as of February 20,
+2012. During 2011, we also purchased a 25% interest in Muskie Holdings LLC, or Muskie, which holds certain rights in a lease covering land in Wisconsin for mining oil and natural gas fracture grade sand. Muskie is controlled by Wexford. 
+Niobrara Formation (Northwestern Colorado) 
+Location and Land 
+Effective as of April 1, 2010, we acquired
+leasehold interests in the Niobrara Formation in northwestern Colorado, and held leases for 14,993 acres as of December 31, 2011. We are the operator on the acreage. 
+Area History 
+The Niobrara Formation is a shale oil rock formation located
+in Colorado, Northwest Kansas, Southwest Nebraska, and Southeast Wyoming. Oil and natural gas can be found at depths of 3,000 to 14,000 feet and is drilled both vertically and horizontally. The Upper Cretaceous Niobrara formation has emerged as
+another 
+9 
+Table of Contents 
+Index to Financial Statements 
+potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the Niobrara has a history of producing through conventional
+technology with some of the earliest production dating back to the early 1900s. Natural fracturing has played a key role in producing the Niobrara historically due to the low porosity and low permeability of the formation. Because of this,
+conventional production has been very localized and limited in area extent. We believe the Niobrara can be produced on a more widespread basis using today’s horizontal multi-stage fracture stimulation technology where the Niobrara is thermally
+mature. 
+Geology 
+The Niobrara Formation oil play in northwestern Colorado is located between the Piceance Basin to the south and the Sand Wash Basin to the north. Rocks mainly consist of interbedded organic-rich shales,
+calcareous shales and marlstones. It is the fractured marlstone intervals locally known as the Buck Peak, Tow Creek and Wolf Mountain benches that account for the majority of the areas production. These fractured carbonate reservoirs are associated
+with anticlinal, synclinal and monoclinal folds, and fault zones. This proven oil accumulation is considered to be continuous in nature and lightly explored. Source rocks are predominantly oil prone and thermally mature with respect oil generation.
+The producing intervals are geologically equivalent to the Niobrara reservoirs of the DJ and Powder River Basins which are currently emerging as a major crude resource play. 
+Production Status 
+In the fourth quarter of 2011, our net production from
+our Niobrara acreage was 3,390 BOE, or an average of 37 BOE per day, 100% of which was from oil. From January 1, 2012 through January 31, 2012, our average daily net production from our Niobrara acreage was 41 BOE, 100% of which was from
+oil. 
+Facilities 
+There are typical land oil and gas processing facilities in the Niobrara Formation. Our facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping
+units. 
+Recent and Future Activity 
+We drilled three gross (1.5 net) wells at Niobrara during 2011. We have completed a 60 square mile 3-D seismic survey over our Craig Dome prospect, have received a processed version of the seismic and are
+selecting future drilling locations. We currently intend to drill five to seven gross wells at Niobrara during 2012. 
+Bakken
+Location and Land 
+The Bakken Shale is located in the Williston Basin areas of western North Dakota and eastern Montana. During 2005, we purchased a 20% ownership interest in Windsor Bakken, LLC, or Bakken. The remaining
+interests in Bakken were owned by entities controlled by Wexford. Beginning in 2005, Bakken acquired leases on undeveloped acreage in the Williston Basin. As of December 31, 2007, Bakken had commenced participating in the drilling of some of
+its undeveloped acreage. Effective January 1, 2008, we acquired a direct, undivided 20% interest in Bakken’s assets in redemption of our 20% interest in Bakken. During May 2009, we sold approximately 12,270 net acres and approximately 190
+net BOEPD of production for approximately $13.0 million, with an effective date of April 1, 2009. During September 2009, we sold approximately 5,721 net acres for approximately $5.8 million with an effective date of July 1, 2009. As of
+December 31, 2011, we held approximately 800 net acres, interests in six wells and an overriding royalty interest in wells drilled prior to our 2009 sale, wells drilled subsequent to such sale and wells that might be drilled in the future.
+10 
+Table of Contents 
+Index to Financial Statements 
+Production Status 
+In the fourth quarter of 2011, our net production from our Bakken acreage was 7,167 BOE, or an average of 78 BOE per day, of which 91% was from oil, 3% was from natural gas liquids and 6% was from natural
+gas. From January 1, 2012 through January 31, 2012, our average net daily production from this acreage was 71 BOE, of which 92% was from oil and 8% was from natural gas. 
+Facilities 
+There are typical land oil and gas processing facilities in the
+Williston Basin. The facilities located at well locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent and future activities 
+One gross (.01 net) well was drilled on our acreage in 2011. There are no new activities currently scheduled for 2012 for our Bakken acreage. 
+Utica Shale (Eastern Ohio) 
+Location and Land 
+As of December 31, 2011, we had acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in the Utica Shale in
+Eastern Ohio. As of February 20, 2012, we had closed on additional acquisitions bringing our leasehold interests to approximately 107,000 gross (53,500 net) acres. We intend to continue to pursue opportunities in this area and have commitments
+with various future closing dates that could increase our acreage position in the Utica Shale to an aggregate of approximately 125,000 gross (62,500 net) leasehold acres. We recently spud our first well on our Utica Shale acreage. 
+Area History 
+Based on
+the estimates published by the Ohio Department of Natural Resources, the Utica Shale has a recoverable potential of 1.3 billion to 5.5 billion barrels of oil and 3.8 to 15.7 trillion cubic feet of natural gas. During 2011, a number of oil and gas
+companies made significant investments in acquiring Utica Shale acreage in Eastern Ohio and applied for drilling permits with the Ohio Department of Natural Resources. 
+During 2011, most of the drilling activity in the Utica Shale occurred in Eastern Ohio, where our acreage is located. Based on the initial drilling results, the Utica Shale is prospective for oil and
+natural gas liquids. Specifically, early wells drilled in the Utica Shale indicated potential for production of significant amounts of natural gas liquids, which generally have a higher value, on an energy-equivalent basis, than natural gas.
+Geology 
+The
+Utica Shale is located in the Appalachian Basin of the United States and Canada. The Utica Shale is a rock unit comprised of organic-rich calcareous black shale that was deposited about 440 million to 460 million years ago during the Late
+Ordovician period. It overlies the Trenton Limestone and is located a few thousand feet below the Marcellus Shale, which is estimated to be the largest exploration play in the Eastern United States. 
+Recently, the application of horizontal drilling, combined with multistaged hydraulic fracturing to create permeable flow paths from
+wellbores into shale units, has resulted in increased drilling activity and production in the Devonian-age Marcellus Shale in the Appalachian Basin states of Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has
+potential for application in other shale units, such as the Ordovician-age Utica Shale, which extends across much of the Appalachian Basin region. 
+11 
+Table of Contents 
+Index to Financial Statements 
+The Utica Shale is estimated to be thicker and more geographically extensive than the
+Marcellus Shale and, based on early drilling results, has the potential to support commercial production. The potential source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West
+Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and part of Ontario, Canada. Throughout the potential source rock area, the Utica Shale ranges in thickness from less than 100 feet to over 500
+feet. Over the rock unit as a whole, there is a general thinning from east to west. 
+The Utica Shale is also significantly
+deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio
+and to the northwest under the Great Lakes and into Canada to less than 2,000 feet below sea level. 
+The Utica Shale is
+estimated to have higher carbonate and lower clay mineral content than the Marcellus Shale. The difference in mineralogy generally produces a different response to hydraulic fracturing treatments. Based on early fracturing results in the Utica
+Shale, the hydraulic fracturing methods used in the Marcellus Shale are less productive when applied in the Utica Shale. However, drillers have improved the fracturing rates in other gas shales with similar carbonate content. For example, drillers
+have discovered methods to make the brittle carbonate zones fracture at higher rates than other gas shale rock units in the Eagle Ford Shale in Texas. Drillers are researching methods to make similar fracturing improvements in the Utica Shale.
+Facilities 
+There are typical land oil and gas processing facilities in the Utica Shale. We will be required to build facilities located at well
+locations include storage tank batteries, oil/gas/water separation equipment and pumping units. 
+Recent and future activities
+We recently spud our first well on our Utica Shale acreage and expect to drill approximately 20 gross (ten net) wells
+during 2012. 
+Additional Properties 
+Louisiana . In addition to our interests in the WCBB, East Hackberry and West Hackberry fields, we also own working interests and overriding royalty interest in various fields in Louisiana, Texas
+and Oklahoma as described in the following table: 
+Field 
+State 
+Parish/County 
+Acreage Working 
+Interest 
+Overriding Royalty 
+Interests 
+Producing 
+Wells 
+Non-Producing 
+Wells 
+Deer Island 
+Louisiana 
+Terrebonne 
+3.125 
+% 
+0 
+% 
+1 
+0 
+Napoleonville 
+Louisiana 
+Assumption 
+0 
+% 
+2.5 
+% 
+3 
+0 
+Crest 
+Texas 
+Ochiltree 
+2.000 
+% 
+0 
+% 
+1 
+0 
+Eagle City South 
+Oklahoma 
+Dewey 
+1.040 
+% 
+0 
+% 
+1 
+0 
+Thailand . During 2005, we purchased a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex
+II, at a cost of $2.4 million. 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 includes the Phu Horm Field. During the year ended December 31, 2011, we received
+$870,000 in distributions, reducing our total investment in Tatex II to $1.0 million. Our investment is accounted for on the equity method. Tatex II accounts for its investment in APICO using the cost method. In December 2006, first gas sales were
+achieved at the Phu Horm field located in 
+12 
+Table of Contents 
+Index to Financial Statements 
+northeast Thailand. Phu Horm’s initial gross production was approximately 60 million cubic feet per day. For 2011, net gas production was approximately 83 MMcf per day and condensate
+production was 380 barrels per day. Hess Corporation operates the field with a 35% interest. Other interest owners include APICO (35% interest), PTTEP (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%. Due to the fact that 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. 
+During the first quarter of 2008, we purchased a 5% ownership interest in Tatex Thailand III, LLC, or Tatex III,
+at a cost of $850,000. In December 2009, we purchased an additional approximately 12.9% ownership interest at a cost of approximately $3.4 million bringing our total ownership interest to approximately 17.9%. 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. In 2009, Tatex III completed a 3-D seismic survey on this concession. During the year ended December 31,
+2011, we paid $3.8 million in cash calls, bringing our total investment in Tatex III to $8.3 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 million cubic feet per day of gas for short intervals, but would subsequently fall to a sustained rate of 2 million cubic
+feet per day. 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, located to the south of the TEW-E well, late this year or early 2013. 
+Grizzly Oil Sands . 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, 2011, Grizzly had approximately 754,000 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 $69.0 million as of December 31, 2011. As of December 31, 2011, Grizzly had drilled an aggregate of 203 core holes and four water supply test wells, tested nine 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 (ERCB) to issue the formal regulatory approval of Grizzly’s Algar Lake SAGD project. Grizzly’s currently contemplated 2012 activities include the completion of the 2011/2012 core
+hole drilling and seismic program, submission of a SAGD project regulatory application for Thickwood Hills and the development of its Algar Lake SAGD project, which includes the fabrication and onsite construction of a central processing facility
+and the drilling of ten initial SAGD well pairs. 
+Competition and Markets 
+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.
+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 demand for oil and natural gas and the level of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of
+13 
+Table of Contents 
+Index to Financial Statements 
+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 trade month average
+differential less $2.70 per barrel for transportation. During 2011, we sold 93% and 7% of our oil production to Shell and Windsor, the operator of our Permian wells, respectively, and 22%, 27% and 50% of our natural gas production to Windsor,
+Chevron and Hilcorp Energy Company, respectively. During 2010, we sold 75% and 19% of our oil production to Shell and Windsor, the operator of our Permian wells, respectively, and 50%, 32%, and 10% of our natural gas production to Windsor, Chevron
+and Hilcorp Energy Company, respectively. During 2009, we sold 92% and 7% of our oil production to Shell and Windsor, the operator of our Permian wells, respectively, and 45%, 38%, and 16% of our natural gas production to Windsor, Chevron and
+Hilcorp Energy Company, respectively. We may not continue to have ready access to suitable markets for our future oil and natural gas production. 
+Oil and natural gas prices can be extremely volatile and are subject to substantial seasonal, political and other fluctuations. The price at which the oil and natural gas we produce may be sold is
+uncertain and it is possible that under some market conditions the production and sale of oil and natural gas from some or all of our properties may not be economical. Because of all of the factors influencing the price of oil and natural gas, it is
+impossible to accurately predict future prices. 
+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 December 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 January 2013 through June 2013, we entered into fixed price swaps for 1,000 barrels of oil per day at a weighted average price of $113.20 per barrel. Under the 2010 contracts, we delivered approximately 45% of our 2010
+production. Under the 2011 contracts, we delivered approximately 31% of our 2011 production. Under the 2012 contracts, we have committed to deliver approximately 32% to 35% of our estimated 2012 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. These forward sales contacts 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. 
+Regulation 
+Regulation of Gas and Oil Production 
+Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation
+affecting the oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry substantial penalties for failure to comply. The regulatory burden on the oil and natural gas industry increases our
+cost of doing business and, consequently, affects our profitability. 
+We own interests in a number of producing oil and
+natural gas properties located along the Louisiana Gulf Coast, West Texas and the Niobrara Formation in northwestern Colorado. The states in which our fields are located in regulate the production and sale of oil and natural gas, including
+requirements for obtaining drilling 
+14 
+Table of Contents 
+Index to Financial Statements 
+permits, the method of developing new fields and the spacing and operation of wells. In addition, regulations governing conservation matters aimed at preventing the waste of oil and natural gas
+resources could affect the rate of production and may include maximum daily production allowables for wells on a market demand or conservation basis. 
+Environmental Regulation 
+Our oil and natural gas exploration, development
+and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental
+Protection Agency, or EPA, issue regulations which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for failure to comply. These laws
+and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production
+activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former
+operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for
+pollution resulting from our operations or relate to our owned or operated facilities. The strict and joint and several liability nature of such laws and regulations could impose liability upon us regardless of fault. Changes in environmental laws
+and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial
+position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from
+compliance with these environmental requirements. This trend, however, may not continue in the future. 
+Waste Handling .
+The Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding
+the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own,
+more stringent requirements. Although most wastes associated with the exploration, development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under RCRA, such wastes may constitute “solid wastes”
+that are subject to the less stringent requirements of non-hazardous waste provisions. However, there can be no assurance that the EPA or the state or local governments will not adopt more stringent requirements for the handling of non-hazardous
+wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as
+“hazardous wastes.” Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses. 
+Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to
+waste handling, and that we hold all necessary and up-to- date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe that the current costs of
+managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.
+Remediation of Hazardous Substances . The Comprehensive Environmental Response, Compensation and Liability Act, as
+amended, also known as CERCLA or the “Superfund” law, and analogous state laws, generally imposes strict and joint and several liability, without regard to fault or legality of the original conduct, on classes
+15 
+Table of Contents 
+Index to Financial Statements 
+of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated
+facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed
+“responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property
+contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury
+and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, would be subject to CERCLA and comparable state statutes. Therefore, governmental
+agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released. 
+Water Discharges . The Federal Water Pollution Control Act of 1972, as amended, also known as the “Clean Water Act”, the
+Safe Drinking Water Act or SDWA, the Oil Pollution Act, or OPA, and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and
+other gas and oil wastes, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. Spill
+prevention, control and countermeasure, or SPCC, plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank
+spill, rupture or leak. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has also adopted regulations requiring certain oil and natural gas
+exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention
+plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.
+The OPA,is the primary federal law for oil spill liability. OPA contains numerous requirements relating to the prevention of
+and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency
+plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs
+and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters. 
+Noncompliance with the Clean Water Act or OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the
+requirements of each of these laws. 
+Air Emissions . The Federal Clean Air Act, as amended, and comparable state laws
+and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. Some of our new facilities will be required to obtain permits before work can begin, permits may be required for
+our facilities’ operations, and existing facilities may be required to incur capital costs to remain in compliance. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified
+sources. In particular, on August 23, 2011, the EPA published in the Federal Register a proposed rule to establish new air emission controls for oil and natural gas production and natural gas processing operations. The new emission
+standards seek to reduce volatile organic compound, or VOC, emissions, including a 95 percent reduction in VOCs emitted during the construction or modification of hydraulically-fractured wells. The EPA received public comment and conducted public
+hearing regarding the proposed rules and must take final action on them by April 3, 2012. These laws and regulations may increase the costs of compliance for some 
+16 
+Table of Contents 
+Index to Financial Statements 
+facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the
+federal Clean Air Act and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our
+operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects. Our operations may also soon be affected by rapidly emerging regulation of “green house gases,” such as carbon dioxide
+and methane, which are emitted in the course of oil and natural gas exploration and production. 
+Operational Hazards and Insurance
+The oil business involves a variety of operating risks, including the risk of fire, explosions, blow outs, pipe failures
+and, in some cases, abnormally high pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be
+required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations. 
+In accordance with what we believe to be industry practice, we maintain insurance against some, but not all, of the operating risks to
+which our business is exposed. We insure some, but not all, of our properties for operational and hurricane related events. We currently have insurance policies that include coverage for general liability, physical damage to our oil and gas
+properties, operational control of certain wells, oil pollution, third party liability, workers compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that must be met prior to recovery.
+Additionally, our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these events could
+cause a significant disruption to our business. For example, we experienced production interruptions in 2005 and 2006 from Hurricanes Katrina and Rita and, in 2008, from Hurricanes Gustav and Ike. A loss not fully covered by insurance could have a
+material adverse affect on our financial position, results of operations and cash flows. 
+Currently, we have general liability
+insurance coverage with an annual aggregate limit of up to $21.0 million which includes environmental impairment coverage for the effects of onshore and offshore pollution on third parties arising from our operations. For our offshore West Cote
+Blanche Bay properties, we also have a $25.0 million property physical damage policy which insures against most operational perils, such as explosions, fire, vandalism, theft, hail and windstorms, provided, however, that this policy is limited to
+$10.0 million for damages arising as a result of a named windstorm. In the event of a loss under this policy, we have up to $6.6 million of business interruption coverage available after a 90 day waiting period. All of our insurance coverage
+includes deductibles of up to $1,000,000 per occurrence ($1.5 million in the case of a named windstorm) that must be met prior to recovery. Additionally, our insurance is subject to customary exclusions and limitations. We reevaluate the purchase of
+insurance, policy terms and limits annually each May. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or
+unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to maintain minimal or no insurance coverage.
+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. The occurrence of a significant
+event, not fully insured against, could have a material adverse effect on our financial condition and results of operations. 
+At the depths and in the areas in which we operate, and in light of the vertical and directional drilling that we undertake, we typically
+do not encounter high pressures or extreme drilling conditions. Accordingly, we typically do not carry a control of well policy, although we currently have such coverage in place for five specific Southern Louisiana wells. In addition, it is
+currently anticipated that we will carry control of well coverage for all of our Utica Shale wells. We also require all of our third party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the
+service provider’s employees as well as contractors and subcontractors hired by the service provider. 
+17 
+Table of Contents 
+Index to Financial Statements 
+We have prepared and have in place spill prevention control and countermeasure plans for
+each of our principal facilities at WCBB in response to federal and state requirements. The plans are reviewed annually and updated as necessary. As required by applicable regulations, our facilities are built with oil containment features and we
+own certain oil containment equipment, such as oil boom to surround drill sites and production facilities if needed. In addition, we have a national emergency response company on retainer. This company specializes in the clean up of hydrocarbons as
+a result of spills, blow-outs and natural disasters. This emergency response company has been involved in the clean up efforts of some of the largest oil spills along the Gulf Coast and is on call to us 24 hours a day when its services are needed.
+It has previously reported that it owns over 164 response vehicles, 65 response vessels, 116 response trailers equipped with decontaminant supplies, personal protective equipment and other equipment used in responding to oil spills, two storage
+barge sets, allowing for storage of up to 248 barrels of recovered oil each, and over 20 roll-off boxes and vacuum boxes. We pay this company a retainer plus additional amounts when it provides us with clean up services. Our aggregate payments for
+the retainer and clean up services during 2011 were approximately $220,000. While this company has been able to meet our service needs when required from time to time in the past, it is possible that its ability to provide services to us in the
+future, if and when needed, could be hindered or delayed in the event of a widespread disaster. However, in light of the depths and the areas in which we operate, and the necessity for gas lift to produce our WCBB wells due to low reservoir pressure
+at our WCBB field, we believe other companies would be available to us in the event our primary remediation company was unable to perform. 
+Headquarters and Other Facilities 
+We own an approximately 28,500 square foot office building in Oklahoma City, Oklahoma that serves as our corporate headquarters. We lease a portion of this office space to certain of our affiliates. We
+also own an approximately 12,500 square foot building in Lafayette, Louisiana. This building contains approximately 6,200 square feet of finished office area and 6,300 square feet of clear span warehouse area. We also lease 3,722 square feet in a
+building in Lafayette that we use as our Louisiana headquarters. Each of these properties is suitable and adequate for its use. 
+Employees
+At December 31, 2011, we had 50 employees. An unrelated Louisiana well servicing company provides all necessary field
+personnel needed to operate the WCBB and the Hackberry fields. In addition, in the past, certain of our employees performed management and administrative services for affiliated companies. We were reimbursed by these affiliates for the salaries and
+benefits of these individuals based on the estimated time they spent working for those affiliates. For the year ended December 31, 2009, expenses reimbursed to us under these arrangements were $0.6 million, respectively, and are reflected as a
+reduction in our general and administrative expenses. No amounts were reimbursed to us under these arrangements in 2011 or 2010. 
+Available
+Information 
+Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments
+to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on the Investor Relations page of our website at www.gulfportenergy.com as soon as reasonably practicable after such
+material is electronically filed with, or furnished to, the Securities and Exchange Commission, or SEC. Information contained on our website, or on other websites that may be linked to our website, is not incorporated by reference into this annual
+report on Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. 
+18 
+Table of Contents 
+Index to Financial Statements

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+ITEM 13. 
+CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 
+For information concerning Item 13—Certain Relationships and Related Transactions, and Director Independence, see our definitive proxy statement, which will be filed with the Securities and
+Exchange Commission with 120 days after the close of our previous fiscal year and is incorporated herein by this reference (with the exception of portions noted therein that are not incorporated by reference).

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+ITEM 9A. 
+CONTROLS AND PROCEDURES 
+Evaluation of Disclosure Control and Procedures . Under the direction of our Chief Executive Officer and Vice President and Chief
+Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the
+60 
+Table of Contents 
+Index to Financial Statements 
+Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are
+also intended to ensure that such information is accumulated and communicated to management, including our Chief Executive Officer and Vice President and Chief Financial Officer, as appropriate to allow timely decisions regarding required
+disclosures. 
+As of December 31, 2011, an evaluation was performed under the supervision and with the participation of
+management, including our Chief Executive Officer and Vice President and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities
+Exchange Act of 1934. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief Financial Officer have concluded that as of December 31, 2011, our disclosure controls and procedures are effective. 
+Changes in Internal Control over Financial Reporting . There have not been any changes in our internal control over financial
+reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting. 
+Management’s Report on Internal Control Over Financial Reporting 
+Management is responsible for the fair presentation of the consolidated financial statements of Gulfport Energy Corporation. Management is
+also responsible for establishing and maintaining a system of adequate internal controls over financial reporting as defined in Rule 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. These internal controls are
+designed to provide reasonable assurance that the reported financial information is presented fairly, that disclosures are adequate and that the judgments inherent in the preparation of financial statements are reasonable. There are inherent
+limitations in the effectiveness of any system of internal control, including the possibility of human error and overriding of controls. Consequently, an effective internal control system can only provide reasonable, not absolute, assurance with
+respect to reporting financial information. 
+Management conducted an evaluation of the effectiveness of our internal control
+over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in Internal
+Control—Integrated Framework , management did not identify any material weaknesses in our internal control over financial reporting and concluded that our internal control over financial reporting was effective as of December 31, 2011.
+Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year
+ended December 31, 2011 included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2011, as stated in their accompanying report. 
+/s/ James D. Palm 
+/s/ Michael G. Moore 
+Name: 
+James D. Palm 
+Name: 
+Michael G. Moore 
+Title: 
+Chief Executive Officer 
+Title: 
+Chief Financial Officer 
+61 
+Table of Contents 
+Index to Financial Statements 
+Report of Independent Registered Public Accounting Firm 
+Board of Directors and Stockholders 
+Gulfport Energy Corporation: 
+We have audited internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 2011, based on criteria established in
+Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). The Company’s management is responsible for maintaining effective internal control over
+financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an
+opinion on the Company’s internal control over financial reporting based on our audit. 
+We conducted our audit in accordance with the
+standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in
+all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control
+based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. 
+A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
+statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that,
+in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in
+accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance
+regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. 
+Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject
+to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. 
+In our opinion, Gulfport Energy Corporation and Subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on criteria
+established in Internal Control—Integrated Framework issued by COSO. 
+We also have audited, in accordance with the standards of
+the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations,
+stockholders’ equity and comprehensive income and cash flows for each of the three years in the period ended December 31, 2011 and our report dated February 27, 2012 expressed an unqualified opinion. 
+/s/ GRANT THORNTON LLP 
+Oklahoma City, Oklahoma 
+February 27, 2012 
+62 
+Table of Contents 
+Index to Financial Statements

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+Certain Relationships and Related Transactions 
+Review and Approval of Related Party Transactions 
+The Audit Committee, as provided in its charter, reviews and approves related party transactions. The Company does not have a formal set of standards to be substantively applied to each transaction
+reviewed by the Audit Committee. Instead of a formalized policy, related party transactions are reviewed and judgment is applied to determine whether such transactions are in the best interests of the Company. Further, the Company’s Code of
+Business Conduct and Ethics governs various compliance areas, including conflicts of interest and fair dealings, which are considered in the process of the review and approval of related party transactions. 
+The Company’s policy that all of its employees and directors, as well as their family members, must avoid any activity that is or has the appearance
+of conflicting with the Company’s business interest. This policy is a written policy included in the Company’s Code of Business Conduct and Ethics posted on its website. Each director and executive officer is instructed to always inform
+the designated compliance officer when confronted with any situation that may be perceived as a conflict of interest. Only the board of directors or a committee consisting solely of independent directors may grant waivers of the provisions of the
+Code of Business Conduct and Ethics for the Company’s executive officers and directors. In addition, at least annually, each director and executive officer completes a detailed questionnaire specifying any business relationship that may give
+rise to a conflict of interest. 
+Further, under the Audit Committee Charter, the Audit Committee is responsible for reviewing and monitoring
+compliance with our Code of Business Conduct and Ethics and recommending any warranted changes to the board of directors. In addition, the board of directors and, pursuant to its written charter, the Audit Committee, reviews and approves all
+relationships and transactions in which the Company and its directors, director nominees and executive officers and their immediate family members, as well as holders of more than 5% of any class of our voting securities and their family members,
+have a direct or indirect material interest. The board of directors and the Audit Committee approve only those transactions that, in light of known circumstances, are consistent, or are not inconsistent with, the Company’s best interests, as
+they determine in the good faith exercise of their discretion. 
+Administrative Services Agreements
+We are a party to administrative service agreements with Stampede Farms LLC, which we refer to as Stampede Farms, Everest Operations
+Management LLC, which we refer to as Everest, and Tatex Thailand III, LLC, which we refer to as Tatex III. Under these agreements, our services include professional and technical support and the fees for such services can be amended by mutual
+agreement of the parties. Each of these administrative service agreements may be cancelled (1) by us with at least 60 days prior written notice and, (2) by the counterparty at any time with at least 30 days prior written notice to us and
+(3) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. We did not provide services under any of these agreements in 2011 and received no
+reimbursements thereunder. Each of Stampede Farms, Everest and Tatex III is controlled by Wexford Capital LP, or Wexford. 
+Services Provided to Us by Our Affiliates 
+We contract with Athena Construction, L.L.C., which we refer to as Athena, to provide barge
+services in our West Cote Blanche Bay, or WCBB, and Hackberry fields located along the Louisiana Gulf Coast. For the year ended December 31, 2011, we paid Athena $3,389,000 and owed an additional $676,000 for such services at that date. Athena
+is controlled by Wexford. 
+34 
+Table of Contents 
+Effective March 1, 2008, Everest provides tax planning, preparation of supporting tax schedules and
+consultation services to us based on an agreed fee structure. The scope of such services can be modified with the mutual agreement of the parties. Everest is controlled by Wexford. We paid Everest $5,000 for these services in 2011. 
+Caliber Development Company, LLC, or Caliber, provides building maintenance services for our headquarters in Oklahoma City, Oklahoma. For the year ended
+December 31, 2011, we paid Caliber $20,000 and owed an additional $2,000 at that date. Caliber is an entity controlled by Wexford. 
+Great
+White Directional Services LLC, which we refer to as Directional, performs directional drilling services for us at our WCBB and Hackberry fields. Directional was an entity controlled by Wexford until August 24, 2011 when it was sold to an
+unrelated third party. Directional is no longer a related party. While still a related party, we paid Directional approximately $2,625,000 and owed an additional $1,133,000 for such services at that date. 
+Great White Pressure Control, which we refer as Pressure Control, performs services for us at our WCBB field. Pressure Control was an entity controlled
+by Wexford until August 24, 2011 when it was sold to an unrelated third party. Pressure Control is no longer a related party. While still a related party, we paid Pressure Control approximately $80,000. No amounts were owed to Pressure Control
+as of August 24, 2011. 
+Black Fin P&A, LLC, which we refer to as Black Fin, performs plugging and abandonment services for us at our
+WCBB field. For the year ended December 31, 2011, we did not pay any amounts to Black Fin and owed $436,000 to for such services at that date. Black Fin is an entity controlled by Wexford. 
+Our Investments in Affiliates and Related Agreements 
+We have a 23.5% ownership interest in Tatex Thailand II, LLC, or Tatex II. The remaining interests in Tatex II are owned by other entities controlled by Wexford. Tatex II 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 two million acres which includes the Phu Horm Field.
+During 2011, we received $870,000 in distributions from Tatex II. 
+We have a 17.9% ownership interest in Tatex III. Tatex III owns a
+concession covering approximately one million acres in Thailand. Approximately 68.7% of the remaining interests in Tatex III are owned by other entities and individuals affiliated with Wexford. During the year ended December 31, 2011, we paid
+$3,794,000 in cash calls to Tatex III. 
+We own a 24.9999% interest in Grizzly, a Canadian unlimited liability company, through our wholly
+owned subsidiary Grizzly Holdings, Inc. The remaining interests in Grizzly are owned by other entities controlled by Wexford. As of December 31, 2011, Grizzly had approximately 754,000 acres under lease in the Athabasca region located in the
+Alberta Province near Fort McMurray. Grizzly Holdings Inc. entered into a loan agreement with Grizzly effective January 1, 2008, under which Grizzly borrowed funds from us. Borrowed funds initially bore interest at LIBOR plus 4% and had an
+original maturity date of December 31, 2012. Effective April 1, 2010, the loan agreement was amended to modify the interest rate to 0.69% and change the maturity date to December 31, 2011. Effective October 15, 2010, the loan
+agreement was further amended to change the maturity date to December 31, 2012. Interest was paid on a paid-in-kind basis by increasing the outstanding balance of the loan. During the year ended December 31, 2011, we loaned Grizzly
+approximately $3,182,000 and recognized interest income of approximately $147,000. Effective December 7, 2011, Grizzly Holdings Inc. entered into a debt settlement agreement with Grizzly under which Grizzly agreed to satisfy the entire
+outstanding debt and accrued interest of $22,325,000 by issuing additional common shares of Grizzly with no effect to the ownership structure of Grizzly. 
+35 
+Table of Contents 
+During the third quarter of 2011, we purchased a 25% ownership interest in Bison Drilling and Field Services
+LLC, or Bison, at a cost of $6,009,000, subject to adjustment. In April 2012, we increased our ownership interest in Bison to 40% for an additional payment of $6,152,000. The remaining interests in Bison are owned by entities controlled by Wexford,
+including Windsor Permian LLC, or Windsor. Bison owns and operates drilling rigs. 
+During the fourth quarter of 2011, we purchased a 25%
+ownership interest in Muskie Holdings LLC, or Muskie, at a cost of $2,142,000, subject to adjustment. The remaining interests in Muskie are owned by entities controlled by Wexford, including Windsor. Muskie holds certain assets, real estate and
+rights in a lease covering land in Wisconsin that is prospective for mining oil and natural gas fracture grade sand. 
+Area of Mutual Interest and Related Agreements 
+Effective as of November 1, 2007, we and Windsor entered into an area of mutual
+interest agreement to jointly acquire oil and gas leases in the Permian Basin. The agreement provides that each party must offer the other party the right to participate in 50% of each such acquisition. The parties also agreed, subject to certain
+exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. During 2011, we acquired approximately 604 net acres from Windsor under the terms
+of this agreement for an aggregate of $1,102,000. Windsor is controlled by Wexford. 
+Windsor is the operator of all of our acreage in the
+Permian Basin. As operator of these properties, Windsor is responsible for the daily operations, monthly operation billings and monthly revenue disbursements for the properties in which we hold an interest. For the year ended December 31, 2011,
+Windsor billed us approximately $56,103,000 and at December 31, 2011, we owed $5,593,000 for these services. 
+Effective April 1,
+2010, we entered into an area of mutual interest agreement with Windsor Niobrara LLC, which we refer to as Windsor Niobrara, to jointly acquire oil and gas leases on certain lands located in Northwest Colorado for the purpose of exploring,
+exploiting and producing oil and gas from the Niobrara Formation. The agreement provides that each party must offer the other party the right to participate in such acquisitions on a 50/50 basis. The parties also agreed, subject to certain
+exceptions, to share third-party costs and expenses in proportion to their respective participating interests and pay certain other fees as provided in the agreement. We are the operator of this acreage in the Niobrara Formation. As operator, we are
+responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the year ended December 31, 2011, we billed Windsor Niobrara $6,642,000 and, at December 31, 2011, Windsor Niobrara
+owed us $3,557,000 for these services. Windsor Niobrara is controlled by Wexford. 
+In February 2011, we entered into an agreement with an
+unrelated third party to acquire certain leasehold interests in acreage located in the Utica Shale in Ohio. The agreement also granted us an exclusive right of first refusal for a period of six months on certain additional tracts leased by the
+seller. As of December 31, 2011, we had acquired leasehold interests in approximately 98,000 gross (49,000 net) acres in the Utica Shale in Eastern Ohio under these and other agreements for approximately $118,421,000. As of February 20,
+2012, we had closed on additional acquisitions bringing our leasehold interests to approximately 107,000 gross (53,500 net) acres. We have commitments with various future closing dates that could increase our acreage position in the Utica Shale to
+an aggregate of approximately 125,000 gross (62,500 net) leasehold acres. Entities affiliated with Wexford, primarily Windsor Ohio LLC, or Windsor Ohio, participated with us on a 50/50 basis in the acquisition of the leases described above and, at
+December 31, 2011, held leasehold interests in approximately 49,000 net acres for which they paid approximately $118,413,000, excluding fees and expenses of $1,184,000 billed under the acquisition team agreement described below. We are the
+operator on this acreage in the Utica Shale. 
+Effective July 1, 2008, we entered into an acquisition team agreement with Everest to
+identify and evaluate potential oil and gas properties in which we and Everest or its affiliates may wish to invest. Pursuant to this agreement, Gulfport and Everest each agreed to form an acquisition team. Upon a successful closing of an
+acquisition or divestiture, the party whose acquisition team identified the acquisition or divestiture is entitled to 
+36 
+Table of Contents 
+receive a fee from the other party and its affiliates, if applicable, participating in such closing. The fee is equal to 1% of the party’s proportionate share of the acquisition or
+divestiture consideration. The agreement has a one-year term unless earlier terminated by either party upon 30 days notice. 
+From time to
+time, certain of our petroleum engineers provide services relating to evaluation of potential investments to Wexford and geological evaluations, seismic review and similar services to Tatex II and Tatex III. Wexford, Tatex II and Tatex III,
+respectively, have agreed to reimburse us based on the amount, scope and nature of services provided by our petroleum engineers to such entities. We did not provide any services under these arrangements in 2011. 
+Our Relationships with Wexford and its Affiliates 
+Charles E. Davidson is the Chairman and Chief Investment Officer of Wexford and he beneficially owned approximately 16.8% of our outstanding common stock as of December 31, 2011. Wexford is the manager of
+the Wexford-controlled entities described above. As manager, Wexford has the exclusive authority to, among other things, purchase, hold and dispose of the assets of each such entity. Mr. Liddell, our Chairman of the Board, is the operating member
+and, in some cases, an officer, of certain of these entities. All distributions made by these entities are first paid to the Wexford members in accordance with their respective ownership interests until they have received amounts equal to their
+respective capital contributions. Thereafter, distributions are to be made 90% to the Wexford members in accordance with their respective ownership interests and 10% to Mr. Liddell. Mr. Liddell is not currently entitled to, and has not received,
+distributions from any of these entities. All transactions between us and these entities are reviewed and approved by our independent directors. 
+37 
+Table of Contents