GULFPORT ENERGY CORP

FORM 10-K

(Annual Report)

Filed 03/01/13 for the Period Ending 12/31/12

 

Address 14313 NORTH MAY AVENUE

SUITE 100

OKLAHOMA CITY, OK 73134

Telephone 4058488807

CIK 0000874499

Symbol GPOR

SIC Code 1311 - Crude Petroleum and Natural Gas

Industry Oil & Gas Operations

Sector Energy

Fiscal Year 12/31

http://www.edgar-online.com

© Copyright 2013, EDGAR Online, Inc. All Rights Reserved.

Distribution and use of this document restricted under EDGAR Online, Inc. Terms of Use.
Table of Contents 

Index to Financial Statements 

UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION 

Washington, D.C. 20549 

 ______________________________________________ 

Form 10-K 

(Mark One) 

Commission File Number: 000-19514 

Gulfport Energy Corporation 

(Exact Name of Registrant as Specified in Its Charter) 

______________________________________________ 

(405) 848-8807 

(Registrant’s Telephone Number, Including Area Code) 

Securities registered pursuant to Section 12(b) of the Act: 

Securities registered pursuant to Section 12(g) of the Act: None 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes  No  

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes  No  

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the 

preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 

days. Yes  No  

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be 

submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant 

was required to submit and post such files). Yes  No  

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will 

not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any 

amendment to this Form 10-K.  

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions 

of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): 

Large Accelerated filer  Accelerated filer  Non-accelerated filer  Smaller reporting company  

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No  

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant computed as of June 29, 2012 , based on the closing 

price of the common stock on the NASDAQ Global Select Market on June 29, 2012 , the last business day of the registrant’s most recently completed second fiscal quarter 

($20.63 per share), was $1,148,840,242.35 . 

As of February 20, 2013 , 77,339,886 shares of the registrant’s common stock were outstanding. 

DOCUMENTS INCORPORATED BY REFERENCE 

Portions of Gulfport Energy Corporation’s Proxy Statement for the 2013 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12, 13 and 

14 of Part III of this Form 10-K. 

 ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 

 

For the fiscal year ended December 31, 2012 

OR 

 TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 

 For the transition period from to 

Delaware 73-1521290 

(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.) 

 

14313 North May Avenue, Suite 100 

Oklahoma City, Oklahoma 73134 

(Address of Principal Executive Offices) (Zip code) 

Title of Each Class Name of Each Exchange on Which Registered 

Common Stock, par value $0.01 per share The NASDAQ Stock Market LLC 
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TABLE OF CONTENTS 

 

 Page 

 

FORWARD-LOOKING STATEMENTS 1 

 

PART I 2 

 

ITEM 1. BUSINESS 2 

 

ITEM 1A. RISK FACTORS 24 

 

ITEM 1B. UNRESOLVED STAFF COMMENTS 43 

 

ITEM 2. PROPERTIES 43 

 

ITEM 3. LEGAL PROCEEDINGS 48 

 

ITEM 4. MINE SAFETY DISCLOSURES 50 

 

PART II 51 

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER 

PURCHASES OF EQUITY SECURITIES 51 

 

ITEM 6. SELECTED FINANCIAL DATA 51 

 

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 53 

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 66 

 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 67 

 

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 67 

 

ITEM 9A. CONTROLS AND PROCEDURES 67 

 

ITEM 9B. OTHER INFORMATION 70 

 

PART III 70 

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 70 

 

ITEM 11. EXECUTIVE COMPENSATION 70 

 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED 

STOCKHOLDER MATTERS 70 

 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 70 

 

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 70 

 

PART IV 71 

 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 71 
 

i 

 

Signatures S -1 

 

Index to Consolidated Financial Statements F -1 

 

Exhibit Index E -1 
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FORWARD-LOOKING STATEMENTS 

Our disclosure and analysis in this Form 10-K may include forward-looking statements within the meaning of Section 27A of the Securities Act of 

1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities 

Litigation Reform Act of 1995, that are subject to risks and uncertainties. These statements involve known and unknown risks, uncertainties and other 

factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements 

expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,” 

“should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar 

expressions intended to identify forward-looking statements. All statements, other than statements of historical facts, included in this Form 10-K that 

address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as estimated future net 

revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), business strategy 

and measures to implement strategy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, 

reference to intentions as to future matters and other such matters are forward-looking statements. 

These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions 

made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors 

relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control. 

Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are 

beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the 

forward-looking statements contained in this Form 10-K are not guarantees of future performance, and we cannot assure any reader that those statements 

will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the 

forward-looking statements due to the factors listed in the “ Risk Factors ” and “ Management's Discussion and Analysis of Financial Condition and 

Results of Operations ” sections and elsewhere in this Form 10-K. All forward-looking statements speak only as of the date of this Form 10-K. We do not 

intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law.

These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. 

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PART I 

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 the Utica Shale in Eastern Ohio. 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, or Grizzly, a

21.4% equity interest in Diamondback Energy, Inc., or Diamondback, a NASDAQ Global Select Market listed company to which we contributed our 

Permian Basin oil and gas interests in October 2012 immediately prior to Diamondback's initial public offering, or the Diamondback IPO (see “- Recent 

Developments-Contribution ” below), and have interests in entities that operate in Southeast Asia, including the Phu Horm gas field in Thailand. We seek 

to achieve reserve growth and increase our cash flow through our annual drilling programs. 

In 2012, at our WCBB field, we recompleted 61 wells and drilled 31 wells for a total cost of approximately $68.2 million as of December 31, 2012. 

Of the 31 new wells drilled at WCBB in 2012, 27 were completed as producing wells and four were non-productive. In the fourth quarter of 2012, 

production at WCBB was approximately 293,906 net barrels of oil equivalent, or BOE, or an average of 3,195 BOE per day, 98% of which was from oil 

and 2% of which was from natural gas. During January 2013, our average net daily production at WCBB was approximately 3,054 BOE, 98% of which 

was from oil and 2% of which was from natural gas. During 2013, we currently anticipate drilling 22 to 24 wells and recompleting 60 wells at our WCBB 

field for an estimated aggregate cost of $42.0 million to $45.0 million. 

In 2012, at our East Hackberry field, we recompleted 32 wells and drilled 23 wells for a total cost of approximately $70.1 million as of December 31, 

2012. Of the 23 new wells drilled at East Hackberry during 2012, 19 were completed as producing wells, three were non-productive and one was being 

drilled at year end. In the fourth quarter of 2012, net production at East Hackberry was approximately 212,975 BOE, or an average of 2,315 BOE per day, 

98% of which was from oil and 2% of which was from natural gas. During January 2013, our average net daily production at East Hackberry was 

approximately 2,623 BOE, 97% of which was from oil and 3% of which was from natural gas. During 2013, we currently anticipate drilling ten to twelve 

wells and recompleting 24 wells for an aggregate estimated cost of $26.0 million to $28.0 million. 

At December 31, 2012, we were drilling one well at our West Hackberry field. In the fourth quarter of 2012, net production at West Hackberry was 

approximately 4,711 BOE, or an average of 51 BOE per day, 96% of which was from oil and 4% of which was from natural gas. During January 2013, 

our average net daily production at West Hackberry was approximately 29 BOE, 100% of which was from oil. 

As of December 31, 2012, we had acquired leasehold interests in approximately 137,000 gross (106,000 net) acres in the Utica Shale in Eastern Ohio, 

and in February 2013 we acquired an additional approximately 22,000 net acres in the Utica Shale. See "-Recent Developments - February 2013 Utica 

Acreage Acquisition." We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2012, had drilled 

14 wells, ten of which had been completed. As of February 15, 2013, three of these wells were producing. Of the 11 additional wells, seven are projected 

to be producing by April 1, 2013 and the other four wells are projected to be producing by June 1, 2013. The delays in bringing these additional wells online have primarily been associated with MarkWest Energy Partners, L.P.'s challenges in obtaining rights-of-way and acquiring necessary state and federal 

permitting. These rights-of-way and permits have now been obtained. In addition, 12 gross (one net) wells were drilled by another operator on our Utica 

Shale acreage during 2012. 

We have three rigs under contract on our Utica Shale acreage. We currently intend to drill 50 gross (44 net) wells on our Utica Shale acreage in 2013 

for approximately $382.0 million to $426.0 million. 

Aggregate net production from our Utica Shale acreage during the three months ended December 31, 2012 was approximately 69,667 BOE, or 757 

BOE per day, 35% of which was from oil and natural gas liquids, or NGLs, and 65% of which was from natural gas. During January 2013, our average 

daily net production from the Utica Shale was approximately 792 BOE, 41% of which was from oil and NGLs and 59% of which was from natural gas. 

The Wagner 1-28H well, our longest producing well in the Utica Shale, was assigned gross proved estimated ultimate recovery reserves at December 31, 

2012 of 65.8 thousand barrels of oil, or MBbls, and 10.0 billion cubic feet, or Bcf, of unshrunk natural gas by Ryder Scott Company, 

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L.P., or Ryder Scott. Adjusting for shrinkage and the extraction of NGLs, we estimate that this is equivalent to 1.8 million BOE, or MMBOE, of proved 

reserves. 

From January 1, 2012 through the closing of the contribution of our Permian Basin acreage to Diamondback on October 11, 2012, 19 gross (8.3 net) 

wells, including our first horizontal well, were spud on our Permian Basin acreage, all of which were completed as producing wells. One gross (0.3 net) 

existing well was recompleted from January 1, 2012 to October 11, 2012. Aggregate net production from our Permian Basin acreage during the first 

eleven days of October 2012 was approximately 17,100 BOE, or 1,555 BOE per day, of which approximately 60% was oil, 28% was NGL's and 12% was 

natural gas. For more information regarding the contribution of our Permian Basin acreage to Diamondback, see “ -Recent Developments-Contribution ” 

below. 

Effective as of April 1, 2010, we acquired leasehold interests in the Niobrara Formation in Northwestern Colorado and held leases for approximately 

11,788 net acres as of December 31, 2012. During the year ended December 31, 2012, three gross (one net) wells, including one gross (.04 net) well 

drilled by another operator, were spud on our Niobrara Formation acreage, two of which were completed as producers and one of which was nonproductive. In the fourth quarter of 2012, net production from our Niobrara Formation acreage was approximately 2,644 BOE, or an average of 29 BOE 

per day, 100% of which was from oil. During January 2013, our average net daily production from our Niobrara Formation acreage was approximately 43 

BOE, 100% of which was from oil. In the Niobrara Formation, we have completed a 60 square mile 3-D seismic survey and have received a processed 

version of the seismic. During 2013, we currently do not anticipate drilling any wells in the Niobrara Formation. 

As of December 31, 2012, we held approximately 864 net acres in the Bakken Formation of Western North Dakota and Eastern Montana with 

interests in nine wells and overriding royalty interests in certain existing and future wells. In the fourth quarter of 2012, our net production from this 

acreage was approximately 7,355 BOE, or an average of 80 BOE per day, of which 87% was from oil, 10% was from natural gas and 3% was from NGLs. 

During January 2013, our average daily net production from our Bakken Formation acreage was approximately 73 BOE, of which 89% was from oil and 

11% was from natural gas. 

We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by 

Grizzly Oils Sands Inc., an entity owned by certain investment funds managed by Wexford Capital LP, or Wexford. An affiliate of Wexford owned 

approximately 13.3% of our outstanding common stock as of December 5, 2011, and approximately 9.5% as of March 13, 2012, which ownership was 

reduced to less than 1% as of September 28, 2012. As of December 31, 2012, Grizzly had approximately 800,000 acres under lease in the Athabasca and 

Peace River oil sands regions of Alberta, Canada. Our total net investment in Grizzly was approximately $172.8 million as of December 31, 2012. As of 

that date, Grizzly had drilled an aggregate of 233 core holes and six water supply test wells on ten separate lease blocks and conducted a number of 

seismic programs. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil sand project at Algar Lake. In 

November 2011, the Government of Alberta provided a formal Order in Council authorizing the Alberta Energy Resources Conservation Board, or 

ERCB, to issue the formal regulatory approval of Grizzly's Algar Lake steam-assisted gravity drainage, or SAGD, project. Construction of the Algar Lake 

Phase 1 SAGD project commenced in 2012. During 2012, an 11 kilometer road was constructed to the project site, water and natural gas supply pipelines 

were installed, central plant modules were assembled, transported to the project site and lifted into place, ten production well pairs were drilled and 

completed and well pad modules and flow lines back to the central plant were installed. Grizzly expects first oil production at Algar Lake by the third 

quarter of 2013. In the first quarter of 2012, Grizzly completed the acquisition of the May River property comprising approximately 47,000 acres. In the 

fourth quarter of 2012, Grizzly initiated a 28 well core hole drilling program at May River and plans to file an initial 12,000 barrel per day development 

application with the ERCB by the end of 2013. At the Thickwood thermal project, Grizzly's 2012 activities included the completion of a 22 well core hole 

drilling program and the acquisition of 31 kilometers of seismic data. A development application for a 12,000 barrel per day oil sands project at 

Thickwood was filed in the fourth quarter of 2012. Grizzly anticipates approval of this development application in mid-2014 and first oil production by 

mid-2017. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National 

Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN's rail network. Grizzly expects that this arrangement will provide 

consistent access to Brent-based pricing from Grizzly's Algar Lake project. Grizzly is also pursuing the design, permitting and construction of rail 

terminals in Northern Alberta and on the Lower Mississippi River, where it plans to develop scalable capacity to accommodate unit trains to ship and 

receive up to 100,000 barrels per day. Grizzly anticipates beginning to transport the company's bitumen starting in the third quarter of 2013. 

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, 

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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 243,000 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 490,000 acres in Southeast Asia. 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, or MMcf, 

per day of gas for short intervals, but would subsequently fall to a sustained rate of two MMcf per day of gas. Pressure buildup information confirmed that 

this wellbore lacked the permeability to deliver commercial quantities of gas. Despite an apparently well-developed porosity system suggesting potential 

for a large amount of gas in place, testing of the well did not exhibit that there was sufficient permeability to produce in commercial quantities. Tatex III 

intends to continue testing some of the structures identified through its 3-D seismic survey and has begun the application process for two more drilling 

locations. Tatex III currently expects to drill the first of these wells, located to the south of the TEW-E well, in 2013. 

In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are

required to support our operations. In the second quarter of 2012, we acquired a 50% equity interest in each of Stingray Pressure Pumping LLC, or 

Stingray Pressure, and Stingray Cementing LLC, or Stingray Cementing. Stingray Pressure and Stingray Cementing provide well completion services. We 

also acquired a 50% equity interest in Blackhawk Midstream LLC, or Blackhawk, which coordinates gathering, compression, processing and marketing 

activities in connection with the development of our Utica Shale acreage. In March 2012, we acquired a 50% equity interest in Timber Wolf Terminals 

LLC, or Timber Wolf, for $1.0 million. Also in March 2012, we acquired a 22.5% equity interest in Windsor Midstream LLC, or Midstream, for $7.0 

million. Midstream owns a 28.4% equity interest in a gas processing plant in West Texas. In the fourth quarter of 2012, we acquired a 50% equity interest

in Stingray Logistics LLC, or Stingray Logistics, which will provide well services. In 2011, we acquired a 25% equity interest in Bison Drilling and Field 

Services LLC, or Bison, which owns and operates drilling rigs and related equipment. In April 2012, we purchased an additional 15% equity interest in 

Bison for approximately $6.2 million, bringing our total ownership interest in Bison to 40%. Also in 2011, we acquired a 25% interest in Muskie 

Holdings LLC, or Muskie, which is engaged in the mining of hydraulic fracturing grade sand. The remaining equity interests in these entities are owned 

by affiliates of Wexford. In 2012, we invested approximately $42.8 million in these entities. In 2013, we expect to invest approximately $10.0 million to

$15.0 million in these entities. 

As of December 31, 2012, we had 13.9 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 $436.8 million and associated standardized measure of discounted future net cash flows of 

approximately $348.6 million , excluding reserves attributable to our interests in Diamondback, Grizzly, Tatex II and Tatex III. See "Item 2. PropertiesProved 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. 

Recent Developments 

February 2013 Utica Acreage Acquisition 

On February 11, 2013, we entered into a purchase and sale agreement, or the PSA, with Windsor Ohio, LLC, or Windsor Ohio, which is an affiliate 

of Wexford, pursuant to which Windsor Ohio agreed to sell, assign, transfer and convey to us approximately 22,000 net acres representing 100% of its 

right, title and interest in and to certain leasehold interests in the Utica Shale in Eastern Ohio for approximately $220.4 million, subject to certain 

adjustments. This transaction, which closed on February 15, 2013, excluded Windsor Ohio's interest in 14 existing wells and 16 proposed future wells 

together with certain acreage surrounding these wells. We acquired our initial acreage in the Utica Shale in February 2011 and subsequently acquired 

additional acreage in the area. Windsor Ohio participated with us in the acquisition of these leases. Through a prior transaction with Windsor Ohio, as 

discussed below under the heading " —December 2012 Utica Acreage Acquisition, " we acquired approximately 37,000 net acres, which increased our 

working interest in the acreage at the time to 77.7%. Through this most recent transaction, we acquired an additional approximately 16.2% interest in 

these leases, increasing our working interest in the acreage to 93.8%. All of the acreage included in this transaction is currently nonproducing and we are 

the operator of all of this acreage, subject to existing development and operating agreements between the parties. 

Pending the completion of title review after the closing, approximately $33.6 million of the purchase price has been placed 

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in an escrow account. The escrow account will terminate on May 1, 2013 and the escrow amount will be distributed to either us or Windsor Ohio based on 

any title benefits or title defects resulting from the title review. Pursuant to the PSA, we and Windsor Ohio have agreed to indemnify each other, our 

respective affiliates and their respective officers, directors, employees and agents from and against all losses that such indemnified parties incur arising 

from any breach of representations, warranties or covenants in the PSA and certain other matters. The transaction was approved by a special committee of 

our board of directors, who engaged independent counsel and financial advisors to assist with their review. 

December 2012 Utica Acreage Acquisition 

On December 17, 2012, we entered into a purchase and sale agreement with Windsor Ohio, pursuant to which Windsor Ohio agreed to sell, assign, 

transfer and convey to us approximately 30,000 net acres which, at the time, represented 50% of its right, title and interest in and to certain leasehold

interests in the Utica Shale in Eastern Ohio. On December 19, 2012, the parties amended that agreement to provide for our acquisition of approximately 

7,000 additional net acres. The aggregate purchase price for these interests was approximately $372.0 million, subject to certain adjustments. As discussed 

above, we acquired our initial acreage in the Utica Shale in February 2011 and subsequently acquired additional acreage in the area. Windsor Ohio has 

participated with us in the acquisition of these leases and through this transaction, we acquired an additional approximately 27.5% interest in these leases, 

increasing our working interest in the acreage to 77.7%. The transaction closed on December 24, 2012. All of the acreage included in this transaction is 

nonproducing and we are the operator of all of this acreage, subject to existing development and operating agreements between the parties. Pending the 

completion of title review after the closing, approximately $53.9 million of the purchase price was placed in an escrow account. The escrow account will 

terminate on April 30, 2013 and the escrow amount will be distributed to either us or Windsor Ohio based on any title benefits or title defects resulting

from the title review. 

Contribution 

On May 7, 2012, we entered into a contribution agreement with Diamondback, which is an affiliate of Wexford. Under the terms of the contribution 

agreement, we agreed to contribute to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and gas interests in the Permian Basin. 

On October 11, 2012, we completed this contribution, which we refer to in this Annual Report as the Contribution. At the closing of the Contribution, 

Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the 

closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the 

working capital, long-term debt and certain other items of a Diamondback subsidiary as of the date of the Contribution. In January 2013, we received an 

additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. As of December 11, 2012, Wexford beneficially 

owned approximately 44.4% of Diamondback's outstanding common stock. 

In connection with the Contribution, we and Diamondback entered into an investor rights agreement in which we have the right, for so long as we 

beneficially own more than 10% of Diamondback's outstanding common stock, to designate one individual as a nominee to serve on Diamondback's 

board of directors. Such nominee, if elected to Diamondback's board, will also serve on each committee of the board so long as he or she satisfies the 

independence and other requirements for service on the applicable committee of the board. So long as we have the right to designate a nominee to 

Diamondback's board and there is no nominee of ours actually serving as a Diamondback director, we will have the right to appoint one individual as an 

advisor to the board who shall be entitled to attend board and committee meetings. We are also entitled to certain information rights and Diamondback 

granted us certain demand and “piggyback” registration rights obligating Diamondback to register with the Securities and Exchange Commission, or the 

SEC, any shares of Diamondback common stock that we own. Immediately upon completion of the Contribution, we owned a 35% equity interest in 

Diamondback, rather than leasehold interests in our Permian Basin acreage. Upon completion of the Diamondback IPO and the exercise in full by the 

underwriters of their over-allotment option to purchase additional shares of common stock of Diamondback, we owned approximately 21.4% of 

Diamondback's outstanding common stock. Our investment in Diamondback is accounted for as an equity method investment. 

Notes Offerings 

On October 17, 2012, we issued $250.0 million in aggregate principal amount of 7.750% Senior Notes due 2020, or the October Notes, to qualified 

institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities 

Act under an indenture among us, our subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, which indenture we refer to as the

senior note indenture. The offering of the October Notes is referred to herein as the October Notes Offering. On December 21, 2012, we issued an 

additional $50.0 million in aggregate principal amount of 7.750% Senior Notes due 2020, or the December Notes, to qualified institutional 

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buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act, which 

offering we refer to herein as the December Notes Offering. The December Notes were issued as additional securities under the senior note indenture. The 

October Notes and the December Notes are referred to collectively herein as the Notes, and we refer to the October Notes Offering and the December 

Notes Offering collectively as the Notes Offerings.

Under the senior note indenture, interest on the Notes accrues at a rate of 7.750% per annum on the outstanding principal amount from October 17, 

2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The Notes are our senior unsecured obligations and 

rank equally in right of payment with all of our other senior indebtedness and senior in right of payment to any of our future subordinated indebtedness.

All of our existing and future restricted subsidiaries that guarantee our secured revolving credit facility or certain other debt guarantee the Notes, provided, 

however, that the Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by any of our future unrestricted subsidiaries. For more 

information regarding the Notes, see Item 7. “ Management's Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and 

Capital Resources-Senior Notes .” 

Equity Offerings 

On December 24, 2012, we issued and sold 11,750,000 shares of our common stock in an underwritten public offering, or the December 2012 Equity 

Offering (including the partial exercise of an over-allotment option for 1,650,000 shares granted to the underwriters, which option was exercised to the 

extent of 750,000 shares). The underwriters subsequently exercised their option to purchase the remaining 900,000 additional shares of common stock 

subject to the over-allotment option at a second closing, which occurred on January 7, 2013. The net proceeds from the December 2012 Equity Offering 

(including the net proceeds from the sale of the shares of common stock to the underwriters under their over-allotment option) were approximately $460.7 

million. We used a portion of these net proceeds to fund the acquisition of approximately 37,000 net acres in the Utica Shale in Eastern Ohio, as described 

above under the caption “ —December 2012 Utica Acreage Acquisition .” The remaining net proceeds will be used for general corporate purposes, 

including the funding of a portion of our 2013 capital development plan. 

On February 15, 2013, we issued and sold 8,912,500 shares of our common stock (including the 1,162,500 shares issued upon the exercise in full 

of an over-allotment option granted to the underwriters) in an underwritten public offering, which we refer to in this report as the February 2013 Equity

Offering. The net proceeds from the February 2013 Equity Offering were approximately $325.8 million. We used a portion of these net proceeds to fund 

the acquisition of approximately 22,000 net acres in the Utica Shale in Eastern Ohio, as described above under the caption “ -February 2013 Utica 

Acreage Acquisition. ” The remaining net proceeds will be used for general corporate purposes, including the funding of a portion of our 2013 capital 

development plan. 

Senior Secured Credit Facility 

Effective as of October 17, 2012, in connection with the completion of the October Notes Offering and the Contribution, our borrowing base under 

our senior secured credit facility was set at $45.0 million until the next borrowing base redetermination. Upon completion of the December Notes 

Offering, our borrowing base was further reduced to $40.0 million. As of December 31, 2012, no borrowings were outstanding under our senior secured 

credit facility. 

Principal Oil and Natural Gas Properties 

The following table presents certain information as of December 31, 2012 reflecting our net interest in our principal producing oil and natural gas 

properties along the Louisiana Gulf Coast, in the Utica Shale in Eastern Ohio, in the Niobrara Formation in Northwestern Colorado and in the Bakken 

Formation in Western North Dakota and Eastern Montana. 

6 
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Index to Financial Statements 

 

(7) 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 1,025 wells drilled as of December 31, 2012, 927 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, 2012, we 

drilled 214 new wells, 193 of which were productive, for a 90% success rate. As of December 31, 2012, estimated field cumulative gross production was 

194.0 MMBOE and 236.9 Bcf of gas. Of the 1,025 wells drilled in WCBB as of December 31, 2012, 102 were producing, 181 were shut-in, seven were 

producing intermittently and five were being used as salt water disposal wells. The other 730 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 

7 

 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) 80.108/100 109 109 181 181 5,668 5,668 556 4,266 4,822 

E. Hackberry Field (5) 80.309/100 41 41 96 96 3,931 3,931 151 1,900 2,051 

W. Hackberry Field 83.333/100 3 3 23 23 1,192 1,192 3 95 98 

Utica Shale (6) 40.641/50.0 2 1 — — 2,441 1,800 4,886 1,702 6,588 

Niobrara Formation 36.2/41.5 7 3 2 1 2,807 1,404 16 204 220 

Bakken Formation (7) 2.7/2.9 8 0.2 — — 1,862 163 10 82 92 

Overrides/Royalty Nonoperated Various 208 0.4 2 0.06 — — 6 2 8 

 

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

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

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

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

by production. 

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

base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI). 

(5) NRI shown is for producing wells. 

(6) Does not give effect to our February 2013 acquisition of approximately 22,000 additional net acres. See "—Recent Developments-February 2013 

Utica Acreage Acquisition." 
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Index to Financial Statements 

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 1,025 wells that had been drilled in the field as of December 31, 2012, 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, 2012 included 36 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 2012, we recompleted 61 gross and net wells and drilled 31 gross and net wells at WCBB. Of the 31 new wells drilled at WCBB in 2012, 27 were 

completed as producers and four were non-productive. As of February 15, 2013, we had recompleted 12 wells during 2013. Of the 31 wells drilled in 

2012, 26 were considered deep wells. The 27 productive wells, with total depths ranging from 2,500 to 10,697 feet, have approximately 1,818 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 2013. 

Production Status 

In the fourth quarter of 2012, our production at WCBB was approximately 293,906 net BOE, or an average of 3,195 BOE per day, 98% of which was 

from oil and 2% of which was from natural gas. From January 1, 2013 through January 31, 2013, our average net daily production at WCBB was 

approximately 3,054 BOE, 98% of which was from oil and 2% of which was from natural gas. As there was no production from new wells brought on line 

in January 2013, the decrease in average net daily 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 80.309% average NRI) in certain producing oil and natural gas properties situated in the East 

Hackberry field. As of December 31, 2012, we held beneficial interests in approximately 4,512 acres, including the Erwin Heirs Block, which is located 

on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. We licensed approximately 54 square 

miles of 3-D seismic data covering a portion of the area and have received a processed version of the seismic 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 

8 
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Index to Financial Statements 

through 2012 was over 2,754 MBOE and 330 Bcf of casinghead gas production. A total of 239 wells have been drilled on our portion of the field. As of 

December 31, 2012, 41 wells had daily production, 96 were shut-in and two had been converted to salt water disposal wells. The remaining 100 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 own and operate three production facilities at East 

Hackberry that include two land based tank batteries, a production barge, four natural gas compressors, dehydration units and salt water disposal systems. 

Recent and Future Activity 

During 2012 at East Hackberry, we recompleted 32 gross and net wells and drilled 14 gross and net land wells and nine gross and net wells on water. 

Of the 23 wells drilled during 2012, 19 were completed as producing wells, three were non-productive and one was being drilled at year end. As of 

February15, 2013, we had recompleted two wells during 2013, drilled two wells and were in the process of drilling one additional well in our East 

Hackberry field. We currently intend to drill ten to twelve gross and net wells and recomplete 24 gross and net wells in our East Hackberry field during 

2013. 

Production Status 

In the fourth quarter of 2012, our net production at East Hackberry was approximately 212,975 BOE, or an average of 2,315 BOE per day, 98% of 

which was from oil and 2% of which was from natural gas. From January 1, 2013 through January 31, 2013, our average net daily production at East 

Hackberry was approximately 2,623 BOE, 97% of which was from oil and 3% of which was from natural gas. The increase in production in 2013 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 83.333% NRI) in 1,192 acres within the West 

Hackberry field. Our leases at West Hackberry are located within two miles of one of the United States Department of Energy's Strategic Petroleum 

Reserves. 

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 2012 was 307 MBOE and 140 Bcf of natural gas. There have 

been 37 wells drilled to date on our portion of West Hackberry. Currently, three of such wells are producing, 23 are shut-in and one has been converted to 

a saltwater disposal well. The remaining ten wells have been plugged and abandoned. At December 31, 2012, we were drilling one well at our West 

Hackberry field. 

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. 

9 
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Index to Financial Statements 

Production Status 

In the fourth quarter of 2012, our net production at West Hackberry was approximately 4,711 BOE, or an average of 51 BOE per day. From 

January 1, 2013 through January 31, 2013, our average net daily production at West Hackberry was approximately 29 BOE and was 100% from oil. 

Facilities 

We own and operate a production facility at West Hackberry that includes a land based tank battery and salt water disposal system. 

Utica Shale (Eastern Ohio) 

Location and Land 

As of December 31, 2012, we had acquired leasehold interests in approximately 137,000 gross (106,000 net) acres in the Utica Shale in Eastern Ohio, 

including the approximately 37,000 net acres acquired in December 2012. In February 2013, we acquired approximately 22,000 additional net acres in the 

Utica Shale. See "-Recent Developments-February 2013 Utica Acreage Acquisition." 

Area History 

Based on the estimates published by the Ohio Department of Natural Resources, or ODNR, in 2012, 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 in Ohio alone. During 2012, a number of oil and gas companies made 

significant investments in acquiring Utica Shale acreage in Eastern Ohio. As of February 9, 2013, the ODNR reported that in the Utica Shale in Ohio there

were 65 producing horizontal wells, 236 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 15 horizontal wells

that were being drilled and an additional 272 horizontal wells that had been permitted. 

During 2012, 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 NGLs. Specifically, early wells drilled in the Utica Shale indicated potential for production of significant 

amounts of NGLs, 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. 

The Utica Shale is estimated to be thicker and more geographically extensive than the Marcellus Shale. 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 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. 

10 
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Index to Financial Statements 

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 including 

storage tank batteries, oil/gas/water separation equipment, vapor recovery line heaters and compression. 

Recent and Future Activities 

We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2012, had drilled 14 wells, ten of 

which had been completed. As of February 15, 2013, three of these wells were producing. Of the 11 additional wells, seven are projected to be producing 

by April 1, 2013 and the other four wells are projected to be producing by June 1, 2013. The delays in bringing these additional wells online have 

primarily been associated with MarkWest Energy Partners, L.P.'s challenges in obtaining rights-of-way and acquiring necessary state and federal 

permitting. These rights-of-way and permits have now been obtained. In addition, 12 gross (one net) wells were drilled by another operator on our Utica 

Shale acreage during 2012. In February 2013, we acquired approximately 22,000 additional net acres in the Utica Shale. 

We have three rigs under contract on our Utica Shale acreage. We currently intend to drill 50 gross (44 net) wells on our Utica Shale acreage in 

2013. 

Production Status 

 

Aggregate net production from the Utica Shale during the three months ended December 31, 2012 was approximately 69,667 BOE, or 757 BOE per 

day, 35% of which was from oil and NGLs and 65% of which was from natural gas. During January 2013, our average daily net production from the Utica 

Shale was approximately 792 BOE, 41% of which was from oil and NGLs and 59% of which was from natural gas. The Wagner 1-28H well, our longest 

producing well in the Utica Shale, was assigned gross proved estimated ultimate recovery reserves at December 31, 2012 of 65.8 MBbls of oil and 10.0 

Bcf of unshrunk natural gas by Ryder Scott. Adjusting for shrinkage and the extraction of NGLs, we estimate that this is equivalent to 1.8 MMBOE of 

proved reserves. 

Permian Basin (West Texas) 

Location and Land 

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 in the Wolfcamp formation. Subsequently, we acquired approximately 14,100 additional net acres, which brought our total net 

acreage position in the Permian Basin to approximately 18,200 net acres as of September 30, 2012. From our initial acquisition in the Permian Basin 

through the contribution of our Permian Basin acreage to Diamondback on October 11, 2012, 118 gross (53.7 net) wells were drilled on our leasehold 

acreage in this area, primarily targeting the Wolfberry formation. We were not the operator of our Permian Basin acreage but were actively involved in the 

planning and execution of the drilling plans governed by a joint operating agreement with a subsidiary of Diamondback, which is the operator in this field. 

From January 1, 2012 through the closing of the contribution of our Permian Basin acreage to Diamondback on October 11, 2012, 19 gross (8.3 net) 

wells, including our first horizontal well, were spud on our Permian Basin acreage, all of which were completed as producing wells. One gross (0.3 net) 

existing well was recompleted from January 1, 2012 to October 11, 2012. Aggregate net production from our Permian Basin acreage during the first 

eleven days of October 2012 was approximately 17,100 BOE, or 1,555 BOE per day, of which approximately 60% was oil, 28% was NGLs and 12% was 

natural gas. 

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. 

11 
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Index to Financial Statements 

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

Pegasus 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. 

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. 

Facilities 

There are typical land oil and natural gas processing facilities in the Permian Basin. The facilities located at well locations included storage tank 

batteries, oil/gas/water separation equipment and pumping units. 

Recent and Future Activity 

As discussed above under the heading “- Recent Developments-Contribution ,” on October 11, 2012, we contributed to Diamondback, prior to the 

closing of the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin. At the closing of this contribution, Diamondback issued to

us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was repaid to us at the closing of the 

Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment based on changes in the working 

capital, long-term debt and certain other items of a subsidiary of Diamondback as of the date of this contribution. In January 2013, we received an 

additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. As of October 23, 2012, following the closing of the 

Diamondback IPO and the underwriters' exercise in full of their option to purchase additional shares of common stock of Diamondback, we owned 

approximately 21.4% of Diamondback's outstanding common stock. Following the Contribution, we account for our interest in Diamondback as an equity 

investment. 

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 approximately 

11,788 net acres as of December 31, 2012. In 2012, three gross (one net) wells, including one gross (.04 net) well drilled by another operator, were spud

on our Niobrara Formation acreage, two of which were completed as producers and one of which was non-productive. 

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 potential crude oil resource play in various basins throughout the northern Rocky Mountain region. As with most resource plays, the 

Niobrara Formation has a history of 

12 
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Index to Financial Statements 

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 Formation 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 Formation can be produced on a more widespread basis using today's horizontal 

multi-stage fracture stimulation technology where the Niobrara Formation 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 Formation 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 2012, our net production from our Niobrara Formation acreage was approximately 2,644 BOE, or an average of 29 BOE per 

day, 100% of which was from oil. From January 1, 2013 through January 31, 2013, our average daily net production from our Niobrara Formation acreage 

was approximately 43 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 have completed a 60 square mile 3-D seismic survey over our Craig Dome prospect and have received a processed version of the seismic. We do 

not anticipate drilling any wells in the Niobrara Formation during 2013. 

Bakken Formation 

Location and Land 

The Bakken Formation 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 BOE per day 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, 2012, we held approximately 864 net acres, interests in nine wells and an 

overriding royalty interests in certain existing and future wells. 

Production Status 

In the fourth quarter of 2012, our net production from our Bakken Formation acreage was approximately 7,355 BOE, or an average of 80 BOE per 

day, of which 87% was from oil, 3% was from NGLs and 10% was from natural gas. From January 1, 2013 through January 31, 2013, our average net 

daily production from this acreage was approximately 73 BOE, of which 89% was from oil and 11% 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. 

13 
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Index to Financial Statements 

Recent and Future Activities 

Three gross (.04 net) wells were drilled on our Bakken Formation acreage in 2012. As of February 15, 2013, two gross (.03 net) wells had been 

drilled on our Bakken Formation acreage in 2013. 

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 as of December 31, 2012: 

Our Equity Investments 

Permian Basin . As discussed above under the heading “- Recent Developments-Contribution ,” on October 11, 2012, we contributed to 

Diamondback, prior to the closing of the Diamondback IPO, all of our oil and natural gas interests in the Permian Basin. At the closing of this 

contribution, Diamondback issued to us (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million, which was 

repaid to us at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash adjustment 

based on changes in the working capital, long-term debt and certain other items of a Diamondback subsidiary as of the date of this contribution. In 

January 2013, we received an additional payment from Diamondback of $18.6 million as a result of this post-closing adjustment. As of October 23, 2012, 

following the closing of the Diamondback IPO and the underwriters' exercise in full of their option to purchase additional shares of common stock of 

Diamondback, we owned approximately 21.4% of Diamondback's outstanding common stock. Our investment in Diamondback is accounted for as an 

equity method investment. 

Grizzly Oil Sands . We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in 

Grizzly is owned by Grizzly Oil Sands Inc., an entity owned by certain investment funds managed by Wexford. As of December 31, 2012, Grizzly had 

approximately 800,000 acres under lease in the Athabasca and Peace River oil sands region of Alberta, Canada. Our total net investment in Grizzly was 

approximately $172.8 million as of December 31, 2012. As of that date, Grizzly had drilled an aggregate of 233 core holes and six water supply test wells

on ten separate lease blocks and conducted a number of seismic programs. In March 2010, Grizzly filed an application for the development of an 11,300 

barrel per day oil sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order in Council authorizing the ERCB to 

issue the formal regulatory approval of Grizzly's Algar Lake steam-assisted gravity drainage, or SAGD, project. Construction of the Algar Lake Phase 1 

SAGD project commenced in 2012. During 2012, an 11 kilometer road was constructed to the project site, water and natural gas supply pipelines were 

installed, central plant modules were assembled, transported to the project site and lifted into place, ten production well pairs were drilled and completed 

and well pad modules and flow lines back to the central plant were installed. Grizzly expects first oil production at Algar Lake during the third quarter of 

2013. In the first quarter of 2012, Grizzly completed the acquisition of the May River property comprising approximately 47,000 acres. In the fourth 

quarter of 2012, Grizzly initiated a 28 well core hole drilling program at May River and plans to file an initial 12,000 barrel per day development 

application with the ERCB by the end of 2013. At the Thickwood thermal project, Grizzly's 2012 activities included the completion of a 22 well core hole 

drilling program and the acquisition of 31 kilometers of seismic data. A development application for a 12,000 barrel per day oil sands project at 

Thickwood was filed in the fourth quarter of 2012. Grizzly anticipates approval of this development application in mid-2014 and first oil production by 

mid-2017. Grizzly has also entered into a memorandum of understanding that outlines the rate structure for a ten year agreement with Canadian National 

Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via CN’s rail network. Grizzly expects that this arrangement will provide 

consistent access to Brent-based pricing from Grizzly’s Algar Lake project. Grizzly is also pursuing the design, permitting and construction of rail 

terminals in Northern Alberta and on the Lower Mississippi River, where it plans to develop scalable capacity to accommodate unit trains to ship and 

receive up to 100,000 barrels per day. Grizzly anticipates beginning to transport the company’s bitumen starting in the third quarter of 2013. 

14 

Field State Parish/County 

Acreage Working 

Interest 

Overriding Royalty 

Interests 

Producing 

Wells 

Non-Producing 

Wells 

Deer Island Louisiana Terrebonne 3.125 % —% 1 —

Napoleonville Louisiana Assumption —% 2.5 % 3 —

Crest Texas Ochiltree 2 % —% 1 —

Eagle City South Oklahoma Dewey 1.04 % —% 1 —

Fay South Oklahoma Blaine 0.301 % —% 1 —

Squaw Cheek Oklahoma Blaine 0.694 % —% 1 —
Table of Contents 

Index to Financial Statements 

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, an international oil and gas exploration company. APICO has a reserve base located in Southeast Asia through its ownership of concessions 

covering approximately 243,000 acres which includes the Phu Horm Field. During the year ended December 31, 2012, we received $0.8 million in 

distributions, reducing our total investment in Tatex II to $0.2 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 northeast Thailand. Phu 

Horm's initial gross production was approximately 60 million cubic feet per day. For 2012, net gas production was approximately 93 MMcf per day and 

condensate production was 428 barrels per day. Hess Corporation, or Hess, operates the field with a 35% interest. Other interest owners include APICO 

(35% interest), PTT Exploration and Production Public Company Limited (20% interest) and ExxonMobil (10% interest). Our gross working interest 

(through Tatex II as a member of APICO) in the Phu Horm field is 0.7%. Since our ownership in the Phu Horm field is indirect and Tatex II's investment 

in APICO is accounted for by the cost method, these reserves are not included in our year-end reserve information. 

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 490,000 acres in Southeast Asia. In 2009, Tatex III completed a 3-D seismic survey on this concession. During the 

year ended December 31, 2012, we paid $0.6 million in cash calls, bringing our total investment in Tatex III to $8.7 million. The first well was drilled on 

our concession in 2010 and was temporarily abandoned pending further scientific evaluation. Drilling of the second well concluded in March 2011. The 

second well was drilled to a depth of 15,026 feet and logged approximately 5,000 feet of apparent possible gas saturated column. The well experienced 

gas shows and carried a flare measuring up to 25 feet throughout drilling below the intermediate casing point of 9,695 feet. During testing, the well 

produced at rates as high as 16 MMcf per day of gas for short intervals, but would subsequently fall to a sustained rate of two MMcf per day of 

gas. Pressure buildup information confirmed that this wellbore lacked the permeability to deliver commercial quantities of gas. Despite an apparently 

well-developed porosity system suggesting potential for a large amount of gas in place, testing of the well did not exhibit that there was sufficient 

permeability to produce in commercial quantities. Tatex III intends to continue testing some of the structures identified through its 3-D seismic survey and 

has begun the application process for two more drilling locations. Tatex III currently expects to drill the first of these wells, located to the south of the 

TEW-E well, in 2013. 

Other Investments . In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can 

provide services that are required to support our operations. In the second quarter of 2012, we acquired a 50% equity interest in each of Stingray Pressure 

and Stingray Cementing. Stingray Pressure and Stingray Cementing will provide well completion services. We also acquired a 50% equity interest in 

Blackhawk, which coordinates gathering, compression, processing and marketing activities in connection with the development of our Utica Shale 

acreage. In the fourth quarter of 2012, we also acquired a 50% equity interest in Stingray Logistics, which will provide well services. In March 2012, we

acquired a 50% equity interest in Timber Wolf for $1.0 million. Also in March 2012, we acquired a 22.5% equity interest in Midstream for $7.0 million. 

Midstream owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011, we acquired a 25% equity interest in Bison, which owns and 

operates drilling rigs and related equipment. In April 2012, we purchased an additional 15% equity interest in Bison for approximately $6.2 million, 

bringing our total ownership interest in Bison to 40%. Also in 2011, we acquired a 25% interest in Muskie, which is engaged in the mining of hydraulic 

fracturing grade sand. The remaining equity interests in these entities are owned by affiliates of Wexford. In 2012, we invested approximately $42.8 

million in these entities. In 2013, we expect to invest approximately $10.0 million to $15.0 million in these entities. 

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. In addition, oil and natural gas compete with other forms of energy available to customers, primarily based on price. These 

alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil and natural gas or other forms of energy, as well 

as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand 

for oil and natural gas. 

15 
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Index to Financial Statements 

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 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 $2.00 per barrel for transportation. During the year 

ended December 31, 2012 , we sold approximately 92% and 8% of our oil production to Shell Trading Company, or Shell, and Diamondback O&G LLC 

(a wholly-owned subsidiary of Diamondback formerly known as Windsor Permian LLC), or Diamondback O&G, respectively, 91% of our natural gas 

liquids production to Diamondback O&G and 41% , 18% and 16% of our natural gas production to Noble Americas Gas, Hess and Chevron, respectively. 

During 2011, we sold 93% and 7% of our oil production to Shell and Diamondback O&G, respectively, 100% of our natural gas liquids production to 

Diamondback O&G, and 22%, 27% and 50% of our natural gas production to Diamondback O&G, Chevron and Hilcorp Energy Company, respectively. 

During 2010, we sold 75% and 19% of our oil production to Shell and Diamondback O&G, respectively, and 50%, 32%, and 10% of our natural gas 

production to Diamondback O&G, Chevron and Hilcorp Energy Company, respectively. Shell has agreed to purchase our Utica Shale oil and we have 

agreements in place with various purchasers for our Utica Shale natural gas production. We may not continue to have ready access to suitable markets for 

our future oil and natural gas production and if a major customer decided to stop purchasing oil and natural gas from us, revenue could decline and our 

operating results and financial condition could be harmed. However, based on the current demand for oil and natural gas, and the availability of other 

purchasers, we believe that the loss of any one or all of our major purchasers would not have a material adverse effect on our financial condition and 

results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers. 

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 July 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per 

barrel. For the period from August 2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average 

price of $107.29 per barrel. For the period from January 2013 through December 2013, we have entered into fixed price swaps for 5,000 barrels of oil per 

day at a weighted average price of $100.90 per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. Under the 2012 

contracts, we hedged approximately 46% of our 2012 production. Under the 2013 contracts, we have hedged approximately 23% of our estimated 2013 

production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected 

or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contracts and fixed 

price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and Hedging, “ and related 

pronouncements. 

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. 

16 
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Index to Financial Statements 

We own interests in a number of producing oil and natural gas properties located along the Louisiana Gulf Coast, and in the Utica Shale in Eastern 

Ohio, the Niobrara Formation in Northwestern Colorado and the Bakken Formation in Western North Dakota and Eastern Montana. 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 the 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 non-compliance. 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. Moreover, it is not uncommon for neighboring 

landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, 

hydrocarbons or other waste products into the environment. 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, we cannot assure you that the 

EPA or 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 the current costs of 

managing our wastes, as 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 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 

17 
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Index to Financial Statements 

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, 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. The 

Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including 

jurisdictional wetlands, unless authorized by an appropriately issued permit. Spill prevention, control and countermeasure 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. In addition, on October 20, 2011, the EPA announced a schedule to 

develop pre-treatment standards for wastewater discharges produced by natural gas extraction from underground coalbed and shale formations. The EPA 

stated that it will gather data, consult with stakeholders, including ongoing consultation with industry, and solicit public comment on a proposed rule for 

coalbed methane in 2013 and a proposed rule for shale gas in 2014. 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. The 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. New facilities may be required to obtain permits before work can begin, and existing facilities 

may be required to obtain additional permits and incur capital costs in order to remain in compliance. For example, on April 17, 2012, the EPA approved 

final regulations under the federal Clean Air Act that establish new emission controls for oil and natural gas production and processing operations, which 

regulations are discussed in more detail under the caption “ -Regulation of Hydraulic Fracturing .” 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. 

Climate Change . Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on 

Climate Change, also known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of 

oil, natural gas, and refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not 

participating in the Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of 

greenhouse gases. Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA , that the EPA has the authority to 

regulate carbon dioxide emissions from automobiles as “air pollutants” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an 

Endangerment Finding that determined that emissions of carbon dioxide, methane and other 

18 
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Index to Financial Statements 

GHGs present an endangerment to public health and the environment because, according to the EPA, emissions of such gases contribute to warming of 

the earth's atmosphere and other climatic changes. These findings by the EPA allowed the agency to proceed with the adoption and implementation of 

regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Subsequently, the EPA adopted two sets of 

related rules, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain 

large stationary sources of emissions such as power plants or industrial facilities. The EPA finalized the motor vehicle rule, which purports to limit 

emissions of GHGs from motor vehicles manufactured in model years 2012-2016, in April 2010 and it became effective in January 2011, although it does 

not require immediate reductions in GHG emissions. A recent rulemaking proposal by the EPA and the Department of Transportation's National Highway 

Traffic Safety Administration seeks to expand the motor vehicle rule to include vehicles manufactured in model years 2017-2025. The EPA adopted the 

stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also became effective in January 2011, although it remains subject of 

several pending lawsuits filed by industry groups. The Tailoring Rule establishes new GHG emissions thresholds that determine when stationary sources 

must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the Clean Air Act. The permitting requirements of 

the PSD program apply only to newly constructed or modified major sources. Obtaining a PSD permit requires a source to install best available control 

technology, or BACT, for those regulated pollutants that are emitted in certain quantities. Phase I of the Tailoring Rule, which became effective on 

January 2, 2011, requires projects already triggering PSD permitting that are also increasing GHG emissions by more than 75,000 tons per year to comply 

with BACT rules for their GHG emissions. Phase II of the Tailoring Rule, which became effective on July 1, 2011, requires preconstruction permits using 

BACT for new projects that emit 100,000 tons of GHG emissions per year or existing facilities that make major modifications increasing GHG emissions 

by more than 75,000 tons per year. Phase III of the Tailoring Rule, which is expected to go into effect in 2013, will seek to streamline the permitting 

process and permanently exclude smaller sources from the permitting process. Additionally, in September 2009, the EPA issued a final rule requiring the 

reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural 

gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its existing GHG reporting rule to 

include onshore and offshore oil and natural gas production and onshore processing, transmission, storage and distribution facilities, which may include 

certain of our facilities, beginning in 2012 for emissions occurring in 2011. In addition, the EPA has continued to adopt GHG regulations of other 

industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants. The proposed rule underwent an 

extended public comment process, which concluded on June 25, 2012. The EPA is also under a legal obligation pursuant to a consent decree with certain 

environmental groups to issue new source performance standards for refineries. The EPA has also adopted regulations imposing best available control 

technology requirements on the largest greenhouse gas stationary sources, regulations requiring reporting of greenhouse gas emissions from certain 

facilities, and it is considering additional regulation of greenhouse gases as “air pollutants.” As a result of this continued regulatory focus, future GHG 

regulations of the oil and gas industry remain a possibility. 

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of 

the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas 

emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it 

may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by 

requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire 

and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each 

year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of 

allowances is expected to escalate significantly. 

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. 

Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing 

federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations

addressing greenhouse gas emissions would impact our business. 

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, 

thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in 

seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their 

historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may 

not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards

affecting our operations. 

19 
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Index to Financial Statements 

Regulation of Hydraulic Fracturing 

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight 

formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding 

rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the 

Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic 

fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing 

with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House 

Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices and the EPA has commenced a study of 

the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study

regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet 

before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information 

concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic 

fracturing under the SDWA or otherwise. 

Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal 

permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids 

used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the SDWA. 

On April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas 

production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions 

of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently 

associated with oil and natural gas production and processing activities. The final rule includes a 95% reduction in VOCs emitted by requiring the use of

reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also

establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These 

rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells by 

January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could 

adversely impact our business. 

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing 

practices. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected

between later in 2013 and 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are 

obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy is 

conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing 

completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how 

hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the 

public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy 

Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale 

formations, as well as uncertainties associated with those estimates. 

Some states in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or 

prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, in 

January 2012, the Ohio Department of Natural Resources issued a temporary moratorium on the development of hydraulic fracturing disposal wells in 

northeast Ohio, to study the relationship between these wells and minor earthquakes reported in the area. The Texas Railroad Commission and Louisiana 

Department of Natural Resources recently adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to

the requirements of federal Occupational Safety and Health Act (OSHA) to state regulators and on a public internet website. Effective August 26, 2011, 

Montana adopted hydraulic fracturing disclosure regulations under which well operators must provide information in drilling permit applications on the 

estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon completion of the well, well operators must 

provide the Montana Board of Oil and Gas Conservation with the volume and type of chemicals used, including the additive type, chemical ingredient 

names, and Chemical Abstracts Service, or CAS, number, subject to certain trade secret protections. On April 1, 2012, the North Dakota 

20 
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Index to Financial Statements 

Industrial Commission enacted regulations requiring hydraulic fracturing well operators to disclose the hydraulic fluid composition, including the trade 

name, supplier, ingredients, CAS Number, and the maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. Colorado enacted 

rules requiring similar disclosures on January 30, 2012. Also, on May 4, 2012, the U.S. Department of Interior, or DOI, issued a draft rule that seeks to

require companies operating on federal and Indian lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its

wells meet certain construction standards and (iii) establish site plans to manage flowback water. We plan to use hydraulic fracturing in connection with

the development and production of certain of our oil and natural gas properties and any increased federal, state, local, foreign or international regulation of 

hydraulic fracturing or offshore drilling, including legislation and regulation in the states in which we operate, could reduce the volumes of oil and gas 

that we can economically recover, which could materially and adversely affect our revenues and results of operations. 

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water 

supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement 

actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic 

fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well 

as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used 

in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our 

fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, 

increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and 

potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any 

failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate 

the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. 

Other Regulation of the Oil and Natural Gas Industry 

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas

industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, 

both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual 

members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our 

cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent 

than they affect other companies in the industry with similar types, quantities and locations of production. 

The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil 

and natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various 

other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and state regulations govern the price and terms for access to 

oil and natural gas pipeline transportation. FERC's regulations for interstate oil and natural gas transmission in some circumstances may also affect the

intrastate transportation of oil and natural gas. 

Although oil and natural gas prices are currently unregulated, Congress historically has been active in the area of oil and natural gas regulation. We 

cannot predict whether new legislation to regulate oil and natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or 

the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of condensate and oil and natural gas liquids are 

not currently regulated and are made at market prices. 

Drilling and Production . Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation 

include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in 

which we operate also regulate one or more of the following: 

21 

• the location of wells; 

• the method of drilling and casing wells; 

• the timing of construction or drilling activities, including seasonal wildlife closures; 

• the rates of production or “allowables”; 

• the surface use and restoration of properties upon which wells are drilled; 
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Index to Financial Statements 

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some 

states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some 

instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state 

conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and 

impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from 

our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with 

respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other 

similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts 

of oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit the number of 

locations we can drill. 

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities 

and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have 

regulations for plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds or 

other financial assurances, some state agencies and municipalities do have such requirements. 

Natural Gas Sales and Transportation . Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce 

and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce

by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted 

which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of 

our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of 

natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. 

FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we may use interstate 

natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas 

and release of our natural gas pipeline capacity. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that 

significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide 

nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate 

pipeline company. FERC's initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all 

purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very

heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue 

indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities. 

Under FERC's current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at 

market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission 

services, is regulated by the states onshore and in state waters. Although its policy is still in flux, FERC has in the past reclassified certain jurisdictional 

transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of transporting gas to point-of-sale locations. 

Oil Sales and Transportation . Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. 

Nevertheless, Congress could reenact price controls in the future. 

Our crude oil sales are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also 

subject to rate regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act and intrastate oil pipeline 

transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory 

oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates are equally 

applicable to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any materially different 

way than such regulation will affect the operations of our competitors. 

22 

• the plugging and abandoning of wells; and 

• notice to, and consultation with, surface owners and other third parties. 
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Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, 

common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full 

capacity, access is governed by prorationing provisions set forth in the pipelines' published tariffs. Accordingly, we believe that access to oil pipeline 

transportation services generally will be available to us to the same extent as to our competitors. 

State Regulation . The states in which we operate regulate the drilling for, and the production and gathering of, oil and natural gas, including through 

requirements relating to the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas 

resources. States may also regulate rates of production and may establish maximum daily production allowables from wells based on market demand or 

resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that 

they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and 

to limit the number of wells or locations we can drill. 

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to 

resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 

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 WCBB 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 $12.5 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 

23 
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Index to Financial Statements 

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 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 2012 and 2011 were approximately $85,000 and $220,000, respectively. 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. Additionally, 

we lease approximately 6,500 square feet of office space in other buildings in Oklahoma City. 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 approximately 3,700 square feet in a building in Lafayette that we use as our Louisiana headquarters. We lease 1,400 square feet of office 

space in St. Clairsville, Ohio that serves as our Ohio headquarters. Each of these properties is suitable and adequate for its use. 

Employees 

At December 31, 2012, we had 128 employees. An unrelated Louisiana well servicing company provides all necessary field personnel needed to 

operate the WCBB and the Hackberry fields. During 2012, certain of our employees performed management and administrative services for affiliated 

companies for which we were reimbursed approximately $3.2 million. 

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 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. 

Risks Related to our Business and Industry 

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

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend significantly 

upon the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to 

changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including: 

24 

ITEM 1A. RISK FACTORS 

• worldwide and domestic supplies of oil and natural gas; 

• the level of prices, and expectations about future prices, of oil and natural gas; 

• the cost of exploring for, developing, producing and delivering oil and natural gas; 

• the expected rates of declining current production;
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Index to Financial Statements 

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any 

certainty. For example, during the past five years, the posted price for West Texas intermediate light sweet crude oil, which we refer to herein as West 

Texas Intermediate or WTI, has ranged from a low of $30.28 per barrel, or Bbl, in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry 

Hub spot market price of natural gas has ranged from a low of $1.83 per MMBtu in September 2009 to a high of $13.31 per MMBtu in July 2008. During 

2012, West Texas Intermediate prices ranged from $80.48 to $108.99 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.80 to 

$3.80 per MMBtu. On December 31, 2012, the West Texas Intermediate posted price for crude oil was $91.82 per barrel and the Henry Hub spot market 

price of natural gas was $3.35 per MMBtu. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our 

operations, financial condition and level of expenditures for the development of our oil and natural gas reserves. In addition, lower oil and natural gas

prices may reduce the amount of oil and natural gas that we can produce economically. This may result in our having to make substantial downward 

adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development results deteriorate,

full cost accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties. 

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

condition. 

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the European debt crisis, the 

United States mortgage market and a weak real estate market in the United States have contributed to increased economic uncertainty and diminished 

expectations for the global economy. These factors, combined with volatile prices of oil, natural gas and natural gas liquids, declining business and 

consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. In addition, continued hostilities in the 

Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United 

States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity 

prices. If the economic climate in the United States or abroad deteriorates further, worldwide demand for petroleum products could diminish, which could 

impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue 

operations and ultimately adversely impact our results of operations, liquidity and financial condition. 

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

Our future success depends upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Our 

proved reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration or development activities or

acquire properties containing proved reserves, or both. To increase reserves and production, we undertake development, exploration and other 

replacement activities or use third parties to accomplish these activities. We have made and expect to make in the future substantial capital expenditures in 

our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. Historically, we have financed 

capital expenditures primarily with cash flow from operations, the issuance of equity securities and borrowings under our bank and other credit facilities. 

Our cash flow from operations and access to capital are subject to a number of variables, including: 

25 

• weather conditions, including hurricanes, and other natural disasters that can affect oil and natural gas operations over a wide area; 

• the level of consumer demand; 

• the price and availability of alternative fuels; 

• technical advances affecting energy consumption; 

• risks associated with operating drilling rigs; 

• the availability of pipeline capacity and other transportation facilities; 

• the price and level of foreign imports; 

• domestic and foreign governmental regulations and taxes; 

• the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; 

• speculative trading in crude oil and natural gas derivative contracts; 

• political or economic instability or armed conflict in oil and natural gas producing regions, including the Middle East, Africa, South America and 

Russia; and 

• the overall domestic and global economic environment. 
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Index to Financial Statements 

We may not have sufficient resources to acquire additional reserves or to undertake exploration, development, production or other replacement 

activities, such activities may not result in significant additional reserves and we may not have success drilling productive wells at low finding and 

development costs. Furthermore, although our revenues may increase if prevailing oil and natural gas prices increase significantly, our finding costs for

additional reserves could also increase. 

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

growth. 

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain

from, completing acquisitions. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing 

and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which we do not currently operate, which could 

result in unforeseen operating difficulties and difficulties in coordinating geographically dispersed operations, personnel and facilities. In addition, if we 

enter into new geographic markets, we may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory 

requirements may impose substantial additional obligations on us and our management, cause us to expend additional time and resources in compliance 

activities and increase our exposure to penalties or fines for non-compliance with such additional legal requirements. Completed acquisitions could 

require us to invest further in operational, financial and management information systems and to attract, retain, motivate and effectively manage additional 

employees. The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, 

which, in turn, could negatively impact our earnings and growth. Our financial position and results of operations may fluctuate significantly from period

to period, based on whether or not significant acquisitions are completed in particular periods. 

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

materially and adversely affected. 

Delays related to capital spending programs involving engineering, procurement and construction of facilities (including improvements and repairs to 

our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required 

changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays 

may arise as a result of unpredictable factors, many of which are beyond our control, including: 

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

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

We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.9% interest in Grizzly. The remaining interest in Grizzly is owned by 

Grizzly Oils Sands Inc., an entity owned by certain investment funds managed by Wexford. As of December 31, 2012, Grizzly had approximately 

800,000 acres under lease in the Athabasca and Peace River oil sands regions of Alberta, Canada. Our total net investment in Grizzly was approximately 

$172.8 million as of December 31, 2012. As of that date, Grizzly had drilled an aggregate of 233 core holes and six water supply test wells on ten separate 

lease blocks and conducted a number of seismic programs. In March 2010, Grizzly filed an application for the development of an 11,300 barrel per day oil 

sand project at Algar Lake. In November 2011, the Government of Alberta provided a formal Order in Council authorizing the ERCB to issue the formal 

regulatory approval of Grizzly's Algar Lake steam-assisted gravity drainage, or SAGD, project. Construction of the Algar Lake Phase 1 SAGD project 

commenced in 2012. During 2012, an 11 kilometer 

26 

• our proved reserves; 

• the level of oil and natural gas we are able to produce from existing wells; 

• the prices at which oil and natural gas are sold; and 

• our ability to acquire, locate and produce new reserves. 

• denial of or delay in receiving requisite regulatory approvals and/or permits; 

• unplanned increases in the cost of construction materials or labor; 

• disruptions in transportation of components or construction materials; 

• adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, 

or those of vendors or suppliers; 

• shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

• market-related increases in a project's debt or equity financing costs; and 

• nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors. 
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Index to Financial Statements 

road was constructed to the project site, water and natural gas supply pipelines were installed, central plant modules were assembled, transported to the

project site and lifted into place, ten production well pairs were drilled and completed and well pad modules and flow lines back to the central plant were 

installed. Grizzly expects first oil production at Algar Lake during the third quarter of 2013. In the first quarter of 2012, Grizzly completed the acquisition 

of the May River property comprising approximately 47,000 acres. In the fourth quarter of 2012, Grizzly initiated a 28 well core hole drilling program at

May River and plans to file an initial 12,000 barrel per day development application with the ERCB by the end of 2013. At the Thickwood thermal 

project, Grizzly's 2012 activities included the completion of a 22 well core hole drilling program and the acquisition of 31 kilometers of seismic data. A 

development application for a 12,000 barrel per day oil sands project at Thickwood was filed in the fourth quarter of 2012. Grizzly anticipates approval of 

this development application in mid- 2014 and first oil production by mid-2017. Grizzly has also entered into a memorandum of understanding that 

outlines the rate structure for a ten year agreement with Canadian National Railway Company, or CN, to transport its bitumen to the U.S. Gulf Coast via 

CN's rail network. Grizzly expects that this arrangement will provide consistent access to Brent-based pricing from Grizzly's Algar Lake project. Grizzly

is also pursuing the design, permitting and construction of rail terminals in Northern Alberta and on the Lower Mississippi River, where it plans to 

develop scalable capacity to accommodate unit trains to ship and receive up to 100,000 barrels per day. Grizzly anticipates beginning to transport the 

company's bitumen starting in the third quarter of 2013. These are complex projects and additional financing may be required. There can be no assurance 

that such financing, if required, could be obtained on commercially reasonable terms or at all. 

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

The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials (particularly sand and other 

proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and 

wage rates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, we rely on independent third 

party service providers to provide most of the services necessary to drill new wells. If we are unable to secure a sufficient number of drilling rigs at 

reasonable costs, our financial condition and results of operations could suffer, and we may not be able to drill all of our acreage before our leases expire. 

Shortages of drilling rigs, equipment, raw materials (particularly sand and other proppants), supplies, personnel, trucking services, tubulars, fracking and 

completion services and production equipment could delay or restrict our exploration and development operations, which in turn could impair our 

financial condition and results of operations. 

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

Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services, particularly the loss of 

Mike Liddell, our Chairman of the Board, James D. Palm, our Chief Executive Officer, Michael G. Moore, our Chief Financial Officer, or our two 

geophysicists could disrupt our operations resulting in a loss of revenues . Our executives are not restricted from competing with us if they cease to be 

employed by us, except under certain limited circumstances prohibiting competition while making use of our trade secrets. We are party to an 

employment agreement with each of these executive officers. As a practical matter, however, employment agreements may not assure the retention of our 

employees. Further, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses 

resulting from the death of our key employees. 

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

reserves in the future. 

SEC rules that went into effect for fiscal years ending on or after December 31, 2009 require that, subject to limited exceptions, proved undeveloped 

reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and

may continue to limit our ability to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to 

write down our proved undeveloped reserves if we do not drill those wells within the required five-year timeframe. 

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

There are numerous uncertainties associated with estimating quantities of proved reserves and in projecting future rates of production and timing of 

expenditures. The reserve information herein represents estimates prepared by (i) Netherland, Sewell & Associates, Inc., or NSAI, with respect to our 

WCBB, Hackberry and Niobrara fields at each of December 31, 2012 and 2011 and with respect to our WCBB and Niobrara fields at December 31, 2010, 

(ii) Ryder Scott with respect to our Utica Shale acreage at December 31, 2012 and our Permian Basin acreage at December 31, 2011 and (iii) Pinnacle 

Energy Services, LLC, 

27 
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Index to Financial Statements 

or Pinnacle, with respect to our Permian Basin acreage at December 31, 2010 (which acreage has been contributed to Diamondback as described in Item 

1. “ Business-Recent Developments-Contribution ”) and (iv) our personnel with respect to our overriding royalty and non-operated interests at December 

31, 2012 and 2011 and with respect to our Hackberry fields, overriding royalty and non-operated interests at December 31, 2010. Petroleum engineering is 

not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of economically 

recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as 

historical production from the area compared with production from other producing areas, future site restoration and abandonment costs, the assumed 

effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise 

taxes, capital expenditures and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of 

the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on 

risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times 

may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may

be material. 

Estimates of reserves as of year-end 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of 

hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2012, 2011 and 

2010, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years. Reserve estimates do not include 

any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net 

revenue interest in our properties. 

The present value of future net revenues from our proved reserves is not necessarily the same as the current market value of our estimated oil and 

natural gas reserves. We base the estimated discounted future net revenue from our proved reserves for 2012, 2011 and 2010 on an average price equal to 

the unweighted arithmetic average of prices received on a field-by-field basis on the first day of each month within the 12-month period ended 

December 31, 2012, 2011 and 2010, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years. 

However, actual future net revenues from our oil and natural gas properties also will be affected by factors such as: 

The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties 

will affect the timing of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use 

when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and

risks associated with us or the oil and natural gas industry in general. 

As of December 31, 2012, approximately 40.2% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires 

significant capital expenditures and may require successful drilling operations. The reserve data assumes that we can and will make these expenditures 

and conduct these operations successfully, but these assumptions may not be accurate, and this may not occur. 

There are numerous uncertainties in estimating quantities of bitumen reserves and resources in connection with our equity investment in Grizzly and 

the indicated level of reserves or recovery of bitumen may not be realized. 

There are numerous uncertainties in estimating quantities of bitumen reserves and resources, and the indicated level of reserves or recovery of 

bitumen may not be realized. In general, estimates of economically recoverable bitumen reserves and the future net cash flow from such reserves are 

based upon a number of factors and assumptions made as of the date on which the reserve and resource estimates were determined, such as geological and 

engineering estimates which have uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and 

operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves 

are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, the classification of 

such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers

at different times, may vary substantially. 

28 

• actual prices we receive for oil and natural gas; 

• the amount and timing of actual production; 

• supply of and demand for oil and natural gas; and 

• changes in governmental regulations or taxation. 
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Index to Financial Statements 

Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric calculations and 

upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than 

those based on actual production history. Subsequent evaluation of the same reserves based upon production history may result in variations in the 

estimated reserves. Reserve and resource estimates may require revision based on actual production experience. Reserve and resources estimates are 

determined with reference to assumed oil prices and operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of 

certain grades of bitumen. The actual gravity or quality of bitumen to be produced from Grizzly's lands cannot be determined at this time. 

The marketability of our production is dependent upon compressors, gathering lines, transportation barges and other facilities, certain of which we do 

not control. When these facilities are unavailable, our operations can be interrupted and our revenues reduced. 

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas lines and 

transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be limited or denied. 

A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our 

ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. We are at particular risk with 

respect to oil and natural gas produced at our WCBB field, which is our largest producing field. In October 2006, for example, a natural gas line in this

field operated by our natural gas purchaser was ruptured by a third party contractor, requiring the field to be shut in for approximately seven weeks until 

the line could be repaired. Further, we are dependent on our oil purchaser to provide the barges necessary to transport our oil production from the WCBB 

field. In addition, we currently intend to focus a significant portion of our future exploration and development activity on our Utica Shale acreage. 

Historically, there has been no or only limited infrastructure in this area and the commencement of production from our initial wells on our Utica Shale 

acreage has been delayed due to challenges in obtaining rights-of-way and acquiring necessary state and federal permitting. If we are unable, for any 

sustained period, to implement acceptable delivery or transportation arrangements or encounter compression or other production related difficulties, we 

will be required to shut in or curtail production from the impacted field(s). Any such shut in or curtailment, or an inability to obtain favorable terms for 

delivery of the oil and natural gas produced from our fields, would adversely affect our financial condition and results of operations. 

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

Our largest field by production, WCBB, is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging 

eight to ten feet. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production from this region caused by 

weather conditions such as fog or rain, hurricanes or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in 

amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates we consider reasonable or 

that any particular types of coverage will be available. 

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

occurrence or timing of their drilling. 

We have identified over 700 drilling locations on our Louisiana, Ohio and Western Colorado properties. These drilling locations represent a 

significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of 

capital, oil and natural gas prices, inclement weather, costs, drilling results and regulatory changes. Because of these uncertainties, we do not know if the 

numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other

potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our 

business. 

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and 

adversely affect our business, financial condition or results of operations. 

Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will 

recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but 

also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling,

operating and other costs. The seismic data and 

29 
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Index to Financial Statements 

other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced 

economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in 

those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or 

otherwise negatively impacted as a result of other factors, including: 

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and 

equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. 

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

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk 

of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally 

pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. In addition, our 

operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of 

fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, 

severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, 

regulatory investigations and penalties, suspension of operations and repairs required to resume operations. 

In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our 

business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if 

it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the 

insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on 

our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. In addition, we understand that 

insurance carriers are modifying or otherwise restricting insurance coverage or ceasing to provide certain types of insurance coverage in the Gulf Coast 

region. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to 

restrict our operations, which might severely impact our financial position. We may also be liable for environmental damage caused by previous owners 

of properties purchased by us, which liabilities may not be covered by insurance. A loss not fully covered by insurance could have a material adverse 

effect on our financial position, results of operations and cash flows. 

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

It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest. 

Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate 

governmental office before attempting to acquire a lease in a specific mineral interest. 

Prior to the drilling of an oil or gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well 

to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative 

work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may

delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. 

Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in the assignment of 

leasehold rights in properties in which we hold an interest, we will suffer a financial loss. 

30 

• unusual or unexpected geological formations; 

• loss of drilling fluid circulation; 

• title problems; 

• facility or equipment malfunctions; 

• unexpected operational events; 

• shortages or delivery delays of equipment and services; 

• compliance with environmental and other governmental requirements; and 

• adverse weather conditions. 
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Index to Financial Statements 

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

We acquire significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in 

the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive 

reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and 

increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our 

investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, 

that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved

property or wells. 

Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce 

sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, 

and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of 

unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. In 

addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices for oil 

and natural gas, expected costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. Drilling results in our 

newer oil and liquids-rich shale plays may be more uncertain than in shale plays that are more developed and have longer established production histories, 

and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize 

recoveries will be ultimately successful when used in newly developed shale formations. 

Part of our strategy involves drilling in existing or emerging shale plays using the latest available horizontal drilling and completion techniques; 

therefore, the results of our planned exploratory drilling in these plays are subject to risks associated with drilling and completion techniques and 

drilling results may not meet our expectations for reserves or production. 

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while 

drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally 

through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the 

horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of 

stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion 

of the final fracture stimulation stage. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas 

that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production 

history and consequently we are less able to predict future drilling results in these areas. 

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles 

are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program 

because of capital constraints, lease expirations, access to gathering systems, and/or natural gas and oil prices decline, the return on our investment in 

these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and 

gas properties and the value of our undeveloped acreage could decline in the future. 

We are not the operator of all of our oil and natural gas properties and therefore are not in a position to control the timing of development efforts, the 

associated costs or the rate of production of the reserves on such properties. 

We are not the operator of all of the properties in which we have an interest, and have limited ability to exercise influence over the operations of such

non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to 

influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and 

timing of development and exploitation activities on properties operated by others will depend upon a number of factors that will be largely outside of our 

control, including: 

31 

• the timing and amount of capital expenditures; 
Table of Contents 

Index to Financial Statements 

In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital

expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited. 

Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure 

to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective 

drilling opportunities. 

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for 

such acreage will expire. As of December 31, 2012, leases representing 45%, 17%, 2%, 12% and 24%, respectively, of our total Niobrara Formation 

undeveloped acreage are scheduled to expire in 2013, 2014, 2015, 2016 and thereafter. None of our Utica Shale acreage leases are scheduled to expire 

until 2015, at which time 36% of our total Utica Shale undeveloped acreage as of December 31, 2012 will be subject to expiration, with 64% of such 

acreage expiring thereafter, although our Utica Shale leases generally grant us the right to extend these leases for an additional five-year period. The cost 

to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our 

actual drilling activities may differ materially from our current expectations, which could adversely affect our business. 

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the 

properties that we acquire or obtain protection from sellers against such liabilities. 

Acquiring oil and gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and 

operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the 

assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course 

of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe 

corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of 

the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform 

in accordance with our expectations. 

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

Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in 

response to economic and political conditions. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports 

concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price 

controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of 

oil and gas. In addition, the production, handling, storage, transportation, remediation, emission and disposal of oil and gas, by-products thereof and other 

substances and materials produced or used in connection with oil and natural gas operations are subject to regulation under federal, state and local laws

and regulations primarily relating to protection of human health and the environment. Failure to comply with these laws and regulations may result in the

assessment of sanctions, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and 

injunctions limiting or prohibiting some or all of our operations. Moreover, these laws and regulations have continually imposed increasingly strict 

requirements for water and air pollution control and solid waste management. Significant expenditures may be required to comply with governmental 

laws and regulations applicable to us. We believe the trend of more expansive and stricter environmental legislation and regulations will continue. See 

Item 1. "Business-Regulations-Environmental Matters and Regulation" and Item 1. "Business-Regulation-Other Regulation of The Oil and Natural Gas 

Industry" for a description of the laws and regulations that affect us. 

32 

• the availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel; 

• the operator's expertise and financial resources; 

• approval of other participants in drilling wells; 

• selection of technology; and 

• the rate of production of the reserves. 
Table of Contents 

Index to Financial Statements 

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

restrictions or delays. 

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight 

formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding 

rock and stimulate production. The federal Safe Drinking Water Act, or SDWA, regulates the underground injection of substances through the 

Underground Injection Control, or UIC, program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic 

fracturing process is typically regulated by state oil and gas commissions. The EPA, however, has recently taken the position that hydraulic fracturing 

with fluids containing diesel fuel is subject to regulation under the UIC program, specifically as “Class II” UIC wells. At the same time, the White House 

Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices and the EPA has commenced a study of 

the potential environmental impacts of hydraulic fracturing activities. Moreover, the EPA announced on October 20, 2011 that it is also launching a study

regarding wastewater resulting from hydraulic fracturing activities and currently plans to propose standards by 2014 that such wastewater must meet 

before being transported to a treatment plant. As part of these studies, the EPA has requested that certain companies provide them with information 

concerning the chemicals used in the hydraulic fracturing process. These studies, depending on their results, could spur initiatives to regulate hydraulic 

fracturing under the SDWA or otherwise. 

Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal 

permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids 

used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the SDWA. 

On April 17, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas 

production and natural gas processing operations. Specifically, the EPA's rule package includes New Source Performance Standards to address emissions 

of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently 

associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the 

use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The 

rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production 

equipment. These rules will require a number of modifications to our operations, including the installation of new equipment to control emissions from 

our wells by January 1, 2015. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs,

and could adversely impact our business. 

In addition, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing 

practices. The federal government is currently undertaking several studies of hydraulic fracturing's potential impacts, the results of which are expected

between later in 2013 and 2014. These ongoing or proposed studies, depending on their degree of pursuit and whether any meaningful results are 

obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. The U.S. Department of Energy is 

conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing 

completion methods. Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how 

hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the 

public regarding the economic feasibility of pursuing natural gas deposits in shale formations by means of hydraulic fracturing, and the U.S. Energy 

Information Administration to provide a better understanding of that agency's estimates regarding natural gas reserves, including reserves from shale 

formations, as well as uncertainties associated with those estimates. 

Some states in which we operate or hold oil and natural gas interests have adopted or are considering adopting regulations that could restrict or 

prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, in 

January 2012, the Ohio Department of Natural Resources issued a temporary moratorium on the development of hydraulic fracturing disposal wells in 

northeast Ohio, to study the relationship between these wells and minor earthquakes reported in the area. The Texas Railroad Commission and Louisiana 

Department of Natural Resources recently adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to

the requirements of federal Occupational Safety and Health Act (OSHA) to state regulators and on a public internet website. Effective August 26, 2011, 

Montana adopted hydraulic fracturing disclosure regulations under which well operators must provide information in drilling permit applications on the 

estimated volume and types of materials to be used in the proposed hydraulic fracturing activities. Upon completion of the well, well operators must 

provide the Montana Board of Oil and Gas 

33 
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Index to Financial Statements 

Conservation with the volume and type of chemicals used, including the additive type, chemical ingredient names, and Chemical Abstracts Service, or 

CAS, number, subject to certain trade secret protections. On April 1, 2012, the North Dakota Industrial Commission enacted regulations requiring 

hydraulic fracturing well operators to disclose the hydraulic fluid composition, including the trade name, supplier, ingredients, CAS Number, and the 

maximum ingredient concentrations of all additives in the hydraulic fracturing fluid. Colorado enacted rules requiring similar disclosures on January 30,

2012. Also, on May 4, 2012, the U.S. Department of Interior, or DOI, issued a draft rule that seeks to require companies operating on federal and Indian 

lands to (i) publicly disclose the chemicals used in the hydraulic fracturing process; (ii) confirm its wells meet certain construction standards and (iii) 

establish site plans to manage flowback water. We plan to use hydraulic fracturing in connection with the development and production of certain of our oil 

and natural gas properties and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or offshore drilling, including 

legislation and regulation in the states in which we operate, could reduce the volumes of oil and gas that we can economically recover, which could 

materially and adversely affect our revenues and results of operations. 

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water 

supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement 

actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic 

fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well 

as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used 

in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our 

fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, 

increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and 

potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any 

failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate 

the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing. 

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

our business activities. 

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to 

our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits

or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing 

and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling 

activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; (iv) require remedial action to prevent 

or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, 

pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These 

laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and 

regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the

suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some 

instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. 

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties 

currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination 

resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions 

were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety 

impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant 

liabilities, penalties and other sanctions under applicable laws. In this regard, in November 2012, we and other entities involved in our WCBB field 

operations received a government subpoena, to which we have responded, for the production of documents and other information related primarily to a 

discharge of produced water that allegedly was identified by the U.S. Coast Guard in March 2012. Moreover, public interest in the protection of the 

environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to 

the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent 

laws are enacted or other governmental action is taken that restricts drilling or imposes more 

34 
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Index to Financial Statements 

stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations 

could be materially adversely affected. 

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of 

the areas where we operate. 

Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to 

protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield 

equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting

shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect 

endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously

unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection 

measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and 

produce our reserves 

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the 

effect of commodity price, interest rate and other risks associated with our business. 

The adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to use derivative instruments to reduce the 

effect of commodity price, interest rate and other risks associated with our business. The U.S. Congress adopted the Dodd-Frank Wall Street Reform and 

Consumer Protection Act (HR 4173), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives 

market and entities that participate in that market. The legislation was signed into law by the President on July 21, 2010. In its rulemaking under the 

legislation, the Commodities Futures Trading Commission, or the CFTC, has issued a final rule on position limits for certain futures and option contracts

in the major energy markets and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). The CFTC's 

final rule was set aside by the U.S. District Court for the District of Columbia on September 28, 2012 and remanded to the CFTC to resolve ambiguity as 

to whether statutory requirements for such limits to be determined necessary and appropriate were satisfied. As a result, the rule has not yet taken effect, 

although the CFTC has indicated that it intends to appeal the court's decision and that it believes the Dodd-Frank Act requires it to impose position limits. 

The impact of such regulations upon our business is not yet clear. Certain of our hedging and trading activities and those of our counterparties may be 

subject to the position limits, which may reduce our ability to enter into hedging transactions. 

In addition, the Dodd-Frank Act does not explicitly exempt end users (such as us) from the requirement to use cleared exchanges, rather than 

hedging over-the-counter, and the requirements to post margin in connection with hedging activities. While it is not possible at this time to predict when 

the CFTC will finalize certain other related rules and regulations, the Dodd-Frank Act and related regulations may require us to comply with margin 

requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although whether these requirements

will apply to our business is uncertain at this time. If the regulations ultimately adopted require that we post margin for our hedging activities or require 

our counterparties to hold margin or maintain capital levels, the cost of which could be passed through to us, or impose other requirements that are more

burdensome than current regulations, our hedging would become more expensive and we may decide to alter our hedging strategy. 

The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to 

separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase 

the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the 

terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our 

derivative contracts in existence at that time, and increase our exposure to less creditworthy counterparties. If we reduce or change the way we use 

derivative instruments as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less 

predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the 

volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and 

natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of 

these consequences could have a material adverse effect on our consolidated financial position, results of operations or cash flows. 

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

The U.S. President's Fiscal Year 2013 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These 

changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the 

deduction from income for domestic production activities relating to oil and natural gas exploration and development, (iii) the repeal of the percentage 

depletion allowance for oil and gas properties, (iv) an extension of the amortization period for certain geological and geophysical expenditures and 

(iv) implementing certain international tax reforms. These proposed changes in the U.S. tax laws, if adopted, or other similar changes that reduce or 

eliminate deductions currently available with respect to oil and natural gas exploration and development, could adversely affect our business, financial 

condition, results of operations and cash flows. 

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

produce. 

Many nations have agreed to limit emissions of “greenhouse gases” pursuant to the United Nations Framework Convention on Climate Change, also 

known as the “Kyoto Protocol.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of oil, natural gas, and 

refined petroleum products, are “greenhouse gases,” or GHGs, regulated by the Kyoto Protocol. Although the United States is not participating in the 

Kyoto Protocol at this time, several states or geographic regions have adopted legislation and regulations to reduce emissions of greenhouse gases. 

Additionally, on April 2, 2007, the U.S. Supreme Court ruled, in Massachusetts, et al. v. EPA , that the EPA has the authority to regulate carbon dioxide 

emissions from automobiles as “air pollutant” under the federal Clean Air Act. Thereafter, in December 2009, the EPA issued an Endangerment Finding 

that determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because, 

according to the EPA, emissions of such gases contribute to warming of the earth's atmosphere and other climatic changes. These findings by the EPA 

allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the 

federal Clean Air Act. Subsequently, the EPA adopted two sets of related rules, one of which purports to regulate emissions of GHGs from motor vehicles 

and the other of which regulates emissions of GHGs from certain large stationary sources of emissions such as power plants or industrial facilities. The 

EPA finalized the motor vehicle rule, which purports to limit emissions of GHGs from motor vehicles manufactured in model years 2012-2016, in April 

2010 and it became effective in January 2011, although it does not require immediate reductions in GHG emissions. A recent rulemaking proposal by the 

EPA and the Department of Transportation's National Highway Traffic Safety Administration seeks to expand the motor vehicle rule to include vehicles 

manufactured in model years 2017-2025. The EPA adopted the stationary source rule, also known as the “Tailoring Rule,” in May 2010, and it also 

became effective in January 2011, although it remains subject of several pending lawsuits filed by industry groups. The Tailoring Rule establishes new 

GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration, or PSD, and 

Title V programs of the Clean Air Act. The permitting requirements of the PSD program apply only to newly constructed or modified major sources. 

Obtaining a PSD permit requires a source to install best available control technology, or BACT, for those regulated pollutants that are emitted in certain 

quantities. Phase I of the Tailoring Rule, which became effective on January 2, 2011, requires projects already triggering PSD permitting that are also 

increasing GHG emissions by more than 75,000 tons per year to comply with BACT rules for their GHG emissions. Phase II of the Tailoring Rule, which 

became effective on July 1, 2011, requires preconstruction permits using BACT for new projects that emit 100,000 tons of GHG emissions per year or 

existing facilities that make major modifications increasing GHG emissions by more than 75,000 tons per year. Phase III of the Tailoring Rule, which is 

expected to go into effect in 2013, will seek to streamline the permitting process and permanently exclude smaller sources from the permitting process. 

Additionally, in September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the 

U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In 

November 2010, the EPA expanded its existing GHG reporting rule to include onshore and offshore oil and natural gas production and onshore 

processing, transmission, storage and distribution facilities, which may include certain of our facilities, beginning in 2012 for emissions occurring in 2011. 

In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future 

development of coal-fired power plants. The proposed rule underwent an extended public comment process, which concluded on June 25, 2012. The EPA 

is also under a legal obligation pursuant to a consent decree with certain environmental groups to issue new source performance standards for refineries.

The EPA has also adopted regulations imposing best available control technology requirements on the largest greenhouse gas stationary sources, 

regulations requiring reporting of greenhouse gas emissions from certain facilities, and it is considering additional regulation of greenhouse gases as “air 

pollutants.” As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. 

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In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of greenhouse gases and almost one-half of 

the states have already taken legal measures to reduce emissions of greenhouse gases primarily through the planned development of greenhouse gas 

emission inventories and/or regional greenhouse gas cap and trade programs. Although the U.S. Congress has not adopted such legislation at this time, it 

may do so in the future and many states continue to pursue regulations to reduce greenhouse gas emissions. Most of these cap and trade programs work by 

requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire 

and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each 

year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of 

allowances is expected to escalate significantly. 

Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry. 

Currently, while we are subject to certain federal GHG monitoring and reporting requirements, our operations are not adversely impacted by existing 

federal, state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations

addressing greenhouse gas emissions would impact our business. 

In addition, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, 

thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in 

seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their 

historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may 

not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards

affecting our operations. 

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those 

agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase. 

Section 1(b) of the Natural Gas Act of 1938, or the NGA, exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory 

Commission, or FERC. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a 

pipeline performs a gathering function and therefore is exempt from FERC's jurisdiction under the NGA. However, the distinction between FERCregulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated 

gathering is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future 

determinations by FERC, the courts or Congress, which could cause our revenues to decline and operating expenses to increase and may materially 

adversely affect our business, financial condition or results of operations. In addition, FERC has adopted regulations that may subject certain of our 

otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and 

legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the

future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations. 

We face extensive competition in our industry. 

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies 

not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a 

regional, national or worldwide basis. These competitors may be better positioned to take advantage of industry opportunities and to withstand changes 

affecting the industry, such as fluctuations in oil and natural gas prices and production, the availability of alternative energy sources and the application of 

government regulation. 

We depend upon a limited number of customers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers 

could, among other factors, limit our access to suitable markets for the oil and natural gas we produce. 

The availability of a ready market for any oil and/or natural gas we produce depends on numerous factors beyond the control of our management, 

including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of gas pipelines, the availability of skilled 

labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of gas sold in interstate 

commerce. The oil and natural gas we produce in 

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Index to Financial Statements 

Louisiana is sold to purchasers who service the areas where our wells are located. We sell the majority of our oil to Shell Trading Company, or Shell. 

Shell takes custody of the oil at the outlet from our oil storage barge. Our production from WCBB is being sold in accordance with the Shell posted price

for West Texas/New Mexico Intermediate crude plus or minus Platt's trade month average P+ value, plus or minus the Platt's HLS/WTI differential less 

$2.00 per barrel for transportation. During the year ended December 31, 2012 , we sold approximately 92% and 8% of our oil production to Shell and 

Diamondback O&G, respectively, 91% of our natural gas liquids production to Diamondback O&G, and 41% , 18% and 16% of our natural gas 

production to Noble Americas Gas, Hess and Chevron, respectively. During 2011, we sold 93% and 7% of our oil production to Shell and Diamondback 

O&G, respectively, 100% of our natural gas liquids production to Diamondback O&G and 22%, 27% and 50% of our natural gas production to 

Diamondback O&G, Chevron and Hilcorp Energy Company, respectively. During 2010, we sold 75% and 19% of our oil production to Shell and 

Diamondback O&G, respectively, and 50%, 32%, and 10% of our natural gas production to Diamondback O&G, Chevron and Hilcorp Energy Company, 

respectively. Shell has agreed to purchase our Utica oil, and we have agreements in place with various purchasers for our Utica natural gas production. 

We may not continue to have ready access to suitable markets for our future oil and natural gas production. 

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

We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general 

and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Net capitalized costs 

are limited to the estimated future net revenues, after income taxes, discounted at 10% per year, from proven oil and natural gas reserves and the cost of 

the properties not subject to amortization. Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are 

depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. 

Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The test 

determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of 

deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per 

annum, from proved reserves, based on the 12-month unweighted arithmetic average of the first-day-of-the-month prices for 2012, 2011 and 2010 

adjusted for any contract provisions or financial derivatives, if any, that hedge oil and natural gas revenue, excluding the estimated abandonment costs for 

properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost 

or market value of unproved properties included in the cost being amortized, less income tax effects related to differences between the book and tax basis 

of the oil and natural gas properties. If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or 

noncash writedown is required. A ceiling test impairment can give us a significant loss for a particular period. Once incurred, a write down of oil and 

natural gas properties is not reversible at a later date, even if oil or gas prices increase. If prices of oil, natural gas and natural gas liquids decrease, we may 

be required to further write down the value of our oil and gas properties. Future non-cash asset impairments could negatively affect our results of 

operations. 

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could 

adversely affect the results of our drilling operations. 

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in 

identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those 

structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, 

and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical. 

We have entered into forward sales contracts and fixed price swaps and may in the future enter into additional contracts for a portion of our 

production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil and gas. 

To mitigate the effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production 

per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 through February 

2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per 

day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November 2010, we entered into fixed price 

swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For 

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January 2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel.

For the period from March 2012 through July 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of 

$109.73 per barrel. For the period from August 2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a 

weighted average price of $107.29 per barrel. For the period from January 2013 through December 2013, we have entered into fixed price swaps for 5,000 

barrels of oil per day at a weighted average price of $100.90 per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. 

Under the 2012 contracts, we hedged approximately 46% of our 2012 production. Under the 2013 contracts, we have hedged approximately 23% of our 

estimated 2013 production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is 

less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales 

contracts and fixed price swaps are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and 

Hedging ,” and related pronouncements. 

Our hedging transactions expose us to counterparty credit risk. 

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial

markets could lead to sudden decreases in a counterparty's liquidity, which could make them unable to perform under the terms of the derivative contract 

and we may not be able to realize the benefit of the derivative contract. 

A terrorist attack or armed conflict could harm our business. 

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United 

States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political 

instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our services

and causing a reduction in our revenues. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be

adversely impacted if infrastructure integral to our customers' operations is destroyed or damaged. Costs for insurance and other security may increase as 

a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all. 

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

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances 

in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services 

and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. 

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

We are dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data 

processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network 

infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability 

to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a 

material adverse effect on our business. 

Risks Relating to Our Indebtedness 

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

As of December 31, 2012, we had total indebtedness (net of associated accrued discount and premium) of approximately $299.0 million, including 

$296.9 million attributable to the Notes, and borrowing base availability of $40.0 million under our secured revolving credit facility, under which no 

borrowings are outstanding. 

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

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

In addition, if we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of 

principal, premium, if any, or interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating 

covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the 

event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with 

accrued and unpaid interest. More specifically, the lenders under our secured revolving credit facility could elect to terminate their commitments, cease

making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or litigation. 

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

In connection with the Contribution and the Notes Offerings, our borrowing base under our senior secured revolving credit facility was reduced to 

$40.0 million. The borrowing base is expected to be redetermined by the lenders on a semiannual basis. Additionally, the required lenders will be able to

request one additional borrowing base redetermination in between scheduled redeterminations, and also have the right to redetermine the borrowing base 

upon the amendment, modification or termination of any swap contract or forward sales contract. In addition, our borrowing base will be reduced in 

connection with certain asset dispositions. 

We repaid all borrowings outstanding under our secured revolving credit facility (approximately $146.5 million) with a portion of the proceeds from 

the October Notes Offering. We currently have no borrowings outstanding under our revolving credit facility, although we intend to reborrow under this 

facility in the future. If the outstanding borrowings under our secured revolving credit facility were to exceed the borrowing base as a result of any such 

recalculation, we would be required to eliminate this excess. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds 

to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new 

financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results. 

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

indebtedness. 

Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness depends on our future performance, 

which is subject to economic, financial, competitive and other factors beyond our control. Our business may not continue to generate cash flow from 

operations in the future sufficient to service our debt and make necessary capital expenditures. If we are unable to generate such cash flow, we may be 

required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional

equity capital on terms that 

40 

• our high level of indebtedness could make it more difficult for us to satisfy our obligations with respect to our indebtedness, and any failure to 

comply with the obligations under any of our debt instruments, including restrictive covenants, could result in a default under our secured 

revolving credit facility or the senior note indenture; 

• the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of 

strategic opportunities to grow our business; 

• our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions or 

general corporate purposes may be impaired, which could be exacerbated by further volatility in the credit markets; 

• we must use a substantial portion of our cash flow from operations to pay interest on the Notes and our other indebtedness, which will reduce the 

funds available to us for operations and other purposes; 

• our high level of indebtedness could place us at a competitive disadvantage compared to our competitors that may have proportionately less debt; 

• our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate may be limited; 

• our high level of indebtedness makes us more vulnerable to economic downturns and adverse developments in our business; and 

• we may be vulnerable to interest rate increases, as our borrowings under our secured revolving credit facility are at variable interest rates. 
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may be onerous or highly dilutive. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material

assets or operations to attempt to meet our debt service and other obligations. Our secured revolving credit facility and the senior note indenture restrict 

our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe 

are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will 

depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities 

on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition. 

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

subsidiaries face. 

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, either under our senior secured credit facility or 

otherwise. The terms of our secured revolving credit facility and the indenture governing the Notes restrict our ability to incur additional indebtedness, but 

in each case do not completely prohibit us from doing so. In addition, the indenture governing the Notes allows us to issue additional notes under certain 

circumstances which will also be guaranteed by the guarantors. The indenture governing the Notes allows us to incur certain other additional secured debt

and will allow our subsidiaries that do not guarantee the Notes to incur additional debt. In addition, the indenture governing the Notes does not prevent us 

from incurring other liabilities that do not constitute indebtedness. If new debt or other liabilities are added to our current debt levels, the related risks that 

we and our subsidiaries now face could intensify. 

Restrictive covenants in our secured revolving credit facility, in the senior note indenture and in future debt instruments may restrict our ability to 

pursue our business strategies. 

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

things, to: 

The restrictions contained in these agreements could limit our ability to plan for, or react to, market conditions, meet capital needs, make acquisitions

or otherwise restrict our activities or business plans. 

A breach of any of these restrictive covenants could result in default under the agreement governing our senior secured revolving credit facility. If 

default occurs, the lenders under our senior secured revolving credit facility may elect to declare all borrowings outstanding, together with accrued interest 

and other fees, to be immediately due and payable, which would result in an event of default under the senior note indenture. The lenders will also have 

the right in these circumstances to terminate any commitments they have to provide further borrowings. If we are unable to repay outstanding borrowings 

when due, the lenders under our senior secured revolving credit facility will also have the right to proceed against the collateral granted to them to secure 

the indebtedness. If the indebtedness under our senior secured revolving credit facility and the Notes were to be accelerated, we cannot assure you that our 

assets would be sufficient to repay in full that indebtedness. 

Risks Related to Our Common Stock 

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

Our revenues and operating results may in the future vary significantly from quarter to quarter. If our quarterly results fluctuate, it may cause our 

stock price to be volatile. We believe that a number of factors could cause these fluctuations, including: 

41 

• incur or guarantee additional indebtedness; 

• make certain investments; 

• declare or pay dividends or make distributions on our capital stock; 

• prepay subordinated indebtedness; 

• sell assets including capital stock of restricted subsidiaries; 

• agree to payment restrictions affecting our restricted subsidiaries; 

• consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; 

• enter into transactions with our affiliates; 

• incur liens; 

• engage in business other than the oil and gas business; and 

• designate certain of our subsidiaries as unrestricted subsidiaries. 
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Because of the factors listed above, among others, we believe that our quarterly revenues, expenses and operating results may vary significantly in the 

future and that period-to-period comparisons of our operating results are not necessarily meaningful. You should not rely on the results of one quarter as 

an indication of our future performance. It is also possible that in some future quarters, our operating results will fall below our expectations or the 

expectations of market analysts and investors. If we do not meet these expectations, the price of our common stock may decline significantly. 

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

We have paid no cash dividends on our common stock, and we may not pay cash dividends on our common stock in the future. We intend to retain 

any earnings to fund our operations. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. In 

addition, the terms of our credit agreement prohibit the payment of any dividends to the holders of our common stock. 

A change of control could limit our use of net operating losses. 

As of December 31, 2012, we had a net operating loss, or NOL, carry forward of approximately $4.3 million for federal income tax purposes. 

Transfers of our stock in the future could result in an ownership change. In such a case, our ability to use the NOLs generated through the ownership 

change date could be limited. In general, the amount of NOLs we could use for any tax year after the date of the ownership change would be limited to the

value of our stock (as of the ownership change date) multiplied by the long-term tax-exempt rate. 

Future sales of our common stock may depress our stock price. 

We have registered a substantial number of shares of our common stock under a registration statement filed with the SEC. Sales of these shares of our 

common stock in the public market or the perception that these sales may occur, could cause the market price of our common stock to decline. In addition,

sales by certain of our stockholders of their shares could impair our ability to raise capital through the sale of common or preferred stock. As of 

February 20, 2013, there were 77,339,886 shares of our common stock issued and outstanding, excluding 245,831 shares of unvested restricted stock 

awarded under our Amended and Restated 2005 Stock Incentive Plan and 335,241 shares issuable upon exercise of outstanding options to purchase our 

common stock granted under our Amended and Restated 2005 Stock Incentive Plan. 

We could issue preferred stock which could be entitled to dividend, liquidation and other special rights and preferences not shared by holders of our 

common stock or which could have anti-takeover effects. 

We are authorized to issue up to 5,000,000 shares of preferred stock, par value $0.01 per share. Shares of preferred stock may be issued from time to 

time in one or more series as our board of directors, by resolution or resolutions, may from time to time determine each such series to be distinctively 

designated. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions, 

if any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to 

certain limitations of our certificate of incorporation and the Delaware General Corporation Law, or DGCL, our board of directors may fix or alter, by 

resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and 

qualifications, limitations and restrictions thereof, of each such series preferred stock. The issuance of any such preferred stock could materially adversely 

affect the rights of holders of our common stock and, therefore, could reduce the value of our common stock. 

In addition, specific rights granted to future holders of preferred stock could be used to restrict our ability to merge with, or sell our assets to, a third 

party. The ability of our board of directors to issue preferred stock could discourage, delay or prevent a takeover of us, thereby preserving control of the 

company by the current stockholders. 

42 

• changes in oil and natural gas prices; 

• changes in production levels; 

• changes in governmental regulations and taxes; 

• geopolitical developments; 

• the level of foreign imports of oil and natural gas; and 

• conditions in the oil and natural gas industry and the overall economic environment. 
Table of Contents 

Index to Financial Statements 

The existence of some provisions in our organizational documents could delay or prevent a change in control of our company, even if that change 

would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company 

difficult. 

None. 

Additional information regarding our properties is included in Item 1. "Business" above and in Note 4 of the notes to our consolidated financial 

statements included in this report, which information is incorporated herein by reference. 

Proved Oil and Natural Gas Reserves 

SEC Rule-Making Activity 

In December 2008, the SEC released its final rule for “Modernization of Oil and Gas Reporting.” These rules require disclosure of oil and gas proved 

reserves by significant geographic area, using the arithmetic 12-month average beginning-of-the-month price for the year, as opposed to year-end prices as 

had previously been required unless contractual arrangements designate the price to be used. Other significant amendments included the following: 

We adopted the rules effective December 31, 2009, as required by the SEC. 

Evaluation and Review of Reserves. 

Reserve estimates at December 31, 2012 were prepared by NSAI with respect to our WCBB, Hackberry and Niobrara fields (52% of our proved 

reserves at December 31, 2012), by Ryder Scott with respect to our assets in the Utica Shale in Eastern Ohio (47% of our proved reserves at December 31, 

2012) and by our personnel with respect to our overriding royalty and non-operated interests (less than 1% of our proved reserves at December 31, 2012). 

NSAI and Ryder Scott are independent petroleum engineering firms. Copies of their summary reserve reports are included as Exhibit 99.1 and 99.2, 

respectively, to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved reserve estimates meet the requirements 

with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and 

Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our 

properties and are not employed by us on a contingent basis. 

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI and Ryder Scott, our independent 

reserve engineers, to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our WCBB, Hackberry and

Niobrara fields and our assets in the Utica Shale. Our internal technical team members meet with NSAI and Ryder Scott periodically throughout the year 

to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI and Ryder Scott for our 

properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs. Our proved reserves 

attributable to our other minority interests are prepared internally by our internal staff of petroleum engineers and geoscience professionals. Our chief

reserve engineer is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer with over 30 years of 

reservoir and operations experience and our geophysical staff has 

43 

ITEM 1B. UNRESOLVED STAFF COMMENTS 

ITEM 2. PROPERTIES 

• Disclosure of unproved reserves: probable and possible reserves may be disclosed separately on a voluntary basis. 

• Proved undeveloped reserve guidelines: reserves may be classified as proved undeveloped if there is a high degree of confidence that the 

quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time. 

• Reserves estimation using new technologies: reserves may be estimated through the use of reliable technology in addition to flow tests and 

production history. 

• Reserves personnel and estimation process: additional disclosure is required regarding the qualifications of the chief technical person who 

oversees the reserves estimation process. We are also required to provide a general discussion of our internal controls used to assure the 

objectivity of the reserves estimate. 

• Non-traditional resources: the definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the 

method of extraction. 
Table of Contents 

Index to Financial Statements 

over 60 years combined industry experience. Our technical staff uses historical information for our properties such as ownership interest, oil and gas 

production, well test data, commodity prices and operating and development costs. 

Our proved reserve estimates are prepared in accordance with our internal control procedures. These procedures, which are intended to ensure 

reliability of reserve estimations, include the following: 

The following table sets forth our estimated proved reserves at December 31, 2012 , 2011 and 2010 : 

 

 _____________________ 

PV-10 is a non-GAAP measure because it excludes income tax effects. Management believes that the presentation of the non-GAAP financial 

measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating 

oil and gas companies. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative 

to the standardized measure as defined under GAAP. We have included a reconciliation of PV-10 to the most directly comparable GAAP measurestandardized measure of discounted future net cash flows. The following table reconciles the standardized measure of future net cash flows to the PV10 value: 

44 

• review and verification of historical production data, which data is based on actual production as reported by us; 

• preparation of reserve estimates by our experienced reservoir engineers or under their direct supervision; 

• review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all 

significant reserve changes and all new proved undeveloped reserves additions; 

• direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer; and 

• verification of property ownership by our land department. 

 Year Ended December 31, 

 2012 2011 2010 

 

Oil 

(MBbls) 

Natural 

Gas 

(MMcf) 

Oil 

(MBbls) 

Natural 

Gas 

(MMcf) 

Oil 

(MBbls) 

Natural 

Gas 

(MMcf) 

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

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

Total (1) 8,251 

 33,771  16,745  15,728  19,704  16,158 

 Year Ended December 31, 

 2012 2011 2010 

Total net proved oil and natural gas reserves (MBOE) (1) 13,879 19,367 22,397 

PV-10 value (in millions) (2) $ 436.8 $ 490.5 $ 392.6 

Standardized measure (in millions) (3) $ 348.6 $ 376.7 $ 315.5 

(1) Estimates of reserves as of year-end 2012, 2011 and 2010 were prepared using an average price equal to the unweighted arithmetic average of 

hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2012, 2011 and 

2010, respectively, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2012, 2011 and 2010. Reserve 

estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The 

reserve estimates represent our net revenue interest in our properties. Although we believe these estimates are reasonable, actual future production, 

cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially 

from these estimates. 

(2) Represents present value, discounted at 10% per annum, of estimated future net revenue before income tax of our estimated proven reserves. The 

estimated future net revenues set forth above were determined by using reserve quantities of proved reserves and the periods in which they are 

expected to be developed and produced based on certain prevailing economic conditions. The estimated future production in our reserve reports for 

the years ended December 31, 2012, 2011 and 2010 is priced based on the 12-month unweighted arithmetic average of the first-day-of-the month 

price for the period January through December of the applicable year, using $ 91.32 per barrel and $ 2.76 per MMBtu for 2012, $ 96.19 per barrel and 

$ 4.12 per MMBtu for 2011 and $ 76.16 per barrel and $ 4.38 per MMBtu for 2010, and in each case adjusted by lease for transportation fees and 

regional price differentials. 
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Index to Financial Statements 

 

 

The above table does not include proved reserves net to our interest in Diamondback, Tatex II, Tatex III or Grizzly. For further discussion of our 

interest in Tatex II, Tatex III and Grizzly, see Item 1. “ Business-Our Equity Investments .” 

The foregoing reserves are all located within the continental United States. Reserve engineering is a subjective process of estimating volumes of 

economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality 

of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of 

drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural 

gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables 

and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A. “ 

Risk Factors ” contained elsewhere in this Form 10-K. We have not filed any estimates of total, proved net oil or gas reserves with any federal authority 

or agency other than the SEC since the beginning of our last fiscal year. 

Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves, or PUDs, at 

December 31, 2012, 2011 and 2010 and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and 

Gas Exploration and Production Activities, or Supplemental Information , in Note 18 to our consolidated financial statements included in this report. Also 

contained in the Supplemental Information are our estimates of future net cash flows and discounted future net cash flows from proved reserves. 

Additional information regarding our proved reserves can be found in Item 7. “ Management's Discussion and Analysis of Financial Condition and 

Results of Operations-Results of Operations ” and “- Critical Accounting Policies and Estimates ” included in this report. 

Proved Undeveloped Reserves (PUDs) 

As of December 31, 2012 , our proved undeveloped reserves totaled 3,032 MBOE of oil and 15,289 MMcf of natural gas, for a total of 5,580 MBOE. 

Approximately 61% of our PUDs at year-end 2012 were located in our Utica field, 21% were located in WCBB, 17% were located in our East Hackberry 

field and 1% of our PUDs were located in our Niobrara field. PUDs will be converted from undeveloped to developed as the applicable wells begin 

production. Changes in PUDs that occurred during 2012 were primarily due to: 

Costs incurred relating to the development of PUDs were approximately $18.0 million in 2012. Estimated future development costs relating to the 

development of PUDs are projected to be approximately $82.8 million in 2013, $16.4 million in 2014, $4.3 million in 2015 and $0.4 million in 2016. 

45 

 December 31, 

 2012 2011 2010 

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

Add: Present value of future income tax discounted at 10% 88,206,000 113,791,000 77,117,000 

PV-10 value $ 436,847,000 

 $ 490,472,000  $ 392,604,000 

(3) The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future 

development, abandonment, production, and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the 

same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the 

effect of future income taxes. 

• The loss of approximately 9,574 MBOE attributable to the contribution of our Permian Basin acreage to Diamondback; 

• Additions of 3,376 MBOE attributable to 2012 acquisitions and extensions in our Utica field and additions of 1,275 MBOE attributable to 2012 

extensions in our Louisiana fields; 

• Conversion of approximately 73 MBOE attributable to PUDs into proved developed reserves; 

• Downward revisions of approximately 31 MBOE in PUDs due to changes in commodity prices; 

• Downward revisions to estimates of approximately 215 MBOE; and 

• Exclusion of 34 MBOE attributable to one PUD location that was not scheduled to be drilled within the next five years. 
Table of Contents 

Index to Financial Statements 

All PUD drilling locations are scheduled to be drilled prior to the end of 2016. 

As of December 31, 2012, 40% of our total proved reserves were classified as proved developed non-producing. 

Production, Prices, and Production Costs 

The following table presents our production volumes, average prices received and average production costs during the periods indicated: 

Excluding the effect of fixed price swaps, the average oil price for 2012 would have been $ 106.11 per barrel of oil and $ 98.12 per BOE. The total 

volume hedged for 2012 represented approximately 46% of our total sales volumes for the year. Excluding the effect of fixed price swap contracts, 

the average oil price for 2011 would have been $ 107.13 per barrel of oil and $ 100.68 per BOE. The total volume hedged for 2011 represented 

approximately 31% of our total sales volumes for the year. Excluding the effect of forward sales contracts, the average oil price for 2010 would have 

been $ 78.12 per barrel of oil and $ 73.45 per BOE. The total volume hedged for 2010 represented approximately 45% of our total sales volumes for 

the year. 

The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or 

more of our total proved reserves as of December 31, 2012 : 

 

46 

 2012 2011 2010 

Production Volumes: 

Oil (MBbls) 2,323 2,128 1,777 

Gas (MMcf) 1,108 878 788 

Natural gas liquids (MGal) 2,714 2,468 2,821 

Oil equivalents (MBOE) 2,573 2,333 1,976 

Average Prices: 

Oil (per Bbl) $ 104.46 (1) $ 104.33 (1) $ 68.29 (1) 

Gas (per Mcf) $ 2.91 $ 4.37 $ 4.40 

Natural gas liquids (per Gal) $ 0.98 $ 1.25 $ 1.00 

Oil equivalents (per BOE) $ 96.63 $ 98.13 $ 64.61 

Production Costs: 

Average production costs (per BOE) $ 9.45 $ 8.96 $ 8.92 

Average production taxes (per BOE) $ 11.43 $ 11.29 $ 7.07 

Total production costs and production taxes (per BOE) $ 20.88 

 $ 20.25  $ 15.99  

(1) Includes various derivative contracts at a weighted average price of: 

January – December 2012 $ 108.31 

January – December 2011 $ 86.96 

January – December 2010 $ 57.55 
Table of Contents 

Index to Financial Statements 

Productive Wells and Acreage 

The following table presents our total gross and net productive and non-productive wells, expressed separately for oil and gas, and the total gross and 

net developed and undeveloped acres as of December 31, 2012. 

47 

 Year Ended December 31, 

 2012 2011 2010 

WCBB 

Net Production 

Oil (MBbls) 1,126 1,258 1,176 

Gas (MMcf) 260 237 410 

NGL (Mgal) — — —

Total (MBOE) 1,169 1,298 1,244 

Average Sales Price: 

Oil (per Bbl) $ 105.19 $ 104.49 $ 62.57 

Gas (per Mcf) $ 2.89 $ 4.16 $ 4.44 

NGL (per Gal) $ — $ — $ —

Average Production Cost (per BOE) $ 9.66 $ 8.71 $ 8.90 

 

Utica Shale 

Net Production 

Oil (MBbls) 25 — —

Gas (MMcf) 365 — —

NGL (Mgal) 80 — —

Total (MBOE) 87 — —

Average Sales Price: 

Oil (per Bbl) $ 78.21 $ — $ —

Gas (per Mcf) $ 2.99 $ — $ —

NGL (per Gal) $ 1.56 $ — $ —

Average Production Cost (per BOE) $ 8.30 $ — $ —

 NRI/WI (1) 

Productive 

Oil Wells (2) 

Productive 

Gas Wells 

Non-Productive 

Oil Wells 

Non-Productive 

Gas Wells 

Developed 

Acreage (3) 

Undeveloped 

Acreage 

Field Percentages Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net 

West Cote 

Blanche Bay 

Field (4) 80.108/100 108 108 1 1 163 163 18 18 5,668 5,668 — —

E. Hackberry 

Field (5) 80.309/100 41 41 — — 96 96 — — 3,931 3,931 581 581 

W. Hackberry 

Field 83.333/100 3 3 — — 23 23 — — 1,192 1,192 — —

Utica Shale (6) 40.641/50.0 1 0.5 1 0.5 — — — — 2,441 1,800 134,693 104,122 

Niobrara 

Formation (7) 36.2/41.5 7 3 — — 2 1 — — 2,807 1,404 21,210 10,384 

Bakken 

Formation (8) 2.7/2.9 8 0.2 — — — — — — 1,862 163 3,505 701 

Overrides/Royalty 

Non-operated Various 208 0.4 — — 2 0.06 — — — — — —

Total 376 156.1 2 1.5 286 283.06 18 18 17,901 14,158 159,989 115,788 
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Index to Financial Statements 

(6) Does not give effect to our acquisition of approximately 22,000 additional net acres in February 2013. See "Item 1. Business-Recent DevelopmentsFebruary 2013 Utica Acreage Acquisition." 

Completed and Present Drilling and Recompletion Activities 

The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered 

indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, 

quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they 

produce a reasonable rate of return. 

Title to Oil and Natural Gas Properties 

It is customary in the oil and natural gas industry to make only a cursory review of title to undeveloped oil and natural gas leases at the time they are

acquired and to obtain more extensive title examinations when acquiring producing properties. In future acquisitions, we will conduct title examinations 

on material portions of such properties in a manner generally consistent with industry practice. Certain of our oil and natural gas properties may be subject 

to title defects, encumbrances, easements, servitudes or other restrictions, none of which, in management's opinion, will in the aggregate materially restrict 

our operations. 

The Louisiana Department of Revenue, or LDR, is disputing our severance tax payments to the State of Louisiana from the sale of oil under fixed 

price contracts during the years 2005 through 2007. The LDR maintains that we paid approximately $1.8 million less in severance taxes under fixed price 

terms than the severance taxes we would have had to pay had we paid severance taxes on the oil at the contracted market rates only. We have denied any 

liability to the LDR for underpayment of 

48 

(1) Net Revenue Interest (NRI)/Working Interest (WI). 

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

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

by production. 

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

base of the 13900 Sand, we have a 40.40% non-operated working interest (29.95% NRI). 

(5) NRI shown is for producing wells. 

(7) The leases relating to our Niobrara Formation acreage will expire at the end of their respective primary terms unless the applicable leases are renewed 

or extended, we have commenced the necessary operations required by the terms of the applicable leases or we have obtained actual production from 

acreage subject to the applicable leases, in which event they will remain in effect until the cessation of production. Leases representing 45%, 17%, 

2%, 12% and 24% of our total Niobrara undeveloped acreage are currently scheduled to expire in 2013, 2014, 2015, 2016 and thereafter, respectively. 

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

 2012 2011 2010 

 Gross Net Gross Net Gross Net 

Recompletions: 

Productive 92 92 100 96 87 84 

Dry 1 0.5 — — — —

Total 93 92.5 100 96 87 84 

Development: 

 Productive 70 57 82 57 57 42 

 Dry 8 7 3 3 — —

Total 78 64 85 60 57 42 

Exploratory: 

Productive 19 6 1 1 — —

Dry — — — — — —

Total 19 

 6  1  1  — —

ITEM 3. LEGAL PROCEEDINGS 
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Index to Financial Statements 

severance taxes and have maintained that we were entitled to enter into the fixed price contracts with unrelated third parties and pay severance taxes based 

upon the proceeds received under those contracts. We have maintained our right to contest any final assessment or suit for collection if brought by the 

State. On April 20, 2009, the LDR filed a lawsuit in the 15th Judicial District Court, Lafayette Parish, in Louisiana against our company seeking 

$2,275,729 in severance taxes, plus interest and court costs. We filed a response denying any liability to the LDR for underpayment of severance taxes 

and are defending our company in the lawsuit. The LDR had taken no further action on this lawsuit since filing its petition other than propounding 

discovery requests to which we have responded. Since serving discovery requests on the LDR and received the LDR's responses in 2012, there has been 

no further activity on the case and no trial date has been set. 

In December 2010, the LDR filed two identical lawsuits against us in different venues to recover allegedly underpaid severance taxes on crude oil for 

the period January 1, 2007 through December 31, 2010, together with a claim for attorney's fees. The petitions do not make any specific claim for 

damages or unpaid taxes. As with the first lawsuit filed by the LDR in 2009, we have denied all liability and will vigorously defend the lawsuit. The cases 

are in the very early stages, and we have not yet filed a response to these lawsuits. Recently, the LDR filed motions to stay the lawsuits before we filed 

any responsive pleadings. The LDR has advised us that it intends to pursue settlement discussions with us and other similarly situated defendants in 

separate proceedings, but has taken no action to initiate settlement talks. There has been no activity on either of these lawsuits for two years. 

In November 2006, Cudd Pressure Control, Inc., or Cudd, filed a lawsuit against us, Great White Pressure Control LLC, or Great White, and six 

former Cudd employees in the 129th Judicial District Harris County, Texas. The lawsuit was subsequently removed to the United States District Court for 

the Southern District of Texas (Houston Division). The lawsuit alleged RICO violations and several other causes of action relating to Great White's 

employment of the former Cudd employees and sought unspecified monetary damages and injunctive relief. On stipulation by the parties, the plaintiff's 

RICO claim was dismissed without prejudice by order of the court on February 14, 2007. We filed a motion for summary judgment on October 5, 2007. 

The Court entered a final interlocutory judgment in favor of all defendants, including us, on April 8, 2008. On November 3, 2008, Cudd filed its appeal 

with the U.S. Court of Appeals for the Fifth Circuit. The Fifth Circuit vacated the district court decision finding, among other things, that the district court 

should not have entered summary judgment without first allowing more discovery. The case was remanded to the district court, and Cudd filed a motion 

to remand the case to the original state court, which motion was granted. Cudd subsequently filed amended petitions with the state court (a) alleging, 

among other things, that we conspired with the other defendants to misappropriate, and misappropriated Cudd's trade secrets and caused its employees to 

breach their fiduciary duties, and (b) seeking monetary damages, including $11.8 million as a reasonable royalty for the alleged use of its trade secrets. 

Cudd also sought disgorgement of the alleged benefits received by the various defendants. Cudd also sought its attorney's fees, which Cudd claimed were 

not less than $450,000 plus 10% of any final judgment. This case went to trial on September 5, 2012 and on September 28, 2012 the jury rendered its 

verdict, awarding no damages to the plaintiffs. We along with all defendants filed a Motion for Entry of Judgment that is consistent with the jury's verdict. 

Cudd filed an Application for Disgorgement and a Motion for Judgment Notwithstanding the Verdict. The court denied all of Cudd's post-trial motions on 

October 12, 2012, the court issued its final judgment on January 10, 2013. On that same day, Cudd filed motions for a new trial and to modify, correct or

reform the judgment. Those motions remain pending. 

On July 30, 2010, six individuals and one limited liability company sued 15 oil and gas companies in Cameron Parish Louisiana for contamination 

across the surface of where the defendants operated in an action entitled Reeds et al. v. BP American Production Company et al., 38th Judicial District. 

No. 10-18714. The plaintiffs' original petition for damages, which did not name us as a defendant, alleges that the plaintiffs' property located in Cameron 

Parish, Louisiana within the Hackberry oil field is contaminated as a result of historic oil and gas exploration and production activities. Plaintiffs allege 

that the defendants conducted, directed and participated in various oil and gas exploration and production activities on their property which allegedly have 

contaminated or otherwise caused damage to the property, and have sued the defendants for alleged breaches of oil, gas and mineral leases, as well as for

alleged negligence, trespass, failure to warn, strict liability, punitive damages, lease liability, contract liability, unjust enrichment, restoration damages, 

assessment and response costs and stigma damages. On December 7, 2010, we were served with a copy of the plaintiffs' first supplemental and amending 

petition which added four additional plaintiffs and six additional defendants, including us, bringing the total number of defendants to 21. It also increased 

the total acreage at issue in this litigation from 240 acres to approximately 1,700 acres. In addition to the damages sought in the original petition, the 

plaintiffs now also seek: damages sufficient to cover the cost of conducting a comprehensive environmental assessment of all present and yet unidentified

pollution and contamination of their property; the cost to restore the property to its pre-polluted original condition; damages for mental anguish and 

annoyance, discomfort and inconvenience caused by the nuisance created by defendants; land loss and subsidence damages and the cost of backfilling 

canals and other excavations; damages for loss of use of land and lost profits and income; attorney fees and expenses; and damages for evaluation and 

remediation of any contamination that threatens groundwater. In addition to us, current defendants include ExxonMobil Oil Corporation, Mobil 

Exploration & Producing North America Inc., Chevron U.S.A. Inc., The Superior 

49 
Table of Contents 

Index to Financial Statements 

Oil Company, Union Oil Company of California, BP America Production Company, Tempest Oil Company, Inc., ConocoPhillips Company, Continental 

Oil Company, WM. T. Burton Industries, Inc., Freeport Sulphur Company, Eagle Petroleum Company, U.S. Oil of Louisiana, M&S Oil Company, and 

Empire Land Corporation, Inc. of Delaware. On January 21, 2011, we filed a pleading challenging the legal sufficiency of the petitions on several grounds

and requesting that they either be dismissed or that plaintiffs be required to amend such petitions. In response to the pleadings filed by us and similar

pleadings filed by other defendants, the plaintiffs filed a third amending petition with exhibits which expands the description of the property at issue,

attaches numerous aerial photos and identifies the mineral leases at issue. In response, we and numerous defendants re-urged their pleadings challenging 

the legal sufficiency of the petitions. Some of the defendants' grounds for challenging the plaintiffs' petitions were heard by the court on May 25, 2011 and 

were denied. The court signed the written judgment on December 9, 2011. We noticed our intent to seek supervisory review on December 19, 2011 and 

the trial court fixed a return date of January 11, 2012 for the filing of the writ application. We filed our supervisory writ, which was denied by the 

Louisiana Third Circuit Court of Appeal and the Louisiana Supreme Court. We have been active in serving discovery requests and responding to 

discovery requests from the plaintiffs. A trial date has been set for September 2013. 

Due to the early stages of the LDR and Reed litigation, the outcome is uncertain and management cannot determine the amount of loss, if any, that 

may result. In each case, management has determined the possibility of loss is remote. However, litigation is inherently uncertain. Adverse decisions in 

one or more of the above matters could have a material adverse affect on our financial condition or results of operations and management cannot 

determine the amount of loss, if any, that may result. 

We have been named as a defendant in various other lawsuits related to our business. In each such case, management has determined that the 

possibility of loss is remote. The resolution of these matters is not expected to have a material adverse effect on our financial condition or results of

operations in future periods. 

Not applicable. 

50 

ITEM 4. MINE SAFETY DISCLOSURES 
Table of Contents 

Index to Financial Statements 

PART II 

 

Price Range of Common Stock 

Our common stock is quoted on the NASDAQ Global Select Market under the symbol “GPOR.” The following table sets forth the high and low 

sale prices of our common stock for the periods presented: 

 

On February 22, 2013, the last reported sale price of our common stock on the NASDAQ Global Select Market was $36.91. 

Unregistered Sales of Equity Securities and Use of Proceeds 

None. 

Repurchases of Equity Securities 

None. 

Holders of Record 

At the close of business on February 21, 2013, there were 325 stockholders of record holding 77,339,886 shares of our outstanding common stock. 

There were approximately 26,202 beneficial owners of our common stock as of February 21, 2013. 

Dividend Policy 

We have never paid dividends on our common stock. We currently intend to retain all earnings to fund our operations. Therefore, we do not intend to 

pay any cash dividends on the common stock in the foreseeable future. In addition, the terms of our credit facility prohibit the payment of any dividends to 

the holders of our common stock. 

You should read the following selected consolidated financial data in conjunction with "Item 7. Management's Discussion and Analysis of Financial 

Condition and Results of Operations” and the consolidated financial statements and the related notes appearing elsewhere in this report. The selected 

consolidated statements of operations data for the fiscal years ended December 31, 2012 , December 31, 2011 and December 31, 2010 and the selected 

consolidated balance sheet data at December 31, 2012 and December 31, 2011 are derived from our audited consolidated financial statements appearing 

elsewhere in this report. The selected consolidated statements of operations data for the fiscal years ended December 31, 2009 and 

51 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER 

PURCHASES OF EQUITY SECURITIES 

 

Price Range of 

Common Stock 

 High Low 

2011 

First Quarter $ 36.38 $ 20.00 

Second Quarter 38.09 23.84 

Third Quarter 37.49 22.00 

Fourth Quarter 37.80 18.72 

2012 

First Quarter $ 37.63 $ 27.66 

Second Quarter 29.66 15.79 

Third Quarter 33.11 18.17 

Fourth Quarter 40.73 28.94 

2013 

First Quarter (through February 22, 2013) $ 42.75 $ 35.65 

ITEM 6. SELECTED FINANCIAL DATA 
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Index to Financial Statements 

December 31, 2008 and the selected consolidated balance sheet data at December 31, 2010 , December 31, 2009 and December 31, 2008 are derived 

from our audited consolidated financial statements that are not included in this report. The historical data presented below is not indicative of future 

results. We did not pay any cash dividends on our common stock during any of the periods set forth in the following table. 

52 

 Fiscal Year Ended December 31, 

 2012 2011 2010 2009 2008 

Selected Consolidated Statements of 

Operations Data: 

Revenues $ 248,926,000 $ 229,254,000 $ 127,921,000 $ 85,968,000 $ 141,873,000 

Costs and expenses: 

Lease operating expenses 24,308,000 20,897,000 17,614,000 16,316,000 22,856,000 

Production taxes 29,400,000 26,333,000 13,966,000 9,797,000 15,813,000 

Depreciation, depletion and amortization 90,749,000 62,320,000 38,907,000 29,225,000 42,472,000 

Impairment of oil and natural gas 

properties — — — — 272,722,000 

General and administrative 13,808,000 8,074,000 6,063,000 4,992,000 6,843,000 

Accretion expense 698,000 666,000 617,000 582,000 560,000 

 Gain on sale of assets (7,300,000 ) — — — —

 151,663,000 118,290,000 77,167,000 60,912,000 361,266,000 

Income (Loss) from Operations 97,263,000 110,964,000 50,754,000 25,056,000 (219,393,000 ) 

Other (Income) Expense: 

Interest expense 7,458,000 1,400,000 2,761,000 2,309,000 4,762,000 

Insurance recoveries — — — (1,050,000 ) (769,000 ) 

Settlement of fixed price contracts — — — — (39,000,000 ) 

Interest income (72,000 ) (186,000 ) (387,000 ) (564,000 ) (540,000 ) 

(Income) loss from equity method 

investments (8,322,000 ) 1,418,000 977,000 706,000 656,000 

 (936,000 ) 2,632,000 3,351,000 1,401,000 (34,891,000 ) 

Income (Loss) from Continuing Operations 

before Income Taxes 98,199,000 108,332,000 47,403,000 23,655,000 (184,502,000 ) 

 Income Tax Expense (Benefit) 26,363,000 (90,000 ) 40,000 28,000 —

Income (Loss) from Continuing Operations 71,836,000 108,422,000 47,363,000 23,627,000 (184,502,000 ) 

Discontinued Operations: 

 Loss on disposal of Belize properties, net of 

tax 3,465,000 — — — —

Net Income (Loss) Available to Common 

Stockholders $ 68,371,000 $ 108,422,000 $ 47,363,000 $ 23,627,000 $ (184,502,000 ) 

Net Income (Loss) Per Common Share—

Basic: $ 1.22 $ 2.22 $ 1.08 $ 0.55 $ (4.33 ) 

Net Income (Loss) Per Common Share—

Diluted: $ 1.21  $ 2.20  $ 1.07  $ 0.55  $ (4.33 ) 
Table of Contents 

Index to Financial Statements 

The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes included elsewhere 

in this Annual Report on Form 10-K. This discussion contains forward-looking statements reflecting our current expectations, estimates and assumptions 

concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ 

materially from those contained in these forward-looking statements due to a number of factors, including those discussed in Item 1A. "Risk Factors” and 

the section entitled “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this Annual Report on Form 10-K. 

Overview 

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 the Utica Shale in Eastern Ohio. 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, or Grizzly, a

21.4% equity interest in Diamondback Energy, Inc., or Diamondback, a NASDAQ Global Select Market listed company to which we contributed our 

Permian Basin oil and gas interests in October 2012 immediately prior to Diamondback's initial public offering, or the Diamondback IPO (see "Item 1. 

Business-Recent Developments-Contribution ” above), 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. 

2012 and 2013 Year to Date Highlights 

53 

 At December 31, 

 2012 2011 2010 2009 2008 

Selected Consolidated Balance Sheet Data: 

Total assets $ 1,578,368,000 $ 691,158,000 $ 319,693,000 $ 227,344,000 $ 221,873,000 

Total debt, including current maturity $ 299,038,000 $ 2,283,000 $ 51,917,000 $ 52,428,000 $ 70,731,000 

Total liabilities $ 451,960,000 $ 58,808,000 $ 108,637,000 $ 102,293,000 $ 107,772,000 

Stockholders’ equity $ 1,126,408,000 $ 632,350,000 $ 211,056,000 $ 125,051,000 $ 114,101,000 

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 

• Oil and natural gas revenues increased 9% to $248.6 million for the year ended December 31, 2012 from $229.0 million for the year ended 

December 31, 2011. 

• Production increased 10% to approximately 2,572,618 barrels of oil equivalent, or BOE, for the year ended December 31, 2012 from 

approximately 2,333,208 BOE for the year ended December 31, 2011. 

• During 2012, we drilled 94 gross (71 net) wells, which included 23 gross (8.4 net) wells drilled by our operators in the Permian Basin, the 

Niobrara Formation and the Bakken Formation. In addition, 12 gross (one net) wells were drilled by another operator on our Utica Shale acreage 

during 2012. During 2012 we recompleted 94 gross (93 net) wells. Of our 94 new wells drilled, 69 were completed as producing wells and eight 

were non-productive and, at year end, 13 were waiting on completion and four were drilling. 

• During 2011 and 2012 , we acquired leasehold interests in approximately 137,000 gross (106,000 net) acres in the Utica Shale in Eastern Ohio, 

including the approximately 37,000 net acres acquired in December 2012. In February 2013, we acquired approximately 22,000 additional net 

acres in the Utica Shale. We spud our first well on our Utica Shale acreage in February 2012 and, as of February 15, 2013, had spud 16 wells, of 

which three were producing, seven had been completed, four were waiting on completion and two were being drilled. 

• In October 2012, we contributed to Diamondback, prior to the closing of the Diamondback IPO, all of our oil and natural gas interests in the 

Permian Basin for shares of Diamondback common stock and a promissory note, which was repaid to us at the closing of the Diamondback IPO. 

As of October 23, 2012, following the closing of the Diamondback IPO and the underwriters' exercise in full of their option to purchase 

additional shares of common stock of Diamondback, we owned approximately 21.4% of Diamondback's outstanding common stock. 

• In October and December of 2012, we issued a total of $300.0 million in aggregate principal amount of our 7.750% Senior Notes due 2020, 

resulting in net proceeds to us of approximately $290.3 million, a portion of which we used to repay all outstanding borrowings under our senior 

secured revolving credit facility. We intend to use the remaining net proceeds for general corporate purposes, which may include funding a 

portion of our 2013 capital development plan. 
Table of Contents 

Index to Financial Statements 

Critical Accounting Policies and Estimates 

Our discussion and analysis of our financial condition and results of operations are based upon consolidated financial statements, which have been 

prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP. The preparation of these consolidated 

financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have 

identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require 

the application of significant judgment by our management. We analyze our estimates including those related to oil and natural gas properties, revenue 

recognition, income taxes and commitments and contingencies, and base our estimates on historical experience and various other assumptions that we 

believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the 

following critical accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements: 

Oil and Natural Gas Properties . We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas 

properties, are capitalized. Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each

quarter. The test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of 

unamortized cost net of deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, 

discounted at 10% per annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the period 2012, 

2011 and 2010, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and excluding the 

estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, 

if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for 

differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, 

an impairment or noncash writedown is required. Such capitalized costs, including the estimated future development costs and site remediation costs of 

proved undeveloped properties are depleted by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one 

barrel of oil. No gain or loss is recognized upon the disposal of oil and natural gas properties, unless such dispositions significantly alter the relationship 

between capitalized costs and proven oil and natural gas reserves. Oil and natural gas properties not subject to amortization consist of the cost of 

undeveloped leaseholds and totaled $626.3 million at December 31, 2012 and $138.6 million at December 31, 2011. These costs are reviewed quarterly 

by management for impairment, with the impairment provision included in the cost of oil and natural gas properties subject to amortization. Factors 

considered by management in its impairment assessment include our drilling results and those of other operators, the terms of oil and natural gas leases 

not held by production and available funds for exploration and development. 

Ceiling Test . Companies that use the full cost method of accounting for oil and gas properties are required to perform a ceiling test each quarter. The 

test determines a limit, or ceiling, on the book value of the oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of 

deferred income taxes or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per 

annum, from proved reserves, based on the 12-month unweighted average of the first-day-of-the-month price for the period January - December of the 

applicable year beginning with 2009, adjusted for any contract provisions or financial derivatives, if any, that hedge our oil and natural gas revenue, and 

excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not 

being amortized, if any, and (c) the lower of cost or market value of unproved 

54 

• In December of 2012, we completed an underwritten public offering of an aggregate of 11,750,000 shares of our common stock (including the 

partial exercise of an over-allotment option for 1,650,000 shares granted to the underwriters, which option was exercised to the extent of 750,000 

shares). In January 2013, the underwriters exercised their option to purchase the remaining 900,000 shares of our common stock to cover overallotments. We received net proceeds of approximately $460.7 million through these sales of our common stock. We used approximately $372.0 

million to fund our acquisition of approximately 37,000 net acres in the Utica Shale in Eastern Ohio and we intend to use the remaining net 

proceeds for general corporate purposes, which may include funding a portion of our 2013 capital development plan. 

• In February 2013, we completed an underwritten public offering of an aggregate of 8,912,500 shares of our common stock (including the 

exercise in full of an over-allotment option for 1,162,500 shares granted to the underwriters). We received net proceeds of approximately $325.8 

million from this offering. We used approximately $220.4 million to fund our acquisition of approximately 22,000 net acres in the Utica Shale in 

Eastern Ohio and we intend to use the remaining net proceeds for general corporate purposes, which may include funding a portion of our 2013 

capital development plan. 
Table of Contents 

Index to Financial Statements 

properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas 

properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. Ceiling test 

impairment can give us a significant loss for a particular period; however, future depletion expense would be reduced. A decline in oil and gas prices may 

result in an impairment of oil and gas properties. For instance, as a result of the drop in commodity prices on December 31, 2008 and subsequent 

reduction in our proved reserves, we recognized a ceiling test impairment of $272.7 million for the year ended December 31, 2008. If prices of oil, natural 

gas and natural gas liquids decline, we may be required to further write down the value of our oil and gas properties, which could negatively affect our 

results of operations. No ceiling test impairment was required for the year ended December 31, 2012 . 

Asset Retirement Obligations . We have obligations to remove equipment and restore land at the end of oil and gas production operations. Our 

removal and restoration obligations are primarily associated with plugging and abandoning wells and associated production facilities. 

We account for abandonment and restoration liabilities under FASB ASC 410 which requires us to record a liability equal to the fair value of the 

estimated cost to retire an asset. The asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is 

generally when the asset is placed into service. When the liability is initially recorded, we increase the carrying amount of the related long-lived asset by 

an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life 

of the related long-lived asset. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change because 

of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. 

The fair value of the liability associated with these retirement obligations is determined using significant assumptions, including current estimates of 

the plugging and abandonment or retirement, annual inflations of these costs, the productive life of the asset and our risk adjusted cost to settle such 

obligations discounted using our credit adjustment risk free interest rate. Changes in any of these assumptions can result in significant revisions to the 

estimated asset retirement obligation. Revisions to the asset retirement obligation are recorded with an offsetting change to the carrying amount of the 

related long-lived asset, resulting in prospective changes to depreciation, depletion and amortization expense and accretion of discount. Because of the 

subjectivity of assumptions and the relatively long life of most of our oil and natural gas assets, the costs to ultimately retire these assets may vary 

significantly from previous estimates. 

Oil and Gas Reserve Quantities . Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological 

analysis demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic 

parameters. NSAI, Ryder Scott and to a lesser extent our personnel have prepared reserve reports of our reserve estimates at December 31, 2012 on a 

well-by-well basis for our properties. 

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion 

and impairment are made concurrently with changes to reserve estimates. Our reserve estimates and the projected cash flows derived from these reserve 

estimates have been prepared in accordance with SEC guidelines. The accuracy of our reserve estimates is a function of many factors including the 

following: 

Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. Therefore, reserve 

estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered. 

Income Taxes . We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized 

for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and 

liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the 

future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and 

liabilities is recognized in income during the period the rate change is enacted. Deferred tax assets are recognized in the year in which realization becomes 

determinable. Periodically, management performs a forecast of its taxable income to determine whether it is more likely than not that a valuation 

allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax assets is established, if in management's 

opinion, it is more likely than not that some portion will not be realized. At 

55 

• the quality and quantity of available data; 

• the interpretation of that data; 

• the accuracy of various mandated economic assumptions; and 

• the judgments of the individuals preparing the estimates. 
Table of Contents 

Index to Financial Statements 

December 31, 2012, a valuation allowance of $4.6 million had been provided for state net operating loss and federal tax credit deferred tax assets based on 

the uncertainty these assets may be realized. 

Revenue Recognition . We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and gas properties. 

Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three 

months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. 

Variances between our estimated revenue and actual payment received for all prior months are recorded at the end of the quarter after payment is 

received. Historically, our actual payments have not significantly deviated from our accruals. 

Investments—Equity Method. Investments in entities greater than 20% and less than 50% are accounted for under the equity method. Under the equity 

method, our share of investees’ earnings or loss is recognized in the statement of operations. In accordance with FASB ASC 825 , "Financial 

Instruments," we have elected the fair value option of accounting for our equity method investment in Diamondback's stock. At the end of each reporting 

period, the quoted closing market price of Diamondback's stock is multiplied by the total shares owned by us and the resulting gain or loss is recognized

in (income) loss from equity method investments in the consolidated statements of operations. 

We review our investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, we 

recognize an impairment provision. There was no impairment of equity method investments at December 31, 2012 or 2011 . 

Commitments and Contingencies . Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it 

is probable that a liability has been incurred and the amount can be reasonably estimated. We are involved in certain litigation for which the outcome is

uncertain. Changes in the certainty and the ability to reasonably estimate a loss amount, if any, may result in the recognition and subsequent payment of

legal liabilities. 

Derivative Instruments and Hedging Activities . We seek to reduce our exposure to unfavorable changes in oil prices by utilizing energy swaps and 

collars, or fixed-price contracts. We follow the provisions of FASB ASC 815, “ Derivatives and Hedging ,” as amended. It requires that all derivative 

instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using 

established index prices and other sources. These values are based upon, among other things, futures prices, correlation between index prices and our 

realized prices, time to maturity and credit risk. The values reported in the financial statements change as these estimates are revised to reflect actual 

results, changes in market conditions or other factors. 

The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation is 

established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness 

guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in 

earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged 

item over time. We recognize any change in fair value resulting from ineffectiveness immediately in earnings. 

To mitigate the effects of commodity price fluctuations, we were party to forward sales contracts for the sale of 3,000 barrels of WCBB production 

per day at a weighted average daily price of $54.81 per barrel, before transportation costs and differentials, for the period January 2010 through February 

2010. For the period March 2010 through December 2010, we were party to forward sales contracts for the sale of 2,300 barrels of WCBB production per 

day at a weighted average daily price of $58.24 per barrel before transportation costs and differentials. In November 2010, we entered into fixed price 

swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 

2012 through February 2012, we entered into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the

period from March 2012 through July 2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per 

barrel. For the period from August 2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average 

price of $107.29 per barrel. For the period from January 2013 through December 2013, we have entered into fixed price swaps for 5,000 barrels of oil per 

day at a weighted average price of $100.90 per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. Under the 2012 

contracts, we hedged approximately 46% of our 2012 production. Under the 2013 contracts, we have hedged approximately 23% of our estimated 2013 

production. Such arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected 

or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil. These forward sales contacts and fixed 

price swaps are 

56 
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Index to Financial Statements 

accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815, “ Derivatives and Hedging, “ and related pronouncements. 

RESULTS OF OPERATIONS 

Results of Operations 

The markets for oil and natural gas have historically been, and will continue to be, volatile. Prices for oil and natural gas may fluctuate in response to 

relatively minor changes in supply and demand, market uncertainty and a variety of factors beyond our control. 

The following table presents our production volumes, average prices received and average production costs during the periods indicated: 

_____________________ 

Excluding the net effect of fixed price swaps, the average oil price for 2012 would have been $ 106.11 per barrel of oil and $ 98.12 per BOE. The 

total volume hedged for 2012 represented approximately 46% of our total sales volumes for the year. Excluding the net effect of fixed price swap 

contracts, the average oil price for 2011 would have been $ 107.13 per barrel of oil and $ 100.68 BOE. The total volume hedged for 2011 represented 

approximately 31% of our total sales volumes for the year. Excluding the net effect of forward sales contracts, the average oil price for 2010 would 

have been $ 78.12 per barrel of oil and $ 73.45 per BOE. The total volume hedged for 2010 represented approximately 45% of our total sales volumes 

for the year. 

From 2011 to 2012, our net equivalent oil production increased 10% from 2,333,208 BOE to 2,572,618 BOE due to the results of our 2012 drilling 

and recompletion activities. From 2010 to 2011, our net equivalent oil production also increased 18% from 1,975,576 BOE to 2,333,208 BOE due to the 

results of our 2011 drilling and recompletion activities. We currently estimate that our 2013 production will be between 7,800,000 and 8,100,000 BOE. 

However, such estimate may change based on a change in our expected drilling and recompletion activities or the changing economic climate and 

unforeseen events, such as hurricanes. 

57 

 2012 2011 2010 

Production Volumes: 

Oil (MBbls) 2,323 2,128 1,777 

Gas (MMcf) 1,108 878 788 

Natural gas liquids (MGal) 2,714 2,468 2,821 

Oil equivalents (MBOE) 2,573 2,333 1,976 

Average Prices: 

Oil (per Bbl) $ 104.46 (1) $ 104.33 (1) $ 68.29 (1) 

Gas (per Mcf) $ 2.91 $ 4.37 $ 4.40 

Natural gas liquids (per Gal) $ 0.98 $ 1.25 $ 1.00 

Oil equivalents (per BOE) $ 96.63 $ 98.13 $ 64.61 

Production Costs: 

Average production costs (per BOE) $ 9.45 $ 8.96 $ 8.92 

Average production taxes (per BOE) $ 11.43 $ 11.29 $ 7.07 

Total production costs and production taxes (per BOE) $ 20.88 

 $ 20.25  $ 15.99  

(1) Includes various derivative contracts at a weighted average price of: 

January – December 2012 $ 108.31 

January – December 2011 $ 86.96 

January – December 2010 $ 57.55 
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Index to Financial Statements 

Comparison of the Years Ended December 31, 2012 and December 31, 2011 

We reported net income of $68,371,000 for the year ended December 31, 2012 as compared to net income of $108,422,000 for the year ended 

December 31, 2011. This 37% decrease in period-to-period net income was due primarily to a 2% decrease in realized BOE prices to $96.63 for the year 

ended December 31, 2012, a 16% increase in lease operating expenses, a 71% increase in general and administrative expenses, a 12% increase in 

production taxes, an approximately $6.0 million increase in interest expense, a $3.5 million loss on the disposal of our Belize properties, net of tax, and a 

$24.2 million increase in income taxes from continuing and discontinued operations, partially offset by a 10% increase in net production to 2,572,618 

BOE, a gain on sale of assets of $7.3 million and income from equity method investments of $8.3 million. 

Oil and Gas Revenues . For the year ended December 31, 2012 , we reported oil and natural gas revenues of $248,601,000 as compared to oil and 

natural gas revenues of $228,953,000 during 2011. This $19,648,000, or 9%, increase in revenues was primarily attributable to a 10% increase in net 

production to 2,572,618 BOE from 2,333,208 BOE, partially offset by a 2% decrease in realized BOE prices to $96.63 from $98.13, for the year ended 

December 31, 2012 as compared to the year ended December 31, 2011. 

The following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2012 and December 31, 

2011: 

Lease Operating Expenses . Lease operating expenses, or LOE, not including production taxes increased to $ 24,308,000 for the year ended 

December 31, 2012 from $ 20,897,000 for 2011. This increase was mainly the result of an increase in expenses related to property taxes, chemicals and 

fuel, compressor rentals, contract pumpers, field supervision, equipment repairs and maintenance, salt water disposal and well workovers. 

Production Taxes . Production taxes increased to $ 29,400,000 for the year ended December 31, 2012 from $ 26,333,000 for 2011. This increase was 

primarily related to a 10% increase in production partially offset by a 2% decrease in the average realized BOE price received, resulting in a 9% increase 

in oil and gas revenues. 

Depreciation, Depletion and Amortization . Depreciation, depletion and amortization, or DD&A, expense increased to $ 90,749,000 for the year 

ended December 31, 2012 , and consisted of $90,230,000 in depletion of oil and natural gas properties and $519,000 in depreciation of other property and 

equipment, as compared to total DD&A expense of $ 62,320,000 for 2011. This increase was due to an increase in our full cost pool as a result of our 

capital activities, an increase in our production and a decrease in our total proved reserves volume used to calculate our total DD&A expense. 

General and Administrative Expenses . Net general and administrative expenses increased to $ 13,808,000 for the year ended December 31, 2012 

from $ 8,074,000 for 2011. This $5,734,000 increase was due to an increase in salaries, stock compensation expenses and benefits resulting from an 

increased number of employees, increases in legal expenses, franchise taxes and fees for auditing and tax services, partially offset by an increase in 

administrative services reimbursements under the acquisition team agreement and an increase in general and administrative costs related to exploration 

and development activity capitalized to the full cost pool. 

58 

 

Year Ended 

December 31, 

 2012 2011 

Oil production volumes (MBbls) 2,323 2,128 

Gas production volumes (MMcf) 1,108 878 

Natural gas liquids production volumes (MGal) 2,714 2,468 

Oil equivalents (MBOE) 2,573 2,333 

Average oil price (per Bbl) $ 104.46 $ 104.33 

Average gas price (per Mcf) $ 2.91 $ 4.37 

Average natural gas liquids (per Gal) $ 0.98 $ 1.25 

Oil equivalents (per BOE) $ 96.63 $ 98.13 
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Index to Financial Statements 

Accretion Expense . Accretion expense increased to $ 698,000 for the year ended December 31, 2012 from $ 666,000 for the same period in 2011. 

Interest Expense . Interest expense increased to $ 7,458,000 for the year ended December 31, 2012 from $ 1,400,000 for 2011 due to higher 

outstanding debt balances and higher weighted average interest rates. During 2011, total weighted debt outstanding under our revolving credit facility was 

approximately $21,084,000 and bore a weighted average interest rate of 3.32%. During 2012, total weighted average debt outstanding under our revolving 

credit facility was approximately $45.0 million and bore a weighted average interest rate of 2.85%. On October 17, 2012, we issued $250.0 million 

aggregate principal amount of our 7.75% Senior Notes due 2020, a portion of the proceeds from which was used to repay all outstanding borrowings 

under our revolving credit facility. On December 21, 2012, we issued an additional $50.0 million aggregate principal amount of our 7.75% Senior Notes 

due 2020. In addition, we wrote off approximately $1,143,000 of unamortized loan fees associated with our revolving credit facility in conjunction with 

the lowering of our borrowing base during the year ended December 31, 2012. 

Income Taxes . As of December 31, 2012 , we had a net operating loss carry forward of approximately $4.3 million, in addition to numerous 

temporary differences, which gave rise to a net deferred tax liability. Periodically, management performs a forecast of our taxable income to determine 

whether it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our 

deferred tax assets is established if, in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2012, a 

valuation allowance of $4.6 million had been provided for state net operating loss and federal tax credit deferred tax assets based on the uncertainty these 

assets may be realized. We recognized an income tax expense from continuing and discontinued operations of $24.1 million for the year ended 

December 31, 2012. 

Comparison of the Years Ended December 31, 2011 and December 31, 2010 

We reported net income of $108,422,000 for the year ended December 31, 2011 as compared to net income of $47,363,000 for the year ended 

December 31, 2010. This 129% increase in period-to-period net income was due primarily to an 18% increase in net production to 2,333,208 BOE and a 

52% increase in realized BOE prices to $98.13 for the year ended December 31, 2011, partially offset by a 19% increase in lease operating expenses, a 

33% increase in general and administrative expenses and an 89% increase in production taxes. 

Oil and Gas Revenues . For the year ended December 31, 2011, we reported oil and natural gas revenues of $228,953,000 as compared to oil and 

natural gas revenues of $127,636,000 during 2010. This $101,317,000, or 79%, increase in revenues was primarily attributable to an 18% increase in net 

production to 2,333,208 BOE from 1,975,576 BOE and a 52% increase in realized BOE prices to $98.13 from $64.61, in each case for the year ended 

December 31, 2011 as compared to the year ended December 31, 2010. 

The following table summarizes our oil and natural gas production and related pricing for the years ended December 31, 2011 and December 31, 

2010: 

Lease Operating Expenses . Lease operating expenses, or LOE, not including production taxes increased to $20,897,000 for the year ended 

December 31, 2011 from $17,614,000 for 2010. This increase was mainly the result of an increase in expenses 

59 

 

Year Ended 

December 31, 

 2011 2010 

Oil production volumes (MBbls) 2,128 1,777 

Gas production volumes (MMcf) 878 788 

Natural gas liquids production volumes (MGal) 2,468 2,821 

Oil equivalents (MBOE) 2,333 1,976 

Average oil price (per Bbl) $ 104.33 $ 68.29 

Average gas price (per Mcf) $ 4.37 $ 4.40 

Average natural gas liquids (per Gal) $ 1.25 $ 1.00 

Oil equivalents (per BOE) $ 98.13 $ 64.61 
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Index to Financial Statements 

related to chemicals and fuel, equipment repairs and maintenance, field supervision, overhead, property taxes, rentals, salt water disposal and well 

workovers. 

Production Taxes . Production taxes increased to $26,333,000 for the year ended December 31, 2011 from $13,966,000 for 2010. This increase was 

primarily related to an 18% increase in production and a 52% increase in the average realized BOE price received resulting in a 79% increase in oil and 

gas revenues. 

Depreciation, Depletion and Amortization . Depreciation, depletion and amortization, or DD&A, expense increased to $62,320,000 for the year ended 

December 31, 2011, and consisted of $61,965,000 in depletion of oil and natural gas properties and $355,000 in depreciation of other property and 

equipment, as compared to total DD&A expense of $38,907,000 for 2010. This increase was due to an increase in our full cost pool as a result of our 

capital activities, an increase in our production and a decrease in our total proved reserves volume, primarily resulting from the contribution to 

Diamondback of our Permian Basin oil and natural gas interests, used to calculate our total DD&A expense. 

General and Administrative Expenses . Net general and administrative expenses increased to $8,074,000 for the year ended December 31, 2011 from 

$6,063,000 for 2010. This $2,011,000 increase was due to an increase in salaries, stock compensation expenses and benefits resulting from an increased 

number of employees, increases in legal expenses, franchise taxes and bank fees, partially offset by an increase in administrative services reimbursements 

under the acquisition team agreement and an increase in general and administrative costs related to exploration and development activity capitalized to the 

full cost pool. 

Accretion Expense . Accretion expense increased slightly to $666,000 for the year ended December 31, 2011 from $617,000 for the same period in 

2010. 

Interest Expense . Interest expense decreased to $1,400,000 for the year ended December 31, 2011 from $2,761,000 for 2010 due to a decrease in the 

interest rate paid and the repayment of all of our outstanding debt under our revolving credit facility during the fourth quarter of 2011 so that no amounts 

were outstanding as of December 31, 2011, as compared to $49,500,000 outstanding as of the same date in 2010. Further, during 2010, in conjunction 

with the repayment of our prior revolving credit facility on September 30, 2010, we expensed approximately $225,000 in unamortized loan fees associated 

with this facility, which is included in interest expense in our consolidated statements of operations for the year ended December 31, 2010. Total weighted 

debt outstanding under our revolving credit facility was $21,084,000 for the year ended December 31, 2011 and $46,931,000 for 2010. As of 

December 14, 2011 (the latest date during the year ended December 31, 2011 on which we had borrowings outstanding), amounts borrowed under our 

credit facility bore interest at the Eurodollar rate of 2.26%. 

Income Taxes . As of December 31, 2011, we had a net operating loss carry forward of approximately $116.8 million, in addition to numerous 

temporary differences, which gave rise to a deferred tax asset. Periodically, management performs a forecast of our taxable income to determine whether 

it is more likely than not that a valuation allowance is needed, looking at both positive and negative factors. A valuation allowance for our deferred tax 

assets is established if, in management's opinion, it is more likely than not that some portion will not be realized. At December 31, 2011, a valuation 

allowance of $12,347,000 had been provided for deferred tax assets, with the exception of $1,000,000 related to alternative minimum taxes. We 

recognized an income tax benefit of $90,000 for the year ended December 31, 2011. 

Liquidity and Capital Resources 

Overview . Historically, our primary sources of funds have been cash flow from our producing oil and natural gas properties, borrowings under our 

credit facilities and the proceeds from issuances of equity securities. Our ability to access any of these sources of funds can be significantly impacted by 

decreases in oil and natural gas prices or our oil and natural gas production. During 2012, we received net proceeds (before offering expenses) of 

approximately $427.9 million from the sale of shares of our common stock and net proceeds of approximately $290.3 million from the Notes Offerings. 

We received an additional $32.8 million of net proceeds (before offering expenses) in January 2013 following the exercise by the underwriters of their 

option to purchase an additional 900,000 shares of our common stock to cover over-allotments and an additional $325.8 million of net proceeds (before 

offering expenses) in February 2013 from the February 2013 Equity Offering. During 2011, we received aggregate net proceeds (before offering 

expenses) of approximately $307.1 million from the sale of shares of our common stock. 

Net cash flow provided by operating activities was $199,158,000 for the year ended December 31, 2012 , as compared to net cash flow provided by 

operating activities of $158,138,000 for 2011. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers 

due to a 10% increase in our net BOE production, partially offset by a 2% decrease in net realized BOE prices. 

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Net cash flow provided by operating activities was $158,138,000 for the year ended December 31, 2011 as compared to net cash flow provided by 

operating activities of $85,835,000 for 2010. This increase was primarily the result of an increase in cash receipts from our oil and natural gas purchasers 

due to a 52% increase in net realized BOE prices and an 18% increase in our net BOE production. 

Net cash used in investing activities for the year ended December 31, 2012 was $840,579,000 as compared to $323,248,000 for 2011. During the year 

ended December 31, 2012 , we spent $757,192,000 in additions to oil and natural gas properties, of which $175,401,000 was spent on our 2012 drilling 

and recompletion programs, $38,838,000 was spent on expenses attributable to the wells drilled and recompleted during 2011, $13,309,000 was spent on 

compressors and other facility enhancements, $1,699,000 was spent on plugging costs, $509,806,000 was spent on lease related costs, primarily the 

acquisition of leases in the Utica Shale, and $4,990,000 was spent on tubulars, with the remainder attributable mainly to capitalized general and 

administrative expenses. In addition, during the year ended December 31, 2012 , $ 103,915,000 was invested in Grizzly and an aggregate of $43,392,000 

was invested in our other equity investments. During the year ended December 31, 2012 , we used cash from operations and proceeds from the Notes 

Offerings and the December 2012 Equity Offering for our investing activities. 

Net cash used in investing activities for the year ended December 31, 2011 was $323,248,000 as compared to $105,315,000 for 2010. During the year 

ended December 31, 2011, we spent $287,292,000 in additions to oil and natural gas properties, of which $106,947,000 was spent on our 2011 drilling 

and recompletion programs, $31,872,000 was spent on expenses attributable to the wells drilled and recompleted during 2010, $8,320,000 was spent on 

compressors and other facility enhancements, $177,000 was spent on plugging costs, $124,713,000 was spent on lease related costs, primarily the 

acquisition of leases in the Utica Shale and $3,651,000 was spent on tubulars, with the remainder attributable mainly to capitalized general and 

administrative expenses. In addition, $3,182,000 was loaned to, and $22,676,000 was invested in, Grizzly during the year ended December 31, 2011, and 

$3,794,000, $6,009,000 and $2,142,000 was invested in our investments in Tatex III, Bison and Muskie, respectively, during the year ended December 31, 

2011. During the year ended December 31, 2011, we used cash from operations and proceeds from our equity offering for our investing activities. 

Net cash provided by financing activities for the year ended December 31, 2012 was $714,612,000 as compared to $256,539,000 for 2011. The 2012 

amount provided by financing activities was primarily attributable to the net proceeds of $426,907,000 from the December 2012 Equity Offering (not 

including the $32,776,000 received in January 2013 following the exercise by the underwriters of the December 2012 Equity Offering of their option to 

purchase an additional 900,000 shares of our common stock to cover over-allotments), $296,835,000 from our offerings of 7.750% Senior Notes due 2020 

and $184,000 from the exercise of stock options. 

Net cash provided by financing activities for the year ended December 31, 2011 was $256,539,000 as compared to $20,224,000 for 2010. The 2011 

amount provided by financing activities was primarily attributable to the net proceeds of $307,154,000 from our equity offerings and exercise of stock 

options, partially offset by net principal payments of $49,500,000 on borrowings under our credit facility. The 2010 amount provided by financing 

activities was primarily attributable to the net proceeds from our equity offerings of $21,358,000. 

Credit Facility . On September 30, 2010, we entered into a senior secured revolving credit facility with The Bank of Nova Scotia, as administrative 

agent and letter of credit issuer and lead arranger, and Amegy Bank National Association, or Amegy Bank. The revolving credit facility initially matured 

on September 30, 2013, had a maximum commitment amount of $100.0 million and had a borrowing base availability of $50.0 million, which was 

increased to $65.0 million effective December 24, 2010. On May 3, 2011, we entered into a first amendment to the revolving credit facility with The Bank 

of Nova Scotia, Amegy Bank, KeyBank National Association, or KeyBank, and Société Générale. Under the terms of the first amendment, KeyBank and 

Société Générale were added as additional lenders, the maximum amount of the revolving credit facility was increased to $350.0 million, the borrowing 

base was increased to $90.0 million, certain fees and rates payable by us under the credit facility were decreased, and the maturity date was extended until 

May 3, 2015. On October 31, 2011, we entered into additional amendments to our revolving credit facility pursuant to which, among other things, the 

borrowing base under the facility was increased to $125.0 million. On December 14, 2011, we repaid all outstanding borrowings under the credit facility 

with a portion of the net proceeds of our equity offering completed on December 5, 2011 pending the application of such proceeds to fund certain Utica 

Shale lease acquisitions and for general corporate purposes. On May 2, 2012, we entered into an amendment to the revolving credit facility under which, 

among other things, the borrowing base was increased to $155.0 million. In addition, Credit Suisse, Deutsche Bank Trust Company Americas and 

IBERIABANK were added as additional lenders and Société Générale left the bank group. As of December 31, 2012, there were no borrowings 

outstanding under our revolving credit facility. This facility is secured by substantially all of our assets. Our wholly-owned subsidiaries guarantee our

obligations under our revolving credit facility. 

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On October 9, 2012, we entered into an amendment to our revolving credit facility that modified certain covenants to permit the October Notes 

Offering. The October Notes Offering closed on October 17, 2012 and we repaid all indebtedness outstanding under our revolving credit facility on that 

date with a portion of the proceeds from the October Notes Offering. Effective as of October 17, 2012, we amended our revolving credit facility to lower 

the applicable rates (i) from a range of 1.00% to 1.75% to a range of 0.75% to 1.50% for the base rate loans and (ii) from a range of 2.00% to 2.75% to a

range of 1.75% to 2.50% for the Eurodollar rate loans and letters of credit. This amendment also lowered the commitment fees for Level 1 and Level 2 

usage levels, in each case, from 0.50% per annum to 0.375% per annum. Also, effective as of October 17, 2012, in connection with the completion of the 

October Notes Offering and the Contribution, our borrowing base under the credit facility was reduced to $45.0 million until the next borrowing base 

redetermination. Effective as of December 18, 2012, we entered into another amendment to our revolving credit facility that modified certain covenants to

permit the December Notes Offering and reduce the borrowing base under our revolving credit facility to $40.0 million until the next borrowing base 

redetermination. 

Advances under our revolving credit facility, as amended, may be in the form of either base rate loans or Eurodollar loans. The interest rate for base 

rate loans is equal to (1) the applicable rate, which ranges from .75% to 1.50%, plus (2) the highest of: (a) the federal funds rate plus 0.5%, (b) the rate of 

interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” and (c) the Eurodollar rate for an interest period of one 

month plus 1.00%. The interest rate for Eurodollar loans is equal to (1) the applicable rate, which ranges from 1.75% to 2.50%, plus (2) the London 

interbank offered rate that appears on Reuters Screen LIBOR01 Page for deposits in U.S. dollars, or, if such rate is not available, the offered rate on such 

other page or service that displays the average British Bankers Association Interest Settlement Rate for deposits in U.S. dollars, or, if such rate is not 

available, the average quotations for three major New York money center banks of whom the agent shall inquire as the “London Interbank Offered Rate” 

for deposits in U.S. dollars. We have had no outstanding borrowings under our revolving credit facility since October 17, 2012, on which date the 

outstanding borrowings, prior to repayment, bore interest at the Eurodollar rate (2.97%) per annum. 

Our revolving credit facility contains customary negative covenants including, but not limited to, restrictions on our and our subsidiaries' ability to: 

incur indebtedness; grant liens; pay dividends and make other restricted payments; make investments; make fundamental changes; enter into swap 

contracts and forward sales contracts; dispose of assets; change the nature of their business; and enter into transactions with their affiliates. The negative 

covenants are subject to certain exceptions as specified in our revolving credit facility. Our revolving credit facility also contains certain affirmative 

covenants, including, but not limited to the following financial covenants: (1) the ratio of funded debt to EBITDAX (net income, excluding any non-cash 

revenue or expense associated with swap contracts resulting from ASC 815, plus without duplication and to the extent deducted from revenues in 

determining net income, the sum of (a) the aggregate amount of consolidated interest expense for such period, (b) the aggregate amount of income, 

franchise, capital or similar tax expense (other than ad valorem taxes) for such period, (c) all amounts attributable to depletion, depreciation, amortization 

and asset or goodwill impairment or writedown for such period, (d) all other non-cash charges, (e) non-cash losses from minority investments, (f) actual 

cash distributions received from minority investments, (g) to the extent actually reimbursed by insurance, expenses with respect to liability on casualty

events or business interruption, and (h) all reasonable transaction expenses related to dispositions and acquisitions of assets, investments and debt and

equity offerings, and less non-cash income attributable to equity income from minority investments) for a twelve-month period may not be greater than 

2.00 to 1.00; and (2) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00. We were in compliance with 

these financial covenants at December 31, 2012. 

Senior Notes . On October 17, 2012, we issued $250.0 million in aggregate principal amount of our 7.750% Senior Notes due 2020, or the October 

Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S 

under the Securities Act under an indenture among us, our subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee. 

On December 21, 2012, we issued an additional $50.0 million in aggregate principal amount of our 7.750% Senior Notes due 2020, or the December 

Notes, to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S 

under the Securities Act. The December Notes were issued as additional securities under the existing senior note indenture. The December Notes and the 

October Notes are treated as a single class of debt securities under the senior note indenture. We used a portion of the net proceeds from the October 

Notes Offering to repay all amounts outstanding at such time under our revolving credit facility. We intend to use the remaining net proceeds of October 

Notes Offering and the net proceeds of the December Notes Offering for general corporate purposes, which may include funding a portion of our 2013 

capital development plan. 

Under the senior note indenture, interest on the Notes accrues at a rate of 7.750% per annum on the outstanding principal amount from October 17, 

2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. 

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The Notes are senior unsecured obligations and rank equally in the right of payment with all of our other senior indebtedness and senior in right of 

payment to any of our future subordinated indebtedness. All of our existing and future restricted subsidiaries that guarantee our secured revolving credit 

facility or certain other debt guarantee the Notes, provided, however, that the Notes are not guaranteed by Grizzly Holdings, Inc. and will not be 

guaranteed by any of our future unrestricted subsidiaries. The guarantees rank equally in the right of payment with all of the senior indebtedness of the

subsidiary guarantors and senior in the right of payment to any future subordinated indebtedness of the subsidiary guarantors. The Notes and the 

guarantees are effectively subordinated to all of our and the subsidiary guarantors' secured indebtedness (including all borrowings and other obligations

under our revolving credit facility) to the extent of the value of the collateral securing such indebtedness, and structurally subordinated to all indebtedness 

and other liabilities of any of our subsidiaries that do not guarantee the Notes. 

We may redeem some or all of the Notes at any time on or after November 1, 2016, at the redemption prices listed in the senior note indenture. Prior 

to November 1, 2016, we may redeem the Notes at a price equal to 100% of the principal amount plus a “make-whole” premium. In addition, prior to 

November 1, 2015, we may redeem up to 35% of the aggregate principal amount of the Notes with the net proceeds of certain equity offerings, provided 

that at least 65% of the aggregate principal amount of the Notes initially issued remains outstanding immediately after such redemption. 

If we experience a change of control (as defined in the senior note indenture), we will be required to make an offer to repurchase the Notes at a price 

equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. If we sell certain assets and fail to use 

the proceeds in a manner specified in the senior note indenture, we will be required to use the remaining proceeds to make an offer to repurchase the 

Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of repurchase. 

The senior note indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and 

the ability of our restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make 

distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions 

affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with 

affiliates, incur liens, engage in business other than the oil and gas business and designate certain of our subsidiaries as unrestricted subsidiaries. 

Building Loans . In June 2004, we purchased the office building we occupy in Oklahoma City, Oklahoma, for $3.7 million. We entered into a new 

building loan in March 2011 to refinance the $2.4 million outstanding at that time. The new agreement matures in February 2016 and bears interest at a 

fixed rate of 5.82% per annum. The new building loan requires monthly interest and principal payments of approximately $22,000 and is collateralized by 

the Oklahoma City office building and associated land. As of December 31, 2012 , approximately $2.1 million was outstanding on this loan. 

Capital Expenditures . Our recent capital commitments have been primarily for the execution of our drilling programs, for acquisitions of oil and 

natural gas interests in the Utica Shale, Permian Basin and the Niobrara Formation, to fund Grizzly's delineation drilling program and initial preparation 

of the Algar Lake facility and for investments in entities that may provide services to facilitate the development of our acreage. Our strategy is to continue 

to (1) increase cash flow generated from our operations by undertaking new drilling, workover, sidetrack and recompletion projects to exploit our existing 

properties, subject to economic and industry conditions, and (2) pursue acquisition and disposition opportunities and (3) business integration 

opportunities. 

Of our net reserves at December 31, 2012 , 40.2% were categorized as proved undeveloped. Our proved reserves will generally decline as reserves 

are depleted, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved developed 

reserves, or both. To realize reserves and increase production, we must continue our exploratory drilling, undertake other replacement activities or use 

third parties to accomplish those activities. 

At December 31, 2012 , our booked inventory of prospects included approximately 36 drilling locations at WCBB. The drilling schedule used in our 

December 31, 2012 reserve report anticipates that all of those wells will be drilled by the end of 2015. During 2012, we recompleted 61 wells and drilled

31 wells, of which 27 were completed as producers and four were non-productive, for an aggregate cost of $68.2 million. From January 1, 2013 through 

February 15, 2013, we recompleted 12 existing wells at our WCBB field. We currently intend to recomplete 60 wells and drill 22 to 24 new wells during 

2013 at our WCBB field. Our aggregate drilling and recompletion expenditures for our WCBB field during 2013 are estimated to be approximately $42.0 

million to $45.0 million. 

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In our Hackberry fields, in 2012, we recompleted 32 existing wells and drilled 24 wells, of which 19 were completed as producers, three were nonproductive and, at December 31, 2012, two were drilling, for an aggregate cost of $70.1 million. From January 1, 2013 through February 15, 2013, we 

recompleted two existing wells and drilled two new wells at our East Hackberry field and, at February 15, 2013, we were in the process of drilling one 

additional well at our East Hackberry field. We currently intend to drill ten to twelve wells and recomplete 24 wells in our Hackberry fields in 2013. Total 

capital expenditures for our Hackberry fields during 2013 are estimated to be approximately $26.0 million to $28.0 million. 

From January 1, 2012 through October 11, 2012, 19 gross (8.3 net) wells were spud on our Permian Basin acreage, all of which were completed as 

producers and one gross (0.3 net) existing well was recompleted between January 1, 2012 and October 11, 2012, for an aggregate cost of $20.9 million. 

As discussed above under the heading "Item 1. Business-Recent Developments-Contribution ,” on October 11, 2012, we contributed all of our oil and gas 

interests in the Permian Basin to Diamondback. We have no further funding obligations for operations relating to this Permian Basin acreage conducted 

after October 11, 2012. 

In the Niobrara Formation in Northwestern Colorado, in 2011, we completed a 60 square mile 3-D seismic survey and have received a processed 

version of the seismic data. During 2012, three gross (one net) wells, including one gross (.04 net) well drilled by another operator, were spud on our 

Niobrara Formation acreage, two of which were completed as producers and one of which was non-productive. Our total capital expenditures with respect 

to these three gross wells in the Niobrara Formation were approximately $2.5 million. We do not currently anticipate any capital expenditures in the 

Niobrara Formation in 2013. 

In the Utica Shale in Eastern Ohio, in 2011 and 2012 , we acquired approximately 137,000 gross (106,000 net) acres for approximately $626.9 

million. As of December 31, 2012 , we had drilled 14 wells on our Utica Shale acreage. Our total lease acquisition costs in the Utica Shale during 2012 

were approximately $508.5 million. In addition, during 2012, we spent approximately $66.1 million to drill 14 gross (6.7 net) wells on our Utica acreage.

In February 2013, we acquired approximately 22,000 additional net acres in the Utica Shale. We currently intend to drill 50 gross (44 net) wells on our 

Utica Shale acreage in 2013. Total capital expenditures in the Utica Shale during 2013 are estimated to be approximately $382.0 million to $426.0 

million, excluding leasehold acquisitions. 

During the third quarter of 2006, we purchased a 24.9% interest in Grizzly. As of December 31, 2012 , our net investment in Grizzly was 

approximately $172.8 million. Our capital requirements in 2012 for Grizzly were approximately $103.9 million, primarily for the expenses associated 

with the construction of the Algar Lake facility, drilling activity during the 2011-2012 winter drilling season and our $56.3 million share of the cost of the 

May River property. This acquisition was completed in February 2012 when Grizzly purchased approximately 47,000 acres of oil sands leases in the 

Athabasca oil sands area for $225.0 million CAD. We funded our portion of the purchase price with borrowings under our revolving credit facility. 

Effective October 5, 2012, Grizzly entered into a $125.0 million revolving credit facility, of which $75.0 million is initially available for borrowing to 

fund additional infrastructure relating to the Algar Lake facility and other future development projects. As of that same date, we entered into an agreement 

with Grizzly in which we committed to make monthly payments from October 2012 to May 2013 in the aggregate amount of approximately $8.5 million 

(of which $4.0 million was paid in 2012) to fund the construction and development of the Algar Lake facility. We also agreed to fund our proportionate 

share of any unfunded cost overruns, which we currently expect to be $3.0 million to $7.0 million. 

We did not have any capital expenditures in 2012 related to our interests in Thailand. Total 2013 capital expenditures for Thailand are estimated to be 

$2.0 million to $2.5 million to drill one gross well. 

In an effort to facilitate the development of our Utica Shale and other domestic acreage, we have invested in entities that can provide services that are

required to support our operations. In the second quarter of 2012, we acquired a 50% equity interest in each of Stingray Pressure Pumping LLC, or 

Stingray Pressure, and Stingray Cementing LLC, or Stingray Cementing. Stingray Pressure and Stingray Cementing provide well completion services. We 

also acquired a 50% equity interest in Blackhawk Midstream LLC, or Blackhawk, which coordinates gathering, compression, processing and marketing 

activities in connection with the development of our Utica Shale acreage. Blackhawk also has an option to acquire up to a 40% equity interest in the entity 

that provides midstream services to us in connection with our Utica Shale acreage. In the fourth quarter of 2012, we acquired a 50% equity interest in 

Stingray Logistics LLC, Stingray Logistics. Stingray Logistics will provide well services. In March 2012, we acquired a 50% equity interest in Timber 

Wolf Terminals LLC, or Timber Wolf, for $1.0 million. Also in March 2012, we acquired a 22.5% equity interest in Windsor Midstream LLC, or 

Midstream, for $7.0 million. Midstream owns a 28.4% equity interest in a gas processing plant in West Texas. In 2011, we acquired a 25% equity interest 

in Bison Drilling and Field Services LLC, or Bison, which owns and operates drilling rigs and related equipment. In April 2012, we purchased an 

additional 15% equity interest for approximately $6.2 million, bringing our total ownership interest in Bison to 40%. Also in 2011, we acquired a 25% 

interest in Muskie Holdings LLC, or Muskie, which is engaged in the mining of 

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hydraulic fracturing grade sand. The remaining equity interests in these entities are owned by affiliates of Wexford. In 2012, we invested approximately 

$42.8 million in these entities. In 2013, we expect to invest approximately $10.0 million to $15.0 million in these entities. 

Our total capital expenditures for 2013 are currently estimated to be in the range of $458.0 million to $512.0 million, excluding the acquisition costs 

associated with our February 2013 Utica Shale acquisition and with any additional Utica Shale acreage or other potential acquisitions and any amounts 

attributable to Grizzly. Approximately 85% of our 2013 estimated capital expenditures are currently expected to be spent in the Utica Shale. This range is 

up from the $277.6 million spent on 2012 activities primarily due to the significant increase in our acreage position in the Utica Shale and our 

contemplated Utica development plans, although such anticipated 2013 expenditures are partially offset relative to 2012 by the elimination of 

development costs in the Permian Basin as a result of the Contribution. We intend to continue to monitor pricing and cost developments and make 

adjustments to our future capital expenditure programs as warranted. 

We believe that our cash on hand, cash flow from operations, proceeds from our recent offerings of debt and equity securities and borrowings under 

our revolving credit facility will be sufficient to meet our normal recurring operating needs and capital requirements for the next twelve months. In the

event we elect to further expand or accelerate our drilling programs, pursue additional acquisitions, exercise our Blackhawk option or accelerate our 

Canadian oil sands project, we may be required to obtain additional funds which we would seek to do through traditional borrowings, offerings of debt or 

equity securities or other means, including the sale of assets. We regularly evaluate new acquisition opportunities. Needed capital may not be available to 

us on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to delay or curtail 

implementation of our business plan or not be able to complete acquisitions that may be favorable to us. 

Commodity Price Risk 

The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For 

example, during the past five years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel in December 2008 

to a high of $145.31 per barrel in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per million British thermal 

units, or MMBtu, in September 2009 to a high of $13.31 per MMBtu in July 2008. On December 31, 2012 , the West Texas Intermediate posted price for 

crude oil was $91.82 per barrel and the Henry Hub spot market price of natural gas was $3.35 per MMBtu. Any substantial decline in the price of oil and 

natural gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and 

natural gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. 

To mitigate the effects of commodity price fluctuations, in November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a 

weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered 

into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through July 

2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from August 

2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average price of $107.29. For the period 

from January 2013 through December 2013, we have entered into fixed price swaps for 5,000 barrels of oil per day at a weighted average price of $100.90 

per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. Under the 2012 contracts, we hedged approximately 46% of 

our 2012 production. Under the 2013 contracts, we have hedged approximately 23% of our expected 2013 production. Such arrangements may expose us 

to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These fixed price swaps 

are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815 and related pronouncements. 

Commitments 

In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, we assumed the seller's (Chevron) obligation to 

contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a minimum of 20 wells 

per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until abandonment obligations 

to Chevron have been fulfilled. Beginning in 2009, we can access the trust for use in plugging and abandonment charges associated with the property. As 

of December 31, 2012, the plugging and abandonment trust totaled approximately $3.1 million . At December 31, 2012, we have plugged 354 wells at 

WCBB since we began our plugging program in 1997, which management believes fulfills our current minimum plugging obligation. 

65 
Table of Contents 

Index to Financial Statements 

Contractual and Commercial Obligations 

The following table sets forth our contractual and commercial obligations at December 31, 2012 : 

 

_____________________ 

(1) Does not include short-term derivative instruments of $9,778,000, which are due in less than one year. 

New Accounting Pronouncements 

In February 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-02 , "Reporting of Amounts Reclassified Out of Accumulated 

Other Comprehensive Income," which requires additional information about amounts reclassified out of accumulated other comprehensive income by 

component. This ASU requires the presentation, either on the face of the statement where net income is presented or in the notes, significant amounts 

reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required 

under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be 

reclassified in their entirety to net income, a cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. 

The requirements of this ASU are effective prospectively for reporting periods beginning after December 15, 2012 with early adoption permitted. The 

Company will adopt the provisions of this ASU for reporting periods in 2013 and does not expect the adoption of this ASU to have a material effect on its

consolidated financial statements. 

Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and natural gas properties depend primarily upon 

the prevailing prices for oil and natural gas. Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to

changes in supply and demand, market uncertainty and a variety of additional factors, including: worldwide and domestic supplies of oil and natural gas; 

the level of prices, and expectations about future prices, of oil and natural gas; the cost of exploring for, developing, producing and delivering oil and 

natural gas; the expected rates of declining current production; weather conditions, including hurricanes, that can affect oil and natural gas operations over 

a wide area; the level of consumer demand; the price and availability of alternative fuels; technical advances affecting energy consumption; risks 

associated with operating drilling rigs; the availability of pipeline capacity; the price and level of foreign imports; domestic and foreign governmental

regulations and taxes; the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production 

controls; political instability or armed conflict in oil and natural gas producing regions; and the overall economic environment. 

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements with any 

certainty. For example, during the past five years, the West Texas Intermediate posted price for crude oil has ranged from a low of $30.28 per barrel, or

Bbl, in December 2008 to a high of $145.31 per Bbl in July 2008. The Henry Hub spot market price of natural gas has ranged from a low of $1.83 per 

MMBtu in September 2009 to a high of $13.31 per MMBtu in July 2008. On February 22, 2013, the West Texas Intermediate posted price for crude oil 

was $93.13 per barrel and the Henry Hub spot market price of natural gas was $3.27 per MMBtu. Any substantial decline in the price of oil and natural 

gas will likely have a material adverse effect on our operations, financial condition and level of expenditures for the development of our oil and natural 

gas reserves, and may result in write downs of oil and natural gas properties due to ceiling test limitations. 

66 

 Payment due by period (1) 

Contractual Obligations Total Less than 1 year 1-3 years 3-5 years 

More than 5 

years 

Building loan (2) $ 2,143,000 $ 150,000 $ 326,000 $ 1,667,000 $ —

7.75% senior unsecured notes due 2020 486,000,000 23,250,000 46,500,000 46,500,000 369,750,000 

Asset retirement obligations 13,275,000 60,000 1,739,000 820,000 10,656,000 

Employment agreements 7,050,000 2,400,000 4,650,000 — —

Grizzly capital commitments 6,280,000 6,280,000 — — —

Operating leases 586,000 179,000 305,000 102,000 —

Total $ 515,334,000 

 $ 32,319,000  $ 53,520,000  $ 49,089,000  $ 380,406,000 

(2) Does not include estimated interest of $121,000 due in less than one year, $214,000 due in 1-3 years and $16,000 due in 3-5 years. 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 
Table of Contents 

Index to Financial Statements 

To mitigate the effects of commodity price fluctuations, in November 2010, we entered into fixed price swaps for 2,000 barrels of oil per day at a 

weighted average price of $86.96 per barrel for the period January 2011 through December 2011. For January 2012 through February 2012, we entered 

into fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from March 2012 through July 

2012, we entered into fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per barrel. For the period from August 

2012 through December 2012, we entered into fixed price swaps for 4,000 barrels of oil per day at a weighted average price of $107.29. For the period 

from January 2013 through December 2013, we have entered into fixed price swaps for 5,000 barrels of oil per day at a weighted average price of $100.90 

per barrel. Under the 2011 contracts, we hedged approximately 31% of our 2011 production. Under the 2012 contracts, we hedged approximately 46% of 

our 2012 production. Under the 2013 contracts, we have hedged approximately 23% of our estimated 2013 production. Such arrangements may expose us 

to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. These fixed price swaps 

are accounted for as cash flow hedges and recorded at fair value pursuant to FASB ASC 815 and related pronouncements. At December 31, 2012, we had 

a net liability derivative position of $9.8 million as compared to a net asset derivative position of $1.6 million as of December 31, 2011, related to our 

fixed price swaps. Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have reduced the fair value of 

these instruments by approximately $19.4 million, while a 10% decrease in underlying commodity prices would have increased the fair value of these 

instruments by approximately $19.4 million. However, any realized derivative gain or loss would be substantially offset by a decrease or increase, 

respectively, in the actual sales value of production covered by the derivative instrument. 

Our revolving credit facility is structured under floating rate terms, as advances under this facility may be in the form of either base rate loans or 

Eurodollar loans. As such, our interest expense is sensitive to fluctuations in the prime rates in the U.S. or, if the Eurodollar rates are elected, the 

Eurodollar rates. As of October 17, 2012 (the latest date during the year ended December 31, 2012 on which we had borrowings outstanding), amounts 

borrowed under our revolving credit facility bore interest at the Eurodollar rate of 2.97%. As of December 31, 2012, we had no variable interest rate 

borrowings outstanding; therefore, an increase in interest rates would not have impacted our interest expense. As of December 31, 2012, we did not have 

any interest rate swaps to hedge our interest risks. 

The information required by this item appears beginning on page F-1 following the signature pages of this Report. 

 

None. 

 

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 Exchange Act 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, 2012, 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 Exchange Act. Based upon our evaluation, our Chief Executive Officer and Vice President and Chief 

Financial Officer have concluded that, as of December 31, 2012, 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. 

67 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 

ITEM 9A. CONTROLS AND PROCEDURES 
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 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 ControlIntegrated 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, 2012. 

Grant Thornton LLP, the independent registered public accounting firm that audited our financial statements for the year ended December 31, 2012 

included with this Annual Report on Form 10-K, has also audited our internal control over financial reporting as of December 31, 2012, as stated in their

accompanying report. 

68 

/s/ James D. Palm /s/ Michael G. Moore 

Name: James D. Palm Name: Michael G. Moore 

Title: Chief Executive Officer Title: Chief Financial Officer 
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 the internal control over financial reporting of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 

2012, 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, 2012, 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 

financial statements of the Company as of and for the year ended December 31, 2012 and our report dated February 28, 2013 expressed an unqualified 

opinion on those financial statements. 

/s/ GRANT THORNTON LLP 

Oklahoma City, Oklahoma 

February 28, 2013 

69 
Table of Contents 

Index to Financial Statements 

None. 

PART III 

 

For information concerning Item 10-Directors, Executive Officers and Corporate Governance, see our definitive proxy statement, which will be filed 

with the Securities and Exchange Commission within 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). 

For information concerning Item 11-Executive Compensation, see our definitive proxy statement, which will be filed with the Securities and 

Exchange Commission within 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). 

For information concerning Item 12-Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, see our 

definitive proxy statement, which will be filed with the Securities and Exchange Commission within 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). 

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). 

For information concerning Item 14-Principal Accounting Fees and Services, 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). 

70 

ITEM 9B. OTHER INFORMATION 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE 

ITEM 11. EXECUTIVE COMPENSATION 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED 

STOCKHOLDER MATTERS 

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE 

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES 
Table of Contents 

Index to Financial Statements 

PART IV 

 

The following documents are filed as part of this report: 

Reference is made to the Index to Financial Statements appearing on Page F-1. 

All financial statement schedules have been omitted because they are not applicable or the required disclosure is presented in the financial 

statements or notes thereto. 

 

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES 

(1) Financial Statements 

(2) Financial Statement Schedules 

(3) Exhibits 

Exhibit 

Number Description 

 

2.1 

 

Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, 

which are listed as a party seller, and Windsor Permian (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, 

filed by the Company with the SEC on December 24, 2007). 

 

2.2 

 

Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each 

of the other parties which are listed as a party seller, Windsor Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the 

Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). 

 

2.3 

 

Contribution Agreement, dated May 7, 2012, by and between the Company and Diamondback Energy, Inc. (incorporated by reference 

to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on May 8, 2012). 

 

2.4 

 

Purchase and Sale Agreement, dated December 17, 2012, by and between Windsor Ohio LLC, as seller, and Gulfport Energy 

Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with 

the SEC on December 18, 2012). 

 

2.5 

 

Amendment, dated December 19, 2012, to the Purchase and Sale Agreement, dated December 17, 2012, by and between Windsor Ohio 

LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-

19514, filed by the Company with the SEC on December 20, 2012). 

 

2.6 

 

Purchase and Sale Agreement, dated February 11, 2013, by and between Windsor Ohio, LLC, as seller, and Gulfport Energy 

Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with 

the SEC on February 15, 2013). 

 

3.1 

 

Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the 

Company with the SEC on April 26, 2006). 

 

3.2 

 

Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File 

No. 000-19514, filed by the Company with the SEC on November 6, 2009). 

 

3.3 

 

Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company 

with the SEC on July 12, 2006). 

 

4.1 

 

Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on 

Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004). 

 

4.2 

 

Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form 

SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004). 

 

4.3 Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited 

partnership, Southpoint Qualified Fund LP, a Delaware limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman 

Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the 
71 

 Company with the SEC on March 31, 2005). 

 
Table of Contents 

Index to Financial Statements 
72 

4.4 

 

Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, 

certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, 

File No. 000-19514, filed by the Company with the SEC on November 11, 2005). 

 

4.5 

 

Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among 

Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party thereto 

(incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 

2006). 

 

4.6 

 

Indenture, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo 

Bank, National Association, as trustee (including the form of Gulfport Energy Corporation's 7.750% Senior Note Due November 1, 

2020) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 

23, 2012). 

 

4.7 

 

Registration Rights Agreement, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto 

and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to 

the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012). 

 

4.8 

 

First Supplemental Indenture, dated December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and 

Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, 

filed by the Company with the SEC on December 26, 2012). 

 

4.9 

 

Registration Rights Agreement, dated as of December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party 

thereto and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to 

Exhibit 4.3 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012). 

 

10.1+ 

 

Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed 

by the Company with the SEC on April 26, 2006). 

 

10.2+ 

 

Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company 

with the SEC on April 26, 2006). 

 

10.3+ 

 

Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the 

Company with the SEC on April 26, 2006). 

 

10.4+ 

 

Employment Agreement, dated November 7, 2012, between the Company and Mike Liddell (incorporated by reference to Exhibit 10.4 

to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). 

 

10.5+ 

 

Employment Agreement, dated November 7, 2012, between the Company and James D. Palm (incorporated by reference to Exhibit 

10.5 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). 

 

10.6+ 

 

Employment Agreement, dated November 7, 2012, between the Company and Michael G. Moore (incorporated by reference to Exhibit 

10.6 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). 

 

10.7 

 

Credit Agreement, dated as of September 30, 2010, by and among the Company, as borrower, the Bank of Nova Scotia, as 

administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association (incorporated by reference to 

Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 6, 2010). 

 

10.8 

 

Amendment, dated as of December 24, 2010, to the Credit Agreement by and among the Company, as borrower, the Bank of Nova 

Scotia, as administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association (incorporated by 

reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 28, 2010). 

 

10.9 

 

First Amendment, dated May 3, 2011 of Credit Agreement, dated September 30, 2011, by and among the Company, as borrower, the 

Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, KeyBank 

National Association and Société Générale (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the 

Company with the SEC on May 9, 2011). 

 

10.10 

 

Second Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of Nova 

Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, as syndication agent, 

KeyBank National Association, as co-documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 

10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 4, 2011). 
Table of Contents 

Index to Financial Statements 

 

10.11 

 

Third Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of Nova 

Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, as syndication agent, 

KeyBank National Association and Société Générale, as co-documentation agents, and the other lenders party thereto (incorporated by 

reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 4, 2011). 

 

10.12 

 

Fourth Amendment, dated May 2, 2012, to Credit Agreement, dated September 30, 2011, by and among the Company, as borrower, 

the Bank of Nova Scotia, as administrative agent and letter of credit issuer, Amegy Bank National Association, Key Bank National 

Association and Société Générale (incorporated by reference to Exhibit 10.1 to Form 10-Q, File No. 000-19514, filed by the Company 

with the SEC on May 10, 2012). 

 

10.13 

 

Fifth Amendment to Credit Agreement, effective as of October 9, 2012, among Gulfport Energy Corporation, as borrower, The Bank 

of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and certain lenders and agents party thereto 

(incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 9, 

2012). 

 

10.14 

 

Sixth Amendment to Credit Agreement, effective as of October 17, 2012, among Gulfport Energy Corporation, as borrower, The Bank 

of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and certain lenders and agents party thereto 

(incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 

2012). 

 

10.15 

 

Seventh Amendment to Credit Agreement, effective as of December 18, 2012, among Gulfport Energy Corporation, as borrower, The 

Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and certain lenders and agents party thereto 

(incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 

2012). 

 

10.16 

 

Investor Rights Agreement, dated as of October 11, 2012, between Gulfport Energy Corporation and Diamondback Energy, Inc. 

(incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 17, 

2012). 

 

14 

 

Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on 

February 14, 2006). 

 

21* Subsidiaries of the Registrant. 

 

23.1* Consent of Grant Thornton LLP. 

 

23.2* Consent of Netherland, Sewell & Associates, Inc. 

 

23.3* Consent of Ryder Scott Company. 

 

23.4* Consent of Pinnacle Energy Services, LLC. 

 

31.1* 

 

Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act 

of 1934, as amended. 

 

31.2* 

 

Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 

1934, as amended. 

 

32.1** 

 

Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act 

of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. 

 

32.2** 

 

Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 

1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. 

 

99.1* Report of Netherland, Sewell & Associates, Inc. 

 

99.2* Report of Ryder Scott Company. 

 
73 

101.INS** XBRL Instance Document. 

 

101.SCH** XBRL Taxonomy Extension Schema Document. 

 
Table of Contents 

Index to Financial Statements 

74 

101.CAL** XBRL Taxonomy Extension Calculation Linkbase Document. 

 

101.DEF** XBRL Taxonomy Extension Definition Linkbase Document. 

 

101.LAB** XBRL Taxonomy Extension Labels Linkbase Document. 

 

101.PRE** XBRL Taxonomy Extension Presentation Linkbase Document. 

 

* Filed herewith. 

** Furnished herewith, not filed. 

+ Management contract, compensatory plan or arrangement. 
Table of Contents 

Index to Financial Statements 

SIGNATURES 

In accordance with Section 13 or 15(d) of the Exchange Act, the registrant caused this report to be signed on its behalf by the undersigned, thereunto 

duly authorized. 

Date: February 28, 2013 

 

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities 

and on the dates indicated. 

 

S -1 

GULFPORT ENERGY CORPORATION 

 

By: /s/ JAMES D. PALM 

 

James D. Palm 

Chief Executive Officer 

Date: February 28, 2013 By: /s/ JAMES D. PALM 

 

James D. Palm 

Chief Executive Officer and Director 

(Principal Executive Officer) 

 

Date: February 28, 2013 By: /s/ MIKE LIDDELL 

 

Mike Liddell 

Chairman of the Board and Director 

 

Date: February 28, 2013 By: /s/ MICHAEL G. MOORE 

 

Michael G. Moore 

Vice President and Chief Financial Officer 

(Principal Financial and Accounting Officer) 

 

Date: February 28, 2013 By: /s/ DONALD DILLINGHAM 

 

Donald Dillingham 

Director 

 

Date: February 28, 2013 By: /s/ CRAIG GROESCHEL 

 

Craig Groeschel 

Director 

 

Date: February 28, 2013 By: /s/ DAVID L. HOUSTON 

 

David L. Houston 

Director 

 

Date: February 28, 2013 By: /s/ SCOTT E. STRELLER 

 

Scott E. Streller 

Director 
Table of Contents 

Index to Financial Statements 

INDEX TO FINANCIAL STATEMENTS 

 

F -1 

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 

 Page 

 

Report of Independent Registered Public Accounting Firm F -2 

 

Consolidated Balance Sheets, December 31, 2012 and December 31, 2011 F -3 

 

Consolidated Statements of Operations, Years Ended December 31, 2012, 2011 and 2010 F -5 

 

Consolidated Statements of Comprehensive Income (Loss), Years Ended December 31, 2012, 2011 and 2010 F -6 

 

Consolidated Statements of Stockholders’ Equity, Years Ended December 31, 2012, 2011 and 2010 F -7 

 

Consolidated Statements of Cash Flows, Years Ended December 31, 2012, 2011 and 2010 F -8 

 

Notes to Financial Statements F -9 
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 the accompanying consolidated balance sheets of Gulfport Energy Corporation and Subsidiaries (the “Company”) as of December 31, 

2012 and 2011, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the 

three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is 

to express an opinion on these financial statements based on our audits. 

We conducted our audits 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 the financial statements are free of material misstatement. An audit 

includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the 

accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe 

that our audits provide a reasonable basis for our opinion. 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Gulfport Energy 

Corporation and Subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the 

period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal 

control over financial reporting as of December 31, 2012, based on criteria established in Internal Control—Integrated Framework issued by the 

Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated February 28, 2013 expressed an unqualified opinion. 

/s/ GRANT THORNTON LLP 

Oklahoma City, Oklahoma 

February 28, 2013 

F -2 
Table of Contents 

Index to Financial Statements 

GULFPORT ENERGY CORPORATION 

CONSOLIDATED BALANCE SHEETS 

(Amounts rounded to nearest thousand) 

 

F -3 

 

December 31, 

2012 

December 31, 

2011 

Assets 

Current assets: 

Cash and cash equivalents $ 167,088,000 $ 93,897,000 

Accounts receivable—oil and gas 25,615,000 28,019,000 

Accounts receivable—related parties 34,848,000 4,731,000 

Prepaid expenses and other current assets 1,506,000 1,327,000 

Short-term derivative instruments 664,000 1,601,000 

Total current assets 229,721,000 129,575,000 

Property and equipment: 

Oil and natural gas properties, full-cost accounting, $626,295,000 and $138,623,000 excluded from 

amortization in 2012 and 2011, respectively 1,611,090,000 1,035,754,000 

Other property and equipment 8,662,000 8,024,000 

Accumulated depletion, depreciation, amortization and impairment (665,884,000 ) (575,142,000 ) 

Property and equipment, net 953,868,000 468,636,000 

Other assets: 

Equity investments ($151,317,000 and $0 attributable to fair value option in 2012 and 2011, 

respectively) 381,484,000 86,824,000 

Other assets 13,295,000 5,123,000 

Total other assets 394,779,000 91,947,000 

Deferred tax asset — 1,000,000 

Total assets $ 1,578,368,000 $ 691,158,000 

Liabilities and Stockholders’ Equity 

Current liabilities: 

Accounts payable and accrued liabilities $ 110,244,000 $ 43,872,000 

Asset retirement obligation—current 60,000 620,000 

Short-term derivative instruments 10,442,000 —

Current maturities of long-term debt 150,000 141,000 

Total current liabilities 120,896,000 44,633,000 

Asset retirement obligation—long-term 13,215,000 12,033,000 

Deferred tax liability 18,607,000 —

Long-term debt, net of current maturities 298,888,000 2,142,000 

Other non-current liabilities 354,000 —

Total liabilities 451,960,000 58,808,000 

Commitments and contingencies (Notes 16 and 17) 

Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative 

preferred stock, Series A; 0 issued and outstanding — —

Stockholders’ equity: 

Common stock - $.01 par value, 100,000,000 authorized, 67,527,386 issued and outstanding in 2012 and 

55,621,371 in 2011 674,000 556,000 

Paid-in capital 1,036,245,000 604,584,000 

Accumulated other comprehensive income (loss) (3,429,000 ) 2,663,000 

Retained earnings 92,918,000 24,547,000 

Total stockholders’ equity 1,126,408,000 632,350,000 

Total liabilities and stockholders’ equity $ 1,578,368,000 

 $ 691,158,000 
Table of Contents 

Index to Financial Statements 

See accompanying notes to consolidated financial statements. 

F -4 
Table of Contents 

Index to Financial Statements 

GULFPORT ENERGY CORPORATION 

CONSOLIDATED STATEMENTS OF OPERATIONS 

(Amounts rounded to nearest thousand) 

 

See accompanying notes to consolidated financial statements. 

F -5 

 Year Ended December 31, 

 2012 2011 2010 

Revenues: 

Oil and condensate sales $ 242,708,000 $ 222,025,000 $ 121,350,000 

Gas sales 3,225,000 3,838,000 3,468,000 

Natural gas liquid sales 2,668,000 3,090,000 2,818,000 

Other income 325,000 301,000 285,000 

 248,926,000 229,254,000 127,921,000 

Costs and expenses: 

Lease operating expenses 24,308,000 20,897,000 17,614,000 

Production taxes 29,400,000 26,333,000 13,966,000 

Depreciation, depletion, and amortization 90,749,000 62,320,000 38,907,000 

General and administrative 13,808,000 8,074,000 6,063,000 

Accretion expense 698,000 666,000 617,000 

Gain on sale of assets (7,300,000 ) — —

 151,663,000 118,290,000 77,167,000 

INCOME FROM OPERATIONS 97,263,000 110,964,000 50,754,000 

OTHER (INCOME) EXPENSE: 

Interest expense 7,458,000 1,400,000 2,761,000 

Interest income (72,000 ) (186,000 ) (387,000 ) 

(Income) loss from equity method investments (8,322,000 ) 1,418,000 977,000 

 (936,000 ) 2,632,000 3,351,000 

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 98,199,000 108,332,000 47,403,000 

INCOME TAX EXPENSE (BENEFIT) 26,363,000 (90,000 ) 40,000 

INCOME FROM CONTINUING OPERATIONS 71,836,000 108,422,000 47,363,000 

DISCONTINUED OPERATIONS 

 Loss on disposal of Belize properties, net of tax 3,465,000 — —

NET INCOME $ 68,371,000 $ 108,422,000 $ 47,363,000 

NET INCOME PER COMMON SHARE: 

Basic net income from continuing operations per share $ 1.28 $ 2.22 $ 1.08 

Basic net income from discontinued operations, net of tax, per share (0.06 ) — —

Basic net income per share $ 1.22 $ 2.22 $ 1.08 

 

Diluted net income from continuing operations per share $ 1.27 $ 2.20 $ 1.07 

Diluted net income from discontinued operations, net of tax, per share (0.06 ) — —

Diluted net income per share $ 1.21 $ 2.20 $ 1.07 

Weighted average common shares outstanding—Basic 55,933,354 48,754,840 43,863,190 

Weighted average common shares outstanding—Diluted 56,417,488 49,206,963 44,256,092 
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Index to Financial Statements 

GULFPORT ENERGY CORPORATION 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) 

(Amounts rounded to nearest thousand) 

(1) Net of $(4,301,000) , $0 , and $0 in taxes for the years ended December 31, 2012, 2011 and 2010, respectively. 

(2) Net of $512,000 , $0 , and $0 in taxes for the years ended December 31, 2012, 2011 and 2010, respectively. 

See accompanying notes to consolidated financial statements. 

F -6 

 2012 2011 2010 

Net income $ 68,371,000 $ 108,422,000 $ 47,363,000 

Foreign currency translation adjustment 1,355,000 (1,865,000 ) 2,255,000 

Change in fair value of derivative instruments, net of taxes (1) (8,452,000 ) 1,576,000 (4,720,000 ) 

Reclassification of settled contracts, net of taxes (2) 1,005,000 4,720,000 18,736,000 

Other comprehensive income (loss) (6,092,000 ) 4,431,000 16,271,000 

Comprehensive income $ 62,279,000  $ 112,853,000  $ 63,634,000 
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Index to Financial Statements 

GULFPORT ENERGY CORPORATION 

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY 

(Amounts rounded to nearest thousand) 

 

See accompanying notes to consolidated financial statements. 

F -7 

 

Additional 

Paid-in 

Capital 

Accumulated 

Other 

Comprehensive 

Income(Loss) 

Retained 

Earnings 

(Accumulated 

Deficit) 

Total 

Stockholders’ 

Equity 

 Common Stock 

 Shares Amount 

Balance at January 1, 2010 42,696,409 $ 427,000 $ 273,901,000 $ (18,039,000 ) $ (131,238,000 ) $ 125,051,000 

Net income — — — — 47,363,000 47,363,000 

Other Comprehensive Income — — — 16,271,000 — 16,271,000 

Stock Compensation — — 492,000 — — 492,000 

Issuance of Common Stock in public offering, net of

related expenses 1,668,503 17,000 21,341,000 — — 21,358,000 

Issuance of Common Stock through exercise of 

warrants 173,109 2,000 204,000 — — 206,000 

Issuance of Restricted Stock 58,525 — — — — —

Issuance of Common Stock through exercise of 

options 48,889 — 315,000 — — 315,000 

Balance at December 31, 2010 44,645,435 446,000 296,253,000 (1,768,000 ) (83,875,000 ) 211,056,000 

Net income — — — — 108,422,000 108,422,000 

Other Comprehensive Income — — — 4,431,000 — 4,431,000 

Stock Compensation — — 1,287,000 — — 1,287,000 

Issuance of Common Stock in public offering, net of

related expenses 10,810,000 108,000 306,053,000 — — 306,161,000 

Issuance of Common Stock through exercise of 

warrants 566 — — — — —

Issuance of Restricted Stock 63,370 1,000 (1,000 ) — — —

Issuance of Common Stock through exercise of 

options 102,000 1,000 992,000 — — 993,000 

Balance at December 31, 2011 55,621,371 556,000 604,584,000 2,663,000 24,547,000 632,350,000 

Net income — — — — 68,371,000 68,371,000 

Other Comprehensive Loss — — — (6,092,000 ) — (6,092,000 ) 

Stock Compensation — — 4,688,000 — — 4,688,000 

Issuance of Common Stock in public offering, net of

related expenses 11,750,000 118,000 426,789,000 — — 426,907,000 

Issuance of Restricted Stock 135,015 — — — — —

Issuance of Common Stock through exercise of 

options 21,000 — 184,000 — — 184,000 

Balance at December 31, 2012 67,527,386 

 $ 674,000  $ 1,036,245,000  $ (3,429,000 )  $ 92,918,000  $ 1,126,408,000 
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Index to Financial Statements 

GULFPORT ENERGY CORPORATION 

CONSOLIDATED STATEMENTS OF CASH FLOWS 

(Amounts rounded to nearest thousand) 

 Year Ended December 31, 

 2012 2011 2010 

Cash flows from operating activities: 

 

Net income $ 68,371,000 $ 108,422,000 $ 47,363,000 

Adjustments to reconcile net income to net cash provided by operating activities: 

Accretion of discount—Asset Retirement Obligation 698,000 666,000 617,000 

Depletion, depreciation and amortization 90,749,000 62,320,000 38,907,000 

Stock-based compensation expense 2,813,000 772,000 295,000 

(Gain) loss from equity investments (8,322,000 ) 1,418,000 977,000 

Interest income—note receivable (2,000 ) (147,000 ) (267,000 ) 

Unrealized loss (gain) on derivative instruments 144,000 (25,000 ) —

Deferred income tax expense (benefit) 24,120,000 (372,000 ) (95,000 ) 

Amortization of loan commitment fees 640,000 540,000 —

Amortization of note discount and premium 59,000 — —

Write off of loan commitment fees 1,143,000 — —

Loss on disposal of assets 5,702,000 — —

Gain on sale of assets (7,300,000 ) — —

Changes in operating assets and liabilities: 

Decrease (increase) in accounts receivable 2,404,000 (13,067,000 ) (5,460,000 ) 

Increase in accounts receivable—related party (30,117,000 ) (4,158,000 ) (437,000 ) 

(Increase) decrease in prepaid expenses (179,000 ) 405,000 315,000 

Increase in other assets — — (75,000 ) 

Increase in accounts payable and accrued liabilities 50,506,000 1,612,000 4,948,000 

Settlement of asset retirement obligation (2,271,000 ) (248,000 ) (1,253,000 ) 

Net cash provided by operating activities 199,158,000 158,138,000 85,835,000 

Cash flows from investing activities: 

 

Deductions to cash held in escrow 8,000 8,000 8,000 

Additions to other property, plant and equipment (638,000 ) (415,000 ) (427,000 ) 

Additions to oil and gas properties (757,192,000 ) (287,292,000 ) (101,644,000 ) 

Proceeds from sale of other property, plant and equipment 140,000 — —

Proceeds from sale of oil and gas properties 63,590,000 1,384,000 304,000 

Advances on note receivable to related party — (3,182,000 ) (2,877,000 ) 

Contributions to equity method investments (147,307,000 ) (34,621,000 ) (1,244,000 ) 

Distributions from equity method investments 820,000 870,000 565,000 

Net cash used in investing activities (840,579,000 ) (323,248,000 ) (105,315,000 ) 

Cash flows from financing activities: 

 

Principal payments on borrowings (158,639,000 ) (97,634,000 ) (52,711,000 ) 

Borrowings on line of credit 158,500,000 48,000,000 52,200,000 

Proceeds from bond issuance 296,835,000 — —

Debt issuance costs and loan commitment fees (9,175,000 ) (981,000 ) (1,144,000 ) 

Proceeds from issuance of common stock, net of offering costs, and exercise of stock options 427,091,000 307,154,000 21,879,000 

Net cash provided by financing activities 714,612,000 256,539,000 20,224,000 

Net increase in cash and cash equivalents 73,191,000 91,429,000 744,000 

Cash and cash equivalents at beginning of period 93,897,000 2,468,000 1,724,000 

Cash and cash equivalents at end of period $ 167,088,000 $ 93,897,000 $ 2,468,000 

Supplemental disclosure of cash flow information: 

 

Interest payments $ 1,461,000 $ 991,000 $ 1,949,000 

Income tax payments $ 261,000 $ 1,000 $ 40,000 

Supplemental disclosure of non-cash transactions: 

 

Capitalized stock based compensation $ 1,875,000 $ 515,000 $ 197,000 

Asset retirement obligation capitalized $ 2,195,000 $ 1,390,000 $ 1,328,000 

Foreign currency translation gain (loss) on investment in Grizzly Oil Sands ULC 
 S ee accompanying notes to consolidated financial statements. 

F -8 

$ 1,355,000 $ (855,000 ) $ 1,313,000 

Foreign currency translation gain (loss) on note receivable—related party $ — $ (1,085,000 ) $ 942,000 
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Index to Financial Statements 

GULFPORT ENERGY CORPORATION 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 

DECEMBER 31, 2012 , 2011 AND 2010 

(Amounts rounded to nearest thousand) 

Business 

Gulfport Energy Corporation (“Gulfport” or the “Company”) is an independent oil and gas exploration, development and production company with 

its principal properties located in the Louisiana Gulf Coast, the Utica Shale in Eastern Ohio and in Western Colorado in the Niobrara Formation and has 

investments in companies operating in the Permian Basin in West Texas, Canada and Thailand. 

Cash and Cash Equivalents 

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents for purposes of the 

statement of cash flows. 

Principles of Consolidation 

The consolidated financial statements include the Company and its wholly owned subsidiaries, Grizzly Holdings Inc., Jaguar Resources LLC, Gator 

Marine, Inc., Gator Marine Ivanhoe, Inc., Westhawk Minerals LLC and Puma Resources, Inc. All intercompany balances and transactions are eliminated 

in consolidation. 

Accounts Receivable 

The Company’s accounts receivable—oil and gas primarily are from companies in the oil and gas industry. The majority of its receivables are from 

two purchasers of the Company’s oil and gas. Credit is extended based on evaluation of a customer’s payment history and, generally, collateral is not 

required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the 

Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company 

determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss 

history, the customer’s current ability to pay its obligation to the Company, amounts which may be obtained by an offset against production proceeds due 

the customer and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they 

become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was 

deemed necessary at December 31, 2012 and December 31, 2011 . 

Oil and Gas Properties 

The Company uses the full cost method of accounting for oil and gas operations. Accordingly, all costs, including nonproductive costs and certain 

general and administrative costs directly associated with acquisition, exploration and development of oil and gas properties, are capitalized. Under the full 

cost method of accounting, the Company is required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the 

oil and gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes or the cost center ceiling. The cost 

center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the 12-month 

unweighted average of the first-day-of-the-month price for 2012 , 2011 and 2010 , adjusted for any contract provisions or financial derivatives, if any, that 

hedge the Company’s oil and natural gas revenue, and excluding the estimated abandonment costs for properties with asset retirement obligations 

recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties 

included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. 

If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or noncash writedown is required. 

Such capitalized costs, including the estimated future development costs and site remediation costs of proved undeveloped properties are depleted 

by an equivalent units-of-production method, converting gas to barrels at the ratio of six Mcf of gas to one barrel of oil. No gain or loss is recognized upon 

the disposal of oil and gas properties, unless such dispositions significantly alter the relationship between capitalized costs and proven oil and gas 

reserves. Oil and gas properties not subject to amortization consist of the cost of unproved leaseholds and totaled $ 626,295,000 and $ 138,623,000 at 

F -9 

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 
Table of Contents 

Index to Financial Statements 

December 31, 2012 and December 31, 2011 , respectively. These costs are reviewed quarterly by management for impairment. If impairment has 

occurred, the portion of cost in excess of the current value is transferred to the cost of oil and gas properties subject to amortization. Factors considered by 

management in its impairment assessment include drilling results by Gulfport and other operators, the terms of oil and gas leases not held by production,

and available funds for exploration and development. 

The Company accounts for its abandonment and restoration liabilities under FASB ASC Topic 410, “ Asset Retirement and Environmental 

Obligations ” (“FASB ASC 410”), which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The 

asset retirement liability is recorded in the period in which the obligation meets the definition of a liability, which is generally when the asset is placed 

into service. When the liability is initially recorded, the Company increases the carrying amount of oil and natural gas properties by an amount equal to

the original liability. The liability is accreted to its present value each period, and the capitalized cost is included in capitalized costs and depreciated 

consistent with depletion of reserves. Upon settlement of the liability or the sale of the well, the liability is reversed. These liability amounts may change 

because of changes in asset lives, estimated costs of abandonment or legal or statutory remediation requirements. 

Other Property and Equipment 

Depreciation of other property and equipment is provided on a straight-line basis over the estimated useful lives of the related assets, which range 

from 3 to 30 years. 

Foreign Currency 

The U.S. dollar is the functional currency for Gulfport’s consolidated operations. However, the Company has an equity investment in a Canadian 

entity whose functional currency is the Canadian dollar. The assets and liabilities of the Canadian investment are translated into U.S. dollars based on the 

current exchange rate in effect at the balance sheet dates. Canadian income and expenses are translated at average rates for the periods presented. 

Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ equity. The 

following table presents the balances of the Company’s cumulative translation adjustments included in accumulated other comprehensive income. 

 

Net Income per Common Share 

Basic net income per common share is computed by dividing income attributable to common stock by the weighted average number of common 

shares outstanding for the period. Diluted net income per common share reflects the potential dilution that could occur if options or other contracts to 

issue common stock were exercised or converted into common stock. Potential common shares are not included if their effect would be anti-dilutive. 

Calculations of basic and diluted net income per common share are illustrated in Note 12. 

Income Taxes 

Gulfport uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the 

future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities 

and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period 

when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is 

recognized in income during the period the rate change is enacted. Deferred tax assets are recognized as income in the year in which realization becomes 

determinable. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized. 

The Company is subject to U.S. federal income tax as well as income tax of multiple jurisdictions. The Company’s 1998 – 2012 U.S. federal and 

state income tax returns remain open to examination by tax authorities, due to net operating losses. As of December 31, 2012 , the Company has no 

unrecognized tax benefits that would have a material impact on the effective rate. The Company recognizes interest and penalties related to income tax 

matters as interest expense and general and administrative 

F -10 

December 31, 2009 $ 696,000 

December 31, 2010 $ 2,952,000 

December 31, 2011 $ 1,087,000 

December 31, 2012 $ 2,442,000 
Table of Contents 

Index to Financial Statements 

expenses, respectively. For the year ended December 31, 2012 , there is no interest or penalties associated with uncertain tax positions in the Company’s

consolidated financial statements. 

Revenue Recognition 

Gas revenues are recorded in the month produced and delivered to the purchaser using the entitlement method, whereby any production volumes 

received in excess of the Company’s ownership percentage in the property are recorded as a liability. If less than Gulfport’s entitlement is received, the 

underproduction is recorded as a receivable. At December 31, 2012 , the Company had a gas imbalance liability of approximately $354,000 . At 

December 31, 2011 , the Company had no imbalances. Oil revenues are recognized when ownership transfers, which occurs in the month produced. 

Investments—Equity Method 

Investments in entities greater than 20% and less than 50% are accounted for under the equity method. Under the equity method, the Company’s 

share of investees’ earnings or loss is recognized in the statement of operations. In accordance with FASB ASC 825 , "Financial Instruments ," the 

Company has elected the fair value option of accounting for its equity method investment in Diamondback Energy Inc.'s ("Diamondback") stock. At the 

end of each reporting period, the quoted closing market price of Diamondback's stock is multiplied by the total shares owned by the Company and the 

resulting gain or loss is recognized in (income) loss from equity method investments in the consolidated statements of operations. 

The Company reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such loss has occurred, 

the Company recognizes an impairment provision. There was no impairment of equity method investments at December 31, 2012 or 2011 . 

Accounting for Stock-Based Compensation 

The Company accounts for stock-based compensation in accordance with the provisions of FASB ASC Topic 718, “ Compensation—Stock 

Compensation ” (“FASB ASC 718”). FASB ASC 718 requires share-based payments to employees, including grants of employee stock options and 

restricted stock, to be recognized as equity or liabilities at the fair value on the date of grant and to be expensed over the applicable vesting period. The 

vesting periods for the options range between three to five years and have a maximum contractual term of ten years. The vesting periods for restricted 

shares range between three to five years with either quarterly or annual vesting installments. 

Accounting for Derivative Instruments and Hedging Activities 

The Company may seek to reduce its exposure to unfavorable changes in oil prices by utilizing energy swaps and collars, or fixed-price contracts. 

The Company follows the provisions of FASB ASC 815, “ Derivatives and Hedging ” (“FASB ASC 815”) as amended. It requires that all derivative 

instruments be recognized as assets or liabilities in the balance sheet, measured at fair value. 

The Company estimates the fair value of all derivative instruments using established index prices and other sources. These values are based upon, 

among other things, futures prices, correlation between index prices and the Company’s realized prices, time to maturity and credit risk. The values 

reported in the consolidated financial statements change as these estimates are revised to reflect actual results, changes in market conditions or other 

factors. 

The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and the resulting designation. Designation 

is established at the inception of a derivative, but re-designation is permitted. For derivatives designated as cash flow hedges and meeting the effectiveness

guidelines of FASB ASC 815, changes in fair value are recognized in accumulated other comprehensive income until the hedged item is recognized in 

earnings. Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged 

item over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. 

Use of Estimates 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires 

management to make estimates, judgments and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial 

statements and revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Significant estimates with

regard to these financial statements include the estimate of proved oil and gas reserve quantities and the related present value of estimated future net cash 

flows there from, the amount and timing of asset retirement obligations, the realization of deferred tax assets and the realization of future net operating 

loss carryforwards available as reductions of income tax expense. The estimate of the Company’s oil and gas reserves is used to 

F -11 
Table of Contents 

Index to Financial Statements 

compute depletion, depreciation, amortization and impairment of oil and gas properties. 

Reclassification 

Certain reclassifications have been made to prior period financial statements to conform to current period presentation. 

Recent Accounting Pronouncements 

In February 2013, the FASB issued Accounting Standards Update ("ASU") No. 2013-02 , "Reporting of Amounts Reclassified Out of Accumulated 

Other Comprehensive Income," which requires additional information about amounts reclassified out of accumulated other comprehensive income by 

component. This ASU requires the presentation, either on the face of the statement where net income is presented or in the notes, significant amounts 

reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required 

under GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under GAAP to be 

reclassified in their entirety to net income, a cross-reference to other disclosures required under GAAP that provide additional detail about those amounts. 

The requirements of this ASU are effective prospectively for reporting periods beginning after December 15, 2012 with early adoption permitted. The 

Company will adopt the provisions of this ASU for reporting periods in 2013 and does not expect the adoption of this ASU to have a material effect on its

consolidated financial statements. 

In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurement: Amendments to Achieve Common Fair Value Measurement and 

Disclosure Requirements in U.S. GAAP and IFRS,” which provides amendments to FASB ASC Topic 820, “Fair Value Measurements and 

Disclosure” (“FASB ASC 820”) . The purpose of the amendments in this update is to create common fair value measurement and disclosure requirements 

between GAAP and IFRS. The amendments change certain fair value measurement principles and enhance the disclosure requirements. The amendments 

to FASB ASC 820 were effective for interim and annual periods beginning after December 15, 2011. Adoption of this ASU for reporting periods in 2012 

had no impact on the Company's financial position or results of operations. 

In June 2011, the FASB issued ASU 2011-05, “Comprehensive Income: Presentation of Comprehensive Income,” which provides amendments to 

FASB ASC Topic 220, “Comprehensive Income” (“FASB ASC 220”). The purpose of the amendments in this update is to provide a more consistent 

method of presenting non-owner transactions that affect an entity’s equity. The amendments eliminate the option to report other comprehensive income 

and its components in the statement of changes in stockholders’ equity and require an entity to present the total of comprehensive income, the components 

of net income and the components of other comprehensive income either in a single continuous statement or in two separate but consecutive statements. 

The amendments to FASB ASC 220 were effective for interim and annual periods beginning after December 15, 2011 and should be applied 

retrospectively. The Company adopted this ASU for reporting periods in 2012 and reports the components of net income and the components of other 

comprehensive income in two separate but consecutive statements. Adoption of this ASU had no impact on the Company's financial position or results of 

operations. 

 

Beginning in February 2011, the Company entered into agreements to acquire certain leasehold interests located in the Utica Shale in Ohio. Certain 

of the agreements also grant the Company an exclusive right of first refusal for a period of six months on certain additional tracts leased by the seller. 

Affiliates of Gulfport initially participated with the Company on a 50/50 basis in the acquisition of all leases described above. On December 17, 2012, 

Gulfport entered into a definitive agreement to purchase approximately 30,000 net acres in the Utica Shale in Eastern Ohio for approximately $302.0 

million . On December 19, 2012, the parties amended that agreement to provide for Gulfport's acquisition of approximately 7,000 additional net acres for 

approximately $70.0 million , resulting in a total purchase price of approximately $372.0 million , subject to certain adjustments. This transaction closed 

on December 24, 2012. At closing, approximately $53.9 million of the purchase price was placed in escrow pending completion of title review after the 

closing. The transaction, which increased Gulfport’s leasehold interests in the Utica Shale to approximately 137,000 gross ( 106,000 net) acres, excluded

14 existing wells, along with certain acreage surrounding each well. Gulfport will continue to serve as operator of its acreage in the Utica Shale. Gulfport 

funded this acquisition with a portion of the net proceeds from its common stock offering that closed on December 24, 2012. The Company received 

aggregate net proceeds (including the net proceeds from the partial exercise of the underwriters' over-allotment option) of approximately $427.9 million 

from this equity offering, as discussed below in Note 8. As of December 31, 2012, Gulfport has paid a total of $619.6 million for its Ohio acreage. 

F -12 

2. ACQUISITIONS 

3. ACCOUNTS RECEIVABLE—RELATED PARTIES 
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Index to Financial Statements 

Included in the accompanying consolidated balance sheets for the years ended December 31, 2012 and 2011 , are amounts receivable from related 

parties of the Company. These receivables consist primarily of amounts billed by the Company to related parties as operator of such parties' Colorado and

Ohio oil and gas properties. At December 31, 2012 and 2011 , these receivables totaled $34,848,000 and $4,731,000 , respectively. 

The Company is a party to administrative service agreements with Stampede Farms LLC ("Stampede"), Everest Operations Management LLC 

("Everest") and Tatex Thailand III, LLC ("Tatex III"), which agreements were each entered into effective March 1, 2008. Under these agreements, the 

Company’s 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 the Company with at least 60 days prior written notice, (2) by the counterparty at any 

time with at least 30 days prior written notice to the Company 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. The Company did not provide services under any of these agreements in 2010, 2011 or 

2012 and received no reimbursements thereunder. Each of Stampede, Everest and Tatex III is controlled by Wexford Capital LP ("Wexford"). Charles E. 

Davidson is the Chairman and Chief Investment Officer of Wexford and he beneficially owned approximately 13.3% and less than 1% of the Company’s 

outstanding common stock as of December 31, 2011 and September 28, 2012, respectively. 

For the years ended December 31, 2011 and 2010 , the Company was reimbursed approximately $66,000 and $20,000 , respectively, by Orange 

Leaf Holdings, LLC, an affiliate of Gulfport, for office space which is included in other income (expense) in the consolidated statements of operations. 

Effective July 1, 2008, the Company entered into an acquisition team agreement with Everest to identify and evaluate potential oil and gas 

properties in which the Company and Everest or its affiliates may wish to invest. Upon a successful closing of an acquisition or divestiture, the party 

identifying 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 may be terminated by either party upon 

30 days notice. Affiliates of Everest were billed approximately $1,087,000 and $1,184,000 under this acquisition team agreement during the years ended 

December 31, 2012 and 2011 , respectively, which amounts are reflected as a reduction of general and administrative expenses in the consolidated 

statements of operations. No amounts were reimbursed under the acquisition team agreement for the year ended 2010 . 

Effective April 1, 2010, the Company entered into an area of mutual interest agreement with Windsor Niobrara LLC (“Windsor Niobrara”), an 

entity controlled by Wexford, 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, Gulfport and Windsor 

Niobrara also entered into a development agreement, effective as of April 1, 2010, pursuant to which the Company and Windsor Niobrara agreed to 

jointly develop the contract area, and Gulfport agreed to act as the operator under the terms of a joint operating agreement. 

The major categories of property and equipment and related accumulated depletion, depreciation, amortization and impairment as of December 31, 

2012 and 2011 are as follows: 

 

No impairment of oil and natural gas properties was required under the ceiling test for the years ended December 31, 

F -13 

4. PROPERTY AND EQUIPMENT 

 December 31, 

 2012 2011 

Oil and natural gas properties $ 1,611,090,000 $ 1,035,754,000 

Office furniture and fixtures 4,476,000 3,692,000 

Building 3,926,000 4,049,000 

Land 260,000 283,000 

Total property and equipment 1,619,752,000 1,043,778,000 

Accumulated depletion, depreciation, amortization and impairment (665,884,000 ) (575,142,000 ) 

Property and equipment, net $ 953,868,000 

 $ 468,636,000 
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Index to Financial Statements 

2012 , 2011 and 2010 . 

Included in oil and natural gas properties at December 31, 2012 and 2011 is the cumulative capitalization of $ 32,562,000 and $ 23,494,000 , 

respectively, in general and administrative costs incurred and capitalized to the full cost pool. General and administrative costs capitalized to the full cost 

pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other 

administrative costs associated with overseeing the exploration and development activities. All general and administrative costs not directly associated 

with exploration and development activities were charged to expense as they were incurred. Capitalized general and administrative costs were 

approximately $ 9,068,000 , $ 5,368,000 and $ 4,117,000 for the years ended December 31, 2012 , 2011 and 2010 , respectively. 

The following is a summary of Gulfport’s oil and gas properties not subject to amortization as of December 31, 2012 : 

 

At December 31, 2012, approximately $ 295,000 of non-producing leasehold costs related to the Company’s Bakken properties and $ 5,998,000 of 

non-producing leasehold costs related to the Company’s Colorado properties are excluded from amortization. In addition, approximately $ 774,000 of 

non-producing leasehold costs related to the Company’s Southern Louisiana assets, $ 619,182,000 of non-producing leasehold costs related to the 

Company’s Ohio leasehold costs and $ 46,000 of non-producing leasehold costs related to other projects are also excluded from amortization. At 

December 31, 2011 , approximately $138,623,000 of non-producing leasehold costs was not subject to amortization. 

During the year ended December 31, 2012, the Company determined that further development of its non-producing leasehold assets located in 

Belize was not in alignment with its current strategic operating plan and therefore recognized a loss on disposal of assets, net of tax, of approximately $3.5 

million which is included in discontinued operations on the accompanying consolidated statements of operations for the year ended December 31, 2012 . 

The Company evaluates the costs excluded from its amortization calculation at least annually. Subject to industry conditions and the level of the 

Company’s activities, the inclusion of most of the above referenced costs into the Company’s amortization calculation is expected to occur within three to 

five years. 

A reconciliation of the asset retirement obligation for the years ended December 31, 2012 and 2011 is as follows: 

 

On May 7, 2012, the Company entered into a contribution agreement with Diamondback. Under the terms of the contribution agreement, the 

Company agreed to contribute to Diamondback, prior to the closing of the Diamondback initial public offering (“Diamondback IPO”), all its oil and gas 

interests in the Permian Basin (the "Contribution"). The Contribution was completed on October 11, 2012. At the closing of the Contribution, 

Diamondback issued to the Company (i) 7,914,036 shares of Diamondback common stock and (ii) a promissory note for $ 63.6 million , which was repaid 

to the Company at the closing of the Diamondback IPO on October 17, 2012. This aggregate consideration was subject to a post-closing cash 

F -14 

 Costs Incurred in 

 2012 2011 2010 Prior to 2010 Total 

Acquisition costs $ 512,636,000 $ 112,591,000 $ 661,000 $ 407,000 $ 626,295,000 

Exploration costs — — — — —

Development costs — — — — —

Total oil and gas properties not subject to 

amortization $ 512,636,000 

 $ 112,591,000  $ 661,000  $ 407,000  $ 626,295,000 

 December 31, 

 2012 2011 

Asset retirement obligation, beginning of period $ 12,653,000 $ 10,845,000 

Liabilities incurred 2,195,000 1,390,000 

Liabilities settled (2,271,000 ) (248,000 ) 

Accretion expense 698,000 666,000 

Asset retirement obligation as of end of period 13,275,000 12,653,000 

Less current portion 60,000 620,000 

Asset retirement obligation, long-term $ 13,215,000 

 $ 12,033,000 
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Index to Financial Statements 

adjustment based on changes in the working capital, long-term debt and certain other items of Diamondback O&G LLC, formerly Windsor Permian LLC 

("Diamondback O&G"), as of the date of the Contribution. In January 2013, the Company received an additional payment from Diamondback of 

approximately $18.6 million as a result of this post-closing adjustment which is included in accounts receivable - related parties on the accompanying 

consolidated balance sheets. Diamondback O&G is a wholly-owned subsidiary of Diamondback. Under the contribution agreement, the Company is 

generally responsible for all liabilities and obligations with respect to the contributed properties arising prior to the Contribution and Diamondback is

responsible for such liabilities and obligations with respect to the contributed properties arising after the Contribution. 

In accordance with the Company's policy under the full cost method of accounting to only recognize a gain or loss upon the disposal of oil and 

natural gas properties if such dispositions significantly alter the relationship between capitalized costs and proven oil and natural gas reserves, the 

Company recognized a gain on the sale of its Permian Basin assets of approximately $7.3 million , which is included in the accompanying consolidated 

statements of operations for the year ended December 31, 2012 . In addition, the Company recorded a reduction to its full cost pool of approximately 

$213.0 million as a result of the Contribution. 

In connection with the Contribution, the Company and Diamondback entered into an investor rights agreement under which the Company has the 

right, for so long as it beneficially owns more than 10% of Diamondback’s outstanding common stock, to designate one individual as a nominee to serve 

on Diamondback’s board of directors. Such nominee, if elected to Diamondback’s board, will also serve on each committee of the board so long as he or 

she satisfies the independence and other requirements for service on the applicable committee of the board. So long as the Company has the right to 

designate a nominee to Diamondback’s board and there is no Gulfport nominee actually serving as a Diamondback director, the Company has the right to 

appoint one individual as an advisor to the board who shall be entitled to attend board and committee meetings. The Company is also entitled to certain 

information rights and Diamondback granted the Company certain demand and “piggyback” registration rights obligating Diamondback to register with 

the Securities and Exchange Commission (the "SEC") any 

shares of Diamondback common stock that the Company owns. Immediately upon completion of the Contribution, the Company owned a 35% equity 

interest in Diamondback, rather than leasehold interests in the Company’s Permian Basin acreage. Upon completion of the Diamondback IPO on October 

17, 2012, Gulfport owned approximately 22.5% of Diamondback's outstanding common stock. On October 18, 2012, the underwriters of the 

Diamondback IPO exercised in full their option to purchase additional shares of common stock of Diamondback and, upon the closing of such purchase 

on October 23, 2012, Gulfport owned approximately 21.4% of Diamondback's outstanding common stock. Following the Contribution, the Company 

accounts for its interest in Diamondback as an equity investment. 

Investments accounted for by the equity method consist of the following as of December 31, 2012 and 2011 : 

 

Tatex Thailand II, LLC 

F -15 

5. EQUITY INVESTMENTS 

 December 31, 

 2012 2011 

Investment in Tatex Thailand II, LLC $ 203,000 $ 1,030,000 

Investment in Tatex Thailand III, LLC 8,657,000 8,282,000 

Investment in Grizzly Oil Sands ULC 172,766,000 69,008,000 

Investment in Bison Drilling and Field Services LLC 13,518,000 6,366,000 

Investment in Muskie Holdings LLC 7,320,000 2,138,000 

Investment in Timber Wolf Terminals LLC 878,000 —

Investment in Windsor Midstream LLC 9,503,000 —

Investment in Stingray Pressure Pumping LLC 13,265,000 —

Investment in Stingray Cementing LLC 3,110,000 —

Investment in Blackhawk Midstream LLC — —

Investment in Stingray Logistics LLC 947,000 —

Investment in Diamondback Energy LLC 151,317,000 —

 $ 381,484,000  $ 86,824,000 
Table of Contents 

Index to Financial Statements 

The Company has a 23.5% ownership interest in Tatex Thailand II, LLC (“Tatex”). The remaining interests in Tatex are owned by entities 

controlled by Wexford. Tatex holds 85,122 of the 1,000,000 outstanding shares of APICO, LLC (“APICO”), an international oil and gas exploration 

company. APICO has a reserve base located in Southeast Asia through its ownership of concessions covering approximately 243,000 acres which includes 

the Phu Horm Field. During the year ended December 31, 2012 , Gulfport received $820,000 in distributions, reducing its total net investment in Tatex to 

$203,000 . The loss on equity investment related to Tatex was immaterial for the years ended December 31, 2012 , 2011 and 2010 . 

Tatex Thailand III, LLC 

The Company has a 17.9% ownership interest in Tatex Thailand III, LLC (“Tatex III”). Approximately 68.7% of the remaining interests in Tatex III 

are owned by entities controlled by Wexford. During the year ended December 31, 2012 , Gulfport paid $ 626,000 in cash calls, increasing its total net 

investment in Tatex III to $ 8,657,000 . The Company recognized a loss on equity investment of $ 251,000 , $ 172,000 and $ 224,000 for the years ended 

December 31, 2012 , 2011 and 2010 , respectively, which is included in (income) loss from equity method investments in the consolidated statements of 

operations. 

Grizzly Oil Sands ULC 

The Company, through its wholly owned subsidiary Grizzly Holdings Inc. ("Grizzly Holdings"), owns a 24.9999% interest in Grizzly Oil Sands 

ULC, ("Grizzly") a Canadian unlimited liability company. The remaining interest in Grizzly is owned by an entity controlled by Wexford. Since 2006 , 

Grizzly has acquired leases in the Athabasca region located in the Alberta Province near Fort McMurray near other oil sands development projects. 

Grizzly has drilled core holes and water supply test wells in ten separate lease blocks for feasibility of oil production and conducted a seismic program. In 

March 2010 , Grizzly filed an application in Alberta, Canada for the development of a steam-assisted gravity drainage ("SAGD") facility 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 formal regulatory approval of the project. During 2012, Grizzly finished SAGD well pair drilling at Algar Lake and began the process of 

completing those well pairs for SAGD injection and production and continued the fabrication and onsite construction of the Algar Lake facility. In the 

first quarter of 2012, Grizzly completed the acquisition of approximately 47,000 acres through the purchase of its May River property and has prepared a 

full field development plan under which the May River property will be developed in multiple phases. In 2012, Grizzly submitted a SAGD project 

regulatory application for the development of a project at Thickwood Hills. During the year ended December 31, 2012 , Gulfport paid $ 103,915,000 in 

cash calls and recorded a currency translation gain of $ 1,355,000 , increasing its total net investment in Grizzly to $ 172,766,000 at December 31, 2012. 

Grizzly’s functional currency is the Canadian dollar. The Company recognized a loss on equity investment of $ 1,512,000 , $ 1,592,000 and $ 740,000 for 

the years ended December 31, 2012 , 2011 and 2010 , respectively, which is included in (income) loss from equity method investments in the consolidated 

statements of operations. 

The Company, through its wholly owned subsidiary Grizzly Holdings Inc., entered into a loan agreement with Grizzly effective January 1, 2008 , 

under which Grizzly borrowed funds from the Company. Borrowed funds initially bore interest at LIBOR plus 400 basis points 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. The Company loaned Grizzly approximately $ 

3,182,000 during the year ended December 31, 2011 . The Company recognized interest income of approximately $ 147,000 and $ 267,000 for the years 

ended December 31, 2011 and 2010 , which is included in interest income in the consolidated statements of operations. 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 by issuing

additional common shares of Grizzly with no effect to the composition of ownership structure of Grizzly. At such date, the Company’s investment in 

Grizzly increased by the total $ 22,325,000 outstanding advances and accrued interest due from Grizzly, the cumulative $ 75,000 currency translation loss

for the note receivable was adjusted through accumulated other comprehensive income and the note receivable was considered paid in full. 

The tables below summarize financial information for Grizzly as of December 31, 2012 , 2011 and 2010 : 

Summarized balance sheet information: 

F -16 
Table of Contents 

Index to Financial Statements 

Summarized results of operations: 

Bison Drilling and Field Services LLC 

During the third quarter of 2011 , the Company purchased a 25% ownership interest in Bison Drilling and Field Services LLC (“Bison”) at a cost of 

$ 6,009,000 , subject to adjustment. In April 2012, the Company purchased an additional 15% ownership interest in Bison for $6,152,000 , bringing its 

total ownership interest in Bison to 40% . The remaining interests in Bison are owned by entities controlled by Wexford. Bison owns and operates drilling 

rigs. During the year ended December 31, 2012, Gulfport paid $ 1,373,000 in cash calls, increasing its total net investment in Bison to $ 13,518,000 . The 

Company recognized a loss on its equity investment in Bison of $ 373,000 for the year ended December 31, 2012 , and income of $ 357,000 for the year 

ended December 31, 2011 , which amounts are included in (income) loss from equity method investments in the consolidated statements of operations. 

The Company entered into a loan agreement with Bison effective May 15, 2012, under which Bison may borrow funds from the Company. Interest 

accrues at LIBOR plus 0.28% or 8% , whichever is lower, and shall be paid on a paid-in-kind basis by increasing the outstanding balance of the loan. The 

loan has a maturity date of January 31, 2015. The Company loaned Bison $1,594,000 during the first nine months of 2012, all of which was repaid by 

Bison during the third quarter of 2012. The interest income recognized on the note was immaterial for the year ended December 31, 2012 . 

Muskie Holdings LLC 

During the fourth quarter of 2011 , the Company purchased a 25% ownership interest in Muskie Holdings LLC (“Muskie”) at a cost of $ 2,142,000 , 

subject to adjustment. The remaining interests in Muskie are owned by entities controlled by Wexford. Muskie holds certain rights in a lease covering 

land in Wisconsin for mining oil and natural gas fracture grade sand. During the year ended December 31, 2012 , Gulfport paid $ 6,213,000 in cash calls, 

increasing its total net investment in Muskie to $ 7,320,000 . The Company recognized a loss on equity investment of $ 1,031,000 for the year ended 

December 31, 2012 , which is included in (income) loss from equity method investments in the consolidated statements of operations. The loss on equity 

investment related to Muskie was immaterial for the year ended December 31, 2011 . 

Timber Wolf Terminals LLC 

During the first quarter of 2012, the Company purchased a 50% ownership interest in Timber Wolf Terminals LLC (“Timber Wolf”) at a cost of $ 

1,000,000 . The remaining interests in Timber Wolf are owned by entities controlled by Wexford. Timber Wolf will operate a crude/condensate terminal 

and a sand transloading facility in Ohio. The Company recognized a loss on equity investment of $ 122,000 for the year ended December 31, 2012 , which 

is included in (income) loss from equity method investments in the consolidated statements of operations. 

Windsor Midstream LLC 

During the first quarter of 2012, the Company purchased a 22.5% ownership interest in Windsor Midstream LLC (“Midstream”) at a cost of 

$7,021,000 . The remaining interests in Midstream are owned by entities controlled by Wexford. Midstream owns a 28.4% interest in MidMar Gas LLC, a 

gas processing plant in West Texas. During the year ended 

F -17 

 December 31, 

 2012 2011 

Current assets $ 30,098,000 $ 21,247,000 

Noncurrent assets $ 720,550,000 $ 284,361,000 

Current liabilities $ 42,547,000 $ 25,984,000 

Noncurrent liabilities $ 14,515,000 $ 1,780,000 

 December 31, 

 2012 2011 2010 

Gross revenue $ — $ — $ —

Net loss $ 6,050,000 $ 6,605,000 $ 3,234,000 
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Index to Financial Statements 

December 31, 2012 , the Company paid $ 1,819,000 in cash calls, increasing its total net investment in Midstream to $ 9,503,000 . The Company 

recognized income on equity investment of $ 663,000 for the year ended December 31, 2012 , which is included in (income) loss from equity method 

investments in the consolidated statements of operations. 

Stingray Pressure Pumping LLC 

During the second quarter of 2012, the Company purchased a 50% ownership interest in Stingray Pressure Pumping LLC ("Stingray Pressure"). The 

remaining interests in Stingray Pressure are owned by entities affiliated with Wexford. Stingray Pressure provides well completion services. During the 

year ended December 31, 2012 , the Company paid $ 14,500,000 in cash calls, increasing its total net investment in Stingray Pressure to $13,265,000 . 

The Company recognized a loss on equity investment of $ 1,235,000 for the year ended December 31, 2012 , which is included in (income) loss from 

equity method investments in the consolidated statements of operations. 

Stingray Cementing LLC 

During the second quarter of 2012, the Company purchased a 50% ownership interest in Stingray Cementing LLC ("Stingray Cementing"). The 

remaining interests in Stingray Cementing are owned by entities affiliated with Wexford. Stingray Cementing provides well cementing services. During 

the year ended December 31, 2012 , the Company paid $ 3,269,000 in cash calls, increasing its net investment in Stingray Cementing to $ 3,110,000 . The 

Company recognized a loss on equity investment of $ 159,000 for the year ended December 31, 2012 , which is included in (income) loss from equity 

method investments in the consolidated statements of operations. 

Blackhawk Midstream LLC 

During the second quarter of 2012, the Company purchased a 50% ownership interest in Blackhawk Midstream LLC ("Blackhawk"). The remaining 

interest in Blackhawk is owned by an entity controlled by Wexford. Blackhawk coordinates gathering, compression, processing and marketing activities 

for the Company in connection with the development of its Utica Shale acreage. During the year ended December 31, 2012 , the Company paid $ 436,000 

in cash calls. The Company recognized a loss on equity investment of $ 436,000 for the year ended December 31, 2012 , which is included in (income) 

loss from equity method investments in the consolidated statements of operations. 

Stingray Logistics LLC 

During the fourth quarter of 2012, the Company purchased a 50% ownership interest in Stingray Logistics LLC ("Stingray Logistics"). The 

remaining interests in Stingray Logistics are owned by entities affiliated with Wexford. Stingray Logistics provides well services. During the year ended

December 31, 2012 , the Company paid $ 983,000 in cash calls. The Company recognized a loss on equity investment of $ 36,000 for the year ended 

December 31, 2012, which is included in (income) loss from equity method investments in the consolidated statements of operations. 

Diamondback Energy, Inc. 

As noted above in Note 4, on May 7, 2012, the Company entered into a contribution agreement with Diamondback. Under the terms of the 

contribution agreement, the Company agreed to contribute to Diamondback, prior to the closing of the Diamondback IPO, all its oil and gas interests in 

the Permian Basin. The Contribution was completed on October 11, 2012. At the closing of the Contribution, Diamondback issued to the Company (i) 

7,914,036 shares of Diamondback common stock and (ii) a promissory note for $63.6 million , which was repaid to the Company at the closing of the 

Diamondback IPO on October 17, 2012. Following the closing of the Diamondback IPO, the Company owned approximately 21.4% of Diamondback's 

outstanding common stock for an initial investment in Diamondback of $ 138,496,000 . The Company accounts for its interest in Diamondback as an 

equity method investment and has elected the fair value option of accounting and valued its investment in Diamondback using the quoted closing market 

price of Diamondback's stock on December 31, 2012 of $19.12 per share multiplied by the Company's number of outstanding shares of Diamondback's 

stock. The Company's investment in Diamondback totaled $151,317,000 at December 31, 2012 . The Company recognized a gain on equity investment of 

$ 12,821,000 for the year ended December 31, 2012 , which is included in (income) loss from equity method investments in the consolidated statements of 

operations. 

The tables below summarize financial information for Diamondback as of December 31, 2012 , 2011 and 2010 : 

Summarized balance sheet information: 

F -18 
Table of Contents 

Index to Financial Statements 

Summarized results of operations: 

Other assets consist of the following as of December 31, 2012 and 2011 : 

 

 

A break-down of long-term debt as of December 31, 2012 and 2011 is as follows: 

Maturities of long-term debt (excluding premiums and discounts) as of December 31, 2012 are as follows: 

F -19 

 December 31, 

 2012 2011 

Current assets $ 50,275,000 $ 30,812,000 

Noncurrent assets $ 556,426,000 $ 232,766,000 

Current liabilities $ 79,232,000 $ 42,298,000 

Noncurrent liabilities $ 65,401,000 $ 92,243,000 

 December 31, 

 2012 2011 2010 

Gross revenue $ 74,962,000 $ 49,366,000 $ 27,253,000 

Income from operations $ 17,307,000 $ 15,147,000 $ 9,181,000 

Net income (loss) $ (36,521,000 ) $ (386,000 ) $ 8,231,000 

6. OTHER ASSETS 

 December 31, 

 2012 2011 

Plugging and abandonment escrow account on the WCBB properties (Note 16) $ 3,113,000 $ 3,121,000 

Certificates of Deposit securing letter of credit 275,000 275,000 

Prepaid drilling costs 515,000 228,000 

Loan commitment fees 9,388,000 1,495,000 

Deposits 4,000 4,000 

 $ 13,295,000  $ 5,123,000 

7. LONG-TERM DEBT 

 December 31, 

 2012 2011 

Revolving credit agreement (1) $ — $ —

Building loans (2) 2,143,000 2,283,000 

7.75% senior unsecured notes due 2020 (3) 300,000,000 —

Unamortized original issue (discount) premium, net (4) (3,105,000 ) —

Less: current maturities of long term debt (150,000 ) (141,000 ) 

Debt reflected as long term $ 298,888,000 

 $ 2,142,000 
Table of Contents 

Index to Financial Statements 

(1) On September 30, 2010, the Company entered into a $100 million senior secured revolving credit agreement with The Bank of Nova Scotia, as 

administrative agent and letter of credit issuer and lead arranger, and Amegy Bank National Association ("Amegy Bank"). The revolving credit facility 

initially matured on September 30, 2013 and had an initial borrowing base availability of $50.0 million , which was increased to $65.0 million effective 

December 24, 2010. The amounts borrowed under the credit agreement were used to repay all of the Company’s outstanding indebtedness under its prior 

revolving credit facility ( $42.0 million ) and term loan ( $2.5 million ), each with Bank of America, N.A., as administrative agent, and for general 

corporate purposes. The credit agreement is secured by substantially all of the Company’s assets. The Company’s wholly-owned subsidiaries guaranteed 

the obligations of the Company under the credit agreement. 

On May 3, 2011, the Company entered into a first amendment to the revolving credit agreement with The Bank of Nova Scotia, Amegy Bank, 

KeyBank National Association (“KeyBank”) and Société Générale. Pursuant to the terms of the first amendment, KeyBank and Société Générale were 

added as additional lenders, the maximum amount of the facility was increased to $350.0 million , the borrowing base was increased to $90.0 million , 

certain fees and rates payable by the Company under the credit agreement were decreased, and the maturity date was extended until May 3, 2015. On 

October 31, 2011, the Company entered into additional amendments to its revolving credit facility pursuant to which, among other things, the borrowing 

base under this facility was increased to $125.0 million . 

Effective May 2, 2012, the Company entered into a fourth amendment to its revolving credit facility under which, among other things, the borrowing 

base was increased to $155.0 million and Credit Suisse, Deutsche Bank Trust Company Americas and Iberiabank were added as additional lenders and 

Société Générale left the bank group. 

On October 9, 2012, and October 17, 2012, the Company entered into a fifth amendment and a sixth amendment, respectively, to the revolving 

credit agreement. The fifth amendment modified certain covenants in the credit agreement to permit the Company to issue senior unsecured notes in an 

aggregate principal amount of up to $300.0 million and provided for a reduction in the borrowing base to an amount to be determined upon the completion 

of any senior unsecured notes issuance. The sixth amendment lowered the applicable rate set forth in the credit agreement (i) from a range of 1.00% to 

1.75% to a range of 0.75% to 1.50% for the base rate loans and (ii) from a range of 2.00% to 2.75% to a range of 1.75% to 2.50% for the Eurodollar rate 

loans and letters of credit. The sixth amendment lowered the commitment fees for Level 1 and Level 2 usage levels, in each case, from 0.50% per annum 

to 0.375% per annum. Also, effective as of October 17, 2012, in connection with the Company's completion of the offering of $250.0 million 7.750% 

senior unsecured notes due 2020, (the "October Notes"), the repayment of all outstanding amounts under the revolving credit agreement with the proceeds 

of the October Notes, and the contribution of Gulfport’s oil and natural gas interests in the Permian Basin to Diamondback discussed in Note 4 above, 

Gulfport’s borrowing base under the credit agreement was reduced to $45.0 million until the next borrowing base redetermination. In conjunction with the 

lowering of the borrowing base in October 2012, the Company expensed a proportional amount of the unamortized loan fees associated with the revolving 

credit facility totaling approximately $1,088,000 , which is included in interest expense on the accompanying consolidated statements of operations. 

On December 18, 2012, the Company entered into a seventh amendment to the revolving credit agreement under which the Company was permitted 

to issue $50.0 million 7.750% senior unsecured notes due 2020, (the "December Notes") under the same indenture as the October Notes, (collectively, the 

"Notes") and upon the issuance of the December Notes, the borrowing base under the revolving credit agreement was reduced from $45.0 million to $40.0 

million until the next borrowing base redetermination. As of December 31, 2012 , the Company had no balance outstanding under the revolving credit 

agreement. In conjunction with the lowering of the borrowing base in December 2012, the Company expensed a proportional amount of unamortized loan 

fees associated with the revolving credit facility totaling approximately $55,000 , which is included in interest expense on the accompanying consolidated 

statements of operations. 

Advances under the credit agreement, as amended, may be in the form of either base rate loans or eurodollar loans. The interest rate for base rate 

loans is equal to (1) the applicable rate, which ranges from 0.75% to 1.50% , plus (2) the highest of: 

F -20 

2013 $ 150,000 

2014 158,000 

2015 168,000 

2016 1,667,000 

2017 —

Thereafter 300,000,000 

Total $ 302,143,000 
Table of Contents 

Index to Financial Statements 

(a) the federal funds rate plus 0.50% , (b) the rate of interest in effect for such day as publicly announced from time to time by agent as its “prime rate,” 

and (c) the eurodollar rate for an interest period of one month plus 1.00% . The interest rate for eurodollar loans is equal to (1) the applicable rate, which 

ranges from 1.75% to 2.50% , plus (2) the London interbank offered rate that appears on Reuters Screen LIBOR01 Page for deposits in U.S. dollars, or, if 

such rate is not available, the offered rate on such other page or service that displays the average British Bankers Association Interest Settlement Rate for 

deposits in U.S. dollars, or, if such rate is not available, the average quotations for three major New York money center banks of whom the agent shall 

inquire as the “London Interbank Offered Rate” for deposits in U.S. dollars. At October 17, 2012 (the latest date during the year ended December 31, 

2012 on which the Company had borrowings outstanding), amounts borrowed under the revolving credit agreement bore interest at the Eurodollar rate 

( 2.97% ). 

The credit agreement contains customary negative covenants including, but not limited to, restrictions on the Company’s and its subsidiaries’ ability 

to: 

• incur indebtedness; grant liens; 

• pay dividends and make other restricted payments; 

• make investments; 

• make fundamental changes; 

• enter into swap contracts and forward sales contracts; 

• dispose of assets; 

• change the nature of their business; and 

• enter into transactions with their affiliates. 

The negative covenants are subject to certain exceptions as specified in the credit agreement. The credit agreement also contains certain affirmative 

covenants, including, but not limited to the following financial covenants: 

(i) the ratio of funded debt to EBITDAX (net income, excluding any non-cash revenue or expense associated with swap contracts resulting from 

ASC 815, plus without duplication and to the extent deducted from revenues in determining net income, the sum of (a) the aggregate amount of 

consolidated interest expense for such period, (b) the aggregate amount of income, franchise, capital or similar tax expense (other than ad valorem taxes) 

for such period, (c) all amounts attributable to depletion, depreciation, amortization and asset or goodwill impairment or writedown for such period, (d) all 

other non-cash charges, (e) non-cash losses from minority investments, (f) actual cash distributions received from minority investments, (g) to the extent 

actually reimbursed by insurance, expenses with respect to liability on casualty events or business interruption, and (h) all reasonable transaction expenses 

related to dispositions and acquisitions of assets, investments and debt and equity offering, and less non-cash income attributable to equity income from

minority investments) for a twelve-month period may not be greater than 2.00 to 1.00 ; and 

(ii) the ratio of EBITDAX to interest expense for a twelve-month period may not be less than 3.00 to 1.00 . The Company was in compliance with 

all covenants at December 31, 2012 . 

(2) In March 2011, the Company entered into a new building loan agreement for the office building it occupies in Oklahoma City, Oklahoma. The 

new loan agreement refinanced the $2.4 million outstanding under the previous building loan agreement. The new agreement matures in February 2016 

and bears interest at the rate of 5.82% per annum. The new building loan requires monthly interest and principal payments of approximately $22,000 and 

is collateralized by the Oklahoma City office building and associated land. 

(3) On October 17, 2012, the Company issued the $250.0 million October Notes to qualified institutional buyers pursuant to Rule 144A under the 

Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act, (the "October Notes Offering") under an 

indenture among the Company, its subsidiary guarantors and Wells Fargo Bank, National Association, as the trustee, (the "senior note indenture"). On 

December 21, 2012, the Company issued an additional $50.0 million in aggregate principal amount of December Notes, to qualified institutional buyers 

pursuant to Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act, ("the December 

Notes Offering"). The December Notes were issued as additional securities under the senior note indenture. The October Notes Offering and the 

December Notes Offering are collectively referred to as the "Notes Offerings". The Company used a portion of the net proceeds from the October Notes 

Offering to repay all amounts outstanding at such time under its revolving credit 

F -21 
Table of Contents 

Index to Financial Statements 

facility. The Company intends to use the remaining net proceeds of October Notes Offering and the net proceeds of the December Notes Offering for 

general corporate purposes, which may include funding a portion of its 2013 capital development plan. 

Under the senior note indenture, interest on the Notes accrues at a rate of 7.750% per annum on the outstanding principal amount from October 17, 

2012, payable semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013. The Notes are the Company's senior unsecured 

obligations and rank equally in the right of payment with all of the Company's other senior indebtedness and senior in right of payment to any future 

subordinated indebtedness. All of the Company's existing and future restricted subsidiaries that guarantee the Company's secured revolving credit facility 

or certain other debt guarantee the Notes; provided, however, that the Notes are not guaranteed by Grizzly Holdings, Inc. and will not be guaranteed by 

any of the Company's future unrestricted subsidiaries. The Company may redeem some or all of the Notes at any time on or after November 1, 2016, at 

the redemption prices listed in the senior note indenture. Prior to November 1, 2016, the Company may redeem the Notes at a price equal to 100% of the 

principal amount plus a “make-whole” premium. In addition, prior to November 1, 2015, the Company may redeem up to 35% of the aggregate principal 

amount of the Notes with the net proceeds of certain equity offerings, provided that at least 65% of the aggregate principal amount of the Notes initially 

issued remains outstanding immediately after such redemption. 

(4) The October Notes were issued at a price of 98.534% resulting in a gross discount of $3,665,000 and an effective rate of 8.000% . The December 

Notes were issued at a price of 101.000% resulting in a gross premium of $500,000 and an effective rate of 7.531% . The premium and discount are being 

amortized using the effective interest method. 

Interest Expense 

The following schedule shows the components of interest expense at December 31, 2012 and 2011 : 

Options 

The Company sponsors the 1999 Stock Option Plan (the “Plan”), which is administered by the Compensation Committee (the “Committee”) of the 

Board of Directors of the Company. Under the terms of the Plan, the Committee could determine: to which eligible participants options shall be granted, 

the number of shares covered by such options, the purchase price or exercise price of such options, the vesting period of such options and the exercisable 

period of such options. Eligible participants are defined as all directors of the Company, all officers of the Company and all key employees of the 

Company with a customary work week of at least 40 hours in the employ of the Company. The maximum number of shares for which options could be 

granted under the Plan, as adjusted for changes in capitalization which have taken place since the Plan’s adoption, was 883,000 . The Company has 

granted 627,337 options for the purchase of shares of the Company’s common stock under the Plan as of December 31, 2012 . No additional securities 

will be issued under the Plan other than upon exercise of options that are outstanding. 

The Company replaced the Plan in January 2005 with the 2005 Stock Incentive Plan (“2005 Plan”), which is administered by the Committee. Under 

the terms of the 2005 Plan, the Committee may determine when options shall be granted, to which eligible participants options shall be granted, the 

number of shares covered by such options, the purchase price or exercise price of such options, the vesting periods of such options and the exercisable 

period of such options. Eligible participants are defined as employees, consultants, and directors of the Company. 

On April 20, 2006, the Company amended and restated the 2005 Plan to (i) include (a) Incentive Stock Options, 

F -22 

 December 31, 

 2012 2011 

Cash paid for interest $ 1,404,000 $ 963,000 

Change in accrued interest 4,155,000 (132,000 ) 

Write-off of deferred loan costs 1,143,000 —

Amortization of loan costs 640,000 540,000 

Amortization of note discount and premium 59,000 —

Other 57,000 29,000 

Total interest expense $ 7,458,000 

 $ 1,400,000 

8. COMMON STOCK OPTIONS, WARRANTS AND CHANGES IN CAPITALIZATION 
Table of Contents 

Index to Financial Statements 

(b) Nonstatutory Stock Options, (c) Restricted Awards (Restricted Stock and Restricted Stock Units), (d) Performance Awards and (e) Stock Appreciation 

Rights and (ii) increase the maximum aggregate amount of common stock that may be issued under the 2005 Plan from 1,904,606 shares to 3,000,000 

shares, including the 627,337 shares underlying options granted to employees under the Plan prior to adoption of the 2005 Plan. As of December 31, 

2012 , the Company has granted 997,269 options for the purchase of shares of the Company’s common stock under the 2005 Plan. The shares of stock 

issued once the options are exercised will be from authorized but unissued common stock. 

Sale of Common Stock 

On May 19, 2010, the Company sold 1,481,481 shares of its common stock in an underwritten public offering at a public offering price of $13.50 

per share less the underwriting discount. On May 25, 2010, the Company sold an additional 187,022 shares of common stock at the public offering price 

less the underwriting discount in connection with the underwriters’ partial exercise of the over-allotment option granted to them by the Company. The 

Company received the aggregate net proceeds of approximately $21.6 million from the sale of these shares after deducting the underwriting discount and 

before offering expenses. A portion of the net proceeds from the offering was used to fund the Company’s Niobrara Formation and Permian Basin 

acquisitions. The remaining net proceeds from this offering were used for general corporate purposes, including expenditures associated with the 

Company’s 2010 drilling programs. 

On March 30, 2011, the Company completed the sale of an aggregate of 2,760,000 shares of its common stock in an underwritten public offering at 

a public offering price of $32.00 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $84.3 million 

from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used the net proceeds from the equity 

offering to fund the Company’s acquisition of leases in the Utica Shale as discussed in Note 2 and for general corporate purposes. Pending the application 

of the Company’s net proceeds for such purposes, the Company repaid all of its outstanding indebtedness under its revolving credit agreement. 

On July 15, 2011, the Company completed the sale of an aggregate of 3,450,000 shares of its common stock in an underwritten public offering at a 

public offering price of $28.75 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $94.7 million 

from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used a portion of the net proceeds 

from the equity offering to fund the Company’s acquisition of leases in the Utica Shale as discussed in Note 2 and for general corporate purposes. Pending 

the application of the Company’s net proceeds for such purposes, the Company repaid all of its outstanding indebtedness under its revolving credit 

agreement. 

On December 5, 2011, the Company completed the sale of an aggregate of 4,600,000 shares of its common stock in an underwritten public offering 

at a public offering price of $29.00 per share less the underwriting discount. The Company received aggregate net proceeds of approximately $128.0 

million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used the proceeds to fund 

capital expenditures associated with drilling, development and infrastructure, principally in the Utica Shale in Ohio and for general corporate purposes. 

On December 24, 2012, the Company completed the sale of an aggregate of 11,750,000 shares of its common stock in an underwritten public 

offering (including the partial exercise of an over-allotment option for 1,650,000 shares granted to the underwriters, which option was exercised to the 

extent of 750,000 shares) at a public offering price of $38.00 per share less the underwriting discount. The Company received aggregate net proceeds 

(including the net proceeds from the sale of the shares of common stock to the underwriters under their over-allotment option) of approximately $427.9 

million from the sale of these shares after deducting the underwriting discount and before offering expenses. The Company used the net proceeds in part 

to fund the acquisition of additional Utica Shale acreage as discussed in Note 2. 

Private Placement Offering 

In March 2002, the Company completed a private placement offering of 10,000 units. Each unit consisted of (i) one share of Cumulative Preferred 

Stock, Series A, of the Company (the “Preferred”) and (ii) a warrant to purchase up to 250 shares of common stock, par value $0.01 per share, of the 

Company (the “Warrants”). Holders of the Preferred were entitled to receive dividends at the rate of 12% of the liquidation preference per annum payable 

quarterly in cash or, at the option of the Company for all quarters ending on or prior to March 31, 2004, payable in whole or in part in additional shares of 

Preferred at the rate of 15% of the liquidation preference per annum. All Preferred shares were redeemed in 2005. 

The 2,322,962 Warrants issued had a term of 10 years and a current exercise price of $1.19 per share of common stock subject to adjustment. The 

Company granted to holders of the Warrants certain demand and piggyback registration rights with respect to shares of common stock issuable upon 

exercise of the Warrants. The 8,875 unexercised warrants expired on March 

F -23 
Table of Contents 

Index to Financial Statements 

31, 2012. 

 

During the years ended December 31, 2012 , 2011 and 2010 , the Company’s stock-based compensation cost was $ 4,688,000 , $ 1,287,000 and $ 

492,000 , respectively, of which the Company capitalized $ 1,875,000 , $ 515,000 and $ 197,000 , respectively, relating to its exploration and 

development efforts. 

The fair value of each option award is estimated on the date of grant using the Black-Scholes option valuation model. Expected volatilities are based 

on the historical volatility of the market price of Gulfport’s common stock over a period of time ending on the grant date. Based upon the historical 

experience of the Company, the expected term of options granted is equal to the vesting period plus one year. The risk-free rate for periods within the 

contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant. The 2005 Plan provides that all options must have 

an exercise price not less than the fair value of the Company’s common stock on the date of the grant. 

No stock options were issued during the years ended December 31, 2012 , 2011 and 2010 . 

The Company has not declared dividends and does not intend to do so in the foreseeable future, and thus did not use a dividend yield. In each case, 

the actual value that will be realized, if any, depends on the future performance of the common stock and overall stock market conditions. There is no 

assurance that the value an optionee actually realizes will be at or near the value estimated using the Black-Scholes model. 

A summary of the status of stock options and related activity for the years ended December 31, 2012 , 2011 and 2010 are presented below: 

 

Unrecognized compensation expense as of December 31, 2012 related to outstanding stock options and restricted shares was $ 6,745,000 . The 

expense is expected to be recognized over a weighted average period of 1.55 years. 

The following table summarizes information about the stock options outstanding at December 31, 2012 : 

 

F -24 

9. STOCK-BASED COMPENSATION 

 Shares 

Weighted 

Average 

Exercise Price 

per Share 

Weighted 

Average 

Remaining 

Contractual Term 

Aggregate 

Intrinsic 

Value 

Options outstanding at December 31, 2009 508,630 $ 7.14 5.38 $ 2,192,000 

Granted — — 

Exercised (48,889 ) 6.46 545,000 

Forfeited/expired (1,500 ) 2.00 

Options outstanding at December 31, 2010 458,241 7.23 4.48 $ 6,621,000 

Granted — — 

Exercised (102,000 ) 9.74 2,308,000 

Forfeited/expired — — 

Options outstanding at December 31, 2011 356,241 6.51 3.41 $ 8,172,000 

Granted — — 

Exercised (21,000 ) 8.80 628,000 

Forfeited/expired — — 

Options outstanding at December 31, 2012 335,241 $ 6.37 2.39 $ 10,678,000 

Options exercisable at December 31, 2012 335,241 

 $ 6.37  2.39  $ 10,678,000 
Table of Contents 

Index to Financial Statements 

The following table summarizes restricted stock activity for the twelve months ended December 31, 2012 , 2011 and 2010 : 

 

 

The carrying amounts on the accompanying consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and 

accrued liabilities, and current and long-term debt related to the building loans are carried at cost, which approximates market value. 

At December 31, 2012 the carrying value of the outstanding debt represented by the Notes was $ 296,895,000 , including the remaining 

unamortized discount of approximately $ 3,595,000 related to the October Notes and the remaining unamortized premium of approximately $ 490,000 

related to the December Notes. Based on the quoted market price, the fair value of the Notes was determined to be approximately $ 308,250,000 at 

December 31, 2012 . 

The fair value of the derivative instruments is computed based on the difference between the prices provided by the fixed-price contracts and 

forward market prices as of the specified date, as adjusted for basis differentials. Forward market prices for oil are dependent upon supply and demand 

factors in such forward market and are subject to significant volatility. 

 

The income tax provision for continuing operations consists of the following: 

 

F -25 

Exercise 

Price 

Number 

Outstanding 

Weighted Average 

Remaining Life 

(in years) 

Number 

Exercisable 

$ 3.36 205,241 2.06 205,241 

$ 9.07 5,000 2.69 5,000 

$ 11.20 125,000 2.92 125,000 

 335,241  335,241 

 

Number of 

Unvested 

Restricted Shares 

Weighted 

Average 

Grant Date 

Fair Value 

Unvested shares as of December 31, 2009 60,244 $ 6.01 

Granted 111,667 12.94 

Vested (58,525 ) 8.17 

Forfeited — —

Unvested shares as of December 31, 2010 113,386 $ 11.72 

Granted 153,332 $ 31.15 

Vested (63,370 ) 12.87 

Forfeited — —

Unvested shares as of December 31, 2011 203,348 $ 26.02 

Granted 196,832 $ 35.87 

Vested (135,015 ) 29.59 

Forfeited (19,334 ) 26.81 

Unvested shares as of December 31, 2012 245,831 

 $ 31.88 

10. FAIR VALUE OF FINANCIAL INSTRUMENTS 

11. INCOME TAXES 
Table of Contents 

Index to Financial Statements 

A reconciliation of the statutory federal income tax amount to the recorded expense follows: 

 

The tax effects of temporary differences and net operating loss carryforwards, which give rise to deferred tax assets and liabilities at December 31, 

2012 , 2011 and 2010 are estimated as follows: 

 

The Company has an available federal tax net operating loss carryforward estimated at approximately $ 4,323,000 as of 

F -26 

 2012 2011 2010 

Current: 

State $ 84,000 $ — $ 40,000 

Federal 646,000 282,000 95,000 

Deferred: 

State 2,214,000 — —

Federal 23,419,000 (372,000 ) (95,000 ) 

Total income tax expense (benefit) provision from continuing operations $ 26,363,000 

 $ (90,000 )  $ 40,000 

 2012 2011 2010 

Income from continuing operations before federal income taxes $ 98,199,000 $ 108,332,000 $ 47,403,000 

Expected income tax at statutory rate 34,370,000 37,916,000 16,591,000 

State income taxes 1,493,000 4,227,000 2,378,000 

Other differences 292,000 (146,000 ) (111,000 ) 

Changes in valuation allowance (9,792,000 ) (42,087,000 ) (18,818,000 ) 

Income tax expense (benefit) recorded for continuing operations $ 26,363,000 

 $ (90,000 )  $ 40,000 

 2012 2011 2010 

Deferred tax assets: 

Net operating loss carryforward $ 1,513,000 $ 40,880,000 $ 20,967,000 

Oil and gas property basis difference — — 32,054,000 

FASB ASC 718 compensation expense 762,000 520,000 347,000 

Investment in pass through entities — 78,000 722,000 

AMT credit 1,643,000 1,000,000 693,000 

Non-oil and gas property basis difference — 103,000 279,000 

Charitable contributions carryover 5,000 3,000 —

Unrealized gain on hedging activities 3,836,000 — —

Foreign tax credit carryforwards 2,074,000 — —

State net operating loss carryover 4,315,000 6,410,000 —

Total deferred tax assets 14,148,000 48,994,000 55,062,000 

Valuation allowance for deferred tax assets (4,629,000 ) (12,347,000 ) (54,434,000 ) 

Deferred tax assets, net of valuation allowance 9,519,000 36,647,000 628,000 

Deferred tax liabilities: 

Oil and gas property basis difference 15,049,000 35,637,000 —

Investment in pass through entities 3,618,000 — —

Non-oil and gas property basis difference 227,000 — —

Investment in nonconsolidated affiliates 9,232,000 — —

Unrealized gain on hedging activities — 10,000 —

Total deferred tax liabilities 28,126,000 35,647,000 —

Net deferred tax asset (liability) $ (18,607,000 ) 

 $ 1,000,000  $ 628,000 
Table of Contents 

Index to Financial Statements 

December 31, 2012 . This carryforward will begin to expire in the year 2018. Based upon the December 31, 2012 net deferred tax liability position of the 

Company's oil and gas assets, management believes that this is a positive source of evidence to utilize the carryforward before it expires. Therefore, a 

valuation allowance has not been provided at December 31, 2012 . A valuation allowance has been provided at December 31, 2011 and 2010 because it 

was management’s belief in those years, based upon the Company’s past history of no taxable income and future projections of no taxable income during 

the carryforward period, it was more likely than not that the net deferred tax assets would not be realized. The Company also has state net operating loss 

carryovers of $84,031,000 from Oklahoma and Louisiana that will begin to expire in 2013, alternative minimum tax credits of $1,643,000 with no 

expiration date and federal foreign tax credit carryovers of $2,074,000 which begin to expire in 2017. The Company has recorded a valuation allowance of 

$4,629,000 related to state net operating loss carryovers and foreign tax credit carryovers as the carryovers may not be utilized based upon a more likely 

than not basis. 

In 2012, the Diamondback Contribution generated an estimated $61.9 million taxable gain. As a result, the Company recognized $9,792,000 of its 

deferred tax assets which had previously been subject to a valuation allowance. The Company also recognized $25,633,000 of deferred tax expense in 

2012 primarily due to the utilization of prior net operating losses from the Diamondback Contribution gain. Current federal expense in 2012, 2011 and 

2010 is primarily attributable to alternative minimum tax. The Company also had income tax expense of $84,000 and $40,000 related to state income tax 

for the years ended December 31, 2012 and 2010 . 

F -27 
Table of Contents 

Index to Financial Statements 

A reconciliation of the components of basic and diluted net income per common share is presented in the table below: 

 

There were no potential shares of common stock that were considered anti-dilutive for the years ended December 31, 2012 , 2011 and 2010 . 

 

F -28 

12. EARNINGS PER SHARE 

 2012 2011 2010 

 Income Shares 

Per 

Share Income Shares 

Per 

Share Income Shares 

Per 

Share 

Basic: 

Net income $ 68,371,000 55,933,354 $ 1.22 $ 108,422,000 48,754,840 $ 2.22 $ 47,363,000 43,863,190 $ 1.08 

Effect of dilutive securities: 

Stock options and awards — 484,134 — 452,123 — 392,902 

Diluted: 

Net income $ 68,371,000 

 56,417,488  $ 1.21  $ 108,422,000  49,206,963  $ 2.20  $ 47,363,000  44,256,092  $ 1.07 
Table of Contents 

Index to Financial Statements 

Oil Price Hedging Activities 

The Company seeks to reduce its exposure to unfavorable changes in oil prices, which are subject to significant and often volatile fluctuation, by 

entering into fixed price swaps and forward sales contracts. These contracts allow the Company to predict with greater certainty the effective oil prices to 

be received for hedged production and benefit operating cash flows and earnings when market prices are less than the fixed prices provided in the 

contracts. However, the Company will not benefit from market prices that are higher than the fixed prices in the contracts for hedged production. 

The Company accounts for its oil derivative instruments as cash flow hedges for accounting purposes under FASB ASC 815 and related 

pronouncements. All derivative contracts are marked to market each quarter end and are included in the accompanying consolidated balance sheets as 

derivative assets and liabilities. 

During the fourth quarter of 2010 , the Company entered into fixed price swap contracts for 2011 with the purchaser of the Company’s WCBB oil 

and with a financial institution. The Company’s 2011 fixed price swap contracts were tied to the commodity prices on the New York Mercantile Exchange 

(“NYMEX”). The Company received the fixed price amount stated in the contract and paid to its counterparty the current market price for oil as listed on 

the NYMEX West Texas Index (“WTI”). During the third quarter of 2011 and in 2012, the Company entered into fixed price swap contracts for 2012 and 

2013 with the purchaser of the Company’s oil and four financial institutions. The Company’s 2012 and 2013 fixed price swap contracts are tied to the 

commodity prices on the International Petroleum Exchange (“IPE”) and NYMEX. For the Company’s 2013 fixed price swap contracts, the Company will 

receive the fixed price amount stated in the contract and pay to its counterparty the current market price for oil as listed on the IPE for Brent Crude and the 

NYMEX WTI. At December 31, 2012 , the Company had the following fixed price swaps in place: 

 

At December 31, 2012 the fair value of derivative assets related to the fixed price swaps was as follows: 

 

At December 31, 2011 , the fair value of derivative assets related to the fixed price swaps was as follows: 

 

All fixed price swaps and forward sales contracts have been executed in connection with the Company’s oil price hedging program. For fixed price 

swaps qualifying as cash flow hedges pursuant to FASB ASC 815, the realized contract price is included in oil sales in the period for which the underlying 

production was hedged. 

For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of FASB ASC 815, changes in fair value are recognized in 

accumulated other comprehensive income until the hedged item is recognized in earnings. Amounts reclassified out of accumulated other comprehensive 

income into earnings as a component of oil and condensate sales for the years ended December 31, 2012 and 2011 are presented below. 

 

The Company expects to reclassify $9,660,000 out of accumulated other comprehensive income into earnings as a component of oil and condensate 

sales during the year ended December 31, 2013 related to fixed price swaps. 

The following table presents the balances of the Company’s cumulative hedging activities included in other comprehensive income. 

 

F -29 

13. HEDGING ACTIVITIES 

 

Daily Volume 

(Bbls/day) 

Weighted 

Average Price 

January - December 2013 5,000 $ 100.90 

Short-term derivative instruments - asset $ 664,000 

Short-term derivative instruments - liability $ 10,442,000 

Short-term derivative instruments - asset $ 1,601,000 

 Year ended December 31, 

 2012 2011 

(Reduction) addition to oil and condensate sales $ (1,517,000 ) $ (4,720,000 ) 
Table of Contents 

Index to Financial Statements 

Hedge effectiveness is measured at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item 

over time. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. The Company recognized a loss of $144,000 

related to hedge ineffectiveness for the year ended December 31, 2012 , which is included in oil and condensate sales in the consolidated statements of 

operations. The Company recognized a gain of $25,000 related to hedge ineffectiveness for the year ended December 31, 2011 , which is included in oil 

and condensate sales in the consolidated statements of operations. The Company did not recognize into earnings any amount related to hedge 

ineffectiveness for the year ended December 31, 2010 . 

For the period January 2010 through February 2010, the Company was 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 March 2010 through 

December 2010, the Company was 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. For the period January 2011 through December 2011, the Company was party to 

fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $86.96 per barrel. For the period from January 2012 through February 

2012, the Company was party to fixed price swaps for 2,000 barrels of oil per day at a weighted average price of $108.00 per barrel. For the period from 

March 2012 through July 2012, the Company was party to fixed price swaps for 3,000 barrels of oil per day at a weighted average price of $109.73 per 

barrel. For the period from August 2012 through December 2012, the Company was party to fixed price swaps for 4,000 barrels of oil per day at a 

weighted average price of $107.29 per barrel. 

The Company delivered approximately 46% of its 2012 production under fixed price swaps. 

 

The Company records certain financial and non-financial assets and liabilities on the balance sheet at fair value in accordance with FASB ASC 820. 

FASB ASC 820 defines fair value as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction 

between market participants at the measurement date. The statement establishes market or observable inputs as the preferred sources of values, followed 

by assumptions based on hypothetical transactions in the absence of market inputs. The statement requires fair value measurements be classified and 

disclosed in one of the following categories: 

Level 1 – Quoted prices in active markets for identical assets and liabilities. 

Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not 

active and model-derived valuations whose inputs are observable or whose significant value drivers are observable. 

Level 3 – Significant inputs to the valuation model are unobservable. 

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. 

The following tables summarize the Company’s financial and non-financial liabilities by FASB ASC 820 valuation level as of December 31, 2012 

and 2011 : 

 

F -30 

December 31, 2009 $ (18,736,000 ) 

December 31, 2010 $ (4,720,000 ) 

December 31, 2011 $ 1,576,000 

December 31, 2012 $ (9,660,000 ) 

14. FAIR VALUE MEASUREMENTS 
Table of Contents 

Index to Financial Statements 

The estimated fair value of the Company’s fixed price swap contracts was based upon forward commodity prices based on quoted market prices, 

adjusted for differentials. See Note 13 for further discussion of the Company's hedging activities. The estimated fair value of the Company's equity 

investment in Diamondback was based upon the public closing share price of Diamondback's common stock as of December 31, 2012 . 

The Company estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “ Asset Retirement and Environmental 

Obligations ” (“FASB ASC 410”). The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow 

techniques and based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, 

including plugging costs and reserve lives, the initial measurement of the asset retirement obligation liability is deemed to use Level 3 inputs. See Note 4 

for further discussion of the Company’s asset retirement obligations. Asset retirement obligations incurred during the twelve months ended December 31, 

2012 were approximately $ 2,195,000 . 

 

In the ordinary course of business, the Company conducts business activities with certain related parties. 

Diamondback operates the Permian Basin wells included in the Contribution as discussed above in Note 4. At December 2012 and 2011 , the 

Company owed Diamondback approximately $269,000 and $5,593,000 , respectively, related to reimbursement for services provided. Approximately 

$7,089,000 and $5,489,000 of services provided by Diamondback are included in lease operating expenses in the consolidated statements of operations for 

the years ended December 31, 2012 and 2011 , respectively. Approximately $40,354,000 and $50,614,000 related to services performed by Diamondback 

are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2012 and 2011 , respectively. 

As discussed in Note 3, Gulfport is the operator of its Niobrara Formation acreage under a development agreement with Windsor Niobrara. As 

operator, the Company is responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the 

year ended December 31, 2012 and 2011 , the Company billed Windsor Niobrara approximately $7,545,000 and $6,642,000 , respectively, for these 

services. At December 31, 2012 and 2011 , Windsor Niobrara owed the Company approximately $173,000 and $3,557,000 , respectively, for these 

services. 

Windsor Ohio LLC ("Windsor Ohio"), an entity controlled by Wexford, participated with the Company in the acquisition of certain leasehold 

interest in acreage located in the Utica Shale in Ohio. The Company is the operator of this acreage in the Utica Shale. As operator, the Company is 

responsible for daily operations, monthly operation billings and monthly revenue disbursements for these properties. For the year ended December 31, 

2012 and 2011 , the Company billed Windsor Ohio approximately $163,650,000 and $93,871,000 , respectively, for these services. At December 31, 

2012 , Windsor Ohio owed the Company approximately $6,520,000 for these services. No amounts were owed by Windsor Ohio at December 31, 2011 . 

Liddell Investments, LLC (“Liddell Investments”), an entity controlled by Gulfport's Chairman of the Board, has a 10% interest in Windsor Ohio. For the 

year ended December 31, 2012 , the Company billed Liddell Investments directly for these services in respect of this 10% interest in the amount of 

approximately $2,020,000 and, at December 31, 2012 , all of this amount was owed to the Company. For the year ended December 2012 , the Company 

paid Liddell Investments approximately $102,000 in respect of its interest in Windsor Ohio. 

F -31 

 December 31, 2012 

 Level 1 Level 2 Level 3 

Assets: 

Fixed price swaps $ — $ 664,000 $ —

 Equity investment in Diamondback 151,317,000 — —

Liabilities: 

Fixed price swaps $ — $ 10,442,000 $ —

 

 December 31, 2011 

 Level 1 Level 2 Level 3 

Assets: 

Fixed price swaps $ — $ 1,601,000 $ —

Liabilities: 

Fixed price swaps $ — $ — $ —

15. RELATED PARTY TRANSACTIONS 
Table of Contents 

Index to Financial Statements 

Rhino Exploration LLC ("Rhino"), an affiliate of Wexford, participated with the Company in the acquisition of certain leasehold interest in acreage 

located in the Utica Shale in Ohio. The Company is the operator of this acreage in the Utica Shale. As operator, the Company is responsible for daily 

operations, monthly operation billings and monthly revenue disbursements for these properties. For the years ended December 31, 2012 and 2011 , the 

Company billed Rhino approximately $4,443,000 and $25,862,000 , respectively, for these services. At December 31, 2012 , Rhino owed the Company 

approximately $4,257,000 for these services. No amounts were owed by Rhino at December 31, 2011 . 

Athena Construction LLC (“Athena”), an entity controlled by Wexford, performs services for the Company at its WCBB and Hackberry fields. At 

December 31, 2012 and 2011 , the Company owed Athena approximately $1,453,000 and $676,000 , respectively, related to these services. 

Approximately $422,000 and $423,000 of services provided by Athena are included in lease operating expenses in the consolidated statements of 

operations for the years ended December 31, 2012 and 2011 , respectively. Approximately $5,009,000 and $2,851,000 related to services performed by 

Athena are included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2012 and 2011 , respectively. 

Great White Directional Services LLC (“Directional”) performed services for the Company at its WCBB and Hackberry fields. At December 31, 

2011 , the Company owed Directional approximately $2,449,000 related to these services. Approximately $6,068,000 related to services performed by 

Directional were included in oil and natural gas properties on the accompanying consolidated balance sheets at December 31, 2011 . Directional was 

controlled by Wexford until it was sold to an unrelated third party in August 2011. 

Black Fin P&A, LLC (“Black Fin”), an entity controlled by Wexford, performs plugging and abandonment services for the Company at its WCBB 

field. At December 31, 2011 , the Company owed Black Fin $436,000 related to these services. No amounts were owed to Black Fin at December 31, 

2012 . Approximately $650,000 and $436,000 of services performed by Black Fin are included in oil and natural gas properties on the accompanying 

consolidated balance sheets at December 31, 2012 and 2011 , respectively. 

Caliber Development Company, LLC ("Caliber"), an entity controlled by Wexford, provides building maintenance services for the Company's 

headquarters in Oklahoma City, Oklahoma. Caliber also leases office space to the Company. At December 31, 2012 and 2011 , the Company owed 

Caliber approximately $12,000 and $2,000 , respectively, related to these services. Approximately $63,000 and $18,000 of services performed by Caliber 

and rent paid to Caliber are included in general and administrative expenses on the accompanying consolidated statements of operations for the years 

ended December 31, 2012 and 2011 , respectively. 

Plugging and Abandonment Funds 

In connection with the acquisition in 1997 of the remaining 50% interest in the WCBB properties, the Company assumed the seller’s (Chevron) 

obligation to contribute approximately $18,000 per month through March 2004, to a plugging and abandonment trust and the obligation to plug a 

minimum of 20 wells per year for 20 years commencing March 11, 1997. Chevron retained a security interest in production from these properties until 

abandonment obligations to Chevron have been fulfilled. Beginning in 2009, the Company could access the trust for use in plugging and abandonment 

charges associated with the property, although it has not yet done so. As of December 31, 2012 , the plugging and abandonment trust totaled 

approximately $3,113,000 . At December 31, 2012 , the Company has plugged 354 wells at WCBB since it began its plugging program in 1997, which 

management believes fulfills its current minimum plugging obligation. 

Contributions to 401(k) Plan 

Gulfport sponsors a 401(k) and Profit Sharing plan under which eligible employees may contribute up to 100% of their total compensation up to the 

maximum pre-tax threshold through salary deferrals. Also under the plan, the Company will make a contribution each calendar year on behalf of each 

employee equal to at least 3% of his or her salary, regardless of the employee’s participation in salary deferrals and may also make additional 

discretionary contributions. During the years ended December 31, 2012 , 2011 and 2010 , Gulfport incurred $ 361,000 , $ 310,000 and $ 316,000 , 

respectively, in contributions expense related to this plan. 

Employment Agreements 

Effective November 1, 2012, the Company entered into employment agreements with its executive officers, each with an initial three -year term that 

expires on November 1, 2015 subject to automatic one -year extensions unless terminated by either 

F -32 

16. COMMITMENTS 
Table of Contents 

Index to Financial Statements 

party to the agreement at least 90 days prior to the end of the then current term. These agreements provide for minimum salary and bonus levels which are 

subject to review and potential increase by the Compensation Committee and/or the Board of Directors, as well as participation in the Company's 

Amended and Restated 2005 Stock Incentive Plan (or other equity incentive plans that may be put in place for the benefit of employees) and other 

employee benefits. The aggregate minimum commitment for future salaries and bonuses at December 31, 2012 was approximately $7,050,000 . 

Grizzly 

On October 5, 2012, the Company entered into an agreement with Grizzly in which it committed to make monthly payments from October 2012 to 

May 2013 in the aggregate amount of approximately $8.5 million to fund the construction and development of the Algar Lake facility. The Company also 

agreed to fund its proportionate share of any unfunded cost overruns in excess of $2.0 million . The remaining aggregate commitment at December 31, 

2012 was approximately $6.3 million . 

Operating Leases 

The Company leases office facilities under non-cancellable operating leases exceeding one year. Future minimum lease commitments under these 

leases at December 31, 2012 are as follows: 

The following table presents rent expense for the years ended December 31, 2012 , 2011 and 2010 , respectively. 

 

The Louisiana Department of Revenue (“LDR”) is disputing Gulfport’s severance tax payments to the State of Louisiana from the sale of oil under 

fixed price contracts during the years 2005 to 2007. The LDR maintains that Gulfport paid approximately $1,800,000 less in severance taxes under fixed 

price terms than the severance taxes Gulfport would have had to pay had it paid severance taxes on the oil at the contracted market rates only. Gulfport 

has denied any liability to the LDR for underpayment of severance taxes and has maintained that it was entitled to enter into the fixed price contracts with 

unrelated third parties and pay severance taxes based upon the proceeds received under those contracts. Gulfport has maintained its right to contest any 

final assessment or suit for collection if brought by the State. On April 20, 2009, the LDR filed a lawsuit in the 15 th Judicial District Court, Lafayette 

Parish, in Louisiana against Gulfport seeking $2,275,729 in severance taxes, plus interest and court costs. Gulfport filed a response denying any liability 

to the LDR for underpayment of severance taxes and is defending itself in the lawsuit. The LDR had taken no further action on this lawsuit since filing its 

petition other than propounding discovery requests to which Gulfport has responded. Since serving discovery requests on the LDR and receiving the 

LDR's responses in 2012 there has been no further activity on the case and no trial date has been set. 

In December 2010, the LDR filed two identical lawsuits against Gulfport in different venues to recover allegedly underpaid severance taxes on 

crude oil for the period January 1, 2007 through December 31, 2010, together with a claim for attorney’s fees. The petitions do not make any specific 

claim for damages or unpaid taxes. As with the first lawsuit filed by the LDR in 2009, Gulfport denies all liability and will vigorously defend the lawsuit. 

The cases are in the early stages, and Gulfport 

F -33 

2013 $ 179,000 

2014 178,000 

2015 127,000 

2016 68,000 

2017 34,000 

Thereafter —

Total $ 586,000 

 

For the years ended December 31, 

 2012 2,010 2011 2,010 2010 

Minimum rentals $ 139,000 — $ 52,000 — $ 65,000 

Less: Sublease rentals 7,000 — — — —

 $ 132,000 $ 52,000 $ 65,000 

17. CONTINGENCIES 
Table of Contents 

Index to Financial Statements 

has not yet filed a response to the recent lawsuits. Recently, the LDR filed motions to stay the lawsuits before Gulfport filed any responsive pleadings.

The LDR has advised Gulfport that it intends to pursue settlement discussions with Gulfport and other similarly situated defendants in separate 

proceedings, but has taken no action to initiate settlement talks. There has been no activity on either of these lawsuits for more than a year. 

Other Litigation 

In November 2006, Cudd Pressure Control, Inc. (“Cudd”) filed a lawsuit against Gulfport, Great White Pressure Control LLC (“Great White”) and 

six former Cudd employees in the 129th Judicial District Harris County, Texas. The lawsuit was subsequently removed to the United States District Court 

for the Southern District of Texas (Houston Division). The lawsuit alleged RICO violations and several other causes of action relating to Great White’s 

employment of the former Cudd employees and sought unspecified monetary damages and injunctive relief. On stipulation by the parties, the plaintiff’s 

RICO claim was dismissed without prejudice by order of the court on February 14, 2007. Gulfport filed a motion for summary judgment on October 5, 

2007. The court entered a final interlocutory judgment in favor of all defendants, including Gulfport, on April 8, 2008. On November 3, 2008, Cudd filed 

its appeal with the U.S. Court of Appeals for the Fifth Circuit. The Fifth Circuit vacated the district court decision finding, among other things, that the 

district court should not have entered summary judgment without first allowing more discovery. The case was remanded to the district court, and Cudd 

filed a motion to remand the case to the original state court, which motion was granted. Cudd subsequently filed amended petitions with the state court 

(a) alleging, among other things, that Gulfport conspired with the other defendants to misappropriate, and misappropriated Cudd’s trade secrets and 

caused its employees to breach their fiduciary duties, and (b) seeking monetary damages including $11.8 million as a reasonable royalty for the alleged

use of its trade secrets. Cudd also sought disgorgement of the alleged benefits received by the various defendants. Cudd also sought its attorney's fees,

which Cudd claimed were not less than $450,000 , plus 10% of any final judgment. This case went to trial on September 5, 2012 and on September 28, 

2012 the jury rendered its verdict, awarding no damages to the plaintiffs. Gulfport along with all defendants filed a Motion for Entry of Judgment that is 

consistent with the jury's verdict. Cudd filed an Application for Disgorgement and a Motion for Judgment Notwithstanding the Verdict. The court denied 

all of Cudd's post-trial motions on October 12, 2012, and issued its final judgment on January 10, 2013. On that same day, Cudd filed motions for a new 

trial and to modify, correct of reform the judgment. Those motions remain pending. 

On July 30, 2010, six individuals and one limited liability company sued 15 oil and gas companies in Cameron Parish Louisiana for 

contamination across the surface of where the defendants operated in an action entitled Reeds et al. v. BP American Production Company et al.,38th 

Judicial District. No. 10-18714. The plaintiffs’ original petition for damages, which did not name Gulfport as a defendant, alleges that the plaintiffs’ 

property located in Cameron Parish, Louisiana within the Hackberry oil field is contaminated as a result of historic oil and gas exploration and production 

activities. Plaintiffs allege that the defendants conducted, directed and participated in various oil and gas exploration and production activities on their 

property which allegedly have contaminated or otherwise caused damage to the property, and have sued the defendants for alleged breaches of oil, gas and 

mineral leases, as well as for alleged negligence, trespass, failure to warn, strict liability, punitive damages, lease liability, contract liability, unjust 

enrichment, restoration damages, assessment and response costs and stigma damages. On December 7, 2010, Gulfport was served with a copy of the 

plaintiffs’ first supplemental and amending petition which added four additional plaintiffs and six additional defendants, including Gulfport, bringing 

the total number of defendants to 21 . It also increased the total acreage at issue in this litigation from 240 acres to approximately 1,700 acres. In 

addition to the damages sought in the original petition, the plaintiffs now also seek: damages sufficient to cover the cost of conducting a comprehensive

environmental assessment of all present and yet unidentified pollution and contamination of their property; the cost to restore the property to its prepolluted original condition; damages for mental anguish and annoyance, discomfort and inconvenience caused by the nuisance created by defendants; land 

loss and subsidence damages and the cost of backfilling canals and other excavations; damages for loss of use of land and lost profits and income; 

attorney fees and expenses and damages for evaluation and remediation of any contamination that threatens groundwater. In addition to Gulfport, current 

defendants include ExxonMobil Oil Corporation, Mobil Exploration & Producing North America Inc., Chevron U.S.A. Inc., The Superior Oil Company, 

Union Oil Company of California, BP America Production Company, Tempest Oil Company, Inc., ConocoPhillips Company, Continental Oil Company, 

WM. T. Burton Industries, Inc., Freeport Sulphur Company, Eagle Petroleum Company, U.S. Oil of Louisiana, M&S Oil Company, and Empire Land 

Corporation, Inc. of Delaware. On January 21, 2011, Gulfport filed a pleading challenging the legal sufficiency of the petitions on several grounds and 

requesting that they either be dismissed or that plaintiffs be required to amend such petitions. In response to the pleadings filed by Gulfport and similar 

pleadings filed by other defendants, the plaintiffs filed a third amending petition with exhibits which expands the description of the property at issue,

attaches numerous aerial photos and identifies the mineral leases at issue. In response, Gulfport and numerous defendants re-urged their pleadings 

challenging the legal sufficiency of the petitions. Some of the defendants’ grounds for challenging the plaintiffs’ petitions were heard by the court on 

May 25, 2011 and were denied. The 

F -34 
Table of Contents 

Index to Financial Statements 

court signed the written judgment on December 9, 2011. Gulfport noticed its intent to seek supervisory review on December 19, 2011 and the trial court 

fixed a return date of January 11, 2012 for the filing of the writ application. Gulfport filed its supervisory writ, which was denied by the Louisiana Third 

Circuit Court of Appeal and the Louisiana Supreme Court. Gulfport has been active in serving discovery requests and responding to discovery requests 

from the plaintiffs. It is anticipated that the discovery phase of this case will become more active in the upcoming months. Plaintiffs' counsel is seeking a 

trial date in mid-2013. 

Due to the early stages of the LDR and Reed litigation, the outcome is uncertain and management cannot determine the amount of loss, if any, that 

may result. In each case, management has determined the possibility of loss is remote. However, litigation is inherently uncertain. Adverse decisions in 

one or more of the above matters could have a material adverse effect on the Company’s financial condition or results of operations and management 

cannot determine the amount of loss, if any, that may result. 

The Company has been named as a defendant in various other lawsuits related to its business. In each such case, management has determined that 

the possibility of loss is remote. The resolution of these matters is not expected to have a material adverse effect on the Company financial condition or 

results of operations in future periods. 

Concentration of Credit Risk 

Gulfport operates in the oil and gas industry principally in the state of Louisiana with sales to refineries, re-sellers such as pipeline companies, and 

local distribution companies. While certain of these customers are affected by periodic downturns in the economy in general or in their specific segment 

of the oil and gas industry, Gulfport believes that its level of credit-related losses due to such economic fluctuations has been immaterial and will continue 

to be immaterial to the Company’s results of operations in the long term. 

The Company maintains cash balances at several banks. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to 

$250,000 . At December 31, 2012 , Gulfport held cash in excess of insured limits in these banks totaling $166,588,000 . 

During the year ended December 31, 2012 , Gulfport sold approximately 92% and 8% of its oil production to Shell Trading Company (“Shell”) and 

Diamondback O&G, respectively, 91% of its natural gas liquids production to Diamondback O&G, and 41% , 18% and 16% of its natural gas production 

to Noble Americas Gas, Hess and Chevron, respectively. During the year ended December 31, 2011 , Gulfport sold approximately 93% and 7% of its oil 

production to Shell and Diamondback O&G, respectively, 100% of its natural gas liquids production to Diamondback O&G and 50% , 27% , and 22% of 

its natural gas production to Hilcorp Energy Company, Chevron, and Diamondback O&G, respectively. During the year ended December 31, 2010 , 

Gulfport sold approximately 75% and 19% of its oil production to Shell and Diamondback O&G, respectively, and 50% , 32% , and 10% of its natural gas 

production to Diamondback O&G, Chevron, and Hilcorp, respectively. 

 

The following is historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United States: 

Capitalized Costs Related to Oil and Gas Producing Activities 

 

Costs Incurred in Oil and Gas Property Acquisition and Development Activities 

 

F -35 

18. SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES 

 2012 2011 

Proven properties $ 984,795,000 $ 897,130,000 

Unproven properties 626,295,000 132,912,000 

 1,611,090,000 1,030,042,000 

Accumulated depreciation, depletion, amortization and impairment reserve (661,442,000 ) (571,213,000 ) 

Net capitalized costs $ 949,648,000 

 $ 458,829,000 
Table of Contents 

Index to Financial Statements 

Results of Operations for Producing Activities 

The following schedule sets forth the revenues and expenses related to the production and sale of oil and gas. The income tax expense is calculated 

by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after 

giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas 

production. 

 

Oil and Gas Reserves (Unaudited) 

The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2012 , 2011 and 

2010 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted arithmetic average of 

hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2012 , 2011 and 

2010 , in accordance with guidelines of the SEC applicable to reserves estimates. Volumes for oil are stated in thousands of barrels (MBbls) and volumes 

for gas are stated in millions of cubic feet (MMcf). The prices used for the 2012 reserve report are $ 91.32 per barrel and $ 2.76 per MMbtu, adjusted by

lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2011 and 2010 for 

reserve report purposes are $ 96.19 per barrel and $ 4.12 per MMbtu and $ 76.16 per barrel and $ 4.38 per MMbtu, respectively. 

Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made 

using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either 

upward or downward, as warranted by additional performance data. 

 

F -36 

 2012 2011 2010 

Acquisition $ 513,904,000 $ 119,522,000 $ 17,627,000 

Development of proved undeveloped properties 121,787,000 123,489,000 64,652,000 

Exploratory 93,397,000 3,994,000 —

Recompletions 24,643,000 17,259,000 16,917,000 

Capitalized asset retirement obligation 2,195,000 1,390,000 1,328,000 

Total $ 755,926,000 

 $ 265,654,000  $ 100,524,000 

 2012 2011 2010 

Revenues $ 248,601,000 $ 228,953,000 $ 127,636,000 

Production costs (53,708,000 ) (47,230,000 ) (31,580,000 ) 

Depletion (90,230,000 ) (61,965,000 ) (38,600,000 ) 

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

Income tax expense (benefit) 

Current 730,000 282,000 40,000 

Deferred 25,633,000 (372,000 ) —

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

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

Depletion per barrel of oil equivalent (BOE) $ 35.07 

 $ 26.56  $ 19.54 
Table of Contents 

Index to Financial Statements 

The Company contributed its Permian Basin assets to Diamondback in 2012, as discussed in Note 4, resulting in a decrease of 12,564 thousand 

barrels of oil equivalent (MBOE) in estimated proved reserves in 2012. In addition, the Company experienced downward reserve revisions of 442 MBOE 

in estimated proved reserves in 2012 primarily due to a change in the drilling schedule of its Niobrara acreage. The Company also experienced downward 

reserve revisions in 2011. These downward revisions were primarily the result of the drilling of PUDs during the Company’s 2011 drilling program and 

ethane takeaway issues in the Permian Basin. The Company experienced downward reserve revisions in estimated proved reserves in 2010. These 

downward revisions were primarily the result of the five-year schedule for proved undeveloped reserves from the SEC’s “Modernization of Oil and Gas 

Reporting” Final Rule. 

Discounted Future Net Cash Flows (Unaudited) 

The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 

2012 , 2011 and 2010 using an unweighted average first-of-the-month price for the period January through December for 2012 , 2011 and 2010 . 

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

 

In order to develop its proved undeveloped reserves according to the drilling schedule used by the engineers in Gulfport’s reserve report, the 

Company will need to spend $ 82,772,000 , $ 16,416,000 and $ 4,335,000 during years 2013 , 2014 and 2015 , respectively. 

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

 

F -37 

 2012 2011 2010 

 Oil Gas Oil Gas Oil Gas 

 (MBbls) (MMcf) (MBbls) (MMcf) (MBbls) (MMcf) 

Proved Reserves 

Beginning of the period 16,745 15,728 19,704 16,158 17,488 14,332 

Purchases in oil and gas reserves in 

place — — 2 19 3,913 3,482 

Extensions and discoveries 4,880 31,265 3,940 2,091 5,574 5,303 

Sales of oil and gas reserves in place (10,604 ) (11,757 ) — — — —

Revisions of prior reserve estimates (382 ) (357 ) (4,714 ) (1,662 ) (5,426 ) (6,171 ) 

Current production (2,388 ) (1,108 ) (2,187 ) (878 ) (1,845 ) (788 ) 

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

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

Proved undeveloped reserves 3,032 

 15,289  9,260  9,576  12,474  10,090 

 Year ended December 31, 

 2012 2011 2010 

Future cash flows $ 954,833,000 $ 1,594,050,000 $ 1,479,295,000 

Future development and abandonment costs (159,113,000 ) (306,810,000 ) (301,651,000 ) 

Future production costs (147,024,000 ) (295,383,000 ) (305,814,000 ) 

Future production taxes (89,175,000 ) (124,739,000 ) (136,323,000 ) 

Future income taxes (114,867,000 ) (229,649,000 ) (159,171,000 ) 

Future net cash flows 444,654,000 637,469,000 576,336,000 

10% discount to reflect timing of cash flows (96,013,000 ) (260,788,000 ) (260,849,000 ) 

Standardized measure of discounted future net cash flows $ 348,641,000 

 $ 376,681,000  $ 315,487,000 
Table of Contents 

Index to Financial Statements 

The following table summarizes quarterly financial data for the years ended December 31, 2012 and 2011 : 

 

 

As discussed in Note 8 above, the Company issued and sold 11,750,000 shares of its common stock in an underwritten public offering on 

December 24, 2012 which included the partial exercise of an over-allotment option for 1,650,000 shares granted to the underwriters, which option was 

exercised to the extent of 750,000 shares. The underwriters subsequently exercised their option to purchase the remaining 900,000 additional shares of 

common stock subject to the over-allotment option in a second closing, which occurred on January 7, 2013. The net proceeds from the equity offering 

(including the net proceeds from the sale of the shares of common stock to the underwriters under their over-allotment option) were approximately $460.7 

million . The Company used a portion of these net proceeds to fund the acquisition of approximately 37,000 net acres in the Utica Shale in Eastern Ohio, 

as described above in Note 2 and for general corporate purposes, including the funding of a portion of its 2013 capital development plan. 

On February 15, 2013, the Company completed the sale of an aggregate of 8,912,500 shares of its common stock in an underwritten public offering 

at a public offering price of $38.00 per share less the underwriting discount. The Company 

F -38 

 Year ended December 31, 

 2012 2011 2010 

Sales and transfers of oil and gas produced, net of production costs $ (194,893,000 ) $ (181,723,000 ) $ (96,056,000 ) 

Net changes in prices, production costs, and development costs 108,941,000 136,071,000 122,147,000 

Acquisition of oil and gas reserves in place — 72,000 63,043,000 

Extensions and discoveries 151,654,000 107,110,000 88,227,000 

Revisions of previous quantity estimates, less related production costs (10,504,000 ) (112,553,000 ) (89,155,000 ) 

Sales of reserves in place (214,867,000 ) — —

Accretion of discount 37,668,000 31,549,000 24,077,000 

Net changes in income taxes 25,585,000 (36,674,000 ) (54,879,000 ) 

Change in production rates and other 68,376,000 117,342,000 17,309,000 

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

 $ 61,194,000  $ 74,713,000 

19. SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED) 

 2012 

 

First 

Quarter 

Second 

Quarter 

Third 

Quarter 

Fourth 

Quarter 

Revenues $ 65,461,000 $ 66,325,000 $ 60,537,000 $ 56,603,000 

Income from operations 27,263,000 25,947,000 18,178,000 25,875,000 

Income tax expense — — 15,514,000 10,849,000 

Net income 26,869,000 25,117,000 502,000 15,883,000 

Income per share: 

Basic $ 0.48 $ 0.45 $ 0.01 $ 0.28 

Diluted 

 $ 0.48 $ 0.45 $ 0.01 $ 0.28 

 

 2011 

 

First 

Quarter 

Second 

Quarter 

Third 

Quarter 

Fourth 

Quarter 

Revenues $ 46,638,000 $ 55,589,000 $ 58,081,000 $ 68,946,000 

Income from operations 22,105,000 28,156,000 29,118,000 31,585,000 

Income tax expense (benefit) — 1,000 — (91,000 ) 

Net income 21,174,000 27,265,000 29,009,000 30,974,000 

Income per share: 

Basic $ 0.47 $ 0.57 $ 0.58 $ 0.59 

Diluted 

 $ 0.47  $ 0.57  $ 0.57  $ 0.59 

20. SUBSEQUENT EVENTS 
Table of Contents 

Index to Financial Statements 

received aggregate net proceeds of approximately $325.8 million from the sale of these shares after deducting the underwriting discount and before 

offering expenses. The Company used a portion of the net proceeds from this equity offering to fund its acquisition of additional Utica Shale acreage as 

described below, and intends to use the balance for general corporate purposes, including the funding of a portion of its 2013 capital development plan. 

On February 15, 2013, the Company completed an acquisition for approximately 22,000 net acres in the Utica Shale in Eastern Ohio. The purchase 

price was approximately $220 million , subject to certain adjustments. This acquisition excluded the seller's interest in 14 existing wells and 16 proposed 

future wells together with certain acreage surrounding these wells. The Company acquired its initial acreage in the Utica Shale in February 2011 and 

subsequently acquired additional acreage in the area. Through a prior transaction in December 2012 discussed in Note 2, the Company acquired 

approximately 37,000 net acres in the Utica Shale, which increased the Company's working interest in the acreage to 77.7% . Through the February 2013 

transaction, the Company acquired an additional approximately 16.2% interest in these leases, increasing its working interest in the acreage to 93.8% . All 

of the acreage included in this transaction is currently nonproducing and the Company is the operator of all of this acreage, subject to existing 

development and operating agreements between the parties. 

 

 

F -39 
Table of Contents 

Index to Financial Statements 

EXHIBIT INDEX 

 

Exhibit 

Number Description 

 

2.1 

 

Purchase and Sale Agreement, dated as of November 28, 2007, by and among Ambrose Energy I, Ltd. and each of the other persons, 

which are listed as a party seller, and Windsor Permian (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, 

filed by the Company with the SEC on December 24, 2007). 

 

2.2 

 

Second Amendment to the Purchase and Sale Agreement, dated as of December 18, 2007, by and among Ambrose Energy I, Ltd., each 

of the other parties which are listed as a party seller, Windsor Permian and Gulfport (incorporated by reference to Exhibit 2.2 to the 

Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 24, 2007). 

 

2.3 

 

Contribution Agreement, dated May 7, 2012, by and between the Company and Diamondback Energy, Inc. (incorporated by reference 

to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on May 8, 2012). 

 

2.4 

 

Purchase and Sale Agreement, dated December 17, 2012, by and between Windsor Ohio LLC, as seller, and Gulfport Energy 

Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with 

the SEC on December 18, 2012). 

 

2.5 

 

Amendment, dated December 19, 2012, to the Purchase and Sale Agreement, dated December 17, 2012, by and between Windsor Ohio 

LLC, as seller, and Gulfport Energy Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-

19514, filed by the Company with the SEC on December 20, 2012). 

 

2.6 

 

Purchase and Sale Agreement, dated February 11, 2013, by and between Windsor Ohio, LLC, as seller, and Gulfport Energy 

Corporation, as purchaser (incorporated by reference to Exhibit 2.1 to the Form 8-K, File No. 000-19514, filed by the Company with 

the SEC on February 15, 2013). 

 

3.1 

 

Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to the Form 8-K, File No. 000-19514, filed by the 

Company with the SEC on April 26, 2006). 

 

3.2 

 

Certificate of Amendment No. 1 to Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to Form 10-Q, File 

No. 000-19514, filed by the Company with the SEC on November 6, 2009). 

 

3.3 

 

Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Form 8-K, File No. 000-19514, filed by the Company 

with the SEC on July 12, 2006). 

 

4.1 

 

Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on 

Form SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004). 

 

4.2 

 

Form of Warrant Agreement (incorporated by reference to Exhibit 10.4 to Amendment No. 2 to the Registration Statement on Form 

SB-2, File No. 333-115396, filed by the Company with the SEC on July 22, 2004). 

 

4.3 

 

Registration Rights Agreement, dated as of February 23, 2005, by and among the Company, Southpoint Fund LP, a Delaware limited 

partnership, Southpoint Qualified Fund LP, a Delaware limited partnership and Southpoint Offshore Operating Fund, LP, a Cayman 

Islands exempted limited partnership (incorporated by reference to Exhibit 10.7 of Form 10-KSB, File No. 000-19514, filed by the 

Company with the SEC on March 31, 2005). 

 

4.4 

 

Registration Rights Agreement, dated as of March 29, 2002, by and among Gulfport Energy Corporation, Gulfport Funding LLC, 

certain other affiliates of Wexford and the other Investors Party thereto (incorporated by reference to Exhibit 10.3 of Form 10-QSB, 

File No. 000-19514, filed by the Company with the SEC on November 11, 2005). 

 

4.5 

 

Amendment No. 1, dated February 14, 2006, to the Registration Rights Agreement, dated as of March 29, 2002, by and among 

Gulfport Energy Corporation, Gulfport Funding LLC, certain other affiliates of Wexford and the other Investors Party thereto 

(incorporated by reference to Exhibit 10.15 of Form 10-KSB, File No. 000-19514, filed by the Company with the SEC on March 31, 

2006). 

 

4.6 

 

Indenture, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and Wells Fargo 

Bank, National Association, as trustee (including the form of Gulfport Energy Corporation's 7.750% Senior Note Due November 1, 

2020) (incorporated by reference to Exhibit 4.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 

23, 2012). 
E -1 

 
Table of Contents 

Index to Financial Statements 

E -2 

4.7 

 

Registration Rights Agreement, dated as of October 17, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto 

and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to Exhibit 4.2 to 

the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 2012). 

 

4.8 

 

First Supplemental Indenture, dated December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party thereto and 

Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Form 8-K, File No. 000-19514, 

filed by the Company with the SEC on December 26, 2012). 

 

4.9 

 

Registration Rights Agreement, dated as of December 21, 2012, among Gulfport Energy Corporation, subsidiary guarantors party 

thereto and Credit Suisse Securities (USA) LLC, as representative of the several initial purchasers (incorporated by reference to 

Exhibit 4.3 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 2012). 

 

10.1+ 

 

Amended and Restated 2005 Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed 

by the Company with the SEC on April 26, 2006). 

 

10.2+ 

 

Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to Form 8-K, File No. 000-19514, filed by the Company 

with the SEC on April 26, 2006). 

 

10.3+ 

 

Form of Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.3 to Form 8-K, File No. 000-19514, filed by the 

Company with the SEC on April 26, 2006). 

 

10.4+ 

 

Employment Agreement, dated November 7, 2012, between the Company and Mike Liddell (incorporated by reference to Exhibit 10.4 

to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). 

 

10.5+ 

 

Employment Agreement, dated November 7, 2012, between the Company and James D. Palm (incorporated by reference to Exhibit 

10.5 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). 

 

10.6+ 

 

Employment Agreement, dated November 7, 2012, between the Company and Michael G. Moore (incorporated by reference to Exhibit 

10.6 to the Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 8, 2012). 

 

10.7 

 

Credit Agreement, dated as of September 30, 2010, by and among the Company, as borrower, the Bank of Nova Scotia, as 

administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association (incorporated by reference to 

Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 6, 2010). 

 

10.8 

 

Amendment, dated as of December 24, 2010, to the Credit Agreement by and among the Company, as borrower, the Bank of Nova 

Scotia, as administrative agent, letter of credit issuer and lead arranger, and Amegy Bank National Association (incorporated by 

reference to Exhibit 10.1 to Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 28, 2010). 

 

10.9 

 

First Amendment, dated May 3, 2011 of Credit Agreement, dated September 30, 2011, by and among the Company, as borrower, the 

Bank of Nova Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, KeyBank 

National Association and Société Générale (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the 

Company with the SEC on May 9, 2011). 

 

10.10 

 

Second Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of Nova 

Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, as syndication agent, 

KeyBank National Association, as co-documentation agent, and the other lenders party thereto (incorporated by reference to Exhibit 

10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 4, 2011). 

 

10.11 

 

Third Amendment to Credit Agreement, dated as of October 31, 2011, by and among the Company, as borrower, The Bank of Nova 

Scotia, as administrative agent, letter of credit issuer and lead arranger, Amegy Bank National Association, as syndication agent, 

KeyBank National Association and Société Générale, as co-documentation agents, and the other lenders party thereto (incorporated by 

reference to Exhibit 10.2 of Form 10-Q, File No. 000-19514, filed by the Company with the SEC on November 4, 2011). 

 

10.12 

 

Fourth Amendment, dated May 2, 2012, to Credit Agreement, dated September 30, 2011, by and among the Company, as borrower, 

the Bank of Nova Scotia, as administrative agent and letter of credit issuer, Amegy Bank National Association, Key Bank National 

Association and Société Générale (incorporated by reference to Exhibit 10.1 to Form 10-Q, File No. 000-19514, filed by the Company 

with the SEC on May 10, 2012). 

 

Table of Contents 

Index to Financial Statements 

10.13 

 

Fifth Amendment to Credit Agreement, effective as of October 9, 2012, among Gulfport Energy Corporation, as borrower, The Bank 

of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and certain lenders and agents party thereto 

(incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 9, 

2012). 

 

10.14 

 

Sixth Amendment to Credit Agreement, effective as of October 17, 2012, among Gulfport Energy Corporation, as borrower, The Bank 

of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and certain lenders and agents party thereto 

(incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 23, 

2012). 

 

10.15 

 

Seventh Amendment to Credit Agreement, effective as of December 18, 2012, among Gulfport Energy Corporation, as borrower, The 

Bank of Nova Scotia, as administrative agent and letter of credit issuer and lead arranger, and certain lenders and agents party thereto 

(incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on December 26, 

2012). 

 

10.16 

 

Investor Rights Agreement, dated as of October 11, 2012, between Gulfport Energy Corporation and Diamondback Energy, Inc. 

(incorporated by reference to Exhibit 10.1 to the Form 8-K, File No. 000-19514, filed by the Company with the SEC on October 17, 

2012). 

 

14 

 

Code of Ethics (incorporated by reference to Exhibit 14 of Form 8-K, File No. 000-19514, filed by the Company with the SEC on 

February 14, 2006). 

 

21* Subsidiaries of the Registrant. 

 

23.1* Consent of Grant Thornton LLP. 

 

23.2* Consent of Netherland, Sewell & Associates, Inc. 

 

23.3* Consent of Ryder Scott Company. 

 

23.4* Consent of Pinnacle Energy Services, LLC. 

 

31.1* 

 

Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act 

of 1934, as amended. 

 

31.2* 

 

Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 

1934, as amended. 

 

32.1** 

 

Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act 

of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. 

 

32.2** 

 

Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 

1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. 

 

99.1* Report of Netherland, Sewell & Associates, Inc. 

 

99.2* Report of Ryder Scott Company. 

 

101.INS** XBRL Instance Document. 

 

101.SCH** XBRL Taxonomy Extension Schema Document. 

 

101.CAL** XBRL Taxonomy Extension Calculation Linkbase Document. 

 

101.DEF** XBRL Taxonomy Extension Definition Linkbase Document. 

 

101.LAB** XBRL Taxonomy Extension Labels Linkbase Document. 

 
E -3 

101.PRE** XBRL Taxonomy Extension Presentation Linkbase Document. 

 

* Filed herewith. 

** Furnished herewith, not filed. 
Table of Contents 

Index to Financial Statements 

E -4 

+ Management contract, compensatory plan or arrangement. 
Exhibit 21 

SUBSIDIARIES OF GULFPORT ENERGY CORPORATION 

 

 

Name of Subsidiary Jurisdiction of Organization 

 

Grizzly Holdings, Inc. 

 Delaware 

Jaguar Resources LLC Delaware 

Puma Resources, Inc. Delaware 

Gator Marine, Inc. Delaware 

Gator Marine Ivanhoe, Inc. Delaware 

Westhawk Minerals LLC Delaware 
Exhibit 23.1 

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 

We have issued our reports dated February 28, 2013, with respect to the consolidated financial statements and internal control over financial reporting 

included in the Annual Report of Gulfport Energy Corporation on Form 10-K for the year ended December 31, 2012. We hereby consent to the 

incorporation by reference of said reports in the Registration Statements of Gulfport Energy Corporation on Forms S-8 (File No. 333-135728, effective 

July 12, 2006; File No. 333-129178, effective October 21, 2005; and File No. 333-55738, effective February 16, 2001), on Form S-3 (File No. 333-

168180, effective July 28, 2010) and on Form S-3ASR (File No. 333-175435, automatically effective July 11, 2011). 

 

/s/ GRANT THORNTON LLP 

 

Oklahoma City, OK 

February 28, 2013 
Exhibit 23.2 

CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. 

We hereby consent to the inclusion in the Form 10-K of Gulfport Energy Corporation (the “Form 10-K”) of our report dated January 11, 2013 on oil and 

gas reserves of Gulfport Energy Corporation and its subsidiaries as of December 31, 2012 and information from our prior reserve reports, to all references 

to our firm included in the Form 10-K and to the incorporation by reference of all such reports in the Registration Statements of Gulfport Energy 

Corporation on Forms S-8 (File No. 333-135728, effective July 12, 2006; File No. 333-129178, effective October 21, 2005; and File No. 333-55738, 

effective February 16, 2001), on Form S-3 (File No. 333-168180, effective July 28, 2010) and on Form S-3ASR (File No. 333-175435, automatically 

effective July 11, 2011). 

NETHERLAND, SEWELL & ASSOCIATES, INC. 

 

By: /s/ J. CARER HENSON, JR. 

J. Carter Henson, Jr., P.E. 

Senior Vice President 

Houston, Texas 

February 28, 2013 
Exhibit 23.3 

CONSENT OF RYDER SCOTT COMPANY, L.P. 

We have issued our report dated January 16, 2013 for the year ended December 31, 2012 on estimates of proved reserves and future net cash flows of 

certain oil and natural gas properties located in the Utica Shale of Eastern Ohio acquired by Gulfport Energy Corporation (“Gulfport”). As independent oil 

and gas consultants, we hereby consent to the inclusion of our report and the information contained therein and information from our prior reserve reports 

in this Annual Report on Form 10-K of Gulfport (this “Annual Report”) and to all references to our firm in this Annual Report. We hereby also consent to 

the incorporation by reference of such reports and the information contained therein in the Registration Statements of Gulfport on Forms S-8 (File No. 

333-135728, effective July 12, 2006; File No. 333-129178, effective October 21, 2005; and File No. 333-55738, effective February 16, 2001), on Form S3 (File No. 333-168180, effective July 28, 2010) and on Form S-3ASR (File No. 333-175435, automatically effective July 11, 2011). 

RYDER SCOTT COMPANY, L.P. 

 

/s/ RYDER SCOTT COMPANY, L.P. 

RYDER SCOTT COMPANY, L.P. 

TBPE Firm Registration No. F-1580 

 

February 28, 2013 

Oklahoma City, Oklahoma 
Exhibit 23.4 

CONSENT OF PINNACLE ENERGY SERVICES, LLC 

We have issued our report letter dated January 26, 2011 for the year ended December 31, 2010 on estimates of proved reserves and future net cash flows 

of certain oil and natural gas properties located in the Permian Basin of West Texas acquired by Gulfport Energy Corporation (“Gulfport”). As 

independent oil and gas consultants, we hereby consent to the inclusion of the information contained in our report letter in this Annual Report on Form 10-

K of Gulfport (this “Annual Report”) and to all references to our firm in this Annual Report. We hereby also consent to the incorporation by reference of

such information in the Registration Statements of Gulfport on Forms S-8 (File No. 333-135728, effective July 12, 2006; File No. 333-129178, effective 

October 21, 2005; and File No. 333-55738, effective February 16, 2001), on Form S-3 (File No. 333-168180, effective July 28, 2010) and on Form S3ASR (File No. 333-175435, automatically effective July 11, 2011). 

 

PINNACLE ENERGY SERVICES, LLC 

 

/s/ JOHN PAUL DICK 

Name: John Paul Dick 

Title: Manager, Registered Petroleum Engineer 

February 28, 2013 

Oklahoma City, Oklahoma 
Exhibit 31.1 

CERTIFICATION 

I, James D. Palm, Chief Executive Officer of Gulfport Energy Corporation, certify that: 

1. I have reviewed this Annual Report on Form 10-K of Gulfport Energy Corporation; 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the 

statement made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the 

financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 

4. The registrant’s other certifying officer and I am responsible for establishing and maintaining disclosure controls and procedures (as defined in 

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in the Exchange Act Rules 13a-15(f) and 15d-15

(f)) for the registrant and have: 

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the 

registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): 

Date: February 28, 2013 

 

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 

to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within 

those entities, particularly during the period in which this report is being prepared; 

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our 

supervision, 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; 

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the 

effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and 

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most 

recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely 

to materially affect, the registrant’s internal control over financial reporting; and 

(a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are 

reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and 

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal 

controls over financial reporting. 

 /s/ James D. Palm 

 James D. Palm 

 Chief Executive Officer 
Exhibit 31.2 

CERTIFICATION 

I, Michael G. Moore, Chief Financial Officer of Gulfport Energy Corporation, certify that: 

1. I have reviewed this Annual Report on Form 10-K of Gulfport Energy Corporation; 

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the 

statement made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the 

financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 

4. The registrant’s other certifying officer and I am responsible for establishing and maintaining disclosure controls and procedures (as defined in 

Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in the Exchange Act Rules 13a-15(f) and 15d-15

(f)) for the registrant and have: 

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the 

registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): 

Date: February 28, 2013 

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 

to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within 

those entities, particularly during the period in which this report is being prepared; 

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our 

supervision, 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; 

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the 

effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and 

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most 

recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely 

to materially affect, the registrant’s internal control over financial reporting; and 

(a) All significant deficiencies and material weaknesses in the design or operation of internal controls over financial reporting which are 

reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and 

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal 

controls over financial reporting. 

 /s/ Michael G. Moore 

 Michael G. Moore 

 Chief Financial Officer 
Exhibit 32.1 

CERTIFICATION OF PERIODIC REPORT 

I, James D. Palm, Chief Executive Officer of Gulfport Energy Corporation (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley Act 

of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge: 

Dated: February 28, 2013 

 

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and 

furnished to the Securities and Exchange Commission or its staff upon request. 

(1) the Annual Report on Form 10-K of the Company for the year ended December 31, 2012 (the “Report”) fully complies with the 

requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and 

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the 

Company. 

 /s/ James D. Palm 

 James D. Palm 

 Chief Executive Officer 
Exhibit 32.2 

CERTIFICATION OF PERIODIC REPORT 

I, Michael G. Moore, Chief Financial Officer of Gulfport Energy Corporation (the “Company”), certify, pursuant to Section 906 of the Sarbanes-Oxley 

Act of 2002, 18 U.S.C. Section 1350, that, to the best of my knowledge: 

Dated: February 28, 2013 

 

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and 

furnished to the Securities and Exchange Commission or its staff upon request. 

(1) the Annual Report on Form 10-K of the Company for the year ended December 31, 2012 (the “Report”) fully complies with the 

requirements of Section 13 (a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)); and 

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the 

Company. 

 /s/ Michael G. Moore 

 Michael G. Moore 

 Chief Financial Officer 
Exhibit 99.1 

 

January 11, 2013 

Mr. Mike Moore 

Gulfport Energy Corporation 

14313 North May Avenue, Suite 100 

Oklahoma City, Oklahoma 73134 

Dear Mr. Moore: 

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2012, to the Gulfport 

Energy Corporation (Gulfport) interest in certain oil and gas properties located in Colorado and Louisiana. We completed our evaluation on 

or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately 52 percent 

of all proved reserves owned by Gulfport. The estimates in this report have been prepared in accordance with the definitions and regulations 

of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the 

FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this 

letter. This report has been prepared for Gulfport's use in filing with the SEC; in our opinion the assumptions, data, methods, and 

procedures used in the preparation of this report are appropriate for such purpose. 

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

Totals may not add because of rounding. 

The oil reserves shown include crude oil and condensate. Oil volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent 

to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases. 

The estimates shown in this report are for proved reserves. As requested, probable reserves that exist for these properties have not been 

included. No study was made to determine whether possible reserves might be established for these properties. This report does not 

include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have 

been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and 

production status. The estimates of reserves and future revenue included herein have not been adjusted for risk. 

 

 Net Reserves Future Net Revenue (M$) 

 Oil Gas Present Worth 

Category (MBBL) (MMCF) Total at 10% 

 

Proved Developed Producing 1,598.0 636.5 105,441.5 98,729.0 

Proved Developed Non-Producing 2,883.2 2,401.8 176,655.7 139,017.3 

Proved Undeveloped 1,983.2 1,322.6 125,827.2 104,987.6 

 

 Total Proved 6,464.4 4,361.0 407,924.4 342,733.9 
Gross revenue is Gulfport's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after 

deductions for Gulfport's share of production taxes, ad valorem taxes, capital costs, abandonment costs, and operating expenses but before 

consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present 

worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted 

or undiscounted, should not be construed as being the fair market value of the properties. 

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the 

period January through December 2012. For oil volumes, the average Shell Trading (US) Company West Texas/New Mexico Intermediate 

posted price of $91.32 per barrel is adjusted by field for quality, transportation fees, and regional price differentials. For gas volumes, the 

average Henry Hub spot price of $2.757 per MMBTU is adjusted by field for energy content, transportation fees, and regional price 

differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production 

over the remaining lives of the properties are $108.46 per barrel of oil and $2.872 per MCF of gas. 

Operating costs used in this report are based on operating expense records of Gulfport, the operator of the properties, and include only 

direct lease- and field-level costs. As requested, these costs do not include the per-well overhead expenses allowed under joint operating 

agreements, nor do they include the headquarters general and administrative overhead expenses of Gulfport. Operating costs are held 

constant throughout the lives of the properties. 

Capital costs used in this report were provided by Gulfport and are based on actual costs from recent activity. Capital costs are included as 

required for workovers, new development wells, and production equipment. Based on our understanding of Gulfport's future development 

plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be 

reasonable. Abandonment costs used in this report are Gulfport's estimates of the costs to abandon the wells and production facilities, net 

of any salvage value. Capital costs and abandonment costs are held constant to the date of expenditure. 

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or 

condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our 

estimates do not include any costs due to such possible liability. 

We have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the Gulfport 

interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our 

projections are based on Gulfport receiving its net revenue interest share of estimated future gross gas production. 

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities 

of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically 

producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved 

reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or 

actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain 

assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties 

will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the 

interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the 

reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because 

of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in 

recovering such reserves may vary from assumptions made while preparing this report. 
For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, 

production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated 

using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and 

Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard 

engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that 

we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. A 

substantial portion of these reserves are for behind-pipe zones, non-producing zones, and undeveloped locations; such reserves are based 

on estimates of reservoir volumes and recovery efficiencies along with analogy to properties with similar geologic and reservoir 

characteristics. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and 

geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Gulfport, public data sources, and the nonconfidential files of Netherland, Sewell & 

Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in our office. The titles to the properties have not 

been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed. The technical persons 

responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and 

confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we 

do not own an interest in these properties nor are we employed on a contingent basis. 

Sincerely, 

NETHERLAND, SEWELL & ASSOCIATES, INC. 

Texas Registered Engineering Firm F-2699 

/s/ C.H. (Scott) Rees III 

By: 

C.H. (Scott) Rees III, P.E. 

Chairman and Chief Executive Officer 

/s/ Derek F. Newton /s/ Mike K. Norton /s/ John R. Cliver 

By: By: By: 

Derek F. Newton Mike K. Norton John R. Cliver 

Texas P.E. 97689 Texas P.G. 441 Louisiana P.E. 37090 

Vice President Senior Vice President Petroleum Engineer 

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

DFN:JLJ 

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document 

is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions 

stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the 

digital document. 
DEFINITIONS OF OIL AND GAS RESERVES 

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

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also 

included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum 

Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC's Compliance 

and Disclosure Interpretations. 

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and 

options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, 

brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties. 

(2) Analogous reservoir . Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir 

conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the 

reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When 

used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of 

interest: 

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

interest. 

(3) Bitumen . Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a 

viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In 

its natural state it usually contains sulfur, metals, and other non-hydrocarbons. 

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

but that, when produced, is in the liquid phase at surface pressure and temperature. 

(5) Deterministic estimate . The method of estimating reserves or resources is called deterministic when a single value for each parameter 

(from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. 

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

Supplemental definitions from the 2007 Petroleum Resources Management System: 

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the 

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

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be 

recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for 

market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered 

from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be 

initiated or restored with relatively low expenditure compared to the cost of drilling a new well. 

Definitions - Page 1 

of 7 

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest); 

(ii) Same environment of deposition; 

(iii) Similar geological structure; and 

(iv) Same drive mechanism. 

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively 

minor compared to the cost of a new well; and 

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by 

means not involving a well. 
DEFINITIONS OF OIL AND GAS RESERVES 

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

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and 

storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment 

and facilities and other costs of development activities, are costs incurred to: 

(8) Development project . A development project is the means by which petroleum resources are brought to the status of economically 

producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated 

development of a group of several fields and associated facilities with a common ownership may constitute a development project. 

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

productive. 

(10) Economically producible . The term economically producible, as it relates to a resource, means a resource which generates revenue 

that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be 

determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section. 

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

production as of that date. 

(12) Exploration costs . Costs incurred in identifying areas that may warrant examination and in examining specific areas that are 

considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type 

stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as 

prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating 

costs of support equipment and facilities and other costs of exploration activities, are: 

(13) Exploratory well . An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be 

productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a 

service well, or a stratigraphic test well as those items are defined in this section. 

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

Definitions - Page 2 

of 7 

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific 

development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the 

extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and 

of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly. 

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring 

devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems. 

(iv) Provide improved recovery systems. 

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries 

and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes 

referred to as geological and geophysical or "G&G" costs. 

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title 

defense, and the maintenance of land and lease records. 

(iii) Dry hole contributions and bottom hole contributions. 

(iv) Costs of drilling and equipping exploratory wells. 

(v) Costs of drilling exploratory-type stratigraphic test wells. 
DEFINITIONS OF OIL AND GAS RESERVES 

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

(15) Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological 

structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening 

impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields 

may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended 

to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. 

(16) Oil and gas producing activities. 

Instruction 1 to paragraph (a)(16)(i) : The oil and gas production function shall be regarded as ending at a "terminal point", which is the 

outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the 

terminal point for the production function as: 

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that 

are saleable in the state in which the hydrocarbons are delivered. 

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. 

Definitions - Page 3 

of 7 

(i) Oil and gas producing activities include: 

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and 

original locations; 

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas 

from such properties; 

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the 

acquisition, construction, installation, and maintenance of field gathering and storage systems, such as: 

(1) Lifting the oil and gas to the surface; and 

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and 

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other 

nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a 

view to such extraction. 

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or 

a marine terminal; and 

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to 

a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a 

refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas. 

(ii) Oil and gas producing activities do not include: 

(A) Transporting, refining, or marketing oil and gas; 

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not 

have the legal right to produce or a revenue interest in such production; 

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas 

can be extracted; or 

(D) Production of geothermal steam. 

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding 

proved plus probable plus possible reserves. When probabilistic methods 
DEFINITIONS OF OIL AND GAS RESERVES 

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

are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved 

plus probable plus possible reserves estimates. 

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but 

which, together with proved reserves, are as likely as not to be recovered. 

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could 

reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible 

outcomes and their associated probabilities of occurrence. 

(20) Production costs. 

Definitions - Page 4 

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(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of 

available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to 

define clearly the area and vertical limits of commercial production from the reservoir by a defined project. 

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place 

than the recovery quantities assumed for probable reserves. 

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative 

technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons 

to results in successful similar projects. 

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within 

the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other 

geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions 

are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or 

lower than the proved area if these areas are in communication with the proved reservoir. 

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the 

potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir 

above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the 

reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on 

reservoir fluid properties and pressure gradient interpretations. 

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of 

estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the 

actual quantities recovered will equal or exceed the proved plus probable reserves estimates. 

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of 

available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable 

certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are 

in communication with the proved reservoir. 

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the 

hydrocarbons in place than assumed for proved reserves. 

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section. 

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating 

costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and 

facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are: 

(A) Costs of labor to operate the wells and related equipment and facilities. 

(B) Repairs and maintenance. 
DEFINITIONS OF OIL AND GAS RESERVES 

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

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

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and 

engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known 

reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts 

providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or 

probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be 

reasonably certain that it will commence the project within a reasonable time. 

(23) Proved properties. Properties with proved reserves. 

Definitions - Page 5 

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(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities. 

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities. 

(E) Severance taxes. 

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, 

refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, 

their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. 

Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but 

also become part of the cost of oil and gas produced along with production (lifting) costs identified above. 

(i) The area of the reservoir considered as proved includes: 

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

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain 

economically producible oil or gas on the basis of available geoscience and engineering data. 

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as 

seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact 

with reasonable certainty. 

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an 

associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, 

engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. 

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, 

fluid injection) are included in the proved classification when: 

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a 

whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable 

technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and 

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

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The 

price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined 

as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined 

by contractual arrangements, excluding escalations based upon future conditions. 
DEFINITIONS OF OIL AND GAS RESERVES 

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

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities 

will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will 

equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as 

changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made 

to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to 

decrease. 

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been 

field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being 

evaluated or in an analogous formation. 

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically 

producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must 

be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of 

delivering oil and gas or related substances to market, and all permits and financing required to implement the project. 

Note to paragraph (a)(26) : Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those 

reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated 

from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). 

Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations). 

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

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

end of the year: 

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

b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the 

operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7). 

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

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in 

accordance with paragraphs 932-235-50-3 through 50-11B: 

a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end 

quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end. 

b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and 

producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If 

estimated development expenditures are significant, they shall be presented separately from estimated production costs. 

c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration 

of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the 

properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil 

and gas reserves. 

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

from future cash inflows. 

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

to proved oil and gas reserves. 

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

Definitions - Page 6 

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DEFINITIONS OF OIL AND GAS RESERVES 

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

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is 

confined by impermeable rock or water barriers and is individual and separate from other reservoirs. 

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources 

may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and 

undiscovered accumulations. 

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells 

include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for 

in-situ combustion. 

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific 

geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification 

also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are 

classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area. 

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered 

from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. 

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

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive 

locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into 

consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should 

be the exception, and not the rule. 

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past 

five years include, but are not limited to, the following: 

 The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum 

number of wells necessary to maintain the lease generally would not constitute significant development activities); 

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

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

 The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its 

development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would 

not be appropriate); and 

 The extent to which delays in development are caused by external factors related to the physical operating environment (for example, 

restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to 

develop properties with higher priority). 

Definitions - Page 7 

of 7 

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of 

production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic 

producibility at greater distances. 

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that 

they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time. 

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid 

injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual 

projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using 

reliable technology establishing reasonable certainty. 
DEFINITIONS OF OIL AND GAS RESERVES 

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

(32) Unproved properties. Properties with no proved reserves. 

Definitions - Page 8 

of 7 
Exhibit 99.2 

GULFPORT ENERGY CORPORATION 

Estimated 

Future Reserves and Income 

Attributable to Certain 

Leasehold Interests 

SEC Parameters 

As of 

December 31, 2012 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
[SEAL] 

RYDER SCOTT COMPANY, L.P. 

TBPE Firm Registration No. F-1580 

\s\ Don P. Griffin 

Don P. Griffin, P.E. 

TBPE License No. 64150 

Senior Vice President 
January 16, 2013 

Gulfport Energy Corporation 

14313 N. May, Suite 100 

Oklahoma City, Oklahoma 73134 

Gentlemen: 

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future 

production, and income attributable to certain leasehold interests of Gulfport Energy Corporation (Gulfport) as of December 31, 

2012. The subject properties are located in the state of Ohio. The reserves and income data were estimated based on the 

definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, 

Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal 

Register (SEC regulations). Our third party study, completed on January 11, 2013, and presented herein, was prepared for 

public disclosure by Gulfport in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC 

regulations. 

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 

100 percent of the total net proved gas reserves of Gulfport in the Ohio Utica Shale as of December 31, 2012. 

The results of this study are summarized below. 

SEC PARAMETERS 

Estimated Net Reserves and Income Data 

Certain Leasehold Interests of 

Gulfport Energy Corporation 

SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790 

621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258 

TBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849 

1100 LOUISIANA SUITE 4600 HOUSTON, TEXAS 77002-5235 TELEPHONE (713) 651-9191 

As of December 31, 2012 
Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (Mbbl). All gas volumes are reported on 

an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the state of 

Ohio. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars (M$). 

The estimated reserves and future net income amounts presented in this report, as of December 31, 2012, are related 

to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during 

the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic 

averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by 

contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices 

required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received 

may differ significantly from the estimated quantities presented in this report. 

The estimates of the reserves, future production, and income attributable to properties in this report were prepared 

using the economic software package Aries TM System Petroleum Economic Evaluation Software, a copyrighted program of 

Halliburton. The program was used solely at the request of Gulfport. Ryder Scott has found this program to be generally 

acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of 

the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash 

flow projections of the same properties, also due to rounding. The rounding differences are not material. 

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs 

of operating the wells, ad valorem taxes, recompletion costs, and development costs. The future net income is before the 

deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding 

loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves 

account for approximately 60.9 percent and gas reserves account for the remaining 39.1 percent of total future gross revenue 

from proved reserves. 

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum 

compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. 

These results are shown in summary form as follows.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 

 Proved 

 Developed Total 

 Producing Non-Producing Undeveloped Proved 

Net Remaining Reserves 

Oil/Condensate – Mbbl 153 457 947 1,557 

Plant Products – Mbbl 43 0 101 145 

Gas – MMCF 4,223 11,126 13,966 29,315 

 

Income Data ($M) 

Future Gross Revenue $28,082 $74,468 $129,773 $232,323 

Deductions 5,369 14,533 66,912 86,814 

Future Net Income (FNI) $22,713 $59,935 $ 62,861 $145,509 

 

Discounted FNI @ 10% $15,909 $42,751 $ 31,348 $ 90,008 
The results shown above are presented for your information and should not be construed as our estimate of fair market 

value. 

Reserves Included in This Report 

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s 

Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum 

Reserves Definitions” is included as an attachment to this report. 

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves 

Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in category. 

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. 

The proved gas volumes included herein do not attribute gas consumed in operations as reserves. 

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically 

producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve 

an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less 

than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount 

of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative 

degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. 

Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and 

possible reserves to denote progressively increasing uncertainty in their recoverability. At Gulfport’s request, this report 

addresses only the proved reserves attributable to the properties evaluated herein. 

Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, 

can be estimated with reasonable certainty to be economically producible from a given date forward. The proved reserves 

included herein were estimated using deterministic methods. If deterministic methods are used, the SEC has defined 

reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 

 Discounted Future Net Income ($M) 

 As of December 31, 2012 

Discount Rate Total 

Percent Proved 

 

5 $111,029 

15 $75,779 

20 $65,403 

25 $57,427 
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or 

as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of 

geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate 

recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.”

Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental 

agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should 

not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, 

could be more or less than the estimated amounts. 

Gulfport’s operations may be subject to various levels of governmental controls and regulations. These controls and 

regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce 

hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various 

taxes and levies including income tax are subject to change from time to time. Such changes in governmental regulations and 

policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ 

significantly from the estimated quantities. 

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which 

Gulfport owns an interest; however, we have not made any field examination of the properties. No consideration was given in 

this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and 

clean up damages, if any, caused by past operating practices. 

Estimates of Reserves 

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the 

quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with 

those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s 

Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of 

certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) 

performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in 

combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select 

the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of 

reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance 

characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property. 

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this 

data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a 

range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental 

quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty 

for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. 

Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent 

uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty 

wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable 

reserves are those additional reserves that are less 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.”

The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable 

reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable 

plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted 

above. 

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional 

geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve 

categories may also be revised due to other factors such as changes in economic conditions, results of future operations, 

effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein. 

Production information for the Utica Shale is very limited. Gulfport currently has 2 wells on production for which 

performance methods were used. Gulfport has interests in an additional 16 wells which have been drilled and are awaiting a 

pipeline connection. Of these 16 wells, 8 have been tested. Proved reserves were assigned to only those wells with test 

information, and assignments were limited to no more than 1 year at the peak production test rates. 

All of the proved undeveloped reserves included herein were estimated by the analogy method. The data utilized from 

the analogues were considered sufficient for the purpose thereof. 

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many 

factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and 

engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, 

and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be 

anticipated to be economically producible from a given date forward based on existing economic conditions including the prices 

and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the 

future prices received for the sale of production and the operating costs and other costs relating to such production may 

increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by 

the SEC, omitted from consideration in making this evaluation. 

Gulfport has informed us that they have furnished us all of the material accounts, records, geological and engineering 

data, and reports and other data required for this investigation. In preparing our forecast of future proved production and 

income, we have relied upon data furnished by Gulfport with respect to property interests owned, production and well tests from 

examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, 

ad valorem and production taxes, and development costs, product prices based on the SEC regulations, adjustments or 

differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. 

Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of 

the data furnished by Gulfport. We consider the factual data used in this report appropriate and sufficient for the purpose of 

preparing the estimates of reserves and future net revenues herein. 

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for 

the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to 

prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the 

United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all 

references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by 

the SEC regulations. 

Future Production Rates 

For wells currently on production, our forecasts of future production rates are based on historical performance data. If 

no production decline trend has been established, future production rates were held constant, or adjusted for the effects of 

curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then 

applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating 

future production rates. 

Test data and other related information were used to estimate the anticipated initial production rates for those wells or 

locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an 

anticipated date furnished by Gulfport. Wells or locations that are not currently producing may start producing earlier or later 

than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors 

may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or 

constraints set by regulatory bodies. 

The future production rates from wells currently on production or wells or locations that are not currently producing may 

be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions 

related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market 

demand and/or allowables or other constraints set by regulatory bodies. 

Hydrocarbon Prices 

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month 

period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the 

prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual 

arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, 

exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted 

to the 12-month unweighted arithmetic average as previously described. 

Gulfport furnished us with the above mentioned average prices in effect on December 31, 2012. These initial SEC 

hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the 

geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as 

described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area 

included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual 

arrangements. 

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments 

to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees , and/or distance from market, 

referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Gulfport. The 

differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not 

conducted an independent verification of the data used by Gulfport to determine these differentials. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and 

referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from 

the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in 

accordance with SEC disclosure requirements for each of the geographic areas included in the report. 

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

individual property evaluations. 

Costs 

Operating costs for the leases and wells in this report are based on the operating expense reports of Gulfport and 

include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and 

administrative costs allocated directly to the leases and wells. The operating costs furnished to us were accepted as factual 

data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the 

operating cost data used by Gulfport. No deduction was made for loan repayments, interest expenses, or exploration and 

development prepayments that were not charged directly to the leases or wells. 

Development costs were furnished to us by Gulfport and are based on authorizations for expenditure for the proposed 

work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by 

us for their reasonableness; however, we have not conducted an independent verification of these costs. Gulfport’s estimates 

of zero abandonment costs after salvage value for onshore properties were used in this report. Ryder Scott has not performed 

a detailed study of the abandonment costs or the salvage value and makes no warranty for Gulfport’s estimate. 

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in 

accordance with Gulfport’s plans to develop these reserves as of December 31, 2012. The implementation of Gulfport’s 

development plans as presented to us and incorporated herein is subject to the approval process adopted by Gulfport’s 

management. As the result of our inquiries during the course of preparing this report, Gulfport has informed us that the 

development activities included herein have been subjected to and received the internal approvals required by Gulfport’s 

management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain 

development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements 

or other administrative approvals external to Gulfport. Additionally, Gulfport has informed us that they are not aware of any 

legal, regulatory, political or economic obstacles that would significantly alter their plans. 

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 

Geographic Area Product 

Price 

Reference 

Average 

Benchmark 

Prices 

Average Realized 

Prices 

North America 

United States Oil/Condensate WTI Cushing $94.71/Bbl $84.88/Bbl 

 NGLs Mt. Belvieu $43.24/Bbl $69.75/Bbl 

 Gas Henry Hub $2.76/MMBTU $3.11/MCF 
Standards of Independence and Professional Qualification 

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting 

services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; 

Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By 

virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a 

material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and 

gas company and are separate and independent from the operating and investment decision-making process of our clients. 

This allows us to bring the highest level of independence and objectivity to each engagement for our services. 

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused 

on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers 

on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively 

participating in ongoing continuing education. 

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received 

professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified 

professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized selfregulating professional organization. 

We are independent petroleum engineers with respect to Gulfport. Neither we nor any of our employees have any 

interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our 

estimates of reserves for the properties which were reviewed. 

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and 

engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for 

the evaluation of the reserves information discussed in this report, are included as an attachment to this letter. 

Terms of Usage 

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure 

requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by 

Gulfport. 

We have provided Gulfport with a digital version of the original signed copy of this report letter. In the event there are 

any differences between the digital version included in filings made by Gulfport and the original signed report letter, the original 

signed report letter shall control and supersede the digital version. 

The data and work papers used in the preparation of this report are available for examination by authorized parties in 

our offices. Please contact us if we can be of further service. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
Very truly yours, 

RYDER SCOTT COMPANY, L.P. 

TBPE Firm Registration No. F-1580 

\s\ Don P. Griffin 

Don P. Griffin P.E. 

TBPE License No. 64150 

Senior Vice President 

[SEAL] 

DPG (DPR)/pl 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers 

from Ryder Scott Company, L.P. Don P. Griffin was the primary technical person responsible for overseeing the estimate of the 

reserves, future production and income presented herein. 

Mr. Griffin, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 1981, is a Senior Vice President responsible for 

coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. 

Before joining Ryder Scott, Mr. Griffin served in a number of engineering positions with Amoco Production Company. For more 

information regarding Mr. Griffin’s geographic and job specific experience, please refer to the Ryder Scott Company website at 

http://www.ryderscott.com/Experience/Employees.php . 

Mr. Griffin graduated with honors from Texas Tech University with a Bachelor of Science degree in Electrical Engineering in 

1975 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers 

and the Society of Petroleum Evaluation Engineers. 

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers 

requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional 

ethics, which Mr. Griffin fulfills. Mr. Griffin attended an additional 15 hours of training during 2012 covering such topics as 

reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for 

consultants. 

Based on his educational background, professional training and more than 30 years of practical experience in the estimation 

and evaluation of petroleum reserves, Mr. Griffin has attained the professional qualifications as a Reserves Estimator and 

Reserves Auditor as set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves 

Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
PETROLEUM RESERVES DEFINITIONS 

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) 

PREAMBLE 

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of 

Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The 

“Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of 

Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies 

Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to 

Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take 

effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after 

January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 

210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC 

document are denoted in italics herein). 

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically 

producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an 

assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than 

the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of 

reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative 

degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. 

Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and 

possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of 

December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible 

oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates 

of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with 

the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 

Instruction to Item 1202. 

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as 

economic conditions change. 

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include 

all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples 

of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the 

use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as 

petroleum technology continues to evolve. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum

accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, 

extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include 

coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale 

deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing 

prior to sale. 

Reserves do not include quantities of petroleum being held in inventory. 

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

different reserves categories. 

RESERVES (SEC DEFINITIONS) 

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

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically 

producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or 

there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, 

installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement 

the project. 

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults 

until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that 

are clearly separated from a known accumulation by a non-productive reservoir ( i.e. , absence of reservoir, structurally low 

reservoir, or negative test results). Such areas may contain prospective resources ( i.e. , potentially recoverable resources from 

undiscovered accumulations). 

PROVED RESERVES (SEC DEFINITIONS) 

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

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of 

geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given 

date forward, from known reservoirs, and under existing economic conditions, operating methods, and government 

regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is 

reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to 

extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project 

within a reasonable time. 

(i) The area of the reservoir considered as proved includes: 

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

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous 

with it and to contain economically producible oil or gas on the basis of available geoscience and engineering 

data. 

PROVED RESERVES (SEC DEFINITIONS) CONTINUED 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known 

hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable 

technology establishes a lower contact with reasonable certainty. 

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential 

exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir 

only if geoscience, engineering, or performance data and reliable technology establish the higher contact with 

reasonable certainty. 

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but 

not limited to, fluid injection) are included in the proved classification when: 

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the 

reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other 

evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the 

project or program was based; and 

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

governmental entities. 

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be 

determined. The price shall be the average price during the 12-month period prior to the ending date of the period

covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each 

month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon 

future conditions. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES 

As Adapted From: 

RULE 4-10(a) of REGULATION S-X PART 210 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC) 

and 

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS) 

Sponsored and Approved by: 

SOCIETY OF PETROLEUM ENGINEERS (SPE) 

WORLD PETROLEUM COUNCIL (WPC) 

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE) 

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be 

made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following 

reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the 

aforementioned SEC and SPE-PRMS documents are denoted in italics herein). 

DEVELOPED RESERVES (SEC DEFINITIONS) 

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

follows: 

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

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required 

equipment is relatively minor compared to the cost of a new well; and 

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if 

the extraction is by means not involving a well. 

Developed Producing (SPE-PRMS Definitions) 

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

Developed Producing Reserves 

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at 

the time of the estimate. 

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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 
Developed Non-Producing 

Developed Non-Producing Reserves include shut-in and behind-pipe reserves. 

Shut-In 

Shut-in Reserves are expected to be recovered from:

Behind-Pipe 

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional

completion work or future re-completion prior to start of production. 

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

well. 

UNDEVELOPED RESERVES (SEC DEFINITIONS) 

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

follows: 

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on 

undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. 

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been 

adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, 

justify a longer time. 

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which 

an application of fluid injection or other improved recovery technique is contemplated, unless such techniques 

have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in 

paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty. 

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS 

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or 

(3) wells not capable of production for mechanical reasons. 

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are 

reasonably certain of production when drilled, unless evidence using reliable technology exists that 

establishes reasonable certainty of economic producibility at greater distances.