Confidential Draft Registration Statement

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If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

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If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

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

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

We are offering shares of our common stock. This is the initial public offering of our common stock. Prior to this offering, there has been no public market for our common stock. The initial public offering price of our common stock is expected to be between $ and $ per share. We intend to apply to list our common stock on the New York Stock Exchange under the symbol “ENXP.”

We are an “emerging growth company” under the federal securities laws and will be subject to reduced public company reporting requirements. See “Summary—Implications of Being an Emerging Growth Company.”

Investing in our common stock involves risks. Please see the section entitled “Risk Factors” starting on page 14 of this prospectus to read about risks you should consider carefully before buying shares of our common stock.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

We have granted the underwriters a 30-day option to purchase up to an additional shares of our common stock at the public offering price, less the underwriting discount, to cover any over-allotments.

You should rely only on the information contained in this document and any free writing prospectus we provide you. We and the underwriters have not authorized anyone to provide you with additional or different information. We and the underwriters are offering to sell, and seeking offers to buy, these securities only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of these securities.

Until , all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Although we believe these third-party sources are reliable and that the information is accurate and complete, we have not independently verified the third-party information and our estimates may differ materially from actual data.

PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all the information that you should consider before investing in our common stock. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical and pro forma financial statements and the notes thereto included elsewhere in this prospectus. Unless otherwise stated in this prospectus, references to “we,” “us” or “our company” refer to the combined business of Energy & Exploration Partners, LLC, Energy & Exploration Partners, LP, Energy & Exploration Partners Operating, LP and Energy & Exploration Partners Operating GP, LLC prior to the completion of our corporate reorganization described in this prospectus, and Energy & Exploration Partners, Inc. and its subsidiaries as of the completion of our corporate reorganization and thereafter. Unless otherwise indicated, information presented in this prospectus assumes that the underwriters’ option to purchase additional shares of our common stock is not exercised. We have provided definitions for some of the industry terms used in this prospectus in the “Glossary of Selected Oil and Natural Gas Terms.”

Overview

We are an independent exploration and production company focused on the acquisition, exploration, development and exploitation of unconventional oil and natural gas resources. We have accumulated 45,276 net acres as of July 31, 2012 in three core areas: the Eagle Ford Shale and Woodbine Sandstone formations in East Texas, which we refer to as the Eaglebine; the Wolfcamp play in the Permian Basin in West Texas, which we refer to as the Wolfcamp; and the Niobrara Shale in the Denver-Julesburg Basin in Colorado and Wyoming, which we refer to as the Niobrara. We target liquids-rich resource plays and have built our leasehold acreage position primarily through direct acquisitions from mineral owners. Our management team has extensive land, engineering, geological, geophysical and technical expertise in our core areas, where we plan to continue to pursue additional leasehold acquisitions.

We have accumulated 15,236 net acres in our Eaglebine core area. Recently we have entered into two agreements with a subsidiary of Halcón Resources Corporation, or Halcón, related to the Eaglebine. These agreements, which are described further under “—Our Core Areas—Eaglebine” below, provided for our conveyance to Halcón of operated working interests in substantially all of our Eaglebine acreage and established two areas of mutual interest with Halcón, which we refer to as AMI #1 and AMI #2. In addition, we have 13,109 net acres in our Wolfcamp area, where we have 100% operated working interests, and 16,931 net acres in our Niobrara area, where we generally have 100% operated working interests. We estimate our current acreage positions in our three core areas could contain a total of 452 net drilling locations, of which roughly half are in the Eaglebine.

The majority of our capital expenditure budget for the period from July 2012 to December 2013 will be focused on the development and expansion of our Eaglebine acreage. The following table presents summary data for our leasehold acreage in our core areas as of July 31, 2012, and our drilling capital budget from July 1, 2012 to December 31, 2013. We have also budgeted estimated capital expenditures of $25 million for leasehold acquisitions and $4 million for 3D seismic data from July 1, 2012 through December 31, 2013. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and “Business—Capital Budget.”


	Net Acres		Acre Spacing		Potential Net Drilling Locations⁽¹⁾		Drilling Capital Budget July 1, 2012 - December 31, 2013
	Net Acres		Acre Spacing		Potential Net Drilling Locations⁽¹⁾		Net Wells		(in millions)
Eaglebine⁽²⁾ :
Horizontal Woodbine/Eagle Ford		15,236		120		127		18	$	125
Vertical Lower Cretaceous		15,236		160		95		7	$	20

Total		15,236				222		25	$	144

Wolfcamp⁽³⁾:
Horizontal Wolfcamp		13,109		160		82		11	$	87
Horizontal Cline		13,109		160		82		—	$	—

Total		13,109				164		11	$	87

Niobrara⁽³⁾:
Horizontal Niobrara		16,350		320		51		—	$	—
Vertical Codell/Niobrara		581		40		15		15	$	10

Total		16,931				66		15	$	10

Total⁽⁴⁾		45,276				452		51	$	242

(1)	Potential net drilling locations are calculated using the acre spacings specified for each area in the table. We have no proved, probable or possible reserves attributable to any of these potential net drilling locations.

(2)	35% non-operated working interest in AMI #1, 20% non-operated working interest in AMI #2, and 100% operated working interest outside AMIs.

(3)

100% operated working interest. In the Niobrara, although we have a 100% operated working interest in our acreage, we will have less than a 100% working interest in, and will not be the operator of, some wells in which we participate as a result of forced pooling of our acreage with the acreage of other operators.

(4)	Certain totals may not add due to rounding.

Our Core Areas

Eaglebine

As of July 31, 2012, we own 15,236 net acres in the Eaglebine located in Grimes, Madison and Walker Counties, Texas. We believe our Eaglebine acreage to be prospective for up to ten zones, including our primary objectives in the Eagle Ford Shale, the Woodbine Sandstone, and the Lower Cretaceous Limestone formations of the Georgetown, Edwards and Glen Rose. We are currently evaluating the Austin Chalk and Sub Clarksville formations, which may eventually present us with additional drilling locations. The majority of our leases in the Eaglebine are in the first year of their three-year primary term and provide for either two- or three-year extension options. We estimate that we have 222 net drilling locations in the Eaglebine. Through the end of 2013, we plan to drill 18 net horizontal wells and 7 net vertical wells and have budgeted $144 million for estimated drilling capital expenditures in the Eaglebine.

In March 2012, we entered into a purchase and sale agreement with Halcón pursuant to which we agreed to sell to Halcón a 65% operated working interest in certain acreage in the Eaglebine that we leased prior to August 1, 2012. We will retain a 35% non-operated working interest in the acreage. Pursuant to the agreement, we conveyed a 65% operated working interest in 38,013 net acres (24,709 net to Halcón) for $37.1 million in proceeds through July 31, 2012. In the final closing under the agreement scheduled for August 2012, we estimate that we will convey to Halcón a 65% operated working interest in an additional 7,000 net acres (4,550 net to Halcón) for approximately $6.8 million in proceeds.

In addition to the proceeds received upon the conveyance of the 65% operated working interests to Halcón, Halcón agreed to make a contingent payment of $1,000 per acre conveyed net to Halcón, or an estimated total of $29.3 million, upon the drilling and completion of two commercial wells on the acreage in which Halcón acquired an interest pursuant to the purchase and sale agreement. If Halcón does not drill two commercial wells on the acreage by April 19, 2013, or if either well is not completed, then Halcón may elect to pay us the contingent payment or reconvey to us, free of costs, the interests in the acreage it acquired pursuant to the purchase and sale

agreement. We expect that, after the final closing under the purchase and sale agreement and receipt of the contingent payment, we will have conveyed to Halcón a 65% operated working interest in a total of 45,013 net acres for total proceeds of $73.1 million.

The purchase and sale agreement also establishes an area of mutual interest, which we refer to as AMI #1, in the area in which the interests sold to Halcón pursuant to the agreement are located. Under the agreement, beginning August 1, 2012 and until the agreement’s termination on August 30, 2015, Halcón will have the right to acquire 65% of the working interest in any leases we acquire in AMI #1, and we will have the right to acquire 35% of the working interest in any leases Halcón acquires in AMI #1, in each case for a pro rata share of leasehold acquisition costs. Halcón will be the operator on all AMI #1 acreage in which we and Halcón jointly acquire an interest pursuant to the agreement.

In June 2012, we entered into a second agreement with Halcón related to a specified area of mutual interest in the Eaglebine, which we refer to as AMI #2, that is primarily located north and east of AMI #1. Pursuant to the terms of this agreement, through January 1, 2014, Halcón will have the right to acquire 80% of the working interest in leases that we acquire in AMI #2 for payment of 100% of the leasehold acquisition costs, and we will have the right to acquire a 20% working interest in leases that Halcón acquires in AMI #2 for payment of 20% of the leasehold acquisition costs. As of July 31, 2012, we had acquired 3,024 acres in AMI #2 of which we expect to convey 2,419 net acres to Halcón in return for payment of 100% of the associated leasehold acquisition costs. Halcón will be the operator on all AMI #2 acreage in which we and Halcón jointly acquire an interest pursuant to the agreement.

We commenced drilling our first Halcón-operated well in AMI #1, the Covington #1H in which we have a 35% non-operated working interest, in May 2012. This well was drilled as a vertical test well to 10,324 feet with 188 feet of core cut from selected sand and shale intervals contained in the Woodbine Sandstone and Eagle Ford Shale formations. We plan to drill the lateral to a length of 6,875 feet and complete the well with a 20-plus stage hydraulic fracture stimulation. We anticipate this well will commence production before the end of the third quarter of 2012. Working with Halcón, we plan to increase our number of active drilling rigs in AMI #1 to three, with the addition of two drilling rigs during the third quarter of 2012.

Based on publicly available information, we believe that average drilling and completion costs for horizontal wells in the Eaglebine, which, for purposes of industry comparisons, we define as Madison, Grimes, Brazos, Leon, Houston, Robertson, and Walker Counties, Texas, have ranged between $5.5 million and $7.0 million per well, average estimated ultimate recoveries, or EURs, have ranged from 400,000 to 500,000 boe per well, and initial 30-day average production has ranged from 400 to 1,200 boe/d per well.

Recently, there has been significant industry activity in the Eaglebine. The most active operators offsetting our acreage position include Halcón, EOG Resources, Inc., Devon Energy Corporation, Apache Corporation, Range Resources Corporation, Chesapeake Energy Corporation, Samson Investment Company, Woodbine Acquisition Corporation, and Newfield Exploration Company. According to Drillinginfo, Inc., there were 320 drilling permits filed in 2011 and 176 filed in 2012 through July 18 in the Eaglebine. According to estimates prepared by Baker Hughes Incorporated, there were 19 rigs operating in the Eaglebine as of July 13, 2012.

The following table provides information regarding recent transactions exceeding $50 million in estimated purchase price in the Eaglebine. The information is based on information publicly released by parties involved in these transactions and does not reflect any post-closing purchase price adjustments.


Date	Buyer	Seller	Net Acres		Estimated Purchase Price ($MM)		Production boe/d
5/25/2011	Woodbine Acquisition Corporation	Petromax Operating Co., Inc.		15,224	$	250.4		2,299
6/25/2012	Halcón	Undisclosed		20,628	$	516.7		2,800

Wolfcamp

As of July 31, 2012, we own 13,109 net undeveloped acres in the Wolfcamp with 100% operated working interest. Our Wolfcamp acreage consists of mostly contiguous acreage in Lynn County, Texas. We intend to initially target the interbedded sands in the Upper and Lower Spraberry and the highly organically-rich carbonates and shales of the Wolfcamp, Dean and Cline intervals. Additional potential targets on our Wolfcamp acreage include the Clear Fork, Canyon, Strawn and Mississippian intervals. The majority of our leases in the Wolfcamp are in the first year of their three-year primary term and provide for two-year extension options. We will be the operator on our Wolfcamp leasehold acreage, and we intend to commence drilling during the first quarter of 2013. We estimate that we have 164 net potential drilling locations in the Wolfcamp. Through the end of 2013, we plan to drill 11 net horizontal wells and have budgeted $87 million for estimated drilling capital expenditures in the Wolfcamp.

Based on publicly available information, we believe that average drilling and completion costs for horizontal wells in the Wolfcamp play have ranged between $6.5 million and $7.7 million per well, average EURs have ranged from 420,000 to 570,000 boe per well, and initial 30-day average production has ranged from 525 to 600 boe/d per well.

Recently, there has been significant industry activity in the Wolfcamp. The most active operators offsetting our acreage position include Royal Dutch Shell plc, BHP Billiton Petroleum, Apache Corporation, and Concho Resources Inc. According to Drillinginfo, Inc., there were 163 drilling permits filed in 2011 and 71 filed in 2012 through July 18 in Lynn, Lubbock, Hockley, and Terry Counties, Texas, which offset our acreage position. According to estimates prepared by Baker Hughes, there were 447 rigs operating in the Permian Basin as of July 13, 2012, a 54% increase since January of 2011.

The following table provides information regarding recent transactions exceeding $50 million in estimated purchase price in the Permian Basin that included significant Wolfcamp acreage. The information is based on information publicly released by parties involved in these transactions and does not reflect any post-closing purchase price adjustments.


Date	Buyer	Seller	Net Acres		Estimated Purchase Price ($MM)		Production boe/d
05/13/12	Concho Resources Inc.	Three Rivers Operating Company LLC		200,000	$	1,000.0		7,000
12/22/11	Concho Resources Inc.	PDC Energy, Inc.		10,200	$	175.0		1,100
06/16/11	Laredo Petroleum, Inc.	Broad Oak Energy Inc.		65,000	$	1,000.0		8,000
04/26/11	W&T Offshore, Inc.	Opal Resources, LLC		21,500	$	366.0		2,950
03/31/11	Berry Petroleum Company	Undisclosed		6,000	$	129.4		500
05/05/11	Petrohawk Energy Corporation	Undisclosed		325,000	$	455.0		—
04/27/11	Antares Energy Limited	Clear Water, Inc.		2,952	$	62.0		—

Niobrara

As of July 31, 2012, we own 16,931 net acres in the Niobrara, substantially all of which are undeveloped, with 100% operated working interest. Our Niobrara acreage is in Weld County, Colorado, and Laramie and Goshen Counties, Wyoming, in the multi-target Denver-Julesburg Basin. Our Niobrara leasehold acreage is focused on the west, north and east flanks of the Wattenberg Field in Weld County, Colorado, the Silo Field in Laramie County, Wyoming, and the deepest parts of the basin in Goshen County, Wyoming. We are evaluating several zones within the Niobrara Shale, Fort Hays Limestone and Codell Sand formations. Additional targets include the J Sandstone, Dakota Sandstone, Greenhorn Limestone and Lyons Sandstone formations along with Permian and Pennsylvanian objectives. We believe our Niobrara leasehold acreage is in areas with a higher incidence of naturally induced faulting and fracturing and moderate to high Niobrara resistivities. The majority of our leases in the Niobrara are in the second year of their five-year primary term and provide for three- to five-year optional extensions. We estimate that we have 66 net potential drilling locations in the Niobrara. Through the end of 2013, we plan to drill 15 net vertical wells and have budgeted $10 million for estimated drilling capital expenditures in the Niobrara.

We participated in the PDC Energy operated Moss 14-16H, a horizontal Niobrara well located in Weld County, Colorado on the north flank of Wattenberg Field. The Moss 14-16H produced 870 bbls (net) of oil and 1,672 Mcf (net) of natural gas in the second quarter of 2012. We own a 9.3% non-operated working interest in this well. We may drill several more horizontal Niobrara wells with PDC Energy in Weld County, Colorado, in which we will have an average working interest of approximately 50%. Although we have a 100% operated working interest in our acreage in the Niobrara, we will have less than a 100% working interest in, and will not be the operator of, some wells in which we participate as a result of forced pooling of our acreage with the acreage of other operators.

Based on publicly available information, we believe that average drilling and completion costs for horizontal wells in the Niobrara have ranged between $3.6 million and $7.5 million per well, average EURs have ranged from 250,000 to 500,000 boe per well, and initial 30-day average production has ranged from 300 to 600 boe/d per well.

Recently, there has been significant industry activity in the Niobrara. The most active operators offsetting our acreage position include PDC Energy Corporation, Noble Energy, Inc., Anadarko Petroleum Corporation, Encana Corporation, Whiting Petroleum Corporation, and Carrizo Oil and Gas, Inc. According to Drillinginfo, Inc., there were 2,903 drilling permits filed in 2011 and 1,218 filed in 2012 through July 18 in Goshen and Laramie Counties, Wyoming, and Weld County, Colorado, which represent the counties where our acreage is located. According to estimates prepared by Baker Hughes, there were 44 rigs operating in the Denver-Julesburg Basin as of July 13, 2012, a 38% increase since January of 2011.

The following table provides information regarding recent transactions exceeding $50 million in estimated purchase price in the Niobrara. The information is based on information publicly released by parties involved in these transactions and does not reflect any post-closing purchase price adjustments.


Date	Buyer	Seller	Net Acres		Estimated Purchase Price ($MM)		Production boe/d
5/14/12	PDC Energy, Inc.	Undisclosed		35,000	$	327.0		2,800
7/13/11	Bill Barrett Corporation	Texas American Resources Company		28,000	$	150.0		650
04/04/11	Marubeni Corporation	Marathon Oil Corporation		54,000	$	270.0		—
01/31/11	CNOOC Limited	Chesapeake Energy Corporation		266,400	$	1,267.0		—

Our Strategy

Our strategy is to increase shareholder value by increasing our leasehold position and growing estimated proved reserves, production and cash flow to generate attractive rates of return on capital. We intend to achieve this objective as follows:

Aggressively drill and develop our existing acreage positions. We plan to aggressively drill our Eaglebine acreage with our partner Halcón. We plan to drill 25 net wells and spend $144 million through 2013 in the Eaglebine alone. We will balance this non-operated development drilling with operated drilling programs in the Wolfcamp, where we plan to drill 11 net wells and spend $87 million, and in the Niobrara, where we plan to drill 15 net wells and spend $10 million, through the end of 2013. We believe our non-operated and operated drilling programs will allow us to begin converting our undeveloped acreage to developed acreage with production, cash flow and proved reserves.

Acquire additional leasehold acreage in our existing core areas. We plan to leverage our relationships and experienced land acquisition team to continue to pursue additional leasehold acquisitions in our core areas. We will focus on additional leasehold acreage in the Eaglebine outside of our Halcón AMIs, and we will continue to opportunistically pursue additional acreage in the Wolfcamp and Niobrara.

Enhance returns through operational efficiencies as our rig count and well count grow. We intend to focus on continuous improvement of our operating measures as we seek to convert early-stage resource opportunities into cost-efficient development projects. In the Wolfcamp and Niobrara where we will be the operator, we intend to focus on decreasing drilling times, increasing EURs and optimizing operating efficiencies, and we plan to work with

Halcón on the same initiatives in the AMIs where it is the operator. We believe the magnitude and concentration of our leasehold acreage within our three core areas provide us with the opportunity to capture economies of scale. On our larger contiguous acreage blocks, we intend to drill multiple wells off of each pad with centralized production facilities, thereby lowering completed well cost and potentially increasing returns on capital.

Maintain financial strength and flexibility. On June 26, 2012, we entered into a $100 million senior secured advancing line of credit with Guggenheim Corporate Funding, LLC, which we refer to as our credit facility. The credit facility has an initial borrowing base of $30 million. We expect that the proceeds from this offering, internally generated cash flow, borrowings under our credit facility and proceeds from asset divestitures will provide us with the financial resources to pursue our leasing and drilling and development programs. As of March 31, 2012, on a pro forma, as adjusted basis giving effect to the Pro Forma Transactions described under “—Summary Historical and Pro Forma Combined Financial Data” and the completion of this offering, we would have had approximately $ million in cash and approximately $ million in borrowing capacity available under our credit facility. We intend to actively manage our exposure to commodity price risk by entering into commodity derivative positions for a significant portion of our anticipated future production.

Our Strengths

We believe we are well positioned to successfully execute our business strategies and achieve our business objectives because of the following competitive strengths:

Significant acreage positions in key unconventional plays. We have accumulated a total of 45,276 net acres as of July 31, 2012 in our three core operating areas, each of which we believe represents a significant unconventional resource play. The majority of our leasehold acreage is in or near areas of considerable activity by both major and independent operators. We believe that lease terms in our three core areas allow us enough time to drill wells needed for our acreage to be held by production based on our current drilling plan.

Substantial drilling inventory. Based on our acreage position of 45,276 net acres, we estimate there could be up to 452 net potential drilling locations in our core areas. Through the end of 2013 we anticipate drilling 18 net horizontal Eaglebine wells, 7 net vertical Eaglebine Lower Cretaceous wells, 11 net horizontal Wolfcamp wells, and 15 net vertical Codell/Niobrara wells, leaving us a substantial drilling inventory for future years.

Experienced technical and land acquisition teams. Our senior technical team is comprised of geoscience, engineering and operational professionals who average 34 years of industry experience. Members of our technical team have previously held technical and management positions with major and independent oil and natural gas companies, including Mobil Corporation, Phillips Petroleum Corporation, and Pitts Energy Group. Our core management and land acquisition team has profitably built and sold large acreage positions in several developing unconventional plays prior to building our current acreage position in the Eaglebine, Wolfcamp and Niobrara. We expect continued organic growth through leasing additional acreage in our current core areas.

Incentivized management, technical and land acquisition team. We believe that equity ownership is one of the best ways to motivate management and employees to act in the best interest of equity stockholders. Our management and employees will own approximately % of our outstanding shares following the completion of this offering, which we believe will align the interests of management, employees and stockholders.

Proximity to significant industry infrastructure and access to multiple product markets. Our core area in the Eaglebine is near substantial existing hydrocarbon gathering, transportation, processing and refining capacity, and has access to multiple product sales points. Our Wolfcamp and Niobrara acreage positions also have access to existing hydrocarbon gathering and transportation infrastructure, which we believe will allow us to get production online more rapidly and achieve competitive product pricing when compared to other more remote producing basins.

Corporate Reorganization

We were recently incorporated pursuant to the laws of the State of Delaware as Energy & Exploration Partners, Inc. to become a holding company for our business. Prior to the completion of this offering, we will effect a series of reorganization transactions, which we refer to collectively as our corporate reorganization.

Prior to the completion of the corporate reorganization, our business has been conducted through two entities directly or indirectly owned and controlled by Hunt Pettit, our founder, President and Chief Executive Officer: Energy & Exploration Partners, LLC, which owns our existing acreage, and Energy & Exploration Partners Operating, LP, which was formed to conduct our drilling operations. In 2011, Mr. Pettit and certain investors formed North American Shale Investment Fund, LP, or NASIF, to acquire net profits interests and overriding royalty interests in certain of our acreage. Mr. Pettit owns all of the equity interests in the general partner of NASIF, and the other investors own all of the limited partner interests in NASIF. Mr. Pettit also owns all of the outstanding equity interests in North American Shale Investment Advisors, LLC, or NASIF Advisors, which is a party to an investment management agreement with NASIF. In addition to the net profits interests in our acreage owned by NASIF, certain investors, which we refer to as the Niobrara investors, own additional net profits interests in our Niobrara acreage.

Our corporate reorganization will consist of the following transactions:

Contributions to Energy & Exploration Partners, Inc. Pursuant to a contribution agreement, the following contributions will be made to us:

•

Hunt Pettit, our founder, President and Chief Executive Officer, and an affiliated entity will contribute the following interests to us in exchange for shares representing approximately 50% of our outstanding common stock:

•

all of the outstanding equity interests in Energy & Exploration Partners, LLC;

•

all of the outstanding equity interests in Energy & Exploration Partners Operating, LP and in its general partner; and

•

all of the outstanding equity interests in the general partner of NASIF and in NASIF Advisors;

•

the limited partners of NASIF will contribute all of the outstanding limited partner interests in NASIF to us in exchange for shares representing approximately 20% of our common stock; and

•

certain of the Niobrara investors will contribute their net profits interests in our Niobrara acreage to us in exchange for shares representing approximately 2% of our common stock.

Immediately prior to the contributions described above, NASIF will distribute to its limited partners the overriding royalty interests held by NASIF in our acreage. For additional information regarding these overriding royalty interests and overriding royalty interests held by members of our management and our other employees, see “Certain Relationships and Related Party Transactions—Overriding Royalty Interests” and “Executive Compensation—Overriding Royalty Interests.”

Additionally, we will repurchase the net profits interests held by the Niobrara investors that will not be parties to the contribution agreement for total cash payments of $1.7 million. Following the transactions described above, NASIF, its general partner and NASIF Advisors will be liquidated and dissolved, the investment management agreement between NASIF and NASIF Advisors will be terminated, and the net profits interests in our acreage previously held by NASIF and the Niobrara investors will be canceled.

Energy & Exploration Partners, LLC also recently assigned its general partnership interest in Energy & Exploration Partners, LP to an affiliated entity of Hunt Pettit for de minimis consideration. Energy & Exploration Partners, LP is a plaintiff in certain immaterial contract disputes related to certain oil and natural gas properties previously held by us and holds no other assets. Mr. Pettit owns all of the limited partnership interests in Energy & Exploration Partners, LP.

Restricted Stock Awards for Management. In connection with the transactions described above, we will make awards to members of our senior management, other than Mr. Pettit, of restricted shares of our common stock representing approximately 28% of our outstanding shares of common stock under our 2012 Stock Incentive Plan. We expect that these shares of restricted stock will vest over a three-year period. See “Executive Compensation—2012 Stock Incentive Plan.”

For more information on our corporate reorganization and the ownership of our common stock by our principal stockholders, see “Corporate Reorganization” and “Principal Stockholders.”

The following diagram indicates our ownership structure after giving effect to our corporate reorganization and this offering.

Ownership Structure After Giving Effect to Corporate Restructuring and this Offering

LOGO

(1)	Represents shares of restricted stock granted to members of our senior management other than Hunt Pettit under our 2012 Stock Incentive Plan. See “Executive Compensation—2012 Stock Incentive Plan.”

Corporate History; Corporate Information

Our company was formed in 2006 and began operations in 2008. In early 2010, we began leasing in the Eagle Ford Shale trend, primarily in McMullen and LaSalle Counties, Texas, where we leased and ultimately sold over 125,000 acres to major and independent oil and natural gas companies, including Murphy Oil Corporation and Comstock Resources, Inc. In early 2011, we began accumulating leasehold acreage in our three core areas.

Our principal executive offices are located at Two City Place, Suite 1700, 100 Throckmorton, Fort Worth, Texas 76102, and our telephone number at that address is (817) 789-6712. Our website address is http://www.enexp.com. Information contained on our website is not incorporated by reference into this prospectus, and you should not consider the information contained on our website to be part of this prospectus.

Risk Factors

An investment in our common stock involves significant risks. In particular, the following considerations may offset our competitive strengths or have a negative effect on our business, financial condition or results of operations, which could cause a decrease in the price of our common stock and result in a loss of all or a portion of your investment:

•

We have not recorded any proved reserves, and areas that we decide to drill may not yield oil or natural gas in commercial quantities, or at all.

•

We have limited operating history on which to base your evaluation of us, and our future performance is uncertain.

•

Oil and natural gas prices are volatile. A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

•

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

•

Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms.

•

Our executive officers and our largest stockholders have direct economic interests in our properties, and their interests may not be aligned with our interests.

•

The concentration of our capital stock ownership by our largest stockholder will limit your ability to influence corporate matters.

•

Our potential drilling locations are expected to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. We have no proved, probable or possible reserves attributable to any of the drilling locations we disclose in this prospectus.

•

We are subject to complex federal, state, local and other laws and regulations, including environmental and operational safety laws and regulations, that could adversely affect the timing, cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

This list is not exhaustive. Please read the full discussion of these risks and other risks under the heading “Risk Factors” beginning on page 14.

Implications of Being an Emerging Growth Company

As a company with less than $1.0 billion in revenue during its last fiscal year, we qualify as an “emerging growth company” as defined in the recently enacted Jumpstart Our Business Startups Act of 2012, or the JOBS Act. An emerging growth company may take advantage of exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies.” These include:

•

an exemption from the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act relating to internal control over financial reporting;

•

reduced disclosure about the emerging growth company’s executive compensation arrangements; and

•

exemptions from the requirements of holding a non-binding advisory vote on executive compensation and shareholder approval of golden parachute arrangements.

We may take advantage of these reporting exemptions until we are no longer an emerging growth company. We will remain an “emerging growth company” until the earliest of the following:

•

the end of the fiscal year in which the fifth anniversary of the completion of this offering occurs;

•

the end of the first fiscal year in which the market value of our common stock that is held by non-affiliates is at least $700 million as of the end of the second quarter of such fiscal year;

•

the end of the first fiscal year in which we have total annual gross revenues of at least $1.0 billion; and

•

the date on which we have issued more than $1.0 billion in non-convertible debt securities in any rolling three-year period.

We may choose to take advantage of some or all of these reduced reporting requirements, and if we do, the information that we provide to our stockholders may be different from information provided by other public companies. We have taken advantage of the reduced executive compensation disclosure requirements in this prospectus. Additionally, in this prospectus we have taken advantage of reduced financial reporting requirements available under the JOBS Act for an emerging growth company in the registration statement for its initial public offering. Specifically, we have provided only two years of audited financial statements and selected financial data and related discussion in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

The Offering

Issuer

Energy & Exploration Partners, Inc.

Common stock offered

Common stock to be outstanding after this offering

Option to purchase additional shares

The underwriters have an option to purchase a maximum of additional shares of common stock from us to cover sales by the underwriters of more than shares. The underwriters can exercise this option at any time within 30 days from the date of this prospectus.

Use of proceeds

We expect to receive approximately $ million of net proceeds from the sale of the common stock offered by us, based upon an assumed initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses payable by us. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $ million.

We intend to use the net proceeds we receive from this offering to fund a portion of our 2012 and 2013 capital expenditure budget for drilling and developing our existing leasehold acreage and acquiring additional oil and natural gas leases. See “Use of Proceeds.”

Dividend policy

After this offering, we do not anticipate paying cash dividends on our common stock in the foreseeable future. See “Dividend Policy.”

Listing

We intend to apply to list our common stock on the New York Stock Exchange under the symbol “ENXP.”

Risk Factors

See “Risk Factors” beginning on page 14 for a discussion of factors you should consider before deciding to purchase shares of our common stock.

Unless otherwise indicated, all share information contained in this prospectus:

•

assumes that the underwriters’ option to purchase additional shares, granted by us, will not be exercised; and

•

does not include shares of common stock reserved for issuance under our 2012 Stock Incentive Plan.

Summary Historical and Pro Forma Combined Financial Data

Set forth below are our summary historical combined financial data as of and for the years ended December 31, 2010 and 2011 and as of and for the three months ended March 31, 2011 and 2012, and our summary pro forma combined and condensed financial data for the year ended December 31, 2011 and as of and for the three months ended March 31, 2012. The summary historical combined financial data as of and for the years ended December 31, 2010 and 2011 are derived from our audited combined financial statements included elsewhere in this prospectus. The summary historical combined financial data as of and for the three months ended March 31, 2011 and 2012 are derived from our unaudited combined financial statements included elsewhere in this prospectus, which, in the opinion of our management, include all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of this information. Results of operations for the three months ended March 31, 2011 and 2012 are not necessarily indicative of the results of operations for the entire year or any future period.

Prior to the completion of our corporate reorganization, our business has been conducted through Energy & Exploration Partners, LLC, Energy & Exploration Partners, LP, Energy & Exploration Partners Operating, LP and Energy & Exploration Partners Operating GP, LLC, each of which has been owned by our founder Hunt Pettit. For this reason, the financial statements included in this prospectus consist of the historical audited and unaudited combined balance sheets of Energy & Exploration Partners, LLC, Energy & Exploration Partners, LP, Energy & Exploration Partners Operating, LP and Energy & Exploration Partners Operating GP, LLC and the related combined statements of operations, owners’ equity and cash flows.

The summary pro forma combined and condensed financial data are derived from the unaudited pro forma combined and condensed financial statements included elsewhere in this prospectus and give effect to:

•

the transactions described under “—Corporate Reorganization;”

•

our conveyance of working interests to Halcón through July, 31, 2012 as described under “—Our Core Areas—Eaglebine;” and

•

entry into our credit facility, the initial borrowings thereunder and the repayment of previously outstanding debt with a portion of those borrowings.

We refer to these transactions collectively as the “Pro Forma Transactions.” The summary pro forma combined and condensed statement of operations data give effect to the Pro Forma Transactions as if they had occurred on January 1, 2011, and the summary pro forma combined and condensed balance sheet data give effect to the Pro Forma Transactions as if they had occurred on March 31, 2012. The summary pro forma combined and condensed financial data are not necessarily indicative of what our results of operations or financial position would have been if the Pro Forma Transactions had actually occurred on those dates or of our future results of operations or financial position.

The information set forth below should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical and pro forma financial statements and the notes thereto included elsewhere in this prospectus. The financial data included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

During the years ended December 31, 2010 and 2011, we were an entity engaged in the acquisition and sale of undeveloped oil and natural gas leasehold interests. Beginning in the first quarter of 2012, we adopted a business strategy to develop and exploit our undeveloped leasehold acreage in order to provide a greater return on investments in those properties. At that time, we adopted the full cost method of accounting for oil and natural gas properties. For purposes of the summary historical combined financial data, proceeds from sales of undeveloped leasehold acreage that we previously reported as revenue in our financial statements when we were an entity engaged in the acquisition and sale of undeveloped oil and natural gas leasehold interests, and the costs of those sales that we previously reported as cost of sales, are reported on a net basis as gains on sales of assets. Similarly, cash outflows for undeveloped leasehold acreage that we previously reported as operating outflows in our financial statements when we were an entity engaged in the acquisition and sale of undeveloped oil and natural gas leasehold interests are reported as investing outflows in the summary historical combined financial data.


	Historical												Pro Forma
	Year Ended December 31,						Three Months Ended March 31,						Year Ended December 31,			Three Months Ended March 31,
	2010			2011			2011			2012			2011			2012
							(unaudited)						(unaudited)
	(in thousands)
Statement of operations data:
Revenues	$	—		$	—		$	—		$	30		$	—		$	30
Operating expenses	$	1,901		$	1,777		$	193		$	693		$	1,912		$	714
Loss from operations	$	(1,901	)	$	(1,777	)	$	(193	)	$	(663	)	$	(1,912	)	$	(684	)
Net income (loss)	$	4,129		$	(1,478	)	$	367		$	(1,189	)	$	514		$	5,502


	As of December 31,				As of March 31,
	2010		2011		2011		2012		Pro Forma 2012
					(unaudited)				(unaudited)
	(in thousands)
Balance sheet data:
Cash and cash equivalents	$	2,565	$	5,333	$	1,137	$	3,513	$	34,269
Property, plant and equipment	$	3,649	$	21,641	$	6,913	$	27,748	$	15,314
Total assets	$	6,728	$	27,904	$	8,558	$	32,557	$	55,141
Note payable, net of discount	$	—	$	9,928	$	—	$	14,978	$	21,471
Total equity	$	5,669	$	4,471	$	6,101	$	3,282	$	28,739


	Year Ended December 31,						Three Months Ended March 31,
	2010			2011			2011			2012
							(unaudited)
	(in thousands)
Other financial data:
Net cash provided by (used in) operating activities	$	3,445		$	51		$	996		$	(626	)
Net cash used in investing activities	$	(3,633	)	$	(18,972	)	$	(3,823	)	$	(5,805	)
Net cash provided by financing activities	$	797		$	21,689		$	1,399		$	4,611
Opening cash	$	1,956		$	2,565		$	2,565		$	5,333
Closing cash	$	2,565		$	5,333		$	1,137		$	3,513

An investment in our common stock involves significant risks. You should carefully consider the risks described below together with the other information set forth in this prospectus before making an investment decision. Our business, financial condition or results of operations could be materially adversely affected by any of these risks. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.

We have not recorded any proved reserves and areas that we decide to drill may not yield oil in commercial quantities or quality, or at all.

We have not recorded any proved reserves. We describe some of our potential drilling locations and our plans to explore those drilling locations in this prospectus. Our potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We have no proved, probable or possible reserves attributable to any of our potential drilling locations. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in sufficient quantities to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production from the well or abandonment of the well. If we drill additional wells that we identify as dry holes, our drilling success rate may decline and materially harm our business. We cannot assure you that the analogies we draw from available data from other wells, more fully explored locations or producing fields will be applicable to our potential drilling locations. Further, drilling costs and initial production rates reported by other operators in the areas in which our properties are located may not be indicative of future or long-term drilling costs or production rates. Ultimately, the cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive.

We may terminate our drilling program for a prospect if data, information, studies and previous reports indicate that the possible development of our prospect is not commercially viable and, therefore, does not merit further investment. If a significant number of our prospects do not prove to be successful, our business, financial condition and results of operations will be materially adversely affected.

We are a company in the initial stages of exploration, development and exploitation of our undeveloped leasehold acreage and will continue to be so until commencement of substantial production from our oil and natural gas properties, which will depend upon successful drilling results, additional and timely capital funding, and access to suitable infrastructure. Companies in their initial stages of development face substantial business risks and may suffer significant losses. We have generated substantial net losses and negative cash flows from operating activities since we adopted a business strategy to develop our undeveloped leasehold acreage and expect to continue to incur substantial net losses as we continue our drilling program. In considering an investment in our common stock, you should consider that there is only limited historical and financial operating information available upon which to base your evaluation of our performance. We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. New companies must develop successful business relationships, establish operating procedures, hire staff, install management information and other systems, establish facilities and obtain licenses, as well as take other measures necessary to conduct their intended business activities. We may not be successful in implementing our business strategies or in completing the development of the infrastructure necessary to conduct our business as planned. In the event that one or more of our drilling programs is not completed or is delayed or terminated, our operating results will be adversely affected and our operations will differ materially from the activities described in this prospectus. As a result of industry factors or factors relating specifically to us, we may have to change our methods of conducting business, which may cause a material adverse effect on our results of operations and financial condition. The uncertainty and risks described in this prospectus may impede our ability to economically find, develop, exploit and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by our operating activities in the future.

A substantial or extended decline in oil, natural gas and natural gas liquids prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we will receive for our oil, natural gas and natural gas liquids will significantly affect our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we will receive for our production, and the levels of our production, will depend on numerous factors beyond our control. These factors include the following:

Lower oil and natural gas prices will reduce our cash flows and our borrowing ability. See also “—Our business plan requires substantial additional capital, which we may be unable to raise on acceptable terms in the future, which may in turn limit our ability to develop our exploration and production plans.” A substantial or extended decline in oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit drilling locations or

properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our costs of drilling, completing and operating wells are uncertain before drilling commences. In addition, the application of new techniques for horizontal fracture stimulation and completion, may make it more difficult to accurately estimate these costs. Overruns in budgeted expenditures are common risks that can make a particular project uneconomic. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

Our business plan requires additional capital, which we may be unable to raise on acceptable terms in the future, which may in turn limit our ability to develop our exploration and production plans.

We expect our capital outlays and operating expenditures to increase substantially over the next several years as we expand our operations. Exploration and production plans are expensive, and we expect that we will need to raise substantial additional capital, through future private or public equity offerings, strategic alliances or debt financing.

While we believe our operations, upon the consummation of this offering, will be adequately funded through 2013, we do not expect to generate significant revenue from production before 2013. Additional financing may not be available on favorable terms, or at all. We intend to finance our future capital expenditures primarily through cash flows provided by operating activities, borrowing under our credit facility, proceeds from asset divestitures and net proceeds from this offering. However, the lenders under our credit facility are not obligated to advance funds to us under the facility for the drilling and completion of any wells after our first four Eaglebine wells. Additionally, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or additional equity securities. The issuance of additional debt may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. If we succeed in selling additional equity securities to raise funds, at such time the ownership percentage of our existing stockholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we raise additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we choose to farm-out interests in our prospects, we may lose operating control over such prospects.

If we are not successful in raising additional capital, we may be unable to continue our exploration and production activities or successfully exploit our oil and natural gas properties, and we may lose the rights to develop these our oil and natural gas properties upon the expiration of our leases.

Our credit facility contains covenants that may inhibit our ability to make certain investments, incur additional indebtedness or engage in certain other transactions, which could adversely affect our ability to meet our future goals.

These covenants may restrict our ability to expand or pursue our business strategies. The breach of any of these covenants could result in a default under our credit facility. Our credit facility also provides for events of default that are not within our control, including the termination of our joint operating agreement with Halcón relating to AMI #1 prior to our receipt of the contingent payment Halcón is required to make to us for the AMI #1 interests conveyed to Halcón under our purchase and sale agreement with Halcón. If an event of default under the credit facility occurs, the lenders could elect to declare all amounts borrowed under our credit facility, together with accrued interest, to be due and payable. If we were unable to repay such borrowings or interest, our lenders could proceed against their collateral. If the indebtedness under our credit facility were to be accelerated, our assets may not be sufficient to repay in full such indebtedness.

Our level of indebtedness, which may increase, could reduce our financial flexibility.

Upon the completion of this offering, we expect to have outstanding indebtedness of approximately $ million and a borrowing capacity of $ million under our credit facility, subject to periodic redetermination. In the future, we may incur significant indebtedness in order to develop our properties or to make future acquisitions.

Our level of indebtedness could affect our operations in several ways, including the following:

A high level of indebtedness would increase the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness will depend on our future performance. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

Our credit facility requires periodic repayments of the principal amounts outstanding beginning in July 2013 and quarterly thereafter until its maturity in December 2014. In addition, the borrowing base under our credit facility will be subject to semi-annual redeterminations beginning in October 2013. We could be forced to repay a portion of our borrowings under our credit facility due to redeterminations of our borrowing base. If we do not have

sufficient funds to repay borrowings under our credit facility when due and 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.

We will not be the operator on a significant portion of our drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

Although we expect to be the operator of many of our future drilling locations, we are not the operator on our Eaglebine AMI #1 and AMI #2 acreage. As we carry out our exploration and development programs in the future, we may enter into arrangements with respect to existing or future drilling locations that result in additional drilling locations being operated by others. As a result, we may have limited ability to exercise influence over the operations of the drilling locations operated by our partners. Dependence on the operator could prevent us from realizing our target returns for those locations. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:

This limited ability to exercise control over the operations of some of our drilling locations may cause a material adverse effect on our results of operations and financial condition.

Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks, and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.

Our operations in the Eaglebine, Wolfcamp and Niobrara involve utilizing the latest drilling and completion techniques in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we may 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 may 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 will be 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 limited takeaway capacity or otherwise, 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 natural gas properties and the value of our undeveloped acreage could decline in the future.

Our properties are geographically concentrated, making us disproportionately vulnerable to risks associated with operating in our areas of operation.

Our properties are geographically concentrated. At July 31, 2012, all of our acreage was located in three basins: the Eaglebine in East Texas, the Wolfcamp in West Texas and the Niobrara in Colorado and Wyoming. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in these areas caused by governmental regulation, processing or transportation capacity constraints, market limitations, or interruption of the processing or transportation of oil, natural gas or natural gas liquids.

If oil and natural gas prices decrease, our development efforts are unsuccessful or our capital and operating costs increase substantially, we may be required to take write-downs of the carrying values of our oil and natural gas properties.

We employ the full cost method of accounting for our oil and natural gas properties which, among other things, imposes limits to the capitalized cost of our assets. The capitalized cost pool cannot exceed the net present value of the underlying oil and natural gas reserves. We will review our future proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Based on specific circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties, which may result in a decrease in the amount available under future credit facilities. A write down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our ability to borrow under our credit facility and our results of operations for the periods in which such charges are taken.

Our business depends on oil and natural gas gathering and transportation facilities owned by third parties.

The marketability of our oil and natural gas production will depend in part on the availability, proximity and capacity of gathering, processing and pipeline systems owned by third parties. The unavailability of, or lack of, available capacity on these systems and facilities could result in the shut-in of producing wells or the delay, or discontinuance, of development plans for properties. We do not expect to purchase firm transportation on third-party facilities and, therefore, we expect the transportation of our production to be generally interruptible in nature and lower in priority to those having firm transportation arrangements. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport our oil and natural gas.

The disruption of third-party facilities due to maintenance and/or weather could also negatively impact our ability to market and deliver our products. We have no control over when or if such facilities are restored by third-party owners or operators, or what prices will be charged for their services. A total shut-in of production resulting from the acts or omissions of third-party transportation providers, or circumstances affecting third-party transportation facilities, could materially affect us due to a lack of cash flow, and if a substantial portion of the price risk associated with production volumes is mitigated through commodity derivative instruments at lower than market prices, those commodity derivative settlements would have to be paid from borrowings absent sufficient cash flow.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our exploration and development operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations. The cost to develop our projects has not been fixed and remains dependent upon an number of factors, including the completion of detailed cost estimates and final engineering, contracting and procurement costs. Our drilling and operation schedules may not proceed as planned and may experience delays or cost overruns. Any delays may increase the costs of the projects, requiring additional capital, and such capital may not be available on a timely and cost-effective fashion.

Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

Our ability to successfully acquire additional properties, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with industry participants and our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and our inability to maintain close working relationships with industry participants or continue to acquire suitable property may impair our ability to execute our business plan.

To continue to develop our business, we will endeavor to use the business relationships of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and natural gas companies, including those that supply equipment and other resources that we will use in our business. We may not be able to establish these strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas gathering and transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production will depend on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production will depend, in substantial part, on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third-parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of oil or natural gas pipelines or gathering system capacity. If our production becomes shut-in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Our potential drilling locations are expected to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill a substantial portion of our potential drilling locations.

We have provided information regarding potential drilling locations on our existing acreage. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, availability of drilling services and equipment, lease expirations, gathering system, marketing and pipeline transportation constraints, oil and natural gas prices, drilling and production costs, drilling results and other factors. Additionally, our leases will expire if, prior to expiration of the initial term of such leases, we do not meet the production levels in the leases to hold the acreage. Because of these uncertainties and the potential for losing acreage where we have insufficient production to hold the acreage, we do not know if the potential drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Pursuant to the U.S. Securities and Exchange Commission (SEC) rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. SEC rules and guidance may limit our potential to book proved undeveloped reserves as we pursue our drilling program.

Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Our leases on oil and natural gas properties typically have a primary term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of July 31, 2012, we had leases representing 87 net acres expiring in 2012, 2,380 net acres expiring in 2013, 17,747 net acres expiring in 2014 and 25,062 net acres expiring thereafter. Of the 87 acres of leases that expire in 2012, we expect to exercise options to extend the leases by two to three years. If our extension options expire and we have to renew such leases on new terms, we could incur significant cost increases, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing, or fracking, processes. According to the Lower Colorado River Authority, during 2011, Texas experienced the lowest inflows of water of any year in recorded history. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing in order to protect local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the timing, cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may experience delays in receiving such permits, approvals and certificates. Delays in permitting could result in delays in execution of our drilling and development program. We may incur substantial costs in order to maintain compliance with existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

See “Business—Regulation of the Oil and Natural Gas Industry” for a further description of the laws and regulations that affect us.

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.

As a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Act. The law prohibits the harming of endangered or threatened species, provides for habitat protection, and imposes stringent penalties for noncompliance. The final 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, delays, or prohibitions on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

Our operations are subject to environmental and operational safety laws and regulations that may expose us to significant costs and liabilities.

Our oil and natural gas exploration and production operations are subject to stringent and complex federal, state and local laws and regulations governing health and safety aspects of our operations, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of permits before conducting drilling or underground injection activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within

wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of our operations.

There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and wastes, because of air emissions and waste water discharges related to our operations, and as a result of historical industry operations and waste disposal practices. Under certain environmental laws and regulations, we could be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which our wells are drilled and facilities where our petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose us to significant liabilities that could have a material adverse effect on our financial condition or results of operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our own results of operations, competitive position or financial condition. We may not be able to recover some or any of these costs from insurance.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. These findings by the EPA have allowed the agency to proceed with the adoption and implementation of regulations restricting emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Among other things, EPA regulations now require specified large greenhouse gas emitters in the United States, including companies in the energy industry, to annually report those emissions. Additionally, starting in 2011, new sources or modifications of existing sources of significant quantities of greenhouse gas emissions are required to obtain permits – and to use best available control technology to control those emissions – pursuant to the Clean Air Act as a prerequisite to the development of that emissions source. While these regulations have not to date materially affected our company, such regulations may over time require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce.

Additionally, the U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane, that are understood to contribute to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that smaller sources could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.

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 essential and common practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. We expect to routinely apply hydraulic-fracturing techniques in many of our oil and natural-gas drilling and completion programs. The process is typically regulated by state oil and natural-gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic-fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process.

Certain states, including Texas, Wyoming and Colorado, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (RCT) and the public of certain information regarding the components used in the hydraulic-fracturing process. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells.

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic-fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, 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. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.

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 shales 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. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate hydraulic fracturing activities.

Further, on April 17, 2012, the EPA approved final rules that would subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance

Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs. These rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion (REC) techniques developed in EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (MACT) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. At this point, the effect these proposed rules could have on our business has not been determined. While these rules have been finalized, many of the rules’ provisions will be phased-in over time, with the more stringent requirements like REC not becoming effective until 2015.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.

Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, obtaining gathering, processing and pipeline transportation services, marketing oil and natural gas and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial and commodity markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel in the regions in which we operate has increased over the past few years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.

The loss of senior management or technical personnel could adversely affect our operations.

To a large extent, we depend on the services of our senior management and technical personnel who have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production, and developing and executing acquisition, financing and hedging strategies. Our ability to hire and retain senior management and technical personnel is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could negatively impact our ability to execute our business strategy. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. Our credit agreement provides that it is an event of default if either Hunt Pettit, our President and Chief Executive Officer, or Brian Nelson, our Executive Vice President and Chief Financial Officer, ceases to serve in those capacities and a replacement approved by our lenders is not installed within 30 days.

Changes in the differential between benchmark prices of oil and natural gas and the reference or regional index price used to price our actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition.

The reference or regional index prices that we will use to price our oil and natural gas sales sometimes will reflect a discount to the relevant benchmark prices. The difference between the benchmark price and the price we reference in our sales contracts is called a differential. We cannot accurately predict oil and natural gas differentials. Changes in differentials between the benchmark price for oil and natural gas and the reference or regional index price we reference in our sales contracts could have a material adverse effect on our results of operations and financial condition.

Future derivative activities could result in financial losses or could reduce our income.

To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we may in the future enter into derivative arrangements for a portion of our oil and natural gas production, including collars and fixed-price swaps. We may not designate our future derivative instruments as hedges for accounting purposes, in which case we would record all derivative instruments on our balance sheet at fair value. Changes in the fair value of derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Derivative arrangements also expose us to the risk of financial loss in some circumstances, including when:

In addition, our commodity derivative transactions will expose us to credit risk in the event of default by counterparties. Further deterioration in the credit markets may impact the credit ratings of our potential counterparties and affect their ability to fulfill their obligations to us and their willingness to enter into future transactions with us. A default under any of these agreements could negatively impact our financial performance.

The adoption of derivatives legislation by Congress, and implementation of that legislation by federal agencies, could have an adverse impact on our ability to mitigate risks associated with our business.

On July 21, 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Reform Act, which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation requires the Commodities Futures Trading Commission, or the CFTC, and the SEC to promulgate rules and regulations implementing the new legislation, which they have done since late 2010 and are expected to continue to do through the remainder of 2012. From late 2010 and continuing to the present date, the CFTC has introduced dozens of proposed rules coming out of the Dodd-Frank Reform Act, and has promulgated numerous final rules based on those proposals. The effect of the proposed rules and any additional regulations on our business is not yet entirely clear, but it is increasingly clear that the costs of derivatives-based hedging for commodities will likely increase for all market participants. Of particular concern, the Dodd-Frank Reform Act does not explicitly exempt end users from the requirements to post margin in connection with hedging activities. While several senators have indicated that it was not the intent of the Act to require margin from end users, the exemption is not in the Act. While rules proposed by the CFTC and federal banking regulators appear to allow for non-cash collateral and certain exemptions from margin for end users, the rules are not final and uncertainty remains. The full range of new Dodd-Frank requirements to be enacted, to the extent applicable to us or our derivatives counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments we use to mitigate and otherwise manage our financial and commercial risks related to fluctuations in natural gas, oil and NGL commodity prices. In addition, final rules promulgated by the CFTC imposing federally-mandated position limits cover a wide range of derivatives positions, including non-exchange traded bilateral swaps related to commodities including oil and natural gas. These position limit rules are likely to increase regulatory monitoring and compliance costs for all

market participants, even where a given trading entity is not in danger of breaching position limits. These and other regulatory developments stemming from the Dodd-Frank Reform Act, including stringent new reporting requirements for derivatives positions and detailed criteria that must be satisfied to continue to enter into uncleared swap transactions, could have a material impact on our derivatives trading and hedging activities in the form of increased transaction costs and compliance responsibilities. Any of the foregoing consequences could have a material adverse effect on our financial position, results of operations and cash flows.

Declining general economic, business or industry conditions could have a material adverse effect on our results of operations.

Concerns over the worldwide economic outlook, geopolitical issues, the availability and cost of credit and the United States mortgage and real estate markets contributed to increased volatility and diminished expectations for the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment resulted in a worldwide recession during the second half of 2008 and 2009. Concerns about global economic growth could have a significant adverse effect on global financial markets and commodity prices. If the economic climate in the United States or abroad were to deteriorate, demand for petroleum products could diminish, which could depress the prices at which we could sell our oil and natural gas and ultimately decrease our revenue and profitability.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

We may be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult.

We regularly evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of properties requires an assessment of multiple factors, including:

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we will perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

Significant acquisitions and other strategic transactions may involve other risks, including:

The process of integrating operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

If we fail to realize the anticipated benefits of a significant acquisition, our results of operations may be lower than we expect.

The success of a significant acquisition will depend, in part, on our ability to realize anticipated growth opportunities from combining the acquired assets or operations into our existing operations. Even if a combination is successful, it may not be possible to realize the full benefits we may expect in estimated proved reserves, production volume, cost savings from operating synergies or other benefits anticipated from an acquisition or realize these benefits within the expected time frame. Anticipated benefits of an acquisition may be offset by operating losses relating to changes in commodity prices, or in oil and natural gas industry conditions, or by risks and uncertainties relating to the exploratory prospects of the combined assets or operations, or an increase in operating or other costs or other difficulties. If we fail to realize the benefits we anticipate from an acquisition, our results of operations may be adversely affected.

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 natural 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 natural 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, and substantially all of our acreage is undeveloped. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

The Obama Administration’s budget proposal for fiscal year 2012 includes potential legislation that would, if enacted, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective.

The passage of any legislation as a result of these proposals or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change, as well as any changes to or the imposition of new state or local taxes (including the imposition of, or increase in, production, severance or similar taxes), could negatively affect our financial condition and results of operations.

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active liquid trading market for our common stock may not develop and our stock price may be volatile.

Prior to this offering, our common stock was not traded on any market. An active and liquid trading market for our common stock may not develop or be maintained after this offering. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a decline in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated between us and representatives of the underwriters, based on numerous factors which we discuss in the “Underwriting” section of this prospectus, and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in the offering.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

Our executive officers and largest stockholders have direct economic interests in our properties, and their interests may not be aligned with our interests.

Each of our executive officers and each of our stockholders beneficially owning more than 5% of our outstanding common stock upon completion of this offering have overriding royalty interests relating to our existing oil and natural gas properties. These overriding royalty interests generally entitle them to percentages ranging from % to % of the net revenue associated with sales of oil and natural gas produced from these oil and natural gas properties, without any corresponding responsibility for payment of any expenses other than certain taxes. Because the amounts of the overriding royalty interest percentages vary among our properties and will not apply to all of our properties, including properties acquired after completion of this offering, the overriding royalty interests may create conflicts of interest for our management in setting our exploration and development priorities.

The concentration of our capital stock ownership by our largest stockholder will limit your ability to influence corporate matters.

Upon completion of this offering, we anticipate that Hunt Pettit, our founder, President and Chief Executive Officer, will initially own approximately % of our outstanding common stock. Consequently, Mr. Pettit will continue to have substantial control over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership will limit your ability to influence corporate matters, and as a result, actions may be taken that you may not view as beneficial.

Purchasers of common stock in this offering will experience immediate and substantial dilution of $ per share.

Based on an assumed initial public offering price of $ per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $ per share in the pro forma net tangible book value per share of our common stock from the initial public offering price, and our pro forma net tangible book value as of March 31, 2012 after giving effect to this offering would be $ per share. See “Dilution” for a complete description of the calculation of net tangible book value.

Because we are a relatively small company, the requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we will need to comply with certain laws, regulations and requirements, including corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the New York Stock Exchange, or the NYSE, with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

However, for as long as we remain an “emerging growth company” as defined in the JOBS Act, we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies. See “Summary—Implications of Being an Emerging Growth Company.” If we choose to take advantage of some or all of these reduced reporting requirements, the information that we provide to our stockholders may be different from information provided by other public companies.

While we believe our internal control over financial reporting has been effective at supporting our past financial reporting needs, it may not continue to be effective at reporting activities as a public company operating under our current business strategy. If one or more material weaknesses emerge related to reporting the activities related to our current business strategy, or if we otherwise fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

Prior to the completion of this offering, we have been a private company with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address our internal control over financial reporting. While we believe our internal control over financial reporting was effective under our business strategy of acquiring and selling undeveloped leasehold acreage, in the first quarter of 2012, we adopted a business strategy to develop and exploit our undeveloped leasehold acreage. We have implemented plans to enhance our financial reporting activities related to our current strategy and to meet the financial reporting requirements required of a public company. However, there is no certainty that as a result of our actions we will be able to maintain effective internal control over financial reporting.

Our independent registered public accounting firm is not required to formally attest to the effectiveness of our internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act until the later of the year following our first annual report required to be filed with the SEC or the date we are no longer an emerging growth company. At such time, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed or operating.

We are an “emerging growth company,” and we cannot be certain whether the reduced disclosure requirements applicable to emerging growth companies will make our common stock less attractive to investors.

We are an “emerging growth company,” as defined in the JOBS Act, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies. See “Summary—Implications of Being an Emerging Growth Company.” We cannot predict whether investors will find our common stock less attractive because we may rely on these exemptions. If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile.

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

We do not intend to pay dividends on our common stock and, consequently, your only opportunity to achieve a return on your investment is if the price of our stock appreciates.

We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our credit facility places certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if the market price of our common stock appreciates, which may not occur, and you sell your shares at a profit. There is no guarantee that the price of our common stock that will prevail in the market after this offering will ever exceed the price that you pay.

Future sales of our common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities will dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings or otherwise issue additional shares of common stock or convertible securities. Assuming no exercise of the underwriters’ option to purchase additional shares, after the completion of this offering, we will have outstanding shares of common stock. Following the completion of this offering, our stockholders who acquire their shares pursuant to our corporate reorganization will beneficially own shares, or % of our total outstanding shares, all of which will be restricted from immediate resale under the federal securities laws and will be subject to a lock-up agreement with the underwriters described in “Underwriting,” but may be sold into the market in the future. All of these stockholders will be parties to a registration rights agreement with us that will require us to effect the registration of their shares in certain circumstances no earlier than 180 days after the date of this prospectus.

As soon as practicable after this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our stock incentive plan. Subject to the satisfaction of vesting conditions and the expiration of lock-up agreements, shares registered under our registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Our amended and restated certificate of incorporation and amended and restated bylaws contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to and desirable by our stockholders, including:

We will be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for and will rely on exemptions from certain corporate governance requirements.

Because Hunt Pettit will own a majority of our outstanding common stock following the completion of this offering, we will be a “controlled company” as that term is set forth in Section 303A of the NYSE Listed Company Manual. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a “controlled company” and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:

These requirements will not apply to us as long as we remain a “controlled company.” Following this offering, we expect to utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. Mr. Pettit’s significant ownership interest could adversely affect investors’ perceptions of our corporate governance.

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

All forward-looking statements speak only as of the date of this prospectus. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, objectives, expectations and intentions reflected in or suggested by the forward-looking statements we make in this prospectus are reasonable, we can give no assurance that these plans, objectives, expectations or intentions will be achieved. We disclose important

factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this prospectus. These factors include risks related to:

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

We expect to receive net proceeds of approximately $ million from the sale of our common stock, assuming an initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus) and after deducting estimated expenses payable by us and underwriting discounts and commissions. An increase or decrease in the initial public offering price of $1.00 per share of common stock would cause the net proceeds that we will receive from this offering, after deducting estimated expenses payable by us and underwriting discounts and commissions, to increase or decrease by approximately $ million.

We intend to use the net proceeds we receive from this offering to fund a portion of our $271 million capital expenditure budget for the second half of 2012 and 2013 for drilling and developing our existing leasehold acreage and acquiring additional oil and natural gas leases. We intend to fund the remainder of our capital expenditure budget with cash on hand, cash flow from operations, proceeds from asset divestitures and borrowings under our credit facility.

The ultimate amount of capital we will expend is largely discretionary and may fluctuate materially based on market conditions, the success of drilling operations and other factors. Additionally, the timing and costs of drilling on our Eaglebine leasehold acreage in AMI #1 and AMI #2 generally will be within the control of Halcón, as operator of the acreage. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and “Business—Our Operations—Capital Expenditures.”

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, our credit facility places certain restrictions on our ability to pay cash distributions.

You should read the following table in conjunction with “Use of Proceeds,” “Selected Combined Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical combined financial statements and unaudited pro forma combined and condensed financial information and related notes thereto appearing elsewhere in this prospectus.

Purchasers of our common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Our net tangible book value as of March 31, 2012, after giving pro forma effect to the Pro Forma Transactions described under “Prospectus Summary—Summary Historical and Pro Forma Combined Financial Data,” was approximately $ million, or $ per share of common stock. Pro forma net tangible book value per share is determined by dividing our pro forma tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock that will be outstanding immediately prior to the closing of this offering, after giving effect to the Pro Forma Transactions. After giving effect to Pro Forma Transactions and the sale of the shares in this offering and assuming the receipt of the estimated net proceeds (after deducting estimated discounts and expenses of this offering), our adjusted pro forma net tangible book value as of March 31, 2012 would have been approximately $ million, or $ per share. This represents an immediate increase in the net tangible book value of $ per share to our existing stockholders and an immediate dilution (i.e., the difference between the offering price and the adjusted pro forma net tangible book value after this offering) to new investors purchasing shares in this offering of $ per share. The following table illustrates the per share dilution to new investors purchasing shares in this offering:

The following table summarizes, on an as adjusted pro forma basis as of March 31, 2012, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $ , which is the midpoint of the range of the initial public offering prices set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions:

Set forth below is our selected combined financial data as of and for the periods indicated. The summary historical combined financial data as of and for the years ended December 31, 2010 and 2011 are derived from our audited combined financial statements included elsewhere in this prospectus. The summary historical combined financial data as of and for the three months ended March 31, 2011 and 2012 are derived from our unaudited combined financial statements included elsewhere in this prospectus, which, in the opinion of our management, include all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of this information. Results of operations for the three months ended March 31, 2011 and 2012 are not necessarily indicative of the results of operations for the entire year or any future period.

Prior to the completion of our corporate reorganization, our business has been conducted through Energy & Exploration Partners, LLC, Energy & Exploration Partners, LP, Energy & Exploration Partners Operating, LP and Energy & Exploration Partners Operating GP, LLC, each of which has been owned by our founder, Hunt Pettit. For this reason, the financial statements included in this prospectus consist of the historical audited and unaudited combined balance sheets of Energy & Exploration Partners, LLC, Energy & Exploration Partners, LP, Energy & Exploration Partners Operating, LP and Energy & Exploration Partners Operating GP, LLC and the related combined statements of operations, owners’ equity and cash flows.

The information set forth below should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements and the notes thereto included elsewhere in this prospectus. The financial data included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

During the years ended December 31, 2010 and 2011, we were an entity engaged in the acquisition and sale of undeveloped oil and natural gas leasehold interests. Beginning in the first quarter of 2012, we adopted a business strategy to develop and exploit our undeveloped leasehold acreage in order to provide a greater return on investments in those properties. At that time, we adopted the full cost method of accounting for oil and natural gas properties. For purposes of the selected combined financial data, proceeds from sales of undeveloped leasehold acreage that we previously reported as revenue in our financial statements when we were an entity engaged in the acquisition and sale of undeveloped oil and natural gas leasehold interests, and the costs of those sales that we previously reported as cost of sales, are reported on a net basis as gains on sales of assets. Similarly, cash outflows for undeveloped leasehold acreage that we previously reported as operating outflows in our financial statements when we were an entity engaged in the acquisition and sale of undeveloped oil and natural gas leasehold interests are reported as investing outflows in the summary historical combined financial data.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our combined financial statements and related notes appearing elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

We have accumulated 15,236 net acres in our Eaglebine core area. Recently we have entered into two agreements with a subsidiary of Halcón Resources Corporation, or Halcón, related to the Eaglebine. These agreements, which are described further under “Business—Our Core Areas—Eaglebine,” provided for our conveyance to Halcón of operated working interests in substantially all of our Eaglebine acreage and established two areas of mutual interest with Halcón, which we refer to as AMI #1 and AMI #2. In addition, we have 13,109 net acres in our Wolfcamp area, where we have 100% operated working interests, and 16,931 net acres in our Niobrara area, where we generally have 100% operated working interests. We estimate our current acreage positions in our three core areas could contain a total of 452 net drilling locations, of which roughly half are in the Eaglebine.

The majority of our capital expenditure budget for the period from July 2012 to December 2013 will be focused on the development and expansion of our Eaglebine acreage.

We began development of our three core areas in the first half of 2012 by participating in a PDC Energy Inc.-operated well in the Niobrara (Moss 14-16H) with a 9.3% working interest that produced 870 bbls (net) of oil and 1,672 Mcf (net) of natural gas in the second quarter of 2012 and a Halcón-operated well in the Eaglebine (Covington #1H) with a 35% working interest that is scheduled to be completed in August 2012. We also plan to increase our number of active drilling rigs to three in the Eaglebine with the addition of two drilling rigs during the third quarter 2012.

We have not recorded proved reserves since our inception, but have engaged Cawley, Gillespie and Associates, Inc. to prepare our initial reserve report as of December 31, 2012.

Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe had significant appreciation potential. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.

We will use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

Production volumes will directly impact our results of operations. We currently have minimal production, all from the Moss 14-16H well in Weld County, Colorado, but expect to increase production assuming drilling success in the future.

We expect to market our crude oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of crude oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.

Oil. The New York Mercantile Exchange—West Texas Intermediate (NYMEX-WTI) futures price is a widely used benchmark in the pricing of domestic crude oil in the United States. The actual prices realized from the sale of crude oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials to NYMEX-WTI prices result from the fact that crude oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (1) the crude oil’s American Petroleum Institute, or API, gravity and (2) the crude oil’s percentage of sulfur content by weight. In general, lighter crude oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value and, therefore, normally sell at a higher price than heavier oil. Crude oil with low sulfur content (“sweet” crude oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content crude oil (“sour” crude oil).

Location differentials to NYMEX-WTI prices result from variances in transportation costs based on the produced crude oil’s proximity to the major consuming and refining markets to which it is ultimately delivered. Crude oil that is produced close to major consuming and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to crude oil that is produced farther from such markets. Consequently, crude oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential to NYMEX-WTI).

In the past, crude oil prices have been extremely volatile, and we expect this volatility to continue. For example, the NYMEX-WTI oil price ranged from a high of $113.39 per bbl to a low of $75.40 per bbl during the year ended December 31, 2011, and from a high of $109.39 per bbl to a low of $77.72 per bbl in the first seven months of 2012.

Natural Gas. The NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to crude oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (1) the Btu content of natural gas, which measures its heating value, and (2) the percentage of sulfur, CO2 and other inert content by volume. Wet natural gas with a high Btu content sells at a

premium to low btu content dry natural gas because it yields a greater quantity of natural gas liquids (NGLs). Natural gas with low sulfur and CO2 content sells at a premium to natural gas with high sulfur and CO2 content because of the added cost to separate the sulfur and CO2 from the natural gas to render it marketable. Wet natural gas is processed in third-party natural gas plants and residue natural gas as well as NGLs are recovered and sold. Dry natural gas residue from our properties is generally sold based on index prices in the region from which it is produced.

Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds. Generally, these index prices have historically been at a discount to NYMEX-Henry Hub natural gas prices.

In the past, natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, the NYMEX-Henry Hub natural gas price ranged from a high of $4.92 per MMBtu to a low of $2.84 per MMbtu during the year ended December 31, 2011, and from a high of $3.19 per MMBtu to a low of $1.82 per MMBtu in the first seven months of 2012.

We expect to adopt a commodity derivative policy designed to minimize volatility in our cash flows from changes in commodity prices. Our credit facility will require us to enter into commodity derivative instruments for specified minimum and maximum levels of anticipated production. See “—Liquidity and Capital Resources—Credit Facilities.” Subject to the requirements of our credit facility, we have not determined the portion of our estimated production for which we will mitigate our risk through the use of commodity derivative instruments, but in no event will we maintain a commodity derivative position in an amount in excess of our estimated production. Should we reduce our estimates of future production to amounts which are lower than our commodity derivative volumes, we will reduce our positions as soon as practical. If forward crude oil or natural gas prices increase to prices higher than the prices at which we have entered into commodity derivative positions, we may be required to make margin calls out of our working capital in the amounts those prices exceed the prices we have entered into commodity derivative positions.

We will strive to increase our production levels to maximize our revenue. Oil and natural gas production expenses are the costs incurred in the operation of producing properties and workover costs. We expect expenses for utilities, direct labor, water injection and disposal, and materials and supplies to comprise the most significant portion of our oil and natural gas production expenses. Oil and natural gas production expenses do not include general and administrative costs or production and other taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities may result in increased oil and natural gas production expenses in periods during which they are performed.

A majority of our operating cost components will be variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we will incur power costs in connection with various production related activities such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with our oil and natural gas production. Over the life of hydrocarbon fields, the amount of water produced may increase for a given volume of oil or gas production, and, as pressure declines in natural gas wells that also produce water, more power will be needed to provide energy to artificial lift systems that help to remove produced water from the wells. Thus, production of a given volume of hydrocarbons may become more expensive each year as the cumulative oil and natural gas produced from a field increases until, at some point, additional production becomes uneconomic.

Texas regulates the development, production, gathering and sale of oil and natural gas, including imposing production taxes and requirements for obtaining drilling permits. For oil production, Texas currently imposes a

production tax at 4.6% of the market value of the oil produced and an additional 3/16 of one cent per barrel produced, and for natural gas, Texas currently imposes a production tax at 7.5% of the market value of the natural gas produced. Colorado imposes production taxes ranging from 2% to 5% and conservation tax of 0.07% based on the gross value of oil and natural gas production. Wyoming imposes production taxes of 6% and conservation tax of 0.04% based on the gross value of oil and natural gas production. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties; however, these valuations are reasonably correlated to revenues, excluding the effects of any commodity derivative contracts.

General and administrative expenses related to being a publicly traded company include: Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley compliance; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation. As a publicly-traded company at the closing of this offering, we expect that general and administrative expenses will increase.

Our properties have historically been owned by a limited liability company that elected to be taxed as a partnership and therefore was not a taxable entity and did not directly pay federal income taxes. Accordingly, no provision for federal corporate income taxes has been provided for the period from February 14, 2006, the date of our inception, to December 31, 2011, or for the three months ended March 31, 2012, because taxable income was allocated directly to our equity holders.

Our income tax expense in our historical financial statements results from the enactment of state income tax laws by the State of Texas that apply to entities organized as partnerships or limited liability companies. In connection with our corporate reorganization, an estimated net deferred tax liability of approximately $1.3 million will be established for differences between the book and tax basis of our assets and liabilities and a corresponding expense will be recorded to net income from operations.

On April 13, 2012, Energy & Exploration Partners, LLC terminated its election to be treated as an S corporation and became a C corporation for federal income tax reporting purposes. Accordingly, we are, and after our corporate reorganization will continue to be, subject to federal income taxes, which may affect future operating results and cash flows.

The discussion of our results of operations and period to period comparisons presented below analyze our historical results, which may not be indicative of future results. For purposes of the discussion of our results of operations and period to period comparisons, proceeds from sales of undeveloped leasehold acreage that we previously reported as revenue in our financial statements when we were an entity engaged in the acquisition and sale of undeveloped oil and natural gas leasehold interests, and the costs of those sales that we previously reported as cost of sales, are reported on a net basis as gains on sales of assets.

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

In March 2012, we recognized approximately $30,000 of oil and natural gas revenues from the Moss 14-16H well in Weld County, Colorado. This well commenced production in March 2012. We had no oil and natural gas revenues for the three months ended March 31, 2011.

Total expenses increased by $500,000 to $693,000 for the three months ended March 31, 2012. The net increase was primarily due to increases in professional fees, salaries and wages, contract labor, and consulting fees.

Interest expense was $512,000 for the three months ended March 31, 2012 compared to $0 for the three months ended March 31, 2011. The increase in the expense was due to interest and amortization of loan costs associated with $15.0 million of outstanding debt at March 31, 2012, compared to no debt outstanding at March 31, 2011.

Gain on sale of assets decreased by $559,000 to $4,000 for the three months ended March 31, 2012, primarily due to de minimis sales of leasehold interests in the 2012 period, compared to sales of approximately 1,554 acres of land for $1.1 million for the three months ended March 31, 2011 at an average price of $726 per acre.

Total expenses decreased by $124,000 to $1.8 million for the year ended December 31, 2011. The decrease was caused by a decrease in general and administrative expenses offset by an increase in abandoned leasehold expense. Abandoned leasehold expense was $679,000 in the year ended December 31, 2011 compared to $0 for the year ended December 31, 2010. This abandoned leasehold expense in the year ended December 31, 2011 was for leasehold interests that were determined to be permanently impaired. We recognized no impairments for the year ended December 31, 2010. General and administrative expenses decreased by $0.8 million to $1.1 million in the year ended December 31, 2011, primarily due to a decrease in contract labor and salaries, partially offset by an increase in consulting and legal fees.

Interest expense was $270,000 for the year ended December 31, 2011 compared to $0 for the year ended December 31, 2010. This increase was due to the increase in interest and amortization of loan costs associated with $10.0 million in debt incurred beginning in September 2011, compared to no debt outstanding during 2010.

Gains on sale of assets declined $5.5 million to $0.6 million for the year ended December 31, 2011. In 2011, we sold undeveloped leasehold interests in approximately 1,554 acres of land for $1.1 million at an average price of $726 per acre. In 2010, we sold our undeveloped leasehold interests in approximately 37,000 net acres of land for $44.3 million at an average sales price of $1,199 per acre.

To date, we have generated a substantial majority of our liquidity by selling all or portions of our leasehold acreage, generating gains compared to the acquisition prices of the acreage. Our first acreage sales were in the Eagle Ford Shale in South Texas during 2009. In 2011, we built acreage positions in our three core areas, including the Eaglebine.

As of March 31, 2012, we had borrowings totaling $15.0 million under a senior secured note with Petro Capital XXV, LLC, which was used to fund leasehold acquisitions and drilling costs. This note was repaid with borrowings under the credit facility described below on June 26, 2012.

On June 26, 2012, we entered into a $100.0 million senior secured advancing line of credit with Guggenheim Corporate Funding, LLC, as administrative agent, and certain of its affiliates, as lenders, which we refer to collectively as Guggenheim. We refer to this line of credit as our credit facility. We initially borrowed $21.5 million under the credit facility to repay the Petro Capital note, increase our working capital and fund 50% of the drilling and completion costs for our first Eaglebine well. The credit facility has an initial borrowing base of $30 million, with remaining undrawn capacity of $8.5 million, and is secured by substantially all of our assets. We anticipate using the remaining capacity under the initial borrowing base of our credit facility to fund 50% of our portion of the drilling and completion costs for our next three Eaglebine wells located in AMI #1, which have been pre-approved by Guggenheim, provided that drilling and completion costs do not exceed $3.5 million per well net to our working interest.

Subsequent borrowings under the credit facility are subject to Guggenheim’s approval, in its sole discretion, of additional well sets in AMI #1, with each set including four wells, and a borrowing base that will be re-determined semi-annually on April 30 and October 31 beginning October 31, 2013. For wells five and six, borrowings will fund up to 75% of the drilling and completion costs for the two wells, provided that such drilling and completion costs do not exceed $2.8 million per well net to our working interest. After the sixth well, borrowings will fund up to 90% of the drilling and completion costs for each additional well, provided that such drilling and completion costs do not exceed $2.8 million per well net to our working interest. Cost overruns may be funded by Guggenheim in its discretion in the same proportions as its funding for the wells described above. Regardless of the number of wells funded by this credit facility, the total outstanding principal cannot exceed $100 million. The advance period lasts until June 26, 2013.

Borrowings under the credit facility bear interest at the variable rate published by the Wall Street Journal as the “Prime Rate” plus 10%, with a Prime Rate floor of 5%.

The credit facility matures on December 17, 2014. There is no prepayment penalty provided the credit facility remains outstanding for one year, but we are required to repay the facility in installments starting on July 1, 2013 based on the following schedule:

We also may be required to repay principal amounts outstanding under the credit facility with the proceeds of certain asset sales.

The credit facility generally provides for the grant to Guggenheim of an overriding royalty interest equal to 5.0%, proportionally reduced to our working interest, of total production from the Eaglebine leases we own or acquire while the credit facility is outstanding other than leases acquired with funds advanced by Halcón pursuant to AMI #2. The overriding royalty interest, which will be earned in 1/12^th increments as advances are made on each of the first twelve wells, will reduce our net revenue interest below 75%, but we will have drag along rights to require Guggenheim to include its overriding royalty interests in any future divestitures. When the lenders achieve a 32.5% internal rate of return for at least one year from fees, interest and principle payments, and production proceeds pursuant to the overriding royalty interest, the overriding royalty interest will decrease to 0. 5%, proportionally reduced to our working interest, of total production.

Additionally, the credit facility requires that we enter into commodity derivative contracts with respect to the following minimum percentages of anticipated production from proved developed producing reserves:

We generally may not enter into commodity derivative contracts with respect to more than 90% of anticipated production from proved developed producing reserves. All such commodity derivative agreements must be on terms approved by Guggenheim.

The credit facility includes certain events of default, some of which may be outside of our control. The events of default include:

As discussed previously, our primary sources of liquidity to date have been proceeds from asset sales and borrowing under our credit facilities. In the first quarter of 2012, we commenced development of some of our undeveloped leasehold acreage in order to provide a greater return on our investment in those properties. In March 2012, the Moss 14-16H well, in which we have a 9.3% non-operated working interest, commenced production. In

May 2012, the Covington #1H well, in which we have a 35% non-operated working interest, commenced drilling. We expect to commence production in the third quarter of 2012. We do not expect to generate significant revenue from production until 2013, which will depend upon successful drilling results, additional and timely capital funding, and access to suitable infrastructure.

We expect to incur substantial expenses and generate significant operating losses as we continue to explore for and develop our oil and natural gas prospects, and as we opportunistically invest in additional oil and natural gas leases adjacent to our current positions, develop our discoveries which we determine to be commercially viable and incur expenses related to operating as a public company and compliance with regulatory requirements.

Our future financial condition and liquidity will be impacted by, among other factors, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, and the actual cost of exploration, appraisal and development of our prospects.

We estimate that we will make capital expenditures, excluding capitalized interest and general and administrative expense, of approximately $271 million during the period from July 1, 2012 to December 31, 2013 in order to achieve our plans. We expect the proceeds of this offering, borrowings under our credit facility, cash flow from operations, proceeds from asset divestitures and our existing cash on hand will be sufficient to fund our planned capital expenditures through the end of 2013. However, we may require significant additional funds earlier than we currently expect in order to execute our strategy as planned. Additionally, because the wells funded by our 2012 and 2013 drilling plans represent only a small percentage of our potential drilling locations, we will be required to generate or raise significant amounts of additional capital to develop our entire inventory of potential drilling locations if we elect to do so. We may seek additional funding through asset sales, farm-out arrangements and public or private financings.

Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control, except that the timing and costs of drilling on our Eaglebine leasehold acreage in AMI #1 and AMI #2 generally will be within the control of Halcón, as operator of the acreage. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, timing of regulatory approvals, availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.

As of March 31, 2012, we had a working capital deficit, as measured by current assets less current liabilities, of $9.7 million. However, we believe that actions subsequent to March 31, 2012, including our disposition of working interests to Halcón and entry into our credit facility, have provided us with sufficient liquidity to support our requirements.

The discussion of our cash flows and period to period comparisons presented below analyze our historical results as presented in the “Selected Combined Financial Data,” which may not be indicative of future results. As noted in the description of the “Selected Combined Financial Data,” and for purposes of the discussion of our cash flows and period to period comparisons, cash outflows for undeveloped leasehold acreage, that we previously reported as operating outflows in our financial statements when we were an entity engaged in the acquisition and sale of undeveloped oil and natural gas leasehold interests, are reported as investing outflows in the summary historical combined financial data.

Net cash used in operating activities was $0.6 million for the three months ended March 31, 2012 compared to net cash provided by operating activities of $1.0 million for the three months ended March 31, 2011. The decrease in cash flows from operating activities of $1.6 million was primarily due to a net loss of $1.2 million for the three months ended March 31, 2012 compared to net income of $367,000 for the three months ended March 31, 2011.

Net cash provided by operating activities was $51,000 for the year ended December 31, 2011 compared to $3.4 million for the year ended December 31, 2010. The decrease of $3.4 million was primarily due to a net loss of $1.5 million in 2011 compared to net income of $4.1 million in 2010.

Net cash used in investing activities was $5.8 million for the three months ended March 31, 2012 compared to net cash used in investing activities of $3.8 million for the three months ended March 31, 2011. This increase of $2.0 million was primarily due to increases in leasing activity and capitalization of general and administrative expenses, other acquisition costs, and interest of $5.7 million in 2012 compared to $3.8 million in 2011.

Net cash used in investing activities was $19.0 million for the year ended December 31, 2011 compared to $3.6 million for the year ended December 31, 2010. This decrease of $15.4 million was primarily due to an increase in acquisitions of undeveloped leasehold costs of $18.9 million in 2011 compared to $3.6 million in 2010.

Net cash provided by financing activities was $4.6 million for the three months end March 31, 2012 compared to net cash provided by financing activities of $1.4 million for the three months ended March 31, 2011. The primary source of cash during the three months ended March 31, 2012 was $4.6 million of net proceeds from issuing notes payable. For the three months ended March 31, 2011, the primary source of financing cash was proceeds from investment deposits of $1.3 million.

Net cash provided by financing activities was $21.7 million for the year ended December 31, 2011 compared to $0.8 million for the year ended December 31, 2010. Cash provided by financing activities for the year ended December 31, 2011 consisted of $9.3 million of net proceeds from issuance of notes payable and $12.6 million received from investment deposits. In 2010, we received investment deposits of $1.5 million.

We had the following contractual obligations and commitments as of March 31, 2012:

The discussion and analysis of our financial condition and results of operations is based upon our combined financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. See Note 2 to our combined financial statements for a discussion of additional accounting policies.

Oil and Natural Gas Properties. Beginning in the first quarter of 2012, we use the full cost method of accounting for oil and natural gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves are capitalized.

Under the full cost accounting rules, capitalized costs, less accumulated amortization, and net of deferred income taxes, shall not exceed an amount (the ceiling) equal to the sum of: (i) the present value of estimated future net revenues less future production, development, site restoration, and abandonment costs derived based on current costs assuming continuation of existing economic conditions and computed using a discount factor of ten percent; (ii) the cost of properties not being amortized; and (iii) the lower of cost or estimated fair value of unproven properties included in the costs being amortized. If unamortized costs capitalized within the cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center ceiling.

Depreciation, depletion, and amortization is provided using the unit-of-production method based upon estimates of proved oil and natural gas reserves with oil and natural gas production being converted to a common unit of measure based upon their relative energy content. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to the full cost pool and amortization begins. The full cost pool also includes estimated future development costs and where significant, dismantlement, restoration and abandonment costs, net of estimated salvage value.

In arriving at depletion rates under the unit-of-production method, the quantities of recoverable oil and natural gas reserves are established based on estimates made by our geologists and engineers, which require significant judgment as does the projection of future production volumes and levels of future costs, including future development costs. In addition, considerable judgment is necessary in determining when unproved properties become impaired and in determining the existence of proved reserves once a well has been drilled. All of these judgments may have significant impact on the calculation of depletion and impairment expense. Sales of proved and unproved properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves, in which case the gain or loss would be recognized in the statement of operations.

Oil and Natural Gas Reserves. We have not recorded proved oil and natural gas reserves since our inception, but anticipate preparing our first third party reserve report as of December 31, 2012. In January 2010, the Financial Accounting Standards Board (FASB) issued an update to the oil and natural gas topic, which aligns the oil and natural gas reserve estimation and disclosure requirements with the requirements in the SEC’s final rule, Modernization of the Oil and Natural Gas Reporting Requirements, which we refer to as the Final Rule. The Final Rule was issued on December 31, 2008. The Final Rule is intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves, which should help investors evaluate the relative value of oil and natural gas companies.

The Final Rule permits the use of new technologies to determine proved reserve estimates if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volume estimates.

The Final Rule also allows, but does not require, companies to disclose their probable and possible reserves to investors in documents filed with the SEC.

In addition, the new disclosure requirements require companies to report oil and natural gas reserves using an average price based upon the first of month simple average prices for prior 12 month period rather than a year-end price. The Final Rule became effective for fiscal years ending on or after December 31, 2009.

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. The reserve estimates and the projected cash flows derived from these reserve estimates are prepared in accordance with SEC guidelines. The accuracy of our reserve estimates is a function of many factors including 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, all of which could deviate significantly from actual results. As such, reserve estimates may vary materially from the ultimate quantities of oil, natural gas, and natural gas liquids eventually recovered.

Asset Retirement Obligations. We comply with Accounting Standards Codification (ASC) 410-20, Asset Retirement and Environmental Obligations, to recognize estimated amounts for asset retirement obligations and asset retirement costs. This standard requires us to record a liability for the fair value of the asset retirement obligations, excluding salvage values. ASC 410-20 requires liability recognition for retirement obligations associated with tangible long-lived assets, such as producing well sites, gathering systems, and related equipment. The obligations included within the scope of ASC 410-20 are those for which we face a legal obligation for settlement. The initial measurement of the asset retirement obligation is fair value, defined as “the price that an entity would have to pay a willing third party of comparable credit standing to assume the liability in a current transaction other than in a forced or liquidation sale.” The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment, remediation costs, and well life. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which the entity treats as an adjustment to the full cost pool.

Revenue Recognition. Our oil and natural gas production is currently sold to purchasers by the operator of the property in which we have an interest. We recognize oil and natural gas revenues based on our proportionate share of such production at market prices.

Use of Estimates. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and from assumptions used in preparation of our combined financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our combined financial statements. See Note 2 to our combined financial statements for a discussion of additional accounting policies and estimates made by management.

On April 5, 2012, the JOBS Act was signed into law. Section 107 of the JOBS Act provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. However, we are choosing to “opt out” of such extended transition period, and as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

Fair Value. In February 2010, FASB issued accounting guidance that requires the gross presentation of activity within the Level 3 fair value measurement roll forward and details of transfer in and out of Level 1 and 2 fair value measurements. It also clarifies existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosure on inputs. We adopted this new accounting guidance for the year ended December 31, 2011. The adoption of this guidance did not have a material impact on our financial statement. See note 2 for additional information.

Presentation of comprehensive income. In June 2011, the FASB issued ASC 2011-12, Comprehensive Income, on the presentation of comprehensive income. Although we have not incurred comprehensive income thus far, we may do so in future periods. ASC 2011-12 provides two options for presenting net income and other comprehensive income. The total of comprehensive income, the components of net income, and the components of other comprehensive income may be presented in either a single continuous statement of comprehensive income in two separate but consecutive statements. This guidance will be effective January 1, 2012, and we do not expect the adoption to have material impact on our financial statements.

No other pronouncements materially affecting our financial statements were issued during 2010, 2011 or thereafter that have impacted, or are expected to impact, our financial statements and results of operations.

We are not currently required to comply with the SEC’s rules related to Section 404 of the Sarbanes-Oxley Act, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to upgrade our systems, implement additional internal controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

Further, our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC or the date we are no longer an emerging growth company, unless it is determined that we are a non-accelerated filer, in which case our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control. When, and if, it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed or operating. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2010 and 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy, and our industry tends to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity.

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management including the use of derivative instruments.

Commodity price exposure. We are exposed to market risk as the prices of oil and natural gas fluctuate as a result of changes in supply and demand and other factors. Due to the inherent volatility in oil and natural gas prices, we may use commodity derivative instruments, such as collars, swaps, puts and basis swaps to mitigate the price risk associated with a significant portion of our anticipated oil and natural gas production. By removing a majority of the price volatility associated with future production, we expect to reduce, but not eliminate, the potential effects of variability in cash flow from operations due to fluctuations in commodity prices. We expect to enter into derivative instruments in the future to cover a significant portion of our future production and comply with the covenants in our credit facility.

Interest rate risk. At July 31, 2012, we had $21.5 million outstanding under our credit facility, which is subject to floating market rates of interest. We may utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expenses related to existing debt. Interest rate derivatives are used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.

Counterparty and customer credit risk. We are exposed to counterparty risk from oil and natural gas sales by our operating partners. When we begin operations, we may be exposed to counterparty risk from a concentration of sales of crude and gas to a few significant customers, and from joint interest receivables from our joint venture partners. We do not require our customers to post collateral. The inability or failure of our significant customers or partners to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In addition, when we begin to enter into commodity derivative positions with respect to our production, our oil and natural gas derivative arrangements will expose us to credit risk in the event of nonperformance by counterparties.

We believe we are well positioned to successfully execute our business strategies and achieve our business objectives because of the following competitive strengths:

The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of July 31, 2012 for each of our core operating areas. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.

The following table sets forth the number of gross and net undeveloped acres as of July 31, 2012 that will expire in the periods indicated unless production is established within the spacing units covering the acreage prior to the expiration dates:

Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities. While we may attempt to secure a new lease upon the expiration of certain of our acreage, there are some third-party leases that may become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date. We have options to extend a majority of our leases through payment of additional lease bonus payments prior to the expiration of the primary term of the leases. Our leases are mainly fee leases with three to five years of primary term.

As of July 31, 2012, we had one gross (0.093 net) productive well: a PDC Energy Inc. operated well in the Niobrara (Moss 14-16H), which commenced production in the first quarter of 2012. We did not participate in the drilling of any wells during 2009, 2010 and 2011. As of July 31, 2012, we had one gross (0.35 net) well in the process of drilling: the Halcón operated Covington #1H well in the Eaglebine AMI #1.

We have targeted a majority of our estimated capital expenditures for the remainder of 2012 and 2013 for drilling and completion and leasehold acquisition in our three core areas. The following table presents for each of our core operating areas our estimated capital expenditures, excluding capitalized interest and general and

administrative expense, for drilling and completion, leasehold acquisition and seismic for the eighteen-month period ending December 31, 2013:

As is customary in the oil and natural gas industry, we initially conduct a preliminary review of the title to our properties. Prior to the commencement of drilling operations on those properties, we will conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we will typically be responsible for curing any title defects at our expense. We will not commence drilling operations on a property until we have cured any material title defects on such property. We will obtain title opinions on substantially all of our producing properties and expect to have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Prior to completing an acquisition of producing oil and natural gas leases, we will perform title reviews on the most significant leases, and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens to secure borrowings under our credit facility, liens for current taxes, and other burdens that we believe do not materially interfere with the use or affect our carrying value of the properties. See “Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—We may incur losses as a result of title defects in the properties in which we invest.”

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties in Texas generally range from 26.75% to 27.375%, resulting in a net revenue interest to us generally ranging from 72.625% to 73.25%, while all of royalties and other leasehold burdens on our properties in Colorado and Wyoming are 20%, resulting in a net revenue interest to us of 80%.

The oil and natural gas industry is highly competitive in all phases. We encounter competition from other oil and natural gas companies in all areas of operation, from the acquisition of leasing options on oil and natural gas properties to the exploration and development of those properties. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well established companies that have substantially larger operating staffs and greater capital resources than we do. Such companies may be able to pay more for lease options on oil and natural gas properties and exploratory locations and to define, evaluate, bid for and purchase a greater number of properties and locations than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See “Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.”

We will use hydraulic fracturing as a means to maximize the productivity of substantially all wells that we drill and complete. Hydraulic fracturing is a necessary part of the completion process because our properties are dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates.

We have and continue to follow applicable industry standard practices and legal requirements for groundwater protection in our operations that are subject to supervision by state and federal regulators (including the Bureau of Land Management on federal acreage). These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by regulatory agencies, and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design essentially eliminates a pathway for the fracturing fluid to contact any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure tested prior to perforating the new completion interval.

Injection rates and pressures are monitored instantaneously and in real time at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. Hydraulic fracturing operations would be shut down immediately if an abrupt change occurred to the injection pressure or annular pressure.

Certain state regulations require disclosure of the components in the solutions used in hydraulic fracturing operations. Approximately 99% of the hydraulic fracturing fluids we expect to use are made up of water and sand. The remainder of the constituents in the fracturing fluid are managed and used in accordance with applicable requirements.

Hydraulic fracture stimulation requires the use of a significant volume of water. Upon flowback of the water, we intend to dispose of it in a way that minimizes the impact to nearby surface water by disposing into approved disposal or injection wells. We do not intend to discharge water to the surface.

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read “—Regulation of the Oil and Natural Gas Industry—Environmental, Health and Safety Regulation.” For related risks to our stockholders, please read “Risk Factors—Risks Related to the Oil and Natural Gas Industry and Our Business—Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.”

Our operations are substantially affected by federal, state and local laws and regulations. In particular, oil and natural gas production and related operations are, or have been, subject to price controls, taxes and numerous other laws and regulations. All of the jurisdictions in which we own or operate properties for oil and natural gas production have statutory provisions regulating the exploration for and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of

wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of oil and natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations could result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in material compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations could be, and are frequently are, amended or reinterpreted. Additionally, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Therefore, we are unable to predict the future costs or impact of compliance or non-compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission, or FERC, and the courts. We cannot predict when or whether any such proposals may become effective.

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 or impose other regulatory requirements in the future.

Our sales of crude oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil (including NGLs) pipeline transportation service and rates under the Interstate Commerce Act. Historically, interstate oil pipeline rates were required to be cost-based. Currently, rates are generally adjusted by reference to an index, although shippers may challenge these adjustments. Rates may be cost-based, and settlement rates agreed to by all shippers are permitted. In addition, market based rates are permitted in circumstances where a pipeline demonstrates a lack of market power in a given geographical area before FERC. Effective January 1, 1995, FERC implemented regulations establishing an indexing system (based on the Producer Price Index (PPI), plus or minus a value set by FERC) for transportation rates for oil that allows for an annual increase or decrease in such index-based transportation rates. FERC re-evaluates the currently applicable index for setting such index-based rates every five years. The most recent review resulted in an increase of the index, and thus allows pipelines to increase rates annually by PPI + 3.65%, a larger percentage in addition to PPI for the five year period ending in July 2016 than had previously been in effect (which was PPI + 1%). This most recent index adjustment is currently being challenged by oil pipeline shippers in Federal court, and if successful this challenge could result in a decrease in the currently applicable index for annual adjustment of oil pipeline rates, although this is by no means certain or likely.

Intrastate oil pipeline transportation rates typically 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 way that is of material difference from those of our competitors who are similarly situated.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this common carrier standard, common carriers must offer service to all similarly situated 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. Often the priority of a given shipper in the event of prorationing is dependent upon its history of shipping on a particular pipeline, with higher priority, and thus more capacity, allocated to relatively long standing shippers over new shippers. However, as a general matter, FERC does not have jurisdiction to prevent a common carrier oil pipeline from abandoning all or part of its services. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors on a given pipeline.

The natural gas industry historically has been very heavily regulated. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other natural gas producers.

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by FERC under the Natural Gas Act of 1938, or NGA, the Natural Gas Policy Act of 1978, or NGPA, and regulations issued under those Acts. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at unregulated market prices, it is conceivable that Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act and culminated in adoption of the Natural Gas Wellhead Decontrol Act which removed all price controls affecting wellhead sales of natural gas effective January 1, 1993.

FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open access and non-discriminatory basis. FERC has stated that open access policies are necessary to improve the competitive structure of the interstate natural gas pipeline industry and to create a regulatory framework that will put natural gas sellers into more direct contractual relations with natural gas buyers by, among other things, unbundling the sale of natural gas from the sale of transportation and storage services. Beginning in 1992, FERC issued a series of orders, beginning with Order No. 636, to implement its open access policies. As a result, the interstate pipelines’ historical role as wholesalers of natural gas was eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC does not directly regulate natural gas producers (except with respect to a producer’s role as a marketer of natural gas, where FERC does exercise certain limited jurisdiction as discussed below), the current FERC regulatory structure is intended to foster increased competition within all phases of the natural gas industry.

In 2000, FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, Order No. 637 revised FERC’s pricing policy by waiving price ceilings for short-term released capacity, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, penalties, rights of first refusal and information reporting. FERC-regulated interstate pipelines’ tariffs now reflect the policies set forth in Order No. 637 and subsequent orders, and most major aspects of these policies that have been subject to court challenges have been upheld on judicial review. In 2008, FERC issued Order No. 712, which further modified applicable rules related to the release by shippers of interstate pipeline capacity, including through revisions intended to facilitate the use of interstate pipeline capacity by shippers. We cannot predict what action FERC will take on these matters in the future, or whether any such FERC’s actions will survive further judicial review. In recent years, FERC has made use of its anti-manipulation authority (discussed below) to extend its jurisdiction to entities such as producers whose role in the interstate natural gas market is typically limited to selling gas or transporting gas on interstate pipelines, including to develop and enforce its policies with respect to capacity release, open season bidding on new pipeline capacity, and related areas of FERC’s jurisdiction over interstate pipeline transportation. There are regulatory risks stemming from FERC’s aggressive enforcement of its regulations and policies related to pipeline capacity release, and the use of interstate pipeline capacity generally, by shippers like us.

The price at which we sell natural gas is not currently subject to federal rate regulation and, for the most part, is not subject to state regulation. However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC and/or the Commodity Futures Trading Commission, or the CFTC. See below the discussion of “Other federal laws and regulations affecting our industry—Energy Policy Act of 2005.” Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities. In addition, pursuant to FERC requirements regarding reporting by anyone who buys or sells more than a de minimis amount of natural gas in the interstate market introduced in Order No. 704, some of our operations may be required to annually report to FERC. Under these FERC reporting requirements, certain natural gas market participants must report information regarding their reporting of transactions to price index publishers and their blanket sales certificate status, as well as certain information regarding their wholesale, physical natural gas transactions for the previous calendar year depending on the volume of natural gas transacted. However, we do not report our gas sales transactions to price index publishers and therefore we do not have any regulatory

requirements associated with reporting to price index publishers. If in the future we decided to report to price index publishers, there would be regulatory requirements to which we would be subject. See below the discussion of “Other federal laws and regulations affecting our industry—FERC Market Transparency Rules.”

Gathering services, which occur upstream of jurisdictional transmission services, are not regulated by FERC under the NGA and may be regulated by the states onshore and in state waters. FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which may increase our costs of getting gas to point of sale locations, since the rates charged for such gathering services are not subject to FERC regulation. State regulation of natural gas gathering facilities generally include various safety, environmental and, in some circumstances, nondiscriminatory take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

Intrastate natural gas transportation and facilities are also subject to regulation by state regulatory agencies, and certain transportation services provided by intrastate pipelines are also regulated by FERC. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. 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.

The failure to comply with these rules and regulations could result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005, or the EPAct 2005. EPAct 2005 is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, EPAct 2005 amends the NGA to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. EPAct 2005 provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-manipulation provision of EPAct 2005, and subsequently denied rehearing. The rule makes it unlawful for any entity, directly or indirectly, to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional

sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, such as Section 311 service, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order 704. The anti-manipulation rules and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority. Should we fail to comply with all applicable FERC administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines.

FERC Market Transparency Rules. On December 26, 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing, or Order No. 704. Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order No. 704. Order No. 704 also requires market participants to indicate whether they report prices to any index publishers and, if so, whether their reporting complies with FERC’s policy statement on price reporting. In October 2011, the U.S. Court of Appeals for the 5th Circuit struck down other FERC regulations designed to promote market transparency that extended new reporting requirements to other entities (in this case certain non-interstate pipelines) historically outside of FERC’s jurisdiction. These rules, originally set forth in Order No. 720, were vacated by the court because they were found to exceed the scope of FERC’s authority under the NGA.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than similarly situated competitors.

Our exploration, development and production operations are subject to various federal, state and local laws and regulations governing health and safety, the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may, among other things, require the acquisition of permits to conduct exploration, drilling and production operations; govern the amounts and types of substances that may be released into the environment in connection with oil and natural gas drilling and production; restrict the way we handle or dispose of our wastes; limit or prohibit construction or drilling activities in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; require investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of orders enjoining some or all of our operations in affected areas.

These laws and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the Congress and federal and state agencies frequently revise environmental, health and safety laws and regulations, and any changes that result in more stringent and costly waste handling, disposal, cleanup and remediation requirements for the oil and natural gas industry could have a significant impact on our operating costs.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal, or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on our financial condition or results of operations, there is no assurance that this trend will continue in the future.

The following is a summary of the more significant existing environmental, health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

The Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. 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 or other pollutants into the environment. We generate materials in the course of our operations that may be regulated as hazardous substances.

We also generate solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the course of our operations we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous wastes.

We currently own or lease, and have in the past owned or leased, properties that have been used for numerous years to explore and produce oil and natural gas. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been taken for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) and to perform remedial operations to prevent future contamination.

Pipelines, gathering systems and terminal operations are subject to increasingly strict safety laws and regulations. Both the transportation and storage of refined products and crude oil involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages, and significant business interruption. The U.S. Department of Transportation, or the DOT, has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our pipeline and storage facilities. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.

There have been recent initiatives to strengthen and expand pipeline safety regulations and to increase penalties for violations. Partly in response to a series of pipeline incidents, new pipeline safety legislation requiring more stringent spill reporting and disclosure obligations was introduced in the U.S. Congress and was passed by the U.S. House of Representatives in 2010, but was not voted on in the U.S. Senate. Similar legislation is being considered by Congress again this year, either independently or in conjunction with the reauthorization of the Pipeline Safety

Act. The DOT has also recently proposed legislation providing for more stringent oversight of pipelines and increased penalties for violations of safety rules, which is in addition to the Pipeline and Hazardous Materials Safety Administration’s announced intention to strengthen its rules. The DOT also recently promulgated new regulations extending safety rules to certain low pressure, small diameter pipelines in rural areas. If adopted, these more stringent pipeline laws and regulations would increase our costs of operations.

On April 17, 20112, the EPA approved final rules that would subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs. These rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion (REC) techniques developed in EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (MACT) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. We are currently researching the effect these proposed rules could have on our business. While these rules have been finalized, many of the rules’ provisions will be phased-in over time, with the more stringent requirements like REC not becoming effective until 2015.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA have allowed the agency to proceed with the adoption and implementation of regulations restricting emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Among other things, EPA regulations now require specified large greenhouse gas emitters in the United States including companies in the energy industry to annually report those emissions. Additionally, starting in 2011, new sources or modifications of existing sources of significant quantities of greenhouse gas emissions are required to obtain permits—and to use best available control technology to control those emissions—pursuant to the Clean Air Act as a prerequisite to the development of that emissions source. While these regulations have not to date materially affected the company, such regulations may over time require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the oil and natural gas we produce.

Additionally, the U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane, which are understood to contribute to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that smaller sources could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

The Federal Water Pollution Control Act, as amended, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into navigable waters. Pursuant to the Clean Water Act and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the U.S. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure 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. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities.

The Oil Pollution Act of 1990, OPA, establishes strict liability for owners and operators of facilities that are the site of a release of oil into waters of the U.S. The OPA and its associated regulations impose a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” under the OPA includes owners and operators of certain onshore facilities from which a release may affect waters of the U.S.

The federal Endangered Species Act, or ESA, restricts activities that may affect endangered and threatened species or their habitats. While some of our facilities may be located in areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas.

As a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the ESA. The law prohibits the harming of endangered or threatened species, provides for habitat protection, and imposes stringent penalties for noncompliance. The final 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, delays, or prohibitions on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.

We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

The federal Energy Policy Act of 2005 amended the Underground Injection Control, or UIC, provisions of the federal Safe Drinking Water Act, or the SDWA, to exclude hydraulic fracturing from the definition of “underground injection.” However, the U.S. Senate and House of Representatives are currently considering bills entitled, the Fracturing Responsibility and Awareness of Chemicals Act, or the FRAC Act, to amend the SDWA to repeal this exemption. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could 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.

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceeding. In addition, we are not aware of any material legal or governmental proceedings contemplated to be brought against us.

As of July 31, 2012, we employed 33 people, including 10 employees in geology and geographic information systems, 1 employee in operations and engineering, 3 employees in accounting and finance, 14 employees in land and 5 employees in management and administration. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory. From time to time we utilize the services of independent contractors to perform various field and other services.

We currently lease approximately 16,000 square feet of office space in Fort Worth, Texas at Two City Place, Suite 1700, 100 Throckmorton, where our principal offices are located. The lease for our Fort Worth office expires in October 2013.

The following table sets forth information regarding our directors and executive officers as of July 31, 2012. There are no family relationships among any of our directors or executive officers.

The following table sets forth information regarding other key employees as of July 31, 2012.

Set forth below is the description of the backgrounds of our directors, executive officers and other key employees.

Mr. Pettit has served as our Director, President and Chief Executive Officer since our formation in February 2006 and has over 16 years of experience in the oil and natural gas industry as an entrepreneur and landman. An early mover in the Eagle Ford Shale, Mr. Pettit identified numerous opportunities across the play between 2008 and 2010. Under his leadership, we acquired and divested over 125,000 acres of leases in the Eagle Ford Shale to numerous large independent oil and natural gas companies including Murphy E&P USA, Chesapeake Energy Corporation, Comstock Resources, Inc. and Hess Corporation. Prior to founding our company, Mr. Pettit served as Contract Land Manager for the Barnett Shale Project for David H. Arrington Oil & Gas, Inc. from May 2005 to February 2008. In October 2007, Arrington successfully divested its Barnett Shale properties to XTO Energy (now Exxon) for approximately $550 million. Mr. Pettit earned a Bachelor of General Studies in Biology, Chemistry and Philosophy from Texas Tech University.

Mr. Pettit has extensive knowledge of our operations and of the oil and natural gas industry. For these reasons, we believe Mr. Pettit is qualified to serve as a director of our company.

Mr. Nelson has served as our Executive Vice President and Chief Financial Officer since September 2011 and has 21 years of experience in the energy industry, including 10 years in oil and natural gas. Prior to joining us, he served as the Chief Financial Officer at ZaZa Energy, LLC from May 2011 to September 2011. From October 2010 to May 2011, Mr. Nelson served as Senior Vice President and Chief Financial Officer of Great Western Oil & Gas Company, LLC. From September 2002 to October 2010, Mr. Nelson served as Vice President of Finance of ATP Oil & Gas Corporation. From 2001 to 2002, he worked as an equity analyst with Frost Securities, Inc., covering exploration and production companies. Mr. Nelson earned a Master of Business Administration from Rice University and Bachelor of Arts in Economics from the University of Texas at Austin.

David L. Patty, Jr., Executive Vice President—Land and Business Development

Mr. Patty has served as our Vice President—Land and Business Development since May 2012 and has over seven years of experience in the oil and natural gas industry with respect to acquisitions, divestitures, contract administration and operations. Mr. Patty worked under contract from July 2006 to April 2012 as a landman for David H. Arrington Oil and Gas, Inc., Quicksilver Resources Inc. and DLP Resources LLC, serving in various positions while handling all aspects of the land and legal parameters of the exploration and development process from lease negotiations, title, due diligence, curative, urban well permitting, overseeing field brokers and acquisitions and divestitures. Mr. Patty earned a Juris Doctor from the University of Houston Law Center and a Bachelor of Arts in Government and Spanish from the University of Texas at Austin.

Mr. Van Ingen has served as our Executive Vice President—Geology since May 2012 and has over 35 years of diversified domestic and international technical and management experience in the oil and natural gas industry in North America, Europe and Asia, including several countries in the Far East and South Pacific. Prior to joining us, Mr. Van Ingen was a co-owner of Alpine Ventures International, LLC, a company that has provided us with consulting services since November 2010. From March 2003 to November 2010, he was the President of Amana Partners, Inc., an oil and natural gas exploration and development company. His company provided the technical work which resulted in the discovery of multiple large gas fields in South Texas totaling 420 billion cubic feet of gas and several million barrels of condensate. Prior to that, he was employed from 1997 to 1999 by Pitts Energy Group. Mr. Van Ingen began his career at Mobil Corporation, where he lived and worked in a variety of domestic and international locations for 19 years and was promoted to positions of increasing responsibility. Mr. Van Ingen earned a Master of Science in Geology from the University of Wyoming and a Bachelor of Arts in Geology from Alfred University.

Tom D. McNutt, Executive Vice President, General Counsel and Corporate Secretary

Mr. McNutt has served as our Executive Vice President, General Counsel and Corporate Secretary since March 2012 and has over ten years of legal experience. From January 2009 to March 2012, Mr. McNutt was of counsel, and from June 2001 to January 2009, he was an associate, in the tax group of Bracewell & Giuliani, LLP. While at Bracewell & Giuliani, LLP Mr. McNutt advised numerous oil and natural gas clients on a variety of issues including international, federal and state tax issues and also designed and implemented tax efficient structures with respect to asset acquisitions and dispositions. Mr. McNutt earned a Master of Laws (LLM) in taxation from the New York University School of Law and a Juris Doctor from South Texas College of Law where he graduated cum laude. He also earned a Bachelor of Arts in Economics from the University of Texas.

Steven C. Wilson, Senior Vice President—Geophysics and Geological Engineering

Mr. Wilson has served as our Senior Vice President—Geophysics and Geological Engineering since January 2011 and has 30 years of oil and natural gas experience. Before joining us, Mr. Wilson worked at Canyon Partners, LLC where he participated in the discovery of several large gas fields in South Texas totaling over 420 billion cubic feet of gas and several million barrels of condensate. Mr. Wilson began his career at Mobil Corporation, generating prospects in the Netherlands, Germany, Norway, Indonesia, Offshore Nigeria, Offshore China, Offshore Deep and Shallow Water Gulf of Mexico, Trinidad, Western Canada, Ohio, Colorado, California and all basins in Texas. A highly skilled geophysical 2D and 3D seismic interpreter and computer programmer, Mr. Wilson is responsible for the development of APM™ proprietary technology and related processing software which when applied with and correlated to 3D seismic data has resulted in a hydrocarbon discovery success rate of greater than 85%. Mr. Wilson earned a Bachelor of Science in Geological Engineering from the Colorado School of Mines.

Mr. Evans has served as our Senior Vice President—Reservoir Engineering since May 2012 and has 38 years of experience in the oil and natural gas industry. He is currently President of Evantech, Inc., a petroleum consulting

company which he started in 1985. He also currently serves as Executive Vice President of Powell Royalty, Inc., a position he has held since January 2004. Mr. Evans recently served as President of CreditPro, Inc., a credit software company. From 1974 to 1979, Mr. Evans worked at Phillips Petroleum, followed by roles of increasing responsibility in engineering and banking at the First National Bank of Fort Worth, Paragon Resources and Jumas Oil Corporation. He is also a contributing editor to the Powell Shale Digest. Mr. Evans has a professional engineering license from the State of Texas in Petroleum Engineering and earned a Bachelor of Science in Earth Sciences (Geophysics) and Civil Engineering from Montana State University.

Mr. Galloway has served as our Senior Vice President—Land and Operations since June 2011 and has 25 years of experience in the oil and natural gas industry. Prior to joining us, he worked as a landman in the Haynesville Shale in East Texas from June 2008 to June 2011. From December 2004 to May 2008 he managed his own independent exploration and production company, Rock Petroleum LLC, which operated in the Barnett Shale and Bend Conglomerate in North Texas. Before that, he worked as a landman from November 2003 to November 2004 in the Permian Basin, North Texas and East Texas. He began his career as a rig hand in the Barnett Shale in 1985. Mr. Galloway earned a Master of Science in Geology and a Bachelor of Science in Geology from Stephen F. Austin State University.

Robert G. Karpman, Executive Vice President—Business Operations and Development

Mr. Karpman serves as our Executive Vice President—Business Operations and Development. Mr. Karpman has 25 years of experience in operations and communications. He joined us in December 2009 as Vice President, Business Operations & Development. He served as Vice President for Westbrook Development Corporation from 2000 to 2007. From March 2005 to December 2009, Mr. Karpman served as President of Karpman Enterprises, LP, where he consulted and managed commercial real estate projects for his company and clients. From 1985 to 1999, Mr. Karpman managed on location filming operations for several major feature films and television productions for 20th Century Fox, Sony and Disney, to name a few. Mr. Karpman earned a Master of Business Administration from Southern Methodist University’s Cox School of Business, a Master of Arts in Clinical Psychology from Pepperdine University and a Bachelor of Arts in Film Production from California State University, Northridge.

Mr. Pettit filed for protection under Chapter 7 of the Federal bankruptcy laws in May 2003 in the U.S. Bankruptcy Court for the Western District of Texas, Austin Division. Except for the petition for bankruptcy filed by Mr. Pettit, none of our directors, executive officers or control persons has been involved in any of the events described in Item 401(f) of Regulation S-K during the past ten years.

Our board of directors currently consists of one member, Hunt Pettit, our President and Chief Executive Officer. We expect to increase the number of members on our board of directors in connection with the completion of this offering.

We intend to appoint independent directors to our board of directors contemporaneously with and following the completion of this offering. We also expect that our board will review the independence of our current directors using the independence standards of the NYSE.

In evaluating director candidates, we will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

Following the completion of this offering, our directors will be divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2013, 2014 and 2015, respectively. At each annual meeting of stockholders held after the initial classification, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

Upon completion of this offering, we expect to be a “controlled company” under NYSE corporate governance standards. A controlled company need not comply with NYSE corporate governance rules that require a listed company’s board of directors to have a majority of independent directors and independent compensation and nominating and governance committees. We intend to avail ourselves of the controlled company exception under the NYSE corporate governance standards. Notwithstanding our status as a controlled company, we will remain subject to the NYSE corporate governance standard that requires us to have an audit committee composed entirely of independent directors. As a result, we must have at least one independent director on our audit committee by the date our common stock is listed on the NYSE, at least two independent directors within 90 days of the listing date and at least three independent directors within one year of the listing date.

If and when we cease to be a controlled company, our board of directors will be required to have a compensation committee and a nominating and governance committee, each with at least one independent director. Within 90 days of ceasing to be a controlled company, we will be required to have a majority of independent directors on each of a compensation committee and a nominating and governance committee, and within one year of ceasing to be a controlled company, a majority of our board of directors and each member of our compensation committee and nominating and governance committee must be independent directors.

Upon the conclusion of this offering, we intend to have an audit committee, and in the event we are no longer a controlled company, a compensation committee and a nominating and governance committee, of our board of directors, and may have such other committees as the board of directors shall determine from time to time. We anticipate that each of the standing committees of the board of directors will have the composition and responsibilities described below.

We will establish an audit committee prior to the completion of this offering. We anticipate that our audit committee will initially consist of three members who are financially literate, one of whom is an “audit committee financial expert” as described in Item 407(d)(5) of Regulation S-K. We will rely on the phase-in rules of the SEC and NYSE with respect to the independence of our audit committee. These rules permit us to have an audit committee that has one member that is independent upon the effectiveness of the registration statement of which this prospectus forms a part and the listing of our common stock on the NYSE, a majority of members that are independent within 90 days thereafter and all members that are independent within one year thereafter.

Our audit committee will oversee, review, act on and report to our board of directors on various auditing and accounting matters, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to our independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee will oversee our compliance programs related to legal and regulatory requirements. Upon formation of the audit committee, we expect to adopt an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE standards.

Because we will be a “controlled company” within the meaning of the NYSE corporate governance standards, we will not be required to, and will not, have a compensation committee.

If and when we are no longer a controlled company, we will be required to establish a compensation committee. We anticipate that, subject to the transition rules described under “—Status as a ‘Controlled Company’” above, the compensation committee will consist of three independent directors. This committee will establish salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee will also administer our incentive compensation and benefit plans. Upon formation of the compensation committee, we expect to adopt a compensation committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE standards.

Because we will be a “controlled company” within the meaning of the NYSE corporate governance standards, we will not be required to, and will not, have a nominating and governance committee. While we are a controlled company, our board of directors will identify and evaluate potential candidates for nomination as a director.

If and when we are no longer a controlled company, we will be required to establish a nominating and governance committee. We anticipate that, subject to the transition rules described under “—Status as a ‘Controlled Company’” above, the nominating and governance committee will consist of three independent directors. This committee will identify, evaluate and recommend qualified nominees to serve on our board of directors, develop and oversee our internal corporate governance processes and maintain a management succession plan. Upon formation of the nominating and governance committee, we expect to adopt a nominating and governance committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and NYSE standards.

Because we will be a “controlled company” within the meaning of the NYSE corporate governance standards, we will not be required to, and will not, have a compensation committee. None of our executive officers serve on the board of directors or compensation committee of a company that has an executive officer that serves on our board. No member of our board is an executive officer of a company in which one of our executive officers serves as a member of the board of directors or compensation committee of that company.

Our board of directors will adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Our code of business conduct and ethics will be available on our corporate website at www.enexp.com on or prior to the completion of this offering.

Our board of directors will adopt corporate governance guidelines in accordance with the corporate governance rules of the NYSE. Our code of corporate governance guidelines will be available on our corporate website at www.enexp.com on or prior to the completion of this offering.

As an emerging growth company, we have opted to comply with the executive compensation disclosure rules applicable to “smaller reporting companies” as such term is defined in the rules promulgated under the Securities Act, which require compensation disclosure for our principal executive officer and the two most highly compensated executive officers other than our principal executive officer during the 2011 fiscal year. Throughout this prospectus, these three officers are referred to as our named executive officers.

The following table shows information concerning the annual compensation for services provided to us by our named executive officers during the fiscal year ended December 31, 2011.

In connection with the completion of this offering, it is anticipated that each of our named executive officers will enter into an employment agreement on terms similar to other comparably sized companies in our industry.

We are in the process of granting overriding royalty interests in our acreage to our executive officers, including the named executive officers, and to NASIF. The terms and allocations of these overriding royalty interests have not been finalized, but we expect that the overriding royalty interests will entitle the holders to receive, in the aggregate for all executive officers and NASIF, percentages ranging from 0% to 5% of the net revenue associated with sales of oil and natural gas produced from our acreage, with no corresponding responsibility for payment of any expenses. We expect that the grants of these overriding royalty interests will be completed during August of 2012. As described under “Corporate Reorganization,” the overriding royalty interests granted to NASIF will be distributed to its limited partners in connection with our corporate reorganization.

There were no outstanding equity awards held by our named executive officers as of December 31, 2011.

To create incentives for our executive officers to continue to grow our company, we are in the process of evaluating a formal long-term stock incentive plan. We intend to adopt the formal plan and issue the restricted stock awards described under “Corporate Reorganization” prior to the completion of this offering. We believe that having an equity component to our compensation program is vital to align our executive officers’ interests with our stockholders’ long-term interests through shared ownership.

We did not award any compensation to any non-employee director during 2011. However, our board of directors believes that attracting and retaining qualified non-employee directors will be critical to the future value growth and governance. Our board of directors also believes that the compensation package for our non-employee directors should require a significant portion of the total compensation package to be equity-based to align the interests of these directors with our stockholders.

We intend to conduct a review of our planned director compensation with our compensation consultant prior to the proposed offering, but believe that the key components of our director compensation will be as follows:

Directors who are also our employees will not receive any additional compensation for their service on the board of directors.

We expect that each director will be reimbursed for (1) travel and miscellaneous expenses to attend meetings and activities of our board of directors or its committees; (2) travel and miscellaneous expenses related to such director’s participation in our general education and orientation program for directors; and (3) travel and miscellaneous expenses for each director’s spouse who accompanies a director to attend meetings and activities of our board of directors or any of our committees.

In connection with our corporate reorganization, we engaged in certain transactions with certain of our stockholders, our director and our executive officers. Please see “Corporate Reorganization” for a description of those transactions.

During the year ended December 31, 2010, we paid to Hunt Pettit, our director, President and Chief Executive Officer, and certain of his family members $1.7 million in commissions related to undeveloped leasehold acreage sales.

A “related party transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeded or exceeds $120,000, and in which any related person had, has or will have a direct or indirect material interest. A “related person” means:

We expect that our board of directors will adopt a written related party transactions policy prior to the completion of this offering. Pursuant to this policy, we expect that the audit committee will review all material facts of all related party transactions and either approve or disapprove entry into the related party transaction, subject to certain limited exceptions. We anticipate that the policy will provide that, in determining whether to approve or disapprove entry into a related party transaction, the audit committee shall take into account, among other factors, the following: (1) whether the related party transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (2) the extent of the related person’s interest in the transaction. Further, we expect the policy to require that all related party transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations.

Contributions to Energy & Exploration Partners, Inc. Pursuant to a contribution agreement, the following contributions will be made to us:

Registration Rights Agreement. In connection with our corporate reorganization, we will enter into a registration rights agreement with all of our stockholders, including management, receiving shares of common stock in the reorganization. Pursuant to the registration rights agreement, these stockholders will have demand and piggyback registration rights under which we will be required to register the resale of shares of our common stock held by these stockholders or their permitted transferees under certain circumstances.

The table below sets forth information regarding the beneficial ownership of the common stock of Energy & Exploration Partners, Inc. as of , 2012 after giving effect to our corporate reorganization by (1) each beneficial owner of more than 5% of our outstanding common stock, (2) each director of Energy & Exploration Partners, Inc., (3) each of our named executive officers, and (4) all executive officers and directors as a group. As of , 2012, there were shares of our common stock outstanding. The ownership percentages after the offering are based on the issuance and sale by us of shares of common stock in the offering, assuming no exercise of the underwriters’ option to purchase additional shares. After the offering, there will be shares of our common stock outstanding.

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities. Except as indicated by footnote, to our knowledge the persons named in the table below have sole voting and investment power with respect to all common stock shown as beneficially owned by them, subject to community property laws where applicable. Unless otherwise indicated, the address for each stockholder, director and executive officer listed is: c/o Two City Place, Suite 1700, 100 Throckmorton, Fort Worth, Texas 76102.

Upon completion of this offering, the authorized capital stock of Energy & Exploration Partners, Inc. will consist of shares of common stock, $0.01 par value per share, of which shares will be issued and outstanding, and shares of preferred stock, $0.01 par value per share, of which no shares will be issued and outstanding.

The following description includes summaries of the material terms and provisions of our amended and restated certificate of incorporation and amended and restated bylaws. This description is qualified by reference to our amended and restated certificate of incorporation and amended and restated bylaws, which will be filed as exhibits to the registration statement of which this prospectus is a part, and to the provisions of applicable law.

Except as provided by law or in a preferred stock designation, holders of common stock are entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders, will have the exclusive right to vote for the election of directors and do not have cumulative voting rights. Except as otherwise required by law, holders of common stock, as such, are not entitled to vote on any amendment to the certificate of incorporation (including any certificate of designations relating to any series of preferred stock) that relates solely to the terms of any outstanding series of preferred stock if the holders of such affected series are entitled, either separately or together with the holders of one or more other such series, to vote thereon pursuant to the amended and restated certificate of incorporation (including any certificate of designations relating to any series of preferred stock) or pursuant to the General Corporation Law of the State of Delaware. Subject to preferences that may be applicable to any outstanding shares or series of preferred stock, holders of common stock are entitled to receive ratably such dividends (payable in cash, stock or otherwise), if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. All outstanding shares of common stock are fully paid and non-assessable, and the shares of common stock to be issued upon completion of this offering will be fully paid and non-assessable. The holders of common stock have no preferences or rights of conversion, exchange, pre-emption or other subscription rights. There are no redemption or sinking fund provisions applicable to the common stock. In the event of any liquidation, dissolution or winding-up of our affairs, holders of common stock will be entitled to share ratably in our assets that are remaining after payment or provision for payment of all of our debts and obligations and after liquidation payments to holders of outstanding shares of preferred stock, if any.

Our amended and restated certificate of incorporation will authorize our board of directors, subject to any limitations prescribed by law, without further stockholder approval, to establish and to issue from time to time one or more classes or series of preferred stock, par value $0.01 per share, covering up to an aggregate of shares of preferred stock. Each class or series of preferred stock will cover the number of shares and will have the powers, preferences, rights, qualifications, limitations and restrictions determined by the board of directors, which may include, among others, dividend rights, liquidation preferences, voting rights, conversion rights, preemptive rights and redemption rights. Except as provided by law or in a preferred stock designation, the holders of preferred stock will not be entitled to vote at or receive notice of any meeting of stockholders.

Anti-Takeover Effects of Provisions of Our Certificate of Incorporation, Our Bylaws and Delaware Law

Some provisions of Delaware law and our amended and restated certificate of incorporation and our amended and restated bylaws, will contain provisions that could make the following transactions more difficult: acquisitions of us by means of a tender offer, a proxy contest or otherwise; or removal of our incumbent directors. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions that might result in a premium over the market price for our shares.

These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with us. We believe that the benefits of increased protection and our potential ability to negotiate with the

proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because, among other things, negotiation of these proposals could result in an improvement of their terms.

In our amended and restated certificate of incorporation, we will elect not to be subject to the provisions of Section 203 of the Delaware General Corporation Law (“DGCL”) regulating corporate takeovers. In general, those provisions prohibit a Delaware corporation, including those whose securities are listed for trading on the NYSE, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:

on or after such time the business combination is approved by the board of directors and authorized at a meeting of stockholders by at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.

Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws

Among other things, upon the completion of this offering, our amended and restated certificate of incorporation and amended and restated bylaws will:

Our amended and restated certificate of incorporation will limit the liability of our directors for monetary damages for breach of their fiduciary duty as directors, except for liability that cannot be eliminated under the DGCL. Delaware law provides that directors of a company will not be personally liable for monetary damages for breach of their fiduciary duty as directors, except for liabilities:

Any amendment, repeal or modification of these provisions will be prospective only and would not affect any limitation on liability of a director for acts or omissions that occurred prior to any such amendment, repeal or modification.

Our amended and restated certificate of incorporation and amended and restated bylaws will also provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. Our amended and restated bylaws will also permit us to purchase insurance on behalf of any officer, director, employee or other agent for any liability arising out of that person’s actions as our officer, director, employee or agent, regardless of whether Delaware law would permit indemnification. We intend to enter into indemnification agreements with each of our current and future directors and officers. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liability that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified. We believe that the limitation of liability provision in our amended and restated certificate of incorporation and the indemnification agreements will facilitate our ability to continue to attract and retain qualified individuals to serve as directors and officers.

We anticipate that the transfer agent and registrar for our common stock will be .

We intend to apply to list our common stock on the NYSE under the symbol “ENXP.”

Prior to this offering, there has been no public market for our common stock. Future sales of our common stock in the public market, or the availability of such shares for sale in the public market, could adversely affect market prices prevailing from time to time. As described below, only a limited number of shares, other than shares sold in this offering, will be available for sale shortly after this offering due to contractual and legal restrictions on resale. Nevertheless, sales of a substantial number of shares of our common stock in the public market after such restrictions lapse, or the perception that those sales may occur, could adversely affect the prevailing market price at such time and our ability to raise equity-related capital at a time and price we deem appropriate.

Upon the closing of this offering, we will have issued and outstanding an aggregate of shares of common stock. Of these shares, all of the shares of common stock to be sold in this offering will be freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. All remaining shares of common stock held by existing stockholders will be deemed “restricted securities” as such term is defined in Rule 144. The restricted securities were issued and sold by us in private transactions and are eligible for public sale only if registered under the Securities Act or if they qualify for an exemption from registration under Rule 144 or Rule 701 under the Securities Act, which rules are summarized below.

Under the provisions of Rule 144 and Rule 701 under the Securities Act, all of the shares of our common stock (excluding the shares to be sold in this offering) will be available for sale in the public market upon the expiration of the lock-up agreements, beginning 180 days after the date of this prospectus (subject to certain exceptions and extensions) and when permitted under Rule 144 or Rule 701.

We, all of our directors and executive officers and all of our existing stockholders have agreed not to sell or otherwise transfer or dispose of any common stock for a period of 180 days from the date of this prospectus, subject to certain exceptions and extensions. See “Underwriting” for a description of these lock-up provisions.

In general, under Rule 144 as currently in effect, once we have been a reporting company subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act for 90 days, a person (or persons whose shares are aggregated) who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months (including any period of consecutive ownership of preceding non-affiliated holders) would be entitled to sell those shares, subject only to the availability of current public information about us. A non-affiliated person who has beneficially owned restricted securities within the meaning of Rule 144 for at least one year would be entitled to sell those shares without regard to the provisions of Rule 144.

In general, once we have been a reporting company subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act for 90 days, a person (or persons whose shares are aggregated) who is deemed to be an affiliate of ours and who has beneficially owned restricted securities within the meaning of Rule 144 for at least six months would be entitled to sell within any three-month period a number of shares that does not exceed the greater of one percent of the then outstanding shares of our common stock or the average weekly trading volume of our common stock reported through the New York Stock Exchange during the four calendar weeks preceding the filing of notice of the sale. Such sales are also subject to certain manner of sale provisions, notice requirements and the availability of current public information about us.

Employees, directors, officers, consultants or advisors who received shares from us in connection with a compensatory stock or option plan or other written compensatory agreement in accordance with Rule 701 before the effective date of the registration statement of which this prospectus is a part are entitled to sell such shares 90 days

after the effective date of the registration statement in reliance on Rule 144 without having to comply with the holding period requirement of Rule 144 and, in the case of non-affiliates, without having to comply with the public information, volume limitation or notice filing provisions of Rule 144.

We intend to file a registration statement on Form S-8 under the Securities Act to register stock issuable under our 2012 Stock Incentive Plan. This registration statement is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, shares registered under such registration statement will be available for sale in the open market following the effective date, unless such shares are subject to vesting restrictions with us, Rule 144 restrictions applicable to our affiliates or the lock-up restrictions described above.

We will enter into a registration rights agreement in connection with our corporate reorganization pursuant to which we will be required to register the resale of shares of our common stock held by certain of our stockholders or their permitted transferees under certain circumstances. See “Corporate Reorganization.”

The following is a general discussion of the material U.S. federal income tax consequences of the acquisition, ownership and disposition of our common stock to a non-U.S. holder. For the purpose of this discussion, a non-U.S. holder is any beneficial owner of our common stock that is not for U.S. federal income tax purposes any of the following:

If a partnership (or an entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership will generally depend on the status of the partner and upon the activities of the partnership. Accordingly, we urge partnerships that hold our common stock and partners in such partnerships to consult their tax advisors.

This discussion assumes that a non-U.S. holder will hold our common stock issued pursuant to the offering as a capital asset (generally, property held for investment). This discussion does not address all aspects of U.S. federal income taxation (including alternative minimum tax, gift and estate tax) or any aspects of state, local or non-U.S. taxation, nor does it consider any U.S. federal income tax considerations that may be relevant to non-U.S. holders that may be subject to special treatment under U.S. federal income tax laws, including, without limitation, U.S. expatriates, life insurance companies, tax-exempt or governmental organizations, dealers in securities or currency, banks or other financial institutions, investors whose functional currency is other than the U.S. dollar, “passive foreign investment companies,” “controlled foreign corporations,” persons who at any time hold more than 5% of the fair market value of any class of our stock and investors that hold our common stock as part of a hedge, straddle or conversion transaction. Furthermore, the following discussion is based on current provisions of the Internal Revenue Code of 1986, as amended, and Treasury Regulations and administrative and judicial interpretations thereof, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect.

We urge each prospective investor to consult a tax advisor regarding the U.S. federal, state, local and non-U.S. income and other tax consequences of acquiring, holding and disposing of shares of our common stock.

We have not made any distributions on our common stock, and we do not plan to make any distributions for the foreseeable future. However, if we do make distributions on our common stock, those payments will constitute dividends for U.S. tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will constitute a return of capital and will first reduce a holder’s adjusted tax basis in the common stock, but not below zero, and then will be treated as gain from the sale of the common stock (see “—Gain on Disposition of Common Stock”).

Any dividends (out of earnings and profits) paid to a non-U.S. holder of our common stock that are not effectively connected with a U.S. trade or business conducted by the non-U.S. holder generally will be subject to U.S. withholding tax either at a rate of 30% of the gross amount of the dividend or such lower rate as may be

specified by an applicable tax treaty. To receive the benefit of a reduced treaty rate, a non-U.S. holder must provide us with an Internal Revenue Service (“IRS”) Form W-8BEN or other appropriate version of IRS Form W-8 certifying qualification for the reduced rate.

Dividends received by a non-U.S. holder that are effectively connected with a U.S. trade or business conducted by the non-U.S. holder are exempt from such withholding tax. To obtain this exemption, the non-U.S. holder must provide us with an IRS Form W-8ECI properly certifying such exemption. Such effectively connected dividends, although not subject to withholding tax, will be subject to U.S. federal income tax on a net income basis at the same graduated rates generally applicable to U.S. persons, subject to any applicable tax treaty providing otherwise. In addition to the income tax described above, dividends received by corporate non-U.S. holders that are effectively connected with a U.S. trade or business of the corporate non-U.S. holder may be subject to a branch profits tax at a rate of 30% or such lower rate as may be specified by an applicable tax treaty.

A non-U.S. holder of our common stock may obtain a refund of any excess amounts withheld if the non-U.S. holder is eligible for a reduced rate of United States withholding tax and an appropriate claim for refund is timely filed with the IRS.

A non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:

Unless an applicable tax treaty provides otherwise, gain described in the first bullet point above will be subject to U.S. federal income tax on net income basis at the same graduated rates generally applicable to U.S. persons. Corporate non-U.S. holders also may be subject to a branch profits tax equal to 30% (or such lower rate as may be specified by an applicable tax treaty) of its earnings and profits that are effectively connected with a U.S. trade or business.

Gain described in the second bullet point above (which may be offset by U.S. source capital losses, provided that the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses) will be subject to a flat 30% U.S. federal income tax (or such lower rate as may be specified by an applicable tax treaty).

With respect to the third bullet point above, we believe we are, and will remain for the foreseeable future, a USRPHC. If we are so classified, gain arising from the sale or other taxable disposition by a non-U.S. holder of our common stock will not be subject to tax if such class of stock is “regularly traded,” as defined by applicable Treasury Regulations, on an established securities market, and such non-U.S. holder owned, actually or constructively, 5% or less of such class of our stock throughout the shorter of the five-year period ending on the date of the sale or exchange or the non-U.S. holder’s holding period for such stock. We expect our common stock to be “regularly traded” on an established securities market, although we cannot guarantee it will be so traded. If gain on the sale or other taxable disposition of our stock were subject to taxation under the third bullet point above, the non-U.S. holder would be subject to regular United States federal income tax with respect to such gain in generally the same manner as a United States person and would have to file a U.S. income tax return reporting such gain or loss.

Non-U.S. holders should consult a tax advisor regarding potentially applicable income tax treaties that may provide for different rules.

Generally, we must report annually to the IRS the amount of dividends paid to each non-U.S. holder, the name and address of the recipient, and the amount, if any, of tax withheld with respect to those dividends. A similar report is sent to each non-U.S. holder. These information reporting requirements apply even if withholding was not required. Pursuant to tax treaties or other agreements, the IRS may make its reports available to tax authorities in the recipient’s country of residence.

Payments of dividends to a non-U.S. holder may be subject to backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption, for example, by properly certifying its non-U.S. status on an IRS Form W-8BEN or another appropriate version of IRS Form W-8. Notwithstanding the foregoing, backup withholding may apply if either we or our paying agent has actual knowledge, or reason to know, that the beneficial owner is a U.S. person that is not an exempt recipient.

Payments of the proceeds from sale or other disposition by a non-U.S. holder of our common stock effected outside the U.S. by or through a foreign office of a broker generally will not be subject to information reporting or backup withholding. However, information reporting (but not backup withholding) will apply to those payments if the broker does not have documentary evidence that the holder is a non-U.S. holder, an exemption is not otherwise established, and the broker has certain relationships with the United States.

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our common stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption, for example, by properly certifying its non-U.S. status on an IRS Form W-8BEN or another appropriate version of IRS Form W-8. Notwithstanding the foregoing, information reporting and backup withholding may apply if the broker has actual knowledge, or reason to know, that the holder is a U.S. person that is not an exempt recipient.

Backup withholding is not an additional tax. Rather, the U.S. income tax liability of persons subject to backup withholding will be reduced by the amount of tax withheld. If withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.

Under recently enacted legislation and administrative guidance, the relevant withholding agent may be required to withhold 30% of any dividends paid after December 31, 2013 and the proceeds of a sale of our common stock paid after December 31, 2014 to (i) a foreign financial institution unless such foreign financial institution agrees to verify, report and disclose its United States accountholders and meets certain other specified requirements or (ii) a non-financial foreign entity that is the beneficial owner of the payment unless such entity certifies that it does not have any substantial United States owners or provides the name, address and taxpayer identification number of each substantial United States owner and such entity meets certain other specified requirements. Investors should consult their own tax advisors regarding this legislation.

Canaccord Genuity Inc. and Johnson Rice & Company L.L.C. are acting as representatives of each of the underwriters named below. Subject to the terms and conditions set forth in an underwriting agreement between us and the representatives, we have agreed to sell to the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us, the number of shares of common stock set forth opposite its name below.

Subject to the terms and conditions set forth in the underwriting agreement, the underwriters have agreed, severally and not jointly, to purchase all of the shares sold under the underwriting agreement if any of these shares are purchased, other than the shares covered by the option described below unless and until this option is exercised.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments the underwriters may be required to make for certain liabilities.

The underwriters are offering the shares, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of the shares, and other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officer’s certificates and legal opinions. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part.

The underwriters have advised us that they propose to offer the shares of common stock directly to the public at the public offering price set forth on the cover page of this prospectus and to dealers at the public offering price less a selling concession not in excess of $ per share. The underwriters also may allow, and dealers may reallow, a concession not in excess of $ per share to brokers and dealers. After the offering, the underwriters may change the offering price and the other selling terms.

The following table shows the public offering price, underwriting discount and proceeds before expenses to us. The information assumes either no exercise or full exercise by the underwriters of their option to purchase additional shares.

The expenses of the offering, not including the underwriting discount, are estimated at $ and are payable by us.

We have granted to the underwriters an option to purchase up to an aggregate of additional shares of common stock at the public offering price less the underwriting discount. The underwriters may exercise this option

solely for the purpose of covering over-allotments, if any, made in connection with the offering of the shares of common stock offered by this prospectus. The underwriters may exercise that option for 30 days. If any shares are purchased pursuant to this option, the underwriters will severally purchase shares in approximately the same proportion as set forth in the table above.

We, each of our executive officers and directors and each of our existing stockholders have agreed not to do any of the following, directly or indirectly, for 180 days after the date of this prospectus without the prior written consent of the representatives (regardless whether the transactions described in the first two bullet points are settled in securities, cash or otherwise):

The restrictions described above do not apply to (1) the issuance of common stock by us to the underwriters pursuant to this offering, (2) the issuance of common stock and options by us in the ordinary course of business pursuant to certain stock compensation plans, (3) the issuance of shares of common stock by us upon the exercise of certain outstanding options, (4) bona fide gifts, other than by us, or transfers by will or intestacy, (5) transfers, other than by us, to any trust for the direct or indirect benefit of the stockholder or the immediate family of the stockholder and (6) transfers, other than by us, to limited partners or stockholders of the stockholder. In the case of (3), (4) and (5) above, (a) the transferee must deliver a signed lock-up agreement for the balance of the 180-day period, (b) the transfer must not involve a disposition for value, (c) the transfer must not be publicly reportable under any law and (d) the stockholder must not otherwise voluntarily effect any public filing, report or announcement regarding such transfer.

If (1) during the last 17 days of the 180-day period, we issue an earnings release or material news or a material event relating to us occurs or (2) prior to the expiration of the 180-day period, we announce that we will release earnings results or become aware that material news or a material event will occur during the 16-day period beginning on the last day of the 180-day period, then the restrictions above will continue to apply until the expiration of the 18-day period beginning on the date of the issuance of the earnings release or the occurrence of the material news or material event, as the case may be, unless the representatives waive, in writing, such extension.

We intend to apply to list our shares of common stock on the New York Stock Exchange under the symbol “ENXP.” In order to meet the requirements for listing on that exchange, the underwriters have undertaken to sell a minimum number of shares to a minimum number of beneficial owners as required by that exchange.

Prior to this offering, there has been no public market for our common stock. The initial public offering price is determined by negotiations between us and the representatives. Among the factors to be considered in determining the initial public offering price will be the information set forth in this prospectus; our history, present state of development and future prospects; an assessment of our management, its past and present operations and the prospects for and timing of future revenues; the history of and future prospects for our industry in general; our sales, earnings and certain other financial and operating information in recent periods; and the price-earnings ratios, price-sales ratios, market prices of securities, valuation multiples and certain financial and operating information of companies engaged in activities similar to ours.

An active trading market for the shares may not develop. It is also possible that after the offering the shares will not trade in the public market at or above the initial public offering price.

Until the distribution of the shares is completed, SEC rules may limit underwriters and selling group members from bidding for and purchasing our common stock. However, the representatives may engage in transactions that stabilize the price of the common stock, such as bids or purchases to peg, fix or maintain that price.

In connection with the offering, the underwriters may purchase and sell our common stock in the open market. These transactions may include over-allotment and stabilizing transactions, passive market making and purchases to cover syndicate short positions created in connection with this offering. Short sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in the offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ option to purchase additional shares described above. The underwriters may close out any covered short position by either exercising their option to purchase additional shares or purchasing shares in the open market. In determining the source of shares to close out the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the option to purchase additional shares. “Naked” short sales are sales in excess of the option to purchase additional shares. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our common stock in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of shares of common stock made by the underwriters in the open market prior to the completion of the offering.

The underwriters also may impose a penalty bid, whereby the underwriters may reclaim selling concessions allowed to syndicate members or other broker-dealers in respect of the common stock sold in the offering for their account if the underwriters repurchase the shares in stabilizing or covering transactions.

These activities may stabilize, maintain or otherwise affect the market price of the common stock, which may be higher than the price that might otherwise prevail in the open market. The underwriters may conduct these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common stock. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

In connection with the offering, certain of the underwriters or securities dealers may distribute prospectuses by electronic means, such as e-mail.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. Certain of the

underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory and investment banking services for us, for which they received or will receive customary fees and expenses.

In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve our securities and/or instruments. The underwriters and their respective affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”), no offer of shares may be made to the public in that Relevant Member State other than:

provided that no such offer of shares shall require us or the representatives to publish a prospectus pursuant to Article 3 of the Prospectus Directive or supplement a prospectus pursuant to Article 16 of the Prospectus Directive.

Each person in a Relevant Member State (other than a Relevant Member State where there is a Permitted Public Offer) who initially acquires any shares or to whom any offer is made will be deemed to have represented, acknowledged and agreed that (A) it is a “qualified investor” within the meaning of the law in that Relevant Member State implementing Article 2(1)(e) of the Prospectus Directive, and (B) in the case of any shares acquired by it as a financial intermediary, as that term is used in Article 3(2) of the Prospectus Directive, the shares acquired by it in the offering have not been acquired on behalf of, nor have they been acquired with a view to their offer or resale to, persons in any Relevant Member State other than “qualified investors” as defined in the Prospectus Directive, or in circumstances in which the prior consent of the Subscribers has been given to the offer or resale. In the case of any shares being offered to a financial intermediary as that term is used in Article 3(2) of the Prospectus Directive, each such financial intermediary will be deemed to have represented, acknowledged and agreed that the shares acquired by it in the offer have not been acquired on a non-discretionary basis on behalf of, nor have they been acquired with a view to their offer or resale to, persons in circumstances which may give rise to an offer of any shares to the public other than their offer or resale in a Relevant Member State to qualified investors as so defined or in circumstances in which the prior consent of the representatives has been obtained to each such proposed offer or resale.

We, the representatives and their affiliates will rely upon the truth and accuracy of the foregoing representation, acknowledgement and agreement.

This prospectus has been prepared on the basis that any offer of shares in any Relevant Member State will be made pursuant to an exemption under the Prospectus Directive from the requirement to publish a prospectus for offers of shares. Accordingly any person making or intending to make an offer in that Relevant Member State of shares which are the subject of the offering contemplated in this prospectus may only do so in circumstances in which no obligation arises for us or any of the underwriters to publish a prospectus pursuant to Article 3 of the Prospectus Directive in relation to such offer. Neither we nor the underwriters have authorized, nor do they authorize, the making of any offer of shares in circumstances in which an obligation arises for us or the underwriters to publish a prospectus for such offer.

For the purpose of the above provisions, the expression “an offer to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe the shares, as the same may be varied in the Relevant Member State by any measure implementing the Prospectus Directive in the Relevant Member State and the expression “Prospectus Directive” means Directive 2003/71/EC (including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member States) and includes any relevant implementing measure in the Relevant Member State and the expression “2010 PD Amending Directive” means Directive 2010/73/EU.

In addition, in the United Kingdom, this document is being distributed only to, and is directed only at, and any offer subsequently made may only be directed at persons who are “qualified investors” (as defined in the Prospectus Directive) (i) who have professional experience in matters relating to investments falling within Article 19 (5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Order”) and/or (ii) who are high net worth companies (or persons to whom it may otherwise be lawfully communicated) falling within Article 49(2)(a) to (d) of the Order (all such persons together being referred to as “relevant persons”). This document must not be acted on or relied on in the United Kingdom by persons who are not relevant persons. In the United Kingdom, any investment or investment activity to which this document relates is only available to, and will be engaged in with, relevant persons.

The shares may not be publicly offered in Switzerland and will not be listed on the SIX Swiss Exchange (“SIX”) or on any other stock exchange or regulated trading facility in Switzerland. This document has been prepared without regard to the disclosure standards for issuance prospectuses under art. 652a or art. 1156 of the Swiss Code of Obligations or the disclosure standards for listing prospectuses under art. 27 ff. of the SIX Listing Rules or the listing rules of any other stock exchange or regulated trading facility in Switzerland. Neither this document nor any other offering or marketing material relating to the shares or the offering may be publicly distributed or otherwise made publicly available in Switzerland.

Neither this document nor any other offering or marketing material relating to the offering, us, the shares have been or will be filed with or approved by any Swiss regulatory authority. In particular, this document will not be filed with, and the offer of shares will not be supervised by, the Swiss Financial Market Supervisory Authority FINMA (“FINMA”), and the offer of shares has not been and will not be authorized under the Swiss Federal Act on Collective Investment Schemes (“CISA”). The investor protection afforded to acquirers of interests in collective investment schemes under the CISA does not extend to acquirers of shares.

This prospectus supplement relates to an Exempt Offer in accordance with the Offered Securities Rules of the Dubai Financial Services Authority (“DFSA”). This prospectus supplement is intended for distribution only to persons of a type specified in the Offered Securities Rules of the DFSA. It must not be delivered to, or relied on by, any other person. The DFSA has no responsibility for reviewing or verifying any documents in connection with Exempt Offers. The DFSA has not approved this prospectus supplement nor taken steps to verify the information set forth herein and has no responsibility for the prospectus supplement. The shares to which this prospectus supplement relates may be illiquid and/or subject to restrictions on their resale. Prospective purchasers of the shares offered should conduct their own due diligence on the shares. If you do not understand the contents of this prospectus supplement you should consult an authorized financial advisor.

The shares may not be offered or sold by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), or

(ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap.571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap.32, Laws of Hong Kong), and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the shares are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the shares under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.

The securities have not been and will not be registered under the Financial Instruments and Exchange Law of Japan (the Financial Instruments and Exchange Law) and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Financial Instruments and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

The validity of the shares of common stock offered by this prospectus will be passed upon for Energy & Exploration Partners, Inc. by Bracewell & Giuliani LLP, Houston, Texas. Certain legal matters in connection with this offering will be passed upon for the underwriters by Mayer Brown LLP, Houston, Texas.

The audited combined financial statements of Energy & Exploration Partners, LLC, Energy & Exploration Partners, LP, Energy & Exploration Partners Operating, LP, and Energy & Exploration Partners Operating GP, LLC as of December 31, 2011 and 2010 and for each of the two years in the period ending December 31, 2011 and the audited combined and consolidated financial statements of North American Shale GP, LLC, North American Shale Investment Fund GP, LP, and North American Shale Investment Advisors, LLC as of December 31, 2011 and for the period of inception to December 31, 2011 included in this prospectus and the related registration statement have been so included in reliance upon the reports of Hein & Associates LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to the shares of our common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to us and the common stock offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of this contract, agreement or other document. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Section of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference facility. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is http://www.sec.gov.

After we have completed this offering, we will file annual, quarterly and current reports, proxy statements and other information with the SEC. After completion of this offering, we expect our website to be located at http://www.enexp.com, and we expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. You may read and copy any reports, statements or other information on file at the public reference rooms. You can also request copies of these documents, for a copying fee, by writing to the SEC, or you can review these documents on the SEC’s website, as described above. In addition, we will provide electronic or paper copies of our filings free of charge upon request.

The unaudited pro forma combined and condensed statements of financial position of Energy & Exploration Partners, Inc. (the “Company”) as of March 31, 2012 and the unaudited pro forma combined and condensed statements of operations for the year ended December 31, 2011 and the three month period ended March 31, 2012 are based upon the audited and unaudited historical combined financial statements of Energy & Exploration Partners, LLC, Energy & Exploration Partners, LP, Energy & Exploration Partners Operating, LP, and Energy & Exploration Partners Operating GP, LLC (collectively, “ENXP”) and the audited and unaudited historical combined and consolidated financial statements of North American Shale Investment Fund GP, LP, North American Shale GP, LLC, and North American Shale Investment Advisors, LLC (collectively, “NASIF”).

The assets contributed to the Company include the membership interests of Energy & Exploration Partners, LLC, North American Shale Investment Advisors, LLC, North American Shale GP, LLC and Energy & Exploration Partners Operating GP, LLC, and the partnership interests of Energy & Exploration Partners Operating, LP, North American Shale Investment Fund, LP, and North American Shale Investment Fund GP, LP. The contribution of the membership interests and partnership interests of the ENXP and the controlling and noncontrolling membership interests and partnership interests of NASIF for equity in the Company will be recorded at historical carrying value as these contributions are considered reorganizations of entities under common control.

The unaudited pro forma combined and condensed financial statements for the year ended December 31, 2011 and as of and for the three month period ended March 31, 2012 have been prepared as if the transactions to be effected at the closing of this offering occurred on March 31, 2012 in the case of the unaudited pro forma combined and condensed statement of financial position, and as of January 1, 2011 in the case of each of the unaudited pro forma combined and condensed statements of operations. The unaudited pro forma combined and condensed financial statements have been prepared based on the assumption that the Company will be treated as a C-corporation for U.S. federal and state income tax purposes and, therefore, will be subject to U.S. federal income taxes, state income taxes, and the Texas margin tax. The unaudited pro forma combined and condensed financial statements should be read in conjunction with the notes accompanying such unaudited pro forma combined financial statements and with the audited combined financial statements and the notes thereto set forth elsewhere in this prospectus.

The unaudited pro forma combined condensed statements of financial position and the unaudited pro forma combined statements of operations were derived by adjusting the audited historical combined financial statements of ENXP and NASIF. The adjustments are based upon currently available information and certain assumptions and estimates. Therefore, the actual effects of these transactions will differ from the pro forma adjustments. However, the Company’s management believes the estimates applied and the assumptions made provide a reasonable basis for the presentation of the significant effects of contemplated transactions that are expected to have a continuing impact on the Company. In addition, the Company’s management considers the pro forma adjustments to be factually supportable and to appropriately represent the expected impact of items that are directly attributable to the formation of the Company and the transfer of the contributed assets to the Company.

The unaudited pro forma combined and condensed financial statements reflect the following significant assumptions and transactions:

The unaudited pro forma combined and condensed financial statements are not necessarily indicative of the results that would have occurred if the Company had assumed the operations of ENXP on the dates indicated nor is it indicative of the future operating results of the Company. The pro forma adjustments do not include the effects of an exercise by the underwriters of their option to purchase additional common equity shares in the Company.

Upon completion of this offering, the Company anticipates that general and administrative expenses will increase as a result of being a publicly traded Company, including expenses associated with annual and quarterly reporting; tax return preparation expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees. The unaudited pro forma combined financial statements do not reflect these additional public company costs.

Because Energy & Exploration Partners, Inc. has not issued any common shares, we have not reported Pro Forma net income per share.

The following offering adjustments for the Company have been prepared as if the transactions to be effected at the closing of this offering had taken place on March 31, 2012, in the case of the unaudited pro forma combined and condensed statement of financial position as of March 31, 2012, and as of January 1, 2011 in the case of the unaudited pro forma combined and condensed statements of operations for the year ended December 31, 2011 and the three month period ended March 31, 2012, respectively:

As reported in the audited and unaudited historical combined financial statements of ENXP, on June 25, 2012, Energy & Exploration Partners, LLC assigned its interests in Energy & Exploration Partners, LP to Septa Holdings LLC. The partnership interests of Energy & Exploration Partners, LP, were not contributed to the Company. The carry value of the assets and liabilities as of March 31, 2012 and the results of operations for the year ended December 31, 2011 and the three months ended March 31, 2012, of Energy & Exploration Partners, LP included in the audited and unaudited historical combined financial statements of ENXP were de minimis. Accordingly, no adjusting entry has been presented in these unaudited pro forma combined and condensed statements to reflect that the partnership interests of Energy & Exploration Partners, LP, were not contributed to the Company.

We have audited the accompanying statement of financial position of Energy & Exploration Partners, Inc. (the “Company”) as of July 31, 2012. This financial statement is the responsibility of Company management. Our responsibility is to express an opinion on this financial statement 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 the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of their internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statement, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statement referred to above presents fairly, in all material respects, the financial position of Energy & Exploration Partners, Inc. as of July 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

Energy & Exploration Partners, Inc. (the “Company”) was formed on July 31, 2012 pursuant to the laws of the state of Delaware to become the corporate parent of Energy & Exploration Partners, LLC.

The accompanying statement of financial position has been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

Concurrent with the formation of the Company, a stock subscription was received for 1,000 shares of $0.01 par value common shares from the Chief Executive Officer for $1.00 per share. As these shares had not been funded as of July 31, 2012, the receivable for this subscription is reflected in the stockholder’s equity section of the statement of financial position.

We have audited the accompanying combined statements of financial position of Energy & Exploration Partners, LLC, Energy & Exploration Partners, LP, Energy & Exploration Partners Operating, LP, and Energy & Exploration Partners Operating GP, LLC (the “Companies”) as of December 31, 2011 and 2010, and the related statements of operations and changes in equity and cash flows for the years then ended. These financial statements are the responsibility of the Companies’ 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. The Companies are not required to have, nor were we engaged to perform, an audit of their internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Companies’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 combined financial statements referred to above present fairly, in all material respects, the financial position of Energy & Exploration Partners, LLC, Energy & Exploration Partners, LP, Energy & Exploration Partners Operating, LP, and Energy & Exploration Partners Operating GP, LLC as of December 31, 2011 and 2010, and the results of their operations and cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

Energy & Exploration Partners, LLC is a Delaware limited liability company formed on February 14, 2006 and was involved in the acquisition and sale of undeveloped oil and natural gas leasehold interests located in the United States during 2010 and 2011.

Energy & Exploration Partners, LP is a Delaware limited partnership formed on February 14, 2006 and was involved in the acquisition and sale of undeveloped oil and natural gas leasehold interests located in the United States during 2010 and 2011.

Energy & Exploration Partners Operating GP, LLC is a Texas limited liability company formed on May 18, 2011 for the purpose of being the general partner of Energy & Exploration Partners Operating, LP.

Energy & Exploration Partners Operating, LP is a Texas limited partnership and was formed on June 8, 2011. The sole asset of this entity is an operating bond with the Texas Railroad Commission. Other activity with respect to this entity was de minimis in nature.

Energy & Exploration Partners, LLC, Energy & Exploration Partners, LP, Energy & Exploration Partners Operating GP, LLC, and Energy & Exploration Partners Operating, LP are collectively referred to as “we” or the “Companies.”

As a limited liability company, the amount of loss at risk for each limited liability company member is limited to the amount of capital contributed to the limited liability company and, unless otherwise noted, the limited liability company member’s liability for indebtedness of a limited liability company is limited to the limited liability company member’s actual capital contribution. As a limited partnership, the amount of loss at risk for each limited partner is limited to the amount of capital contributed to the limited partnership and, unless otherwise noted, the limited partner’s liability for indebtedness of a limited partner is limited to limited partner’s actual capital contribution.

Beginning in the first quarter of 2012, Energy & Exploration Partners, LLC was engaged in the exploration and development of unconventional onshore oil and natural gas resources in the three core areas: (i) the Woodbine Sands and Eagle Ford Shale in East Texas (“Eaglebine”), (ii) Wolfcamp Shale in the Permian Basin in West Texas (“Wolfcamp”), and (iii) Niobrara Shale in the Denver-Julesburg Basin in Colorado and Wyoming (“Niobrara”).

The accompanying combined financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”).

The accompanying combined financial statements include the accounts of Energy & Exploration Partners, LLC, Energy & Exploration Partners, LP, Energy & Exploration Partners Operating, LP, and Energy & Exploration Partners Operating GP, LLC. These entities were wholly owned and controlled by a single individual. All significant intercompany transactions and balances have been eliminated for presentation purposes.

expenses during the reporting period. Significant estimates include leasehold interest impairment and the valuation of detachable warrants issued in conjunction with debt. Actual results could differ from those estimates and the differences could be material.

The carrying amounts of financial instruments including cash and cash equivalents, debt service and long-term deposits, prepaid expenses, accounts receivable, accounts payable, accrued liabilities, and long-term notes payable approximate fair value, unless otherwise stated, as of December 31, 2011 and 2010.

Cash equivalents are highly liquid investments purchased with an original maturity of three months or less. At times, the amount of cash and cash equivalents on deposit in financial institutions may exceed federally insured limits. Management monitors the soundness of the financial institutions and believes the Companies’ risk is negligible.

Debt service deposits consist of cash held on behalf of the Companies by their lender for the purpose of servicing its debt requirements.

The Companies acquire, aggregate, and sell undeveloped leasehold acreage to customers. Such revenues are generally recognized when the transaction is closed, proceeds are deemed collectible, and no substantial performance obligations remain related to the leasehold interests.

The Companies generate income by investing in leases alongside outside investors and through charging an incentive fee to the outside investors. The incentive fee is based on a sliding scale share of the returns based upon the performance of the investment.

Accounts receivable are uncollateralized and are generally due within 30 days of the invoice date. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. Management periodically reviews accounts receivable. The allowance for doubtful accounts is established through provisions charged against income and is maintained at a level believed adequate by management to absorb estimated bad debts based on historical experience and current economic conditions. Based on management’s review of amounts outstanding at December 31, 2011 and 2010, no reserve for allowance for doubtful accounts was considered necessary.

The Companies acquire undeveloped leasehold interests in oil and natural gas mineral rights for the purpose of selling them to third parties. All costs that are directly identifiable with acquisition of these leasehold interests are capitalized. Management reviews the carrying value of capitalized leasehold interests periodically. If permanent impairment indicators exist, the carrying value is reduced to the amount management estimates may be recovered through the sale of such assets. The Companies recorded $679,000 in leasehold abandonment expense in 2011 for leasehold interests which were deemed to be permanently impaired. No equivalent expense was noted for 2010.

In the first quarter of 2012, the Companies adopted a business strategy to develop their undeveloped leasehold acreage. At that time, the Companies elected the full cost method of accounting for oil and natural gas activities.

Furniture, fixtures, and equipment are recorded at cost less accumulated depreciation. Depreciation of the related assets is computed using the straight-line method over their respective estimated useful lives.

When assets are sold or retired, the applicable costs and accumulated depreciation are removed and any gain or loss is included in income. Maintenance and repairs are expensed as incurred. Major renewals and improvements are capitalized.

Currently, the Companies own certain computers and other office-related equipment which are being depreciated on a straight-line basis over their useful lives of five to seven years. Depreciation expense of furniture, fixtures, and equipment amounted to $29,000 and $43,000 for the years ended December 31, 2011 and 2010, respectively.

The Companies fund a portion of the undeveloped acreage acquisition costs through direct investments from outside parties who do not own an equity interest in the Companies. Instead, they own a pro-rata share in the project in which they have invested. These advances are recorded as deposits for investments on the balance sheet.

In the event a project is sold for a loss, the Companies are not obligated to reimburse investors for the loss on investment. Instead, the Companies are only required to distribute project capital recovered on a pro-rata basis. If a loss event occurs, the investor’s portion of the loss is passed to the investor by recording the remaining deposit for investment after pro-rata distributions as a reduction to the cost of sales of the lease.

The Companies sold substantially all of their leasehold interests to one customer during 2011 and 2010. Management does not believe that the loss of this purchaser would have a material adverse effect on the Companies’ results of operations or cash flows, as they believe other purchasers could be readily located.

Ninety-two percent of the Companies’ accounts receivable balance as of December 31, 2010 was outstanding to one leasehold interest. This balance was ultimately the subject of litigation and was deemed to be uncollectible and expensed during the year ended December 31, 2011.

The Companies are organized as limited liability companies or limited partnerships under state law and are treated as S corporations, partnerships, or disregarded entities for federal income tax purposes. Under this type of organization, the Companies’ earnings pass through to the equity owners in accordance with the Companies’ formation agreements and are taxed at the member level. Accordingly, no federal income tax provision has been calculated or reflected in the accompanying financial statements.

However, the Companies are subject to Texas franchise taxes on their operations within the state of Texas. The Companies accrued $29,000 and $12,000 in Texas franchise tax expense for the years ended December 31, 2011 and 2010, respectively.

The Companies have evaluated their income tax positions, noting no significant uncertain tax positions as of December 31, 2011 or 2010. No interest and penalties have been accrued or recorded.

As of December 31, 2011, the carrying basis of undeveloped oil and natural gas leasehold interests for U.S. GAAP exceeded the carrying basis for U.S. federal income tax purposes by $3.8 million.

Undeveloped oil and natural gas leasehold interests consist of leasing costs, direct labor costs, geophysical costs, legal costs, and other miscellaneous carrying costs for leaseholds located in Texas, Colorado and Wyoming. As of December 31, the carrying costs by project were as follows:

During 2011, the Companies sold leasehold interests in Wildcatter II, March Ranch, and other miscellaneous acreage for $1.1 million to oil and natural gas exploration and production companies. The cost basis of the sold properties was $556,000; therefore, a net gain of $573,000 was recognized on the sale of these properties.

During the year ended December 31, 2011, the Companies determined that their investment in one project funded through investor deposits with a carrying cost of $409,000 was unrecoverable due to an ongoing dispute with the landholder. The project was funded equally between the equity owner of the Companies and an outside investor. The Companies recognized $409,000 in abandonment expense related to this project, which was partially offset by $205,000 of pass-through loss to the outside investor.

As of December 31, the Companies held the following investor deposits relating to the acquisition of undeveloped oil and natural gas leasehold interests:

As of December 31, 2011 and 2010, the portion of the investor deposits held on behalf of related parties was $10.9 million and $664,000, respectively.

assets. This loan was amended on October 7, 2011, December 21, 2011, and March 8, 2012 to increase the principal amount of the loan to $5.0 million, $10.0 million, and $15.0 million, respectively. The note was amended again on April 19, 2012 to assign certain overriding royalty interests to the lender. Interest is due monthly and the principal is due in full at the maturity of the loan.

The loan matures on September 8, 2012 with two extension options. The Companies have the right to extend the maturity date to March 8, 2013 and June 8, 2013 in exchange for extension payments of $150,000 and $75,000 respectively. In order to extend the loan to the June 8, 2013 date, the Companies are required to repay at least $3.0 million of the principal balance outstanding prior to that date.

For the year ended December 31, 2011, the Companies recognized $156,000 in interest expense related to this note payable. The credit agreement requires compliance with certain financial covenants. As of December 31, 2011, the Companies were in compliance with these covenants. However, the Companies received notification of certain covenant violations in April 2012. A waiver was received on May 15, 2012 from the lender through May 30, 2012 in exchange for a payment of $50,000 and a requirement to maintain a drilling reserve account deposit of $2.0 million.

In conjunction with the October 7, 2011 notes payable amendment, a detachable warrant instrument was issued to the lender entitling the holder to purchase 2.5% of the diluted equity of Energy & Exploration Partners, LLC at the time of exercise in exchange for $1 at any point subsequent to October 17, 2012 until the expiration date. The expiration date of this warrant is October 7, 2018. This repurchase amount has been recorded as a discount on the notes payable and as an accrued liability based upon the Companies’ intent to exercise the buy-out option. This amount will be amortized over the life of the associated loan. On July 5, 2012, the Companies exercised their repurchase option for $125,000 and retired the detachable warrants. For the year ended December 31, 2011, the Companies recognized $52,000 as interest expense related to these instruments.

The Companies incurred $234,000 in loan origination costs for the year ended December 31, 2011. These costs were paid for fees to amend the loan agreements and as compensation to third parties for assistance in restructuring and securing the debt agreements. Amortization expense has been calculated using the effective yield method. For the year ended December 31, 2011, the Companies recognized $57,000 as interest expense.

The net cash received in association with the note payable during 2011 was as follows:

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The Companies use market data, or assumptions that market participants would use, to value the asset or liability. These assumptions include market risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.

The Companies primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. Accounting standards establish a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities, a Level 1 measurement, and lowest priority to unobservable inputs, a Level 3 measurement. The three levels of fair value hierarchy are as follows:

The Companies recorded the fair value of the detachable warrant issued in conjunction with the note payable as a discount to the face value of the note payable and as a warrant liability. The discount is being amortized over the life of the loan and is recorded as interest expense within the Statement of Operations.

Upon issuance, and as of December 31, 2011, the Companies valued the warrants based upon the cash buyout option held by the Companies of $125,000 as it was the outcome achieved with this instrument.

As of December 31, 2011, the Companies had a lease agreement related to office space. The future minimum lease payments were as follows:

The Companies from time to time are involved with various claims, lawsuits, disputes with third parties, actions involving allegations of fraud, discrimination, or breach of contract incidental to the operations of their business. The Companies are not currently involved in any litigation which they believe could have a materially adverse effect on their financial condition or results of operations.

The Companies’ operations are subject to certain environmental and remediation claims arising from federal, state, and local laws and regulations. The Companies continually monitor these risks for potential liability. As of December 31, 2011 and 2010, no such claims had been made against the Companies.

During 2011, we paid $69,000 in expenses on behalf of North American Shale Investment Fund, LP (“NASIF”). NASIF is controlled by the Companies’ equity owner. NASIF reimbursed the Companies for such costs during 2011.

During the year ended December 31, 2011, NASIF paid the Companies $34,000 in management fees due to another related entity. This amount remained as an outstanding payable as of December 31, 2011.

During the year ended December 31, 2010, the Companies paid $1.7 million in commissions related to undeveloped leasehold acreage sales to the equity owner of the Companies and family members. In addition, the Companies had $23,000 in payables outstanding related to commissions payable to related parties at December 31, 2010 which were paid in 2011.

The Companies executed a sublease agreement related to new office space on January 22, 2012. The future minimum lease payments are as follows:

On April 5, 2012, the Companies entered into a purchase and sale agreement to purchase a series of undeveloped leasehold acreage in Grimes County, Texas. The gross purchase price of this transaction was $5.3 million.

delivered a deposit of $1,000,000. On May 15, 2012, EX Operating LLC assigned all of its rights, title and interest in and to the Lease Purchase Agreement to Energy & Exploration Partners, LLC for $1,000,000, and Energy & Exploration Partners, LLC purchased the leases effective as of April 10, 2012.

On April 13, 2012, Energy & Exploration Partners, LLC terminated its election to be treated as an S corporation and became a C corporation for federal income tax reporting purposes. In addition, one outstanding membership unit of the Energy & Exploration Partners, LLC was transferred to a holding corporation controlled by the Companies’ equity owner.

On April 19, 2012, the Companies closed on a property conveyance with a third-party operator to develop the Companies’ undeveloped leasehold acreage in the Eaglebine formation. The gross proceeds of this transaction were approximately $19.9 million and the operator purchased a 65% working interest in the undeveloped leasehold acreage. An additional working interest conveyance was closed on May 23, 2012 related to the purchase of a 65% working interest in newly acquired undeveloped leasehold acreage in the same formation. The gross proceeds of this transaction were approximately $9.9 million. The third working interest conveyance of newly acquired undeveloped leasehold acreage in the same formation was closed on June 21, 2012, for gross proceeds of $4.1 million. The fourth working interest conveyance of newly acquired undeveloped leasehold acreage in the same formation was closed July 31, 2012 for gross proceeds of $3.2 million. The areas covered by the conveyances through July 31, 2012 are collectively known as Area of Mutual Interest #1 (“AMI #1”).

On June 25, 2012, Energy & Exploration Partners, LLC assigned its equity interests in Energy & Exploration Partners, LP to Septa Holdings LLC, a Texas limited liability company owned by Energy & Exploration Partners, LLC’s equity owner, for de minimis consideration.

On June 26, 2012, we closed on a $100.0 million credit facility with an initial borrowing base of $30.0 million. We initially borrowed $21.5 million under the credit facility, a portion of which was used to repay the remaining outstanding balance on the note payable described in Note 4. The credit facility bears interest at the variable rate published by the Wall Street Journal as the “Prime Rate” plus 10.0%, with a Prime Rate floor of 5.0%. The credit facility provides for the grant to the lenders of an overriding royalty interest of 5.0%, proportionally reduced to our working interest, which applies to substantially all of the Eaglebine acreage. This overriding royalty interest is reduced to 0.5%, proportionally reduced to our working interest, after the lenders receive a target internal rate of return. This overriding royalty interest is earned in increments of one twelfth times the number of wells funded by the facility up to twelve wells. Principal payments are due on a quarterly basis, beginning July 2013, with interest due on a monthly basis. The maturity date of this credit facility is December 17, 2014.

On June 29, 2012, we entered into a second agreement with the third-party operator related to a specified area of mutual interest in the Eaglebine (“AMI #2”) that is primarily located north and east of AMI #1. Pursuant to the terms of this agreement, the third-party will be the operator of interests acquired in AMI #2 and at its election will pay 100% of the leasehold costs for 80% of the working interest in leases that we acquire in AMI#2. For leases that the third-party acquires in AMI #2, we, at our election, will pay 20% of the leasehold costs for a 20% working interest.

On July 24, 2012, the Companies acquired a series of undeveloped leasehold acreage in Walker County, Texas. The gross purchase price of this transaction was approximately $2 million.

Management has evaluated subsequent events through August 1, 2012, the date these combined financial statements were available to be issued. No events or transactions other than those already described in these financials have occurred subsequent to the balance sheet date that might require recognition or disclosure in the combined financial statements.

Energy & Exploration Partners, LLC, Energy & Exploration Partners, LP, Energy & Exploration Partners Operating GP, LLC, and Energy & Exploration Partners Operating LP are collectively hereinafter referred to as “we” or the “Companies.”

The interim combined financial statements of the Companies are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented.

The accompanying unaudited interim financial statements and related notes have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Certain information and footnotes have been condensed or omitted, although we believe that the disclosures are adequate to make the information presented not misleading. These interim financial statements should be read in conjunction with the audited financial statements of the Companies for the years ended December 31, 2011 and 2010 and the notes thereto.

In February 2012, we adopted a business strategy to develop our undeveloped leasehold acreage in order to provide a greater return on our investment in those properties. At that time, we elected the full cost method of accounting for oil and natural gas activities. We recognize revenue related to oil and natural gas activities as production is extracted and sold.

In accordance with this business strategy, we are principally engaged in the exploration and development of unconventional onshore oil and natural gas resources in the three core areas: (i) the Woodbine Sands and the Eagle Ford Shale in East Texas (“Eaglebine”), (ii) Wolfcamp Shale in the Permian Basin in West Texas (“Wolfcamp”), and (iii) Niobrara Shale in the Denver-Julesburg Basin Colorado and Wyoming (“Niobrara”).

The Companies have reclassified certain prior year amounts in the accompanying financial statements to be consistent with the current year presentation.

Prior to the Companies’ change in strategy to develop our oil and natural gas leasehold acreage, the Companies acquired undeveloped leasehold interests in oil and natural gas mineral rights for the purpose of selling them to third parties. All costs that are directly identifiable with acquisition of these leasehold interests have been capitalized. Management reviews the carrying value of capitalized leasehold interests periodically. If permanent impairment indicators exist, the carrying value is reduced to the amount management estimates may be recovered through the sale of such assets.

The Companies elected the full cost method of accounting (“FCA”) for their oil and natural gas activities in February 2012. Under this method, all costs associated with the acquisition, exploration, development and abandonment of oil and natural gas properties are capitalized. Exploration costs include costs of drilling exploratory wells. The Companies will include external geological and geophysical costs, which mainly consist of seismic costs when such expenditures occur. Development costs include the cost of drilling development wells and costs of completions, facilities and pipelines. Costs associated with production and general and administrative costs are expensed in the period incurred.

Oil and natural gas properties and equipment will also include costs of unproved properties. Subsequent to the sale of interests associated with undeveloped oil and natural gas leasehold interests discussed above, the Companies will

retain their proportionate share of such costs, if any, as unproven properties until such time that such properties are evaluated and proved reserves may be assigned or until such time as the Companies make an evaluation that impairment has occurred. The Companies will include the costs of drilling exploratory dry holes in the amortization base immediately upon determination that such wells are non-commercial. Oil and natural gas properties included in the amortization base are amortized using the units-of-production method based on production and estimates of proved reserve quantities. In addition to costs associated with evaluated properties, the Companies will also include capitalized asset retirement obligations and estimated future development costs to be incurred in developing proved reserves.

Under the full cost method of accounting, the Companies will be required to periodically perform a “ceiling test” which determines a limit on the book value of its oil and natural gas properties. If the net capitalized cost of oil and natural gas properties including capitalized asset retirement costs, net of related deferred income taxes, exceeds the present value of estimated future net revenues from proved reserves discounted at 10%, plus the cost of unproved oil and natural gas properties not being amortized, plus the lower of cost or estimated fair value of unproved oil and natural gas properties included in the amortization base, net of related tax effects, the excess is charged to expense and reflected as additional accumulated depreciation, depletion, and amortization. Any such write-downs are not recoverable or reversible in future periods.

The Companies’ oil and natural gas revenues are currently sold to purchasers by the operator of the property in which we have an interest. The Companies are recognizing oil and natural gas revenues based on the quantities of our proportionate share of such production at market prices.

Undeveloped oil and natural gas leasehold interests consist of leasing costs, direct labor costs, geophysical costs, legal costs, and other miscellaneous carrying costs for undeveloped lease acreage located in Texas, Colorado and Wyoming. As of March 31, 2012 and December 31, 2011 the carrying costs by project were as follows:

As of March 31, 2012 and December 31, 2011, we held the following investor deposits:

As of March 31, 2012 and December 31, 2011, the portion of the investor deposits held on behalf of related parties was $10.9 million.

In September 2011, the Companies entered into a credit agreement for $425,000. The stated annual interest rate of this loan was 14% and was collateralized by the Companies’ undeveloped leasehold acreage and other tangible assets. This loan was amended on October 7, 2011, December 21, 2011, and March 8, 2012 to increase the principal amount of the loan to $5.0 million, $10.0 million, and $15.0 million, respectively. The note was amended again on April 19, 2012 to assign certain overriding royalty interests to the lender. Interest is due monthly and the principal is due in full at the maturity of the loan.

The loan matures on September 8, 2012 with two extension options. The Companies have the right to extend the maturity date to March 8, 2013 and June 8, 2013 in exchange for extension payments of $150,000 and $75,000, respectively. In order to extend the loan to the June 8, 2013 date, the Companies are required to repay at least $3.0 million of the principal balance outstanding prior to that date.

The credit agreement requires compliance with certain financial covenants. The Companies received notification of certain covenant violations in April 2012. A waiver was received on May 15, 2012 from the lender through May 30, 2012 in exchange for a payment of $50,000 and a requirement to maintain a drilling reserve account deposit of $2.0 million.

The Companies incurred $60,000 and $234,000 in loan origination costs during the three months ended March 31, 2012 and for the year-end 2011, respectively, for fees to amend the loan agreements and as compensation to third parties for assistance in restructuring and securing the debt agreements. Amortization expense is calculated using the effective yield method.

At March 31, 2012, the fair value of the detachable warrant issued in conjunction with the note payable was measured using Level 3 measurements, the cash buyout option held by the Companies, as it is the most likely outcome associated with this instrument. There has been no change in the fair value of the detachable warrant as of March 31, 2012.

Changes in the fair value of the detachable warrants for the three month period ended March 31, 2012 are as follows:

The following table presents the fair value of the detachable warrants as of March 31, 2012:

As of March 31, 2012 and December 31, 2011, we had a related party account payable with North American Shale Investment Fund, LP (“NASIF”) in the amount of $34,000. NASIF is controlled by the Companies’ equity owner.

The Companies owed the equity owner of the Companies $39,000 in reimbursements for general and administrative expenses as of March 31, 2012.

On April 10, 2012, EX Operating LLC, a Texas limited liability company wholly owned by a consultant of the Companies, executed a Lease Purchase Agreement to purchase certain oil and gas leases in Lynn County, Texas and delivered a deposit of $1,000,000. On May 15, 2012, EX Operating LLC assigned all of its rights, title and interest in and to the Lease Purchase Agreement to Energy & Exploration Partners, LLC for $1,000,000, and Energy & Exploration Partners, LLC purchased the leases effective as of April 10, 2012.

On April 13, 2012, Energy & Exploration Partners, LLC terminated its election to be treated as an S corporation and became a C corporation for federal income tax reporting purposes. In addition, one outstanding membership unit of Energy & Exploration Partners, LLC was transferred to a holding corporation controlled by the Companies’ equity owner.

On April 19, 2012, the Companies closed on a property conveyance with a third-party operator to develop the Companies’ undeveloped leasehold acreage in the Eaglebine formation. The gross proceeds of this transaction were approximately $19.9 million and the operator purchased a 65% working interest in the undeveloped leasehold acreage. An additional working interest conveyance was closed on May 23, 2012 related to the purchase of a 65% working interest in newly acquired undeveloped leasehold acreage in the same formation. The gross proceeds of this transaction were approximately $9.9 million. The third working interest conveyance of newly acquired undeveloped leasehold acreage in the same formation was closed on June 21, 2012, for gross proceeds of $4.1 million. The fourth working interest conveyance of newly acquired undeveloped leasehold acreage in the same formation was closed July 31, 2012 for gross proceeds of $3.2 million. The areas covered by these conveyances through July 31, 2012 are collectively known as Area of Mutual Interest #1 (“AMI #1”).

On July 24, 2012, the Companies acquired a series of undeveloped leasehold acreage in Walker County, Texas. The gross purchase price of this transaction was approximately $2 million.

We have audited the accompanying combined and consolidated statement of assets and liabilities, including the combined and consolidated schedule of investments of North American Shale Investment Fund GP, LP, North American Shale GP, LLC, and North American Shale Investment Advisors, LLC (the “Companies”) as of December 31, 2011, and the related combined and consolidated statement of operations, changes in net assets and cash flows and financial highlights for the period from February 1, 2011 (inception) through December 31, 2011. These financial statements and financial highlights are the responsibility of the Companies’ management. Our responsibility is to express an opinion on these financial statements and financial highlights 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 the financial statements are free of material misstatement. The Companies are not required to have, nor were we engaged to perform, an audit of their internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Companies’ internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the combined and consolidated financial statements and financial highlights referred to above present fairly, in all material respects, the financial position of North American Shale Investment Fund GP, LP, North American Shale GP, LLC, and North American Shale Investment Advisors, LLC as of December 31, 2011, and the results of their operations ,cash flows and financial highlights for the period from February 1, 2011 (inception) through December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.

See accompanying notes to these combined and consolidated financial statements.

North American Shale Investment Fund, LP is a Delaware limited partnership. North American Shale Investment Fund, LP’s primary business is investing in Energy and Exploration Company, LLC’s projects in three core areas: (i) the Woodbine Sands and Eagle Ford Shale in East Texas (“Eaglebine”), (ii) Wolfcamp Shale in the Permian Basin in West Texas (“Wolfcamp”) and (iii) Niobrara Shale in the Denver-Julesburg Basin Colorado and Wyoming (“Niobrara”).

North American Shale Investment Fund GP, LP, a Texas limited partnership, was formed on February 1, 2011 and is the general partner of record for North American Shale Investment Fund, LP. North American Shale Investment Fund, LP is consolidated into the financial statements of North American Shale Investment Fund GP, LP as it serves as its general partner.

North American Shale GP, LLC, a Texas limited liability company was formed on February 1, 2011 and is the general partner of record for North American Shale Investment Fund GP, LP.

Indy Exploration I, LLC, a Texas limited liability company, was formed on May 26, 2011. Indy Exploration II, LLC, a Texas limited liability company, was formed on June 13, 2011. Indy Exploration III, LLC, a Texas limited liability company, was formed on June 13, 2011. Each limited liability company is consolidated into the financial statements of North American Shale Investment Fund, LP, as it is the equity owner of each limited liability company.

The investment activities of the aforementioned entities are managed by North American Shale Investment Advisors, LLC, a Texas limited liability company, which was formed on February 1, 2011.

North American Shale Investment Fund, LP, North American Shale Investment Fund GP, LP, North American Shale Investment Advisors, LLC, North American Shale Investment Fund GP, LLC, Indy Exploration I, LLC, Indy Exploration II, LLC, and Indy Exploration III, LLC are collectively referred to as “we” or the “Companies.”

The accompanying combined and consolidated financial statements have been prepared on the basis of accounting principles generally accepted in the United States of America (“U.S. GAAP”). Under the investment-company reporting method assets and liabilities are recorded at estimated fair value, distributions are reported as income, and the change in the fair market value of investments is reported as an unrealized gain or loss on investments in the statement of operations. The statements do not include any assets, liabilities, revenues, or expenses attributable to the individual activities of the members of the Companies.

The accompanying combined and consolidated financial statements include the accounts of North American Shale GP, LLC, North American Shale Investment Fund GP, LLC, and North American Shale Investment Advisors, LLC and all consolidated entities. These entities were either wholly owned by, or under common control of, the Companies’ management. All significant intercompany transactions and balances have been eliminated for presentation purposes.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Significant estimates include the valuation of investment assets. Actual results could differ from those estimates and the differences could be material.

The Companies make direct cost investment in Energy and Exploration Partners, LLC (“ENEXP”), which is wholly owned by the controlling interest members of the Companies. The Companies do not own equity in ENEXP; rather, they own a pro-rata share in the ENEXP’s projects. In the event a project incurs a loss, ENEXP is not obligated to reimburse the Companies, although they are required to distribute capital recovered on the project on a pro-rata basis to us.

Investments are recorded at fair value. Increases and decreases in the fair value are record in the statement of operations as unrealized gain or loss on investments. We recorded $20.7 million in unrealized gains for the period from February 1, 2011 (inception) through December 31, 2011.

Financial instruments including cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities are recorded at fair value.

The Companies are organized as limited liability companies or limited partnerships under state law and are treated as partnerships, or disregarded entities for federal income tax purposes. Under this type of organization, the Companies’ earnings pass through to the equity owner in accordance with the Companies’ formation agreements and are taxed at the member level. Accordingly, no federal income tax provision has been calculated or reflected in the accompanying financial statements.

However, the Companies are subject to Texas franchise taxes on their operations within the state of Texas. For the period from February 1, 2011 (inception) through December 31, 2011, the Companies did not record any expenses or liabilities related to Texas franchise taxes due to net losses of the entity excluding unrealized gains on investments.

The Companies have evaluated their income tax positions and determined they have no significant uncertain tax positions as of December 31, 2011. No interest or penalties have been accrued or recorded.

As of December 31, 2011, the carrying basis of investments for U.S. GAAP exceeded the carrying basis for U.S. federal income tax purposes by $20.7 million.

A net investment income ratio is a metric that expresses the comparison between the income earned from investments and premiums earned. The net investment income ratio is calculated as the net asset interest holders’ pro-rata share of the income and expenses from the statement of operations, or income before unrealized loss on investments, for the reporting period divided by the net asset interest holders’ average capital balance. The expense ratio is calculated as the net asset interest holders’ pro-rata share of expenses from the statement of operations for the reporting period divided by the net asset interest holders’ average capital balance. These ratios are calculated for all net asset interest holders taken as a whole. Average net asset interest holders’ net assets are determined by taking the average of the beginning and ending net asset interest holders’ net assets balances for the period from February 1, 2011 (inception) through December 31, 2011.

For the period from February 1, 2011 (inception) through December 31, 2011 the net investment income and combined expense ratios are:

The internal rate of return (“IRR”) since inception, net of all fees, was -4% through December 31, 2011. The IRR is computed based on actual dates of cash inflows, cash outflows, and the ending net asset interest holders’ net asset account at the end of each period.

The ratio of total contributed capital to total committed capital as of December 31, 2011 was 100%.

The noncontrolling interests in the Companies represent a noncontrolling interest of 100% of the net assets of North American Shale Investment Fund, LP and are shown as a separate item in the net assets section of the statement of assets and liabilities.

The estimated fair value of the Company’s investments in undeveloped oil and natural gas leases was derived from observable market prices in the form of sales of similar assets between third parties in the approximate location of the leases (“Level 3” inputs). The Company subsequently calculated a pro-rata estimate of net proceeds using the third-party sale price, and these investments were adjusted to the calculated fair value as of December 31, 2011.

The following tables present the fair value per acre for the investment leases held and the change in fair value for the period from February 1, 2011 (inception) through December 31, 2011:

During the period from February 1, 2011 (inception) through December 31, 2011 certain expenses were paid to ENEXP, a related party, in the amount of $34,000. These expenses are reimbursable by ENEXP and are shown as an outstanding receivable from a related party as of December 31, 2011.

In accordance with the limited partnership agreement of North American Shale Investment Fund, LP, incentive allocations are paid to the general partner upon the sale of investments or withdrawal of a limited partner (“realization event”). The allocation to the general partner will equal 20% of each limited partner’s cumulative unrealized net capital appreciation. For the period from February 1, 2011 (inception) through December 31, 2011 there has been no realization event and, therefore, no incentive allocation to the general partner.

The Companies, from time to time, are involved in various claims, lawsuits, disputes with third parties, actions involving allegations of fraud, discrimination, or breach of contract incidental to the operations of its business. The Companies are not currently involved in any litigation which they believe could have a materially adverse effect on their financial condition or results of operations.

The Companies entered into a service agreement with a third party, Blue River Partners, LLC. The service contract is for a two-year term effective January 25, 2011, and the Companies are obligated to pay a monthly fee of $3,000. The agreement cannot be terminated without payment for the full term being rendered. As of December 31, 2011 the Companies had the following obligations for the remaining 13-month term of the original agreement:

Management has evaluated subsequent events through August 1, 2012, the date these combined and consolidated financial statements were available to be issued. No events or transactions other than those already described in these financials have occurred subsequent to the balance sheet date that might require recognition or disclosure in the combined and consolidated financial statements.

See accompanying notes to these combined and consolidated financial statements.

North American Shale Investment Fund, LP, North American Shale Investment Fund GP, LP, North American Shale GP, LLC, Indy Exploration I, LLC, Indy Exploration II, LLC, Indy Exploration III, LLC and North American Shale Investment Advisors, LLC are collectively referred to as “we” or the “Companies.”

The interim combined and consolidated financial statements of the Companies are unaudited and contain all adjustments (consisting primarily of normal recurring accruals) necessary for a fair statement of the results for the interim periods presented.

For the three months ended March 31, 2012 the net investment income and combined expense ratios are:

The internal rate of return (“IRR”) since inception, net of all fees, was -3% through December 31, 2011. The IRR is computed based on actual dates of cash inflows, cash outflows, and the ending net asset interest holders’ net asset account at the end of each period.

The ratio of total contributed capital to total committed capital for the periods ended March 31, 2012 and December 31, 2011 was 100%.

The estimated fair value of the Companies’ investments in undeveloped oil and natural gas leases was derived from observable market prices in the form of sales of similar assets between third parties in the approximate location of the leases (“Level 3” inputs). The Companies subsequently calculated a pro-rata estimate of net proceeds using the third-party sale price, and these investments were adjusted to the calculated fair value as of March 31, 2012.

The following tables present the fair value per acre for the investment leases held and the change in fair value for the period from December 31, 2012 through March 31, 2012:

During the period from February 1, 2011 (inception) through December 31, 2011, certain expenses were paid to ENEXP a related party, in the amount of $34,000. These expenses are reimbursable by ENEXP and is shown as an outstanding receivable from a related party as of December 31, 2011.

In accordance with the limited partnership agreement of North American Shale Investment Fund, LP, incentive allocations are paid to the general partner upon the sale of investments or withdrawal of a limited partner (“realization event”). The allocation to the general partner will equal 20% of each limited partner’s cumulative unrealized net capital appreciation. For the three-month period ended March 31, 2012 and for the period from February 1, 2011 (inception) through December 31, 2011 there has been no realization event and, therefore, no incentive allocation to the general partner.

Management has evaluated subsequent events through August 1, 2012, the date these financial statements were available to be issued. No events or transactions other than those already described in these financial statements have occurred subsequent to the balance sheet date that might require recognition or disclosure in the consolidated financial statements.

We are in the business of exploring for and producing oil and natural gas. Oil and natural gas exploration is a specialized industry. Many of the terms used to describe our business are unique to the oil and natural gas industry. The following is a description of the meanings of some of the oil and natural gas industry terms used in this document.

Area of mutual interest or AMI. A geographic location in which more than one oil and/or natural gas company has a stake. The area of mutual interest is defined by the contract that describes the geographic area contained in the area of mutual interest, the rights each party has (such as the percentage of interest allocated to each company), the length of time during which the contract will be in effect, and how the contract provisions are to be implemented.

Analogous reservoir. Analogous reservoirs, as used in resource 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, analogous reservoir refers to a reservoir that shares all of the following characteristics with the reservoir of interest: (i) the same geological formation (but not necessarily in pressure communication with the reservoir of interest; (ii) the same environment of deposition; (iii) similar geologic structure; and (iv) the same drive mechanism.

Basin. A large natural depression on the earth’s surface in which sediments accumulate.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of oil or other liquid hydrocarbons.

Boe. Barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of oil or natural gas.

Deterministic method. 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.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Capital costs incurred in the acquisition, exploration, development and revisions of proved oil and natural gas reserves divided by proved reserve additions.

Development well. A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Economically producible or viable. The term economically producible or economically viable, as it relates to a resource, means a resource that 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 natural gas producing activities.

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

Exploitation. Optimizing oil and natural gas production from producing properties or establishing additional reserves in producing areas through additional drilling or the application of new technology.

Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Held- by-production acreage. Acreage covered by a mineral lease that perpetuates a company’s right to operate a property as long as the property produces a minimum paying quantity of oil or gas.

Horizontal well. A well in which a portion of the well has been drilled horizontally within a productive or potentially productive formation. This operation usually results in the ability of the well to produce higher volumes than a vertical well drilled in the same formation.

Hydraulic fracturing (or fracking). The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

Injection. A well which is used to place liquids or natural gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.

Overriding royalty interest. A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of the oil or natural gas, produced from a specified tract or tracts, which is limited in duration to the terms of an existing lease and which is not subject to any portion of the expense of development, operation or maintenance.

Pad. A temporary drilling location generally consisting of 4-5 acres that is cleared, leveled and surfaced over for siting a drilling rig, trucks and various other equipment required for drilling and completion activities.

Probabilistic method. 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.

Productive well. A well that is producing or is capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved oil and natural gas reserves or Proved reserves. Proved oil and natural gas reserves are those quantities of oil and natural 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 regulation 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 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.

The area of the reservoir considered as proved includes all of the following: (i) the area identified by drilling and limited by fluid contacts, if any; and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil and natural gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil 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.

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: (i) 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 (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the twelve-month first day of the month historical average price during the twelve-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.

Proved undeveloped reserves. Proved undeveloped oil and natural gas reserves are reserves 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. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves will not 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 tests in the area and in the same reservoir.

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 with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.

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.

Reserves. Reserves are estimated remaining quantities of oil and natural 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 natural gas or related substances to market and all permits and financing required to implement the project.

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

Resource play. These plays develop over long periods of time, well-by-well, in large-scale operations. They typically have lower than average long-term decline rates and lower geological and commercial development risk than conventional plays. Unlike most conventional exploration and development, resource plays are relatively predictable in timing, costs, production rates and reserve additions which can provide steady long-term reserves and production growth.

Resources. Resources are quantities of oil and natural 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 unrecoverable. Resources include both discovered and undiscovered accumulations.

Stratigraphic horizon. A sealed geologic container capable of retaining hydrocarbons that was formed by changes in rock type or pinch-outs, unconformities, or sedimentary features such as reefs.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas regardless of whether or not such acreage contains proved reserves.

Undeveloped oil and natural gas reserves or Undeveloped reserves. Undeveloped oil and natural 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. 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. 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. 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, or by other evidence using reliable technology establishing reasonable certainty.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

Workover. The repair or stimulation of an existing production well for the purpose of restoring, prolonging or enhancing the production of hydrocarbons.

No action is being taken in any jurisdiction outside the United States to permit a public offering of the common stock of possession or distribution of this prospectus supplement and the accompanying prospectus in that jurisdiction. Persons who come into possession of this prospectus supplement and the accompanying prospectus in jurisdictions outside the United States are required to inform themselves about and to observe any restrictions as to this offering and the distribution of this prospectus supplement and the accompanying prospectus applicable to that jurisdiction.

The following table sets forth an itemized statement of the amounts of all expenses (excluding underwriting discounts) payable by us in connection with the registration of our common stock offered hereby. With the exception of the Registration Fee, FINRA Filing Fee and New York Stock Exchange listing fee, the amounts set forth below are estimates.

Our amended and restated certificate of incorporation will provide that a director will not be liable to the corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (1) for any breach of the director’s duty of loyalty to the corporation or its stockholders, (2) for acts or omissions not in good faith or which involved intentional misconduct or a knowing violation of the law, (3) under section 174 of the DGCL for unlawful payment of dividends or improper redemption of stock or (4) for any transaction from which the director derived an improper personal benefit. In addition, if the DGCL is amended to authorize the further elimination or limitation of the liability of directors, then the liability of a director of the corporation, in addition to the limitation on personal liability provided for in our certificate of incorporation, will be limited to the fullest extent permitted by the amended DGCL.

Section 145 of the DGCL provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses, including attorneys’ fees, judgments, fines and amounts paid in settlement in connection with specified actions, suits and proceedings whether civil, criminal, administrative, or investigative, other than a derivative action by or in the right of the corporation, if they acted in good faith and in a manner they reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful. A similar standard is applicable in the case of derivative actions, except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation. The statute provides that it is not exclusive of other indemnification that may be granted by a corporation’s certificate of incorporation, bylaws, disinterested director vote, stockholder vote, agreement or otherwise.

Our amended and restated certificate of incorporation and bylaws will contain indemnification rights for our directors and our officers. Specifically, our amended and restated certificate of incorporation and amended and restated bylaws will provide that we shall indemnify, and advance expenses to, our officers and directors to the fullest extent authorized by the DGCL.

We will enter into written indemnification agreements with our directors and officers. Under these proposed agreements, if an officer or director makes a claim of indemnification to us, either a majority of the independent directors or independent legal counsel selected by the independent directors must review the relevant facts and make a determination whether the officer or director has met the standards of conduct under Delaware law that would permit (under Delaware law) and require (under the indemnification agreement) us to indemnify the officer or director.

Further, we may maintain insurance on behalf of our officers, and directors against expense, liability or loss asserted incurred by them in their capacities as officers and directors, and on behalf of some of our employees for certain liabilities.

In connection with our formation on July 31, 2012, we issued 1,000 shares of our common stock, par value $0.01 per share, to Hunt Pettit in exchange for consideration of $1,000. The issuance of these shares did not involve any underwriters, underwriting discounts or commissions, or any public offering, and we believe the issuance was exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereunder.

A list of exhibits filed as part of this registration statement is set forth in the Index to Exhibits, which is incorporated herein by reference.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement on Form S-1 to be signed on its behalf by the undersigned, thereunto duly authorized in the City of Fort Worth, State of Texas, on August 3, 2012.

Pursuant to the requirements of the Securities Act of 1933, this registration statement on Form S-1 has been signed by the following persons in the capacities and on the date indicated.

This Purchase and Sale Agreement (this “Agreement”), dated effective as of March 5, 2012 (the “Execution Date”), is by and between Energy & Exploration Partners, LLC, a Delaware limited liability company (“Seller”), and RWG Energy, Inc., a Delaware corporation (“Buyer”). Seller and Buyer are sometimes referred to herein individually as a “Party” and collectively as the “Parties”.

WHEREAS, Seller owns or intends to acquire the Properties (as defined below) and desires to sell the Properties to Buyer, and Buyer desires to purchase the Properties from Seller, upon the terms and conditions set forth herein.

NOW THEREFORE in consideration of the mutual covenants contained in this Agreement and other valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Buyer and Seller agree as follows:

(a) an undivided sixty-five percent (65%) (of 8/8ths) interest in and to the oil and gas leases described more particularly on Exhibit A and the leasehold estates created thereby, as to all lands and depths covered thereby or the applicable part or portion thereof if specifically limited in depth and/or geographic extent in Exhibit A (collectively, the “Initial Leases”), together with any and all other rights, interests, privileges, benefits, and powers of any kind or character conferred upon Seller as the owner of any of such interests;

(b) an undivided sixty-five percent (65%) (of 8/8ths) interest in and to all crude oil, natural gas, condensate, distillate, natural gasoline, natural gas liquids, plant products, and other liquid or gaseous hydrocarbons, the right to explore for which, or an interest in which, is granted pursuant to the Initial Leases (“Hydrocarbons”) and that are produced from or allocable to such interests of Assignor from and after the Effective Time;

(c) an undivided sixty-five percent (65%) (of 8/8ths) interest in and to all other economic benefits of every kind and character attributable to the owner of the Initial Leases that accrue on and after the Effective Time;

(d) an undivided sixty-five percent (65%) (of 8/8ths) interest in and to all wellbores (whether active, inactive, or plugged and abandoned), equipment, machinery, fixtures, and other real, personal, and mixed property (if any), movable or immovable, and whether located on or off the lands covered by the Initial Leases to the extent used in connection with or attributable to the interests of Seller described in clause (a) of this Section 1 (except for any such personal property leased from third Persons); and

(e) an undivided sixty-five percent (65%) (of 8/8ths) interest in and to all intangible rights, inchoate rights, transferable rights under warranties made by prior owners, manufacturers, vendors, and third Persons, and rights accruing under applicable statutes of limitation or prescription, insofar only as the foregoing rights and interests relate or are attributable to the items listed in this Section 1.

Seller and Buyer acknowledge and agree that Seller: (i) originally acquired an undivided 100% (of 8/8ths) Working Interest (as hereinafter defined) in and to each of the Initial Leases; (ii) previously assigned an aggregate undivided one percent (1%) (of 8/8ths) Working Interest in and to the Initial Leases to Petro Capital XXV, LLC, and PetroStone, LLC (collectively, “Petro Capital”); (iii) has an agreement with Petro Capital, pursuant to which, prior to the First Closing, Petro Capital shall re-assign to Seller all of its Working Interests in the Initial Leases in exchange for an overriding royalty interest such Initial Leases (the “Converted PC ORRI”); and (iv) intends to deliver to Buyer at Closing (and notwithstanding the Converted PC ORRI) not less than an undivided 75% Net Revenue Interest (as hereinafter defined) (calculated based on a 100% Working Interest) in each Initial Lease. Petro Capital will have no right to receive any Working Interests in the Supplemental Leases. To the extent that one or more Supplemental Leases (as hereinafter defined) become additional Initial Leases under Section 2 below, then Seller shall retain an undivided 35% (of 8/8ths) Working Interest therein, and shall sell and convey to Buyer an undivided 65% (of 8/8ths) Working Interest therein. Notwithstanding anything stated herein to the contrary, the “Initial Properties” shall not include (and Buyer shall not assume or be responsible for any Liabilities or obligations in, under, or related to) any contract or agreement between Seller and Petro Capital or any Affiliate thereof. To the extent that any oil and gas lease that would otherwise constitute an Initial Lease for purposes of this Agreement is excluded in its entirety from this Agreement by operation of Section 19 or Section 20, such oil and gas lease shall no longer constitute a Lease for purposes hereof.

(a) From and after the Execution Date and continuing until the date that is sixty (60) days after the First Closing Date (as hereinafter defined) (the “Supplemental Acquisition Period”), Seller shall have the right to acquire additional oil and gas leases that, upon their acquisition, will become subject to the terms of this Agreement, to the extent and only to the extent that: (i) all such additional oil and gas leases cover lands located within the boundaries of the AMI (as described in Section 5 below); (ii) such oil and gas leases have not less than a 75% Net Revenue Interest (calculated based upon a 100% Working Interest); (iii) Seller has provided Buyer with written notice of Seller’s acquisition of such additional oil and gas lease prior to the expiration of the Supplemental Acquisition Period, containing (A) copies of the additional oil and gas lease(s) acquired, (B) any ownership and/or title opinions or reports covering the surface and/or mineral estates of the acreage leased, and (C) a statement of the Net Mineral Acres covered thereby, as well as the Net Revenue Interest and Working Interest attributable to such additional oil and gas leases; and (iv) Buyer expressly approves the inclusion in this Agreement of such additional oil and gas leases. Additional oil and gas leases that meet all of the above conditions are referred to herein, collectively, as “Supplemental Leases”

and, individually, a “Supplemental Lease”. To the extent any Supplemental Leases are acquired by Seller prior to the date that is ten (10) days prior to the First Closing (“Initial Cut Off Date”), then such Supplemental Leases shall be added to the Initial Leases for purposes of Section 1, and the undivided interest therein set forth in Section 1(a) (together with the other related interests described in clauses (b), (c), (d), and (e) of Section 1) shall be sold and conveyed to Buyer as part of the Initial Properties at the First Closing pursuant to the other terms and conditions of this Agreement. If an oil and gas lease that would otherwise constitute an Initial Lease for purposes of this Agreement is withheld from the First Closing pursuant to Section 19(a)(ii), such oil and gas lease, to the extent it is not ultimately excluded from this Agreement by operation of Section 19(a)(ii), shall be treated, for all purposes hereof, as a Supplemental Lease.

(b) To the extent that any Supplemental Leases are acquired by Seller after the Initial Cut Off Date and prior to the expiration of the Supplemental Acquisition Period, then there shall be a supplemental closing (the “Supplemental Closing”) on a date mutually agreed to by the Parties, but in no event later than ninety (90) days after the expiration of the Supplemental Acquisition Period (the “Supplemental Closing Date”), at which time, subject to the terms and conditions hereof, Seller shall sell and convey to Buyer an undivided interest identical to that set forth in Section 1(a) in and to such Supplemental Leases, as well as the interests related thereto identical to those described in clauses (b), (c), (d), and (e) of Section 1, and otherwise on the terms set forth in this Agreement (collectively, the “Supplemental Properties”). For purposes hereof, each Initial Lease and each Supplemental Lease may be referred to herein, individually, as a “Lease” and, collectively, as the “Leases”; and each Initial Property and each Supplemental Property may be referred to herein, individually, as a “Property” and, collectively, as the “Properties.” Except with regard to the Supplemental Purchase Price paid by Buyer to Seller pursuant to Section 3(c), Buyer shall have no responsibility for (and Seller, alone, shall bear and pay) any acquisition costs related to the Supplemental Properties.

(c) If Buyer fails or refuses to approve the inclusion in this Agreement of additional oil and gas leases covering lands located within the AMI acquired by Seller during the Supplemental Acquisition Period pursuant to Section 2(a), Seller shall be free to own and hold such additional oil and gas lease(s) for its own account and at Seller’s sole cost and expense, free and clear of the terms of this Agreement, including those relating to the AMI, to the extent that such additional oil and gas leases have a Net Revenue Interest (calculated based on a 100% Working Interest) of not less than 75%. During the Supplemental Acquisition Period, Seller shall have no right to acquire any oil and gas leases within the AMI that have a Net Revenue Interest (calculated based on a 100% Working Interest) of less than 75%.

(a) The total consideration for the sale of the Properties (the “Consideration”) shall be the sum of (i) the Initial Purchase Price and the Supplemental Purchase Price, as defined hereinafter, paid by Buyer to Seller for the Properties delivered by Seller to Buyer at the First Closing and the Supplemental Closing (collectively, the “Purchase Price”), plus (ii) the Contingent Payment, if any, to be paid in accordance with Section 4 below.

(b) On the First Closing Date, Buyer shall pay to Seller, as the “Initial Purchase Price”, an amount calculated as described on Exhibit E attached hereto. The Initial Purchase Price shall be subject to increase if any Supplemental Leases are included in the Initial Properties pursuant to Section 2(a) and subject to further adjustment pursuant to Section 17.

(c) If the Supplemental Closing occurs, then on the Supplemental Closing Date, Buyer shall pay to Seller, as the “Supplemental Purchase Price”, an amount calculated with respect to the Supplemental Properties in the same manner as the Initial Purchase Price, subject to adjustment pursuant to Section 17.

(a) At the First Closing, the Parties shall execute and deliver one or more Joint Operating Agreement(s), prepared using the A.A.P.L. 1989 Model Form of Operating Agreement modified as may be mutually agreed by Seller and Buyer prior to the First Closing, covering the Parties’ respective interests in and to the Initial Properties (as amended at the Supplemental Closing to cover the Supplemental Properties, if any) (the “JOA”). The JOA shall contain a provision whereby if the interests retained by Seller are ever held by a total of more than three (3) Persons, other than Seller, simultaneously, such interest holders shall be required to appoint a single Person as agent to administer such interests collectively, on behalf of all such interest holders, including, without limitation, for purposes of receiving notices, making elections (collectively), making payments, receiving revenues, and under other matters contemplated under the JOA; and Buyer, as Operator, shall not be required to look to any other interest owner, and any election by, notice by or to, or payment to such appointed agent, or other action taken by such agent in connection with such interests, shall be binding on all interest holders. Buyer or its Affiliate shall be designated Operator under the JOA. Except as otherwise provided in this Agreement, all operations conducted on the Properties from and after the applicable Closing shall be governed by the JOA.

(b) Subject to the terms of this Section 4 and the JOA, on or before the expiration of twelve (12) months after the First Closing Date, Buyer, as Operator under the JOA, agrees to commence, or to cause to be commenced, the actual drilling (either vertically or horizontally, as Buyer may determine) of not less than two (2) wells in search of Hydrocarbons at legal locations selected by Buyer on the Properties. Thereafter, Buyer shall cause both of such wells to be drilled to a vertical depth and/or horizontal extent, as applicable, sufficient to test the respective target subsurface intervals selected by Buyer (in each case, the “Target Depth”), tested, and either plugged and abandoned in the case of a dry hole, or completed (including the performance of hydraulic fracturing or other formation stimulation operations) and equipped for production (including the installation of production facilities). For purposes of this Agreement, such initial two (2) wells located on the Properties shall be referred to as the “Commitment Wells”. Seller agrees to participate with Buyer in such drilling, testing,

and plugging and abandonment or completion and equipping for production operations in or with respect to the Commitment Wells in accordance with the terms of this Section 4. If the aggregate costs attributable to the drilling, testing, and plugging and abandonment or completion and equipping for production of the two Commitment Wells do not exceed the Aggregate CW Amount (as defined below), there shall be no further approvals, AFEs, or consents required from Seller in connection therewith; and Seller shall pay its Ownership Percentage of the costs and expenses actually incurred by Buyer in connection with the drilling, testing, completion and equipping for production or plugging and abandonment of the Commitment Wells within fifteen (15) days after Seller’s receipt of each invoice therefor from Buyer; provided, however, that if the aggregate costs and expenses (on a 100% Working Interest basis) of incurred by Buyer in connection with the drilling, testing, and plugging and abandonment or completion and equipping for production of the Commitment Wells exceeds the sum of $20,000,000 (the “Aggregate CW Amount”), the authority of Buyer, as Operator, to incur, on behalf of the joint account, and the obligation of Seller to participate in and pay its Ownership Percentage of, any of such costs attributable to the two Commitment Wells in excess of the Aggregate CW Amount shall be subject to the well operation approval procedures in Article VI of the JOA by the Working Interest owners.

(c) Once the drilling of each Commitment Well has been commenced, Buyer shall cause all operations conducted in such Commitment Well to be prosecuted with diligence and in a workmanlike manner consistent with the practices of a reasonably prudent operator. During all operations in the Commitment Wells conducted by Buyer pursuant to this Agreement, Buyer shall comply with all of the terms, covenants, and conditions, either expressed or implied, set forth in the Leases, this Agreement, the JOA (to the extent not inconsistent with this Agreement), and all applicable Laws. Until the earlier of (i) the drilling and completion (or plugging and abandonment) of the two Commitment Wells, or (ii) the date that is twelve (12) months after the First Closing Date, Seller shall not have the right to propose any new well under any JOA.

(d) If Operator is unable to reach the Target Depth in a Commitment Well, or having reached the Target Depth, is unable to complete a Commitment Well because of subsurface conditions or formations, including, without limitation, heaving shale, domal formations, or excessively high pressure water sands or cavities, that would render further drilling operations by a prudent operator impracticable, or because of mechanical conditions in such Commitment Well beyond Buyer’s control, Buyer shall be entitled to plug and abandon the relevant Commitment Well and restore the drillsite premises thereof in accordance with the terms of the applicable Lease(s) and all applicable Laws.

(e) As between the Parties, the decision whether to attempt to complete a Commitment Well as a producer of Hydrocarbons shall be determined by Buyer acting as a reasonably prudent operator, and subject to the restrictions regarding the Aggregate CW Amount limitation set forth above in Section 4(b), there shall be no separate election for Seller whether to participate in such a completion attempt. If Buyer elects not to attempt to complete, or unsuccessfully attempts to complete, a Commitment Well as a producer of Hydrocarbons, Buyer shall plug and abandon the relevant Commitment Well and restore the drill site premises thereof, for the joint account, in accordance with the terms

of the applicable Lease(s) and applicable Laws. If Buyer plugs and abandons a Commitment Well pursuant to Section 4(d) or this Section 4(e), Buyer shall be deemed to have satisfied and discharged in full its obligations under this Agreement with respect to such Commitment Well. Similarly, if Seller pays Buyer its Ownership Percentage of the applicable costs thereof, then subject to the restrictions regarding the Aggregate CW Amount set forth above in Section 4(b), Seller shall be deemed to have satisfied and discharged in full its obligations under this Agreement with respect to such Commitment Well.

(f) All costs and expenses incurred by Buyer in connection with the drilling, testing, and plugging and abandonment as a dry hole or completion (including the performance of hydraulic fracturing or other formation stimulation operations) and equipping for production (including the installation of production facilities) of the Commitment Wells shall be borne and paid by Seller and Buyer, in accordance with their respective Ownership Percentages.

(g) If Buyer (i) commences the actual drilling of both Commitment Wells in a timely manner as provided in Section 4(b) and (ii) successfully completes both Commitment Wells as Commercial Wells, Buyer shall pay to Seller, no later than thirty (30) days after the commencement of Hydrocarbon production from the second Commitment Well, an amount calculated as described on Exhibit E attached hereto as the “Contingent Payment”. If Buyer fails to pay the Contingent Payment to Seller in a timely manner under this Section 4(g), Buyer shall be deemed to have withdrawn from, and terminated its participation in, the Properties and the AMI in accordance with Section 4(i).

(h) If (i) Buyer fails to commence the actual drilling of both Commitment Wells in a timely manner as provided in Section 4(b), or (ii) (A) Buyer commences the actual drilling of both Commitment Wells in a timely manner as provided in Section 4(b), but (B) one or both Commitment Wells is not completed as a Commercial Well, then Buyer shall have the option either (1) to pay to Seller the Contingent Payment, in which case Seller and Buyer would remain co-owners of the Properties subject to the terms of this Agreement and the applicable JOA(s), or (2) not to pay the Contingent Payment to Seller, in which case Buyer shall be deemed to have withdrawn from, and terminated its participation in, the Properties and the AMI in accordance with the terms of Section 4(i). Buyer shall exercise such option by written notice given to Seller (x) in the case of a notice given pursuant to clause (i) of this Section 4(h), no later than the expiration of twelve (12) months after the First Closing Date, or (y) in the case of a notice given pursuant to clause (ii) of this Section 4(h), no later than the earlier of (x) thirty (30) days after either the commencement of Hydrocarbon production from, or the completion of plugging and abandonment and surface restoration operations in or with respect to, the second Commitment Well, or (y) the expiration of twelve (12) months after the First Closing Date. Payment of the Contingent Payment shall be made concurrently with Buyer’s delivery of its notice under clause (1) of the first sentence of this Section 4(h). A written notice of election by Buyer to pay the Contingent Payment to Seller that is unaccompanied by such payment shall be deemed to be an election by Buyer to withdraw from, and terminate its participation in, the Properties and the AMI in accordance with the terms of Section 4(i).

(i) If Buyer elects, or is deemed to have elected, to withdraw from and terminate its participation in the Properties and the AMI pursuant to Section 4(h), Buyer shall be deemed to have forfeited its rights in and to the Properties, the Commitment Wells and the AMI and, for no additional consideration, Buyer shall re-assign and re-transfer to Seller all of the rights, titles, and interests in and to the Properties conveyed by Seller to Buyer pursuant to Section 2, the Commitment Wells, and any Mineral Interests acquired by the Parties within the AMI pursuant to Section 5, free and clear of all Liens against, and all overriding royalties, production payments, net profits interests, and other burdens upon, measured by, or payable out of production, created in each case by, through, or under Buyer. Such re-conveyance shall be pursuant to a form of assignment, reasonably acceptable to Seller and Buyer (and also executed by Seller), and shall provide for a special warranty of title by Buyer but for no other representations or warranties of any kind from Buyer, and state that such Properties and Mineral Interests are being re-assigned to Seller in their “AS IS, WHERE IS, WITH ALL FAULTS” condition. Such assignment shall also provide that Seller shall assume, agree to be bound by, and shall indemnify, defend, release, and hold Buyer and its Indemnity Group harmless from, all Claims and Liabilities that are associated with, arise out of, or relate to the ownership and operation of such Properties and Mineral Interests for the period from and after the effective date of such reassignment. Nothing contained in this Agreement shall relieve Buyer of Liability or responsibility for, and Buyer shall indemnify, defend, release, and hold Seller and its Indemnity Group harmless from and against, any of the Assumed Liabilities and Buyer’s Ownership Percentage of any other Claims or Liabilities associated with, arising out of, or relating to the ownership of such Properties or Mineral Interests, to the extent that the acts, omissions, events, or conditions giving rise to such Assumed Liabilities or other Claims or Liabilities arose, occurred, or came into existence after the Effective Time and prior to the effective date of such reassignment. Upon the execution and delivery of such reassignment by Buyer to Seller, this Agreement shall be deemed to have terminated, subject to the terms of Section 16. This Section 4(i) represents the sole and exclusive remedy of Seller with regard to any failure by Buyer to perform its obligations under this Section 4 relating to the Commitment Wells and the Contingent Payment, and Buyer shall have no other obligation or Liability with regard thereto.

(j) If Seller fails to pay in full when due any properly invoiced amount regarding the drilling, testing, completion and equipping for production or plugging and abandonment of any Commitment Well, up to the Ownership Percentage of Seller of the Aggregate CW Amount, Buyer shall provide to Seller written notice of such failure to pay. If Seller fails to make the required payment within five (5) Business Days after Seller’s receipt of such notice of non-payment from Buyer, Seller shall be deemed to have forfeited to Buyer all rights, titles, and interests of Seller in the Properties and Commitment Wells, and shall have forfeited and waived any rights to the Contingent Payment or any other rights under Section 2(b) or otherwise under this Agreement (including, without limitation, the AMI). Seller shall immediately assign (for no consideration) to Buyer all of the rights, titles, and interests of Seller in and to the Leases,

the Commitment Wells, and any Mineral Interests acquired by the Parties within the AMI pursuant to Section 5, free and clear of any and all Liens against, and all overriding royalties, production payments, net profits interests, and other burdens upon, measured by, or payable out of production, created in each case by, through, or under Seller. Such assignment shall be pursuant to a form of conveyance containing a special warranty of title and that is otherwise reasonably acceptable to Seller and Buyer. Nothing contained in this Agreement shall relieve Seller of Liability or responsibility for, and Seller shall indemnify, defend, release, and hold Buyer and its Indemnity Group harmless from and against, the Retained Liabilities and Seller’s Ownership Percentage of any other Claims and Liabilities associated with, arising out of, or relating to the ownership of such Leases or Mineral Interests, to the extent that the acts, omissions, events, or conditions giving rise to such other Claims or Liabilities arose, occurred, or came into existence after the Effective Time and prior to the effective date of such assignment. Upon the execution and delivery of such assignment by Seller to Buyer, this Agreement shall be deemed to have terminated, subject to the terms of Section 16. If Seller fails to pay in full when due any properly invoiced amount relating to the drilling, testing, and completion and equipping for production or plugging and abandonment of any Commitment Well that is in excess of the their Ownership Percentages of Aggregate CW Amount and has been consented to by Seller, Buyer, as Operator under the applicable JOA, shall have the remedies set forth in Article VII.B of the JOA.

(k) If, as the result of Force Majeure, Buyer either (i) fails to commence the actual drilling of both Commitment Wells on or before the expiration of twelve (12) months after the First Closing Date, or (ii) fails to complete and equip for production one or both Commitment Wells during such twelve-month period, the deadlines for Buyer’s payment of the Contingent Fee under Section 4(g) and for Buyer’s election whether to pay the Contingent Fee under Section 4(h) shall be extended after expiration of the twelve (12) months after the First Closing Date, in each case, for a period of thirty (30) days following the resolution or removal of the Force Majeure. For purposes hereof, the term “Force Majeure” shall be defined as set forth in Article XI of the JOA.

(l) Except as otherwise provided in the last sentence of Section 4(c), nothing contained in this Agreement shall prevent or restrict either Seller or Buyer from proposing or participating in the drilling of, or other operations conducted in or with respect to, wells located on the Properties in addition to the Commitment Wells subject to the terms of the JOA; provided, however, that during the first calendar year following the First Closing Date, neither Buyer nor Seller shall propose AFEs (as contemplated under the JOA) for drilling operations (whether as part of the two Commitment Wells or one or more subsequent wells under the JOA) in excess of $100,000,000.00 (on an 8/8ths basis), in the aggregate, relative to the Properties. From and after such first calendar year after the First Closing Date, there shall be no restrictions on the wells and operations that may be proposed under the JOA.

(a) Buyer and Seller designate the outlined areas in Madison, Grimes and Walker Counties, Texas, on the attached Exhibit C as the area of mutual interest

(“AMI”). Subject to the restrictions described in this Agreement, from and after the expiration of the Supplemental Acquisition Period and continuing thereafter until the third (3^rd) anniversary of the Supplemental Closing Date (the “AMI Term”), the acquisition by Seller, any Affiliate of Seller, Buyer, or any Affiliate of Buyer of any oil, gas and mineral lease, mineral fee interest, royalty, overriding royalty, net profits interest, production payment, or other mineral interest located in, or covering lands in, the AMI (collectively, the “Mineral Interests” and, individually, a “Mineral Interest”) shall be governed by the terms and provided hereinafter in this Section 5. Prior to the expiration of the Supplemental Acquisition Period, Buyer agrees not to acquire, or to negotiate for the acquisition of, any Mineral Interests within the AMI.

(b) The AMI shall remain in force and effect for the AMI Term, unless sooner terminated by the Parties.

(c) During the AMI Term, if any Party or any Affiliate of any Party (“Acquiring Party”) contracts to acquire any Mineral Interest which affects lands and minerals lying within the AMI, the Acquiring Party shall promptly advise the other Party (“Offeree”) of such acquisition. In such event, Offeree shall have the right to acquire its Ownership Percentage of such Mineral Interest in accordance with the other provisions of this Section 5.

(d) Promptly upon contracting to acquire a Mineral Interest (but not more than ten (10) Business Days prior to the acquisition thereof), the Acquiring Party shall, in writing, advise the Offeree of such acquisition. The notice shall include a copy of all instruments of acquisition, including, by way of example but not of limitation, copies of the leases, deeds, assignments, subleases, farmouts, or other contracts or instruments affecting the Mineral Interest. The Acquiring Party shall also enclose with such notice an itemized statement of the acquisition costs related thereto (including, without limitation, the purchase price, lease bonus, engineering costs, environmental consulting costs, title examination costs, other legal costs, land services costs, due diligence costs, brokerage or finders fees, recordation costs, and any and all other direct costs and expenses incurred in connection with the evaluation and acquisition of such Mineral Interest (collectively, the “Acquisition Costs”). Offeree shall have a period of ten (10) days after receipt of the notice within which to furnish to the Acquiring Party written notice of its election whether to acquire its Ownership Percentage of the offered Mineral Interest on the same terms and conditions on which the Acquiring Party is acquiring them (except as expressly set forth otherwise herein). If, however, a well in search of oil or gas is being drilled within the AMI or at a location outside the AMI, the result of which could be expected to materially affect the value of the offered Mineral Interest, Offeree shall have a period of twenty-four (24) hours (exclusive of Saturday, Sunday and legal holidays) after receipt of the notice within which to elect to acquire its Ownership Percentage of the Mineral Interest so offered; provided that such twenty-four (24) hour (exclusive of Saturday, Sunday and legal holidays) election period shall not apply unless the Acquiring Party gives the notice to the Offeree within twenty-four (24) hours (exclusive of Saturday, Sunday and legal holidays) after the date on which the Acquiring Party executed the contract to acquire the Mineral Interest so offered. In addition thereto, the Acquiring Party shall also:

The information in clauses (i) and (ii) above shall be in addition to the information and copies of instruments provided for in connection with the usual notices of acquisition of a Mineral Interest given under this Section 5(d).

(e) If the Acquiring Party shall not have received actual written notice of the election of the Offeree to acquire its Ownership Percentage of the offered Mineral Interest within the applicable ten (10) day or twenty-four (24) hour (exclusive of Saturday, Sunday and legal holidays) period, as the case may be, such failure shall constitute an election by Offeree not to acquire its Ownership Percentage of the offered Mineral Interest. Offeree, if accepting the offered Mineral Interest, shall be entitled to participate to the extent of its Ownership Percentage in such Mineral Interest acquired by the Acquiring Party. If Offeree elects to participate in the offered Mineral Interest, then promptly after the expiration of the election period, the Acquiring Party shall invoice Offeree for its Ownership Percentage of the Acquisition Costs and, if Seller is the Acquiring Party, an additional fee of equal to the product of $100.00 per Net Mineral Acre, by (ii) the actual number of Net Mineral Acres attributable to the portion of the Mineral Interest actually conveyed and delivered to Buyer in connection therewith (the “Seller Acquisition Fee”). Offeree shall immediately reimburse the Acquiring Party for (i) its Ownership Percentage of the Acquisition Costs, as reflected by the invoice, and (ii) if Seller is the Acquiring Party, the full amount of the Seller Acquisition Fee. Upon receipt of such reimbursement, the Acquiring Party shall execute and deliver to Offeree an assignment in form and substance acceptable to both Parties of Offeree’s Ownership Percentage of the Mineral Interest acquired by the Acquiring Party, and Offeree shall execute such other instruments and agreements reflecting its agreement to assume and be bound by the terms of acquisition relating thereto.

(f) No Mineral Interest acquired by either Seller or Buyer within the AMI shall entitle the Acquiring Party to receive less than an undivided 75% Net Revenue Interest in Hydrocarbon production from such Mineral Interest. If Seller is the Acquiring Party, and the relevant Mineral Interest entitles the Acquiring Party to greater than an undivided 75% Net Revenue Interest, Seller shall be entitled to reserve from its assignment to Buyer a sliding scale overriding royalty interest in such Mineral Interest, proportionately reduced by the mineral fee interest covered by such Mineral Interest (and further proportionately reduced to the extent that Seller owns or acquires less than an undivided 100% of 8/8ths Working Interest in such Mineral Interest), based on the Net Revenue Interest in such Mineral Interest actually received or acquired by Seller, insofar and only insofar as the overriding royalty interest reserved by Seller does not (and would not) cause the Net Revenue Interest actually delivered to Buyer to be less than 75% in

any Mineral Interest (“Seller Overriding Royalty Interest”). If the Net Revenue Interest in such Mineral Interest is the percentage set forth below, the corresponding Seller Overriding Royalty Interest shall be the percentage set forth beside such indicated Net Revenue Interest:

In addition, the Seller Overriding Royalty Interest shall, among other things: (a) expressly allow Buyer (and its successors and assigns) to pool its interests in the applicable Mineral Interest; (b) be calculated in a manner consistent with the calculation of the applicable lessor’s royalty under the applicable oil and gas lease; (c) apply to any renewal or extensions of any oil and gas lease included in the relevant Mineral Interest that is acquired prior to, or within one (1) year after, the expiration or termination of the underlying oil and gas lease; (d) provide that Seller shall have no right to take in kind any production attributable to the Seller Overriding Royalty; (e) be proportionately reduced, to the extent that Seller owned less than an undivided 100% of the Working Interest in the Lease, and to the extent the Lease covered less than an undivided 100% of the mineral fee estate, and (f) otherwise be in substantially the form of the reservation of overriding royalty interest provisions set forth on Exhibit D attached hereto. If Buyer (or its Affiliate) is the Acquiring Party, Seller shall not be entitled to any overriding royalty interest in any such Mineral Interests acquired.

(g) If the Acquiring Party does not receive the amount due from Offeree within ten (10) days after the receipt by Offeree of the invoice for costs provided for in Section 5(e), the Acquiring Party may, at its election, give written notice to such delinquent Offeree that the failure of the Acquiring Party to receive the amount due within forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) after receipt of such notice by the delinquent Offeree shall constitute a withdrawal by the delinquent Offeree of its former election to acquire its Ownership Percentage of the offered Mineral Interest, and such Offeree shall no longer have the right to acquire an interest in the offered Mineral Interest. Unless the delinquent Offeree pays the amount due within such forty-eight (48) hour period, the delinquent Offeree shall have no right to acquire its Ownership Percentage of the offered Mineral Interest.

(h) Any assignment made by the Acquiring Party shall be made free and clear of any liens, burdens or encumbrances placed thereon by the Acquiring Party (except for Seller’s Overriding Royalty, if applicable) but otherwise shall be made without warranty of title, either express or implied. The assignment shall be made and accepted subject to, and each assignee shall expressly assume its portion of, all of the obligations of the Acquiring Party.

(i) If a Mineral Interest covers lands both within and outside the AMI, the Acquiring Party may, at its option, offer either the entire Mineral Interest, or only the portion of the Mineral Interest covering lands within the AMI. If less than the entirety is offered, the Acquiring Party’s costs applicable to the offered portion of the Mineral Interest shall be that proportion of the total costs which the portion of the Mineral Interest offered bears to the total Mineral Interest acquired. If the entirety of the Mineral Interest is offered and each Party acquires its Ownership Percentage thereof, the lands lying outside the AMI shall become a part of the Mineral Interests subject hereto, but the AMI shall not thereby be enlarged. If Offeree elects, or is deemed to have elected, not to acquire its Ownership Percentage of an offered Mineral Interest pursuant to this Section 5, the Acquiring Party may nevertheless proceed with such acquisition, and such Mineral Interest shall not become subject to this Agreement.

(a) Seller (i) has been duly formed and is validly existing and in good standing under the laws of the State of Delaware and is duly qualified to do business, and is in good standing as a foreign entity, in the State of Texas, (ii) is authorized to enter into this Agreement and consummate the transactions contemplated hereby, and (iii) has all requisite power and authority to own and operate its property (including the Properties).

(b) Neither the execution and delivery of this Agreement nor the consummation or performance of the transactions contemplated hereby will (i) result in any default under any agreement or instrument to which Seller is a party or by which any of the Properties is bound, (ii) violate any provision of Seller’s organizational or governing documents, (iii) violate any order, writ, injunction, permit, decree or Law applicable to Seller or to any of the Properties, or (iv) require any filing, consent or approval under any Law (except for approvals required to be obtained from Governmental Authorities who are lessors under the Leases or who administer such Leases on behalf of such lessors) that are customarily obtained post-closing.

(c) This Agreement constitutes (and the other instruments delivered pursuant hereto, when executed and delivered, will constitute) the legal, valid and binding obligations of Seller, enforceable against Seller in accordance with their respective terms, except as limited by bankruptcy or other Laws applicable generally to creditor’s rights and as limited by general equitable principles.

(d) There are no pending suits, actions, or other proceedings to which Seller is a party, and, to Seller’s Knowledge, none have been threatened, relating to any of the Properties, including, without limitation, any actions challenging or pertaining to Seller’s title to any of the Properties or seeking to affect, impair, or prevent the execution and delivery by Seller of this Agreement or the consummation by Seller of the transactions contemplated hereby.

(e) None of the Properties (i) is subject to the terms of any preferential right for a third Person to purchase such Property, a right of first refusal, or (except for the AMI) any area of mutual interest agreement or (ii) requires the consent of any third Person to the valid assignment of such Property to Buyer. In addition, (x) the Properties do not include any contracts, agreements or commitments (other than the Initial Leases, and, as applicable, the Supplemental Leases); (y) none of the Properties (or any portion thereof) has been pooled, unitized or communitized; (z) other than any easements or rights-of-way contained in the Initial Leases or the Supplemental Leases, as well as any easements or rights-of-way implied under the Initial Leases, Supplemental Leases, or applicable Laws, the Properties do not include any other, separate easements or rights-of-way.

(f) Seller has not engaged any financial advisor, broker, agent, or finder, or incurred any Liability, contingent or otherwise, in favor of any other such Person relating to the transactions contemplated by this Agreement for which Seller will have any responsibility, obligation, or Liability of any kind or, as the result of which, Seller (or Buyer as transferee) would be obligated to further transfer any interest in the Properties to such individual or entity.

(g) Seller has not (nor, to Seller’s Knowledge, except as set forth on Schedule 6(g), has any of Seller’s predecessors in interest) conducted oil and gas exploration, development, or production operations on the Leases, or any lands pooled or unitized therewith.

(h) Seller has provided Buyer with true, correct and complete copies (with all amendments) of all of the Leases, all of which are valid and binding and in full force and effect, and no default or breach has occurred or is continuing.

(i) Except for items for which an adjustment to the Purchase Price is made pursuant to Section 17, (i) the expiration date for each Lease is set forth on Exhibit A (as the same may be amended in connection with the Supplemental Closing), together with any extension rights and extension costs; (ii) all Leases are “paid-up” and require no further obligation payments (including lease bonuses, delay rentals and deferred payments of any kind) throughout the remainder of the respective terms of the Leases, except that the primary terms of certain Leases may be extended with an additional payment; and (iii) all Leases expressly permit pooling, including, without limitation, with regard to planned horizontal wells thereon.

(j) There are no outstanding authorities for expenditure or other commitments to make capital expenditures relating to any portion of the Leases that will be binding on Buyer after the applicable Closing Date.

(k) There is no equipment and no contracts or agreements that are material to the Leases or operations related thereto.

(l) None of the Leases contains any express provision obligating Seller to drill any wells, or contains provisions or conditions (such as continuous drilling clauses) which, if not satisfied, could result in a forfeiture or loss by Seller of all or any part of any Lease.

(m) Seller is (individually and with regard to its ownership of the Leases), and to Seller’s Knowledge, the Leases are, in compliance with all applicable Laws.

(n) No Property-Related Taxes have been imposed upon or assessed with respect to the Leases, or the ownership thereof, or the production of Hydrocarbons therefrom or otherwise become due and payable by Seller. No tax returns or tax filings have been, or are currently, due from Seller to any Governmental Authority. None of the Leases is held in or subject to an arrangement or agreement that results in any of the Properties being treated as held in or subject to a partnership (or otherwise treated as an interest in any entity) for federal, state, or local income tax purposes.

(o) Except as set forth on Schedule 6(o), none of the Leases is subject to a Lien or other Claim or encumbrance, including, without limitation, any net profits interest, call on production, or obligation to deliver any production from the Leases after the applicable Effective Time without the right to be immediately paid for the same.

(p) To Seller’s Knowledge: (i) there are no currently active wells located on the Leases; and (ii) all inactive wells located on the Leases have been properly plugged and abandoned in accordance with all applicable Laws.

(q) Seller has not elected not to participate in any operation or activity proposed with respect to any of the Leases that could result in any of Buyer’s interest in any portion of the Properties becoming subject to relinquishment, reassignment, penalty or forfeiture as a result of such election not to participate in such operation or activity.

(r) Neither Seller, nor any Affiliate, has received, reserved or otherwise obtained any royalty, overriding royalty, net profits interest, production payment, or other burden or encumbrance on any of the Properties that would survive Closing or otherwise burden any interest in the Properties being conveyed to Buyer at Closing, insofar as the result thereof would cause the actual Net Revenue Interest in any Properties to be conveyed to Buyer hereunder (calculated based on a 100% Working Interest) to fall below 75%.

(a) Buyer (i) has been duly formed and is validly existing and in good standing under the laws of the State of Delaware and is duly qualified or licensed to do business and is in good standing as a foreign entity in each jurisdiction in which the character or location of its assets or properties (whether owned, leased or licensed) or the nature of its business make such qualification necessary, (ii) is authorized to enter into this Agreement and consummate the transactions contemplated hereby, and (iii) has all requisite power and authority to own and operate its property.

(b) Neither the execution and delivery of this Agreement nor the consummation or performance of the transactions contemplated hereby will (i) result in any default under any agreement or instrument to which Buyer is a party, (ii) violate any provision of Buyer’s organizational or governing documents, (iii) violate any order, writ, injunction, permit, decree, or Law applicable to Buyer, or (iv) require any filing, consent or approval under any Law (except for approvals required to be obtained from Governmental Authorities who are lessors under the Leases, or who administer the Leases on behalf of such lessors, that are customarily obtained post-closing).

(c) This Agreement constitutes (and the other instruments delivered pursuant hereto, when executed and delivered, will constitute) the legal, valid and binding obligations of Buyer, enforceable against Buyer in accordance with their respective terms, except as limited by bankruptcy or other Laws applicable generally to creditor’s rights and as limited by general equitable principles.

(d) There are no pending suits, actions, or other proceedings to which Buyer is a party, and, to Buyer’s Knowledge, none have been threatened, relating to or seeking to affect, impair, or prevent Buyer’s execution and delivery of this Agreement or the consummation by Buyer of the transactions contemplated hereby.

(e) Buyer has not engaged any financial advisor, broker, agent, or finder, or incurred any Liability, contingent or otherwise, in favor of any other such Person relating to the transactions contemplated by this Agreement for which Seller will have any responsibility, obligation, or Liability of any kind.

(f) There are no bankruptcy, insolvency, reorganization, or arrangement proceedings pending, being contemplated by, or, to Buyer’s Knowledge, threatened against Buyer or any Affiliate that controls Buyer.

(g) Buyer is acquiring the Properties for its own account, for investment, and not with a view to, or for offer or resale in connection with, a distribution thereof (including, without limitation, the transfer of fractional undivided interests therein) within the meaning of the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder, or a distribution thereof in violation of any applicable securities Law.

(h) Buyer has, or has unconditionally arranged for, the funds necessary to purchase the Properties from Seller and will cause the timely availability of such funds for the purposes of consummating the purchase of the Properties in accordance with the terms of this Agreement.

(a) the performance of the terms, conditions, and covenants of, and the discharge of the duties, obligations, and Liabilities of the lessee (including obligations or Liabilities for the payment of bonus, royalties, lease maintenance payments, and other sums of money) arising under the terms of, the Leases for the period from and after the applicable Effective Time;

(b) ALL CLAIMS AND LIABILITIES ARISING OUT OF, RESULTING FROM, OR RELATING IN ANY WAY TO THE ENVIRONMENTAL CONDITION OF THE LEASES, OR ANY PORTION THEREOF, REGARDLESS OF WHETHER SUCH ENVIRONMENTAL CONDITION IS KNOWN, ANTICIPATED, OR SUSPECTED AS OF THE APPLICABLE CLOSING DATE, OR RESULTS, IN WHOLE OR IN PART, FROM THE NEGLIGENCE OR STRICT LIABILITY (BUT NOT THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT) OF SELLER OR ITS AFFILIATES, EMPLOYEES, AGENTS, OR REPRESENTATIVES, AND REGARDLESS OF WHETHER SUCH CLAIM OR LIABILITY, OR THE ACTS, OMISSIONS, EVENTS, OR CONDITIONS GIVING RISE THERETO, AROSE, OCCURRED, OR EXISTED BEFORE OR AT, OR AFTER THE APPLICABLE EFFECTIVE TIME; AND

(c) all Claims and Liabilities relating to the payment of taxes (including interest, penalties, and additions to tax) for which Buyer has agreed to be responsible hereunder.

(a) the performance of the terms, conditions, and covenants of, and the discharge of Seller’s share of the duties, obligations, and Liabilities of the lessee (including obligations or Liabilities for the payment of bonus, royalties, lease maintenance payments, and other sums of money) arising under the terms of Leases for the period prior to the applicable Effective Time;

(b) SELLER’S OWNERSHIP PERCENTAGE OF ALL CLAIMS AND LIABILITIES ARISING OUT OF, RESULTING FROM, OR RELATING IN ANY WAY TO THE ENVIRONMENTAL CONDITION OF THE ASSETS, OR ANY PORTION THEREOF, REGARDLESS OF WHETHER SUCH ENVIRONMENTAL CONDITION RESULTS, IN WHOLE OR IN PART, FROM THE NEGLIGENCE OR STRICT LIABILITY (BUT NOT THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT) OF BUYER OR ITS AFFILIATES, EMPLOYEES, AGENTS, OR REPRESENTATIVES, AND REGARDLESS OF WHETHER SUCH CLAIM OR LIABILITY, OR THE ACTS, OMISSIONS, EVENTS, OR CONDITIONS GIVING RISE THERETO, AROSE, OCCURRED, OR EXISTED BEFORE, AT, OR AFTER THE APPLICABLE EFFECTIVE TIME;

(c) all Claims and Liabilities relating to the payment of taxes (including interest, penalties, and additions to tax) for which Seller has agreed to be responsible hereunder.

(a) Except as otherwise provided in this Section 11, the indemnities provided by each Party to the other under this Section 11 shall constitute the sole and exclusive remedies for such Party after the applicable Closing Date with respect to (a) the inaccuracy or breach of any representation or warranty made by the other Party hereunder as of such Closing Date and (b) a breach or default in the performance by such other Party of any covenant or agreement of such other Party contained in this Agreement as of such Closing Date. Except for the remedy of enforcement of the indemnities provided in this Section 11, and except with regard to rights under Section 24, each Party hereby waives any Claim or remedy arising under common law, any statute, or otherwise against the other Party arising from or out of the inaccuracy or breach of any representation or warranty made by the other Party hereunder, or the breach or default in the performance by such other Party of any covenant or agreement of such other Party contained in this Agreement, in either case that arose or occurred prior to the applicable Closing Date.

(b) Upon Closing, regardless of any investigation made at any time by or on behalf of any Party or any information any Party may have, and regardless of the presence or absence of insurance, Buyer shall INDEMNIFY, DEFEND AND HOLD HARMLESS Seller and its Indemnity Group from and against any and all Claims and Liabilities caused by, arising out of, resulting from, or relating in any way to, and to pay to Seller any sum that Seller pays, or becomes obligated to pay, on account of: (a) any breach or default in the performance by Buyer of any covenant or agreement of Buyer contained in this Agreement or any other document executed in connection herewith; (b) any breach of a warranty or an inaccurate or erroneous representation made by Buyer in this Agreement; and (c) all Assumed Liabilities, REGARDLESS OF WHETHER ANY OF THE ABOVE ARE ATTRIBUTABLE TO OR RESULTS, IN WHOLE OR IN PART, FROM THE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR RESPONSIBILITY OF BUYER, SELLER OR ANY OTHER PERSON (BUT NOT THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SELLER).

(c) Upon Closing, regardless of any investigation made at any time by or on behalf of any Party or any information any Party may have, and regardless of the presence or absence of insurance, Seller shall INDEMNIFY, DEFEND AND HOLD HARMLESS Buyer and its Indemnity Group and against any and all Claims and Liabilities caused by, arising out of, resulting from, or relating in any way to, and to pay Buyer any sum that Buyer pays or becomes obligated to pay, on account of: (a) any breach or default in the performance by Seller of any covenant or agreement of Seller contained in this Agreement or any other document executed in connection herewith; (b) any breach of a warranty or an inaccurate or erroneous representation made by Seller in this Agreement; and (c) all Retained Liabilities, REGARDLESS OF WHETHER ANY OF THE ABOVE ARE ATTRIBUTABLE TO OR RESULTS, IN WHOLE OR IN PART, FROM THE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR RESPONSIBILITY OF BUYER, SELLER OR ANY OTHER PERSON (BUT NOT THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF BUYER).

(d) Except as provided hereinafter, after the Closing Date, neither Buyer nor Seller shall be entitled to assert a Claim for indemnification against the other Party as the result of the inaccuracy or breach of any representation or warranty (other Seller’s representations and warranties in Sections 6(a) through 6(c) and 6(f) and Buyer’s representations and warranties under Sections 7(a) through 7(c), all of which shall survive indefinitely), unless the Party seeking indemnification gives written notice of the alleged breach or inaccuracy to the Party from whom indemnification is sought no later than the expiration of twenty-four (24) months after the Supplemental Closing Date; provided, however, that in the case of an alleged breach or default by Seller under Section 6(n) (which relates to taxes), and with regard to an alleged breach or failure to perform any covenant of or made by a Party hereunder, such notice from the other Party seeking indemnification must be given no later than sixty (60) days after the expiration of the statute of limitations applicable to the relevant Claim.

(e) Upon the discovery by a Party entitled to indemnification under any provision of this Agreement (the “Indemnified Party”) of facts believed to entitle such Party to indemnification hereunder, including the receipt by any such Party of notice of a Claim from any third Person, the Indemnified Party shall give reasonably prompt written notice of any such Claim to the Party from whom indemnity is sought hereunder (the “Indemnified Party”). Each such notice shall set forth the facts known to the Indemnified Party pertaining to the relevant Claim and shall specify the manner in which the Indemnified Party proposes to respond to such Claim. Within ten (10) days after the receipt by the Indemnifying Party of such notice, the Indemnifying Party shall state in writing to the Indemnified Party: (i) whether the Indemnified Party may proceed to respond to the Claim in the manner set forth in its notice, or (ii) whether the Indemnifying Party shall assume responsibility for and conduct the negotiation, defense, or settlement of the Claim, and if so, the specific manner in which the Indemnifying Party proposes to proceed. If the Indemnifying Party assumes control of the Claim, the Indemnified Party shall at all times have the right to participate in the defense thereof and to be represented, at its sole expense, by counsel selected by it. No such Claim shall be compromised or settled by either the Indemnifying Party or the Indemnified Party, as applicable, in any manner that admits liability on the part of the other Party or that might

otherwise adversely affect the interest of such other Party without the prior written consent of such other Party, which consent will not be unreasonably withheld or delayed. As a condition precedent to indemnification under this Agreement, the Indemnified Party shall assign to the Indemnifying Party, and the Indemnifying Party shall become subrogated to, all rights and Claims, up to the amount of indemnification, of the Indemnified Party against third Persons arising out of or pertaining to the matters for which the Indemnifying Party shall provide indemnification. The amount of the Indemnified Party’s claim for indemnification shall be reduced by the amount of any insurance reimbursement paid to the Indemnified Party pertaining to the Claim.

(f) Subject to any limitations on the total amount of indemnification for which either Party is liable hereunder for any breach or non-performance by any Party of any representation, warranty, covenant, or agreement contained in this Agreement, the liability of the obligor shall be limited to direct actual damages only, except to the extent that the obligee is entitled to specific performance or injunctive relief. AS BETWEEN THE PARTIES, NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS AGREEMENT, NEITHER SELLER NOR BUYER SHALL BE LIABLE TO THE OTHER PARTY AS THE RESULT OF A BREACH OR A VIOLATION OF ANY REPRESENTATION, WARRANTY, COVENANT, AGREEMENT, OR CONDITION CONTAINED IN THIS AGREEMENT FOR SPECIAL, CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS, OR OTHER BUSINESS INTERRUPTION DAMAGES, IN TORT, IN CONTRACT, UNDER ANY INDEMNITY PROVISION, OR OTHERWISE, OTHER THAN IN CONNECTION WITH A BREACH OF THE AMI OBLIGATIONS UNDER SECTION 5 OR IN CONNECTION WITH A BREACH OF THE CONFIDENTIALITY OBLIGATIONS UNDER SECTION 22. WITH RESPECT TO CLAIMS BY THIRD PERSONS, THE INDEMNIFIED PARTY MAY RECOVER FROM THE INDEMNIFYING PARTY ALL COSTS, EXPENSES, OR DAMAGES, INCLUDING, WITHOUT LIMITATION, SPECIAL, CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS, OR OTHER BUSINESS INTERRUPTION DAMAGES, OTHER THAN AND IN ADDITION TO ACTUAL DIRECT DAMAGES PAID OR OWED TO ANY SUCH THIRD PERSON IN SETTLEMENT OR SATISFACTION OF CLAIMS AS TO WHICH THE INDEMNIFIED PARTY IS ENTITLED TO INDEMNIFICATION HEREUNDER.

correspondence received from a Governmental Authority with respect to the Properties within five (5) days after receipt thereof. In addition, it is acknowledged that some of the Leases described on Exhibit A have not yet been filed of record, but prior to the Initial Closing, Seller shall (x) file the unrecorded Leases in the official public records of the County where the lands covered by such Lease are located, and (y) supplement Exhibit A to include the recording information for such Leases (the “Recording Information Supplement”).

shall have performed and satisfied all of its covenants set forth herein that were required to have been performed or satisfied at or prior to applicable Closing Date; (c) no suit, action, or other proceeding instituted by a third Person against Buyer shall be pending before any Governmental Authority or arbitrator seeking to restrain, prohibit, enjoin, or declare illegal, or seeking substantial damages in connection with, the transactions contemplated by this Agreement; (d) no order shall have been entered by any court or Governmental Authority against Buyer that restrains or prohibits the transactions contemplated by this Agreement; (e) all consents and approvals (if any) required to be obtained by Buyer from Governmental Authorities or from third Persons for the consummation of the transactions contemplated by this Agreement shall have been granted (except for consents and approvals of Governmental Authorities customarily obtained subsequent to transfer of title); and (f) adjustments to the Purchase Price contemplated in Sections 19 (including, without limitation, those adjustments resulting from holding some Properties back under Section 19(a)(ii), but exclusive of the amounts required to discharge the Liens encumbering the Properties granted by Seller to Petro Capital XXV, LLC, as to which Liens Seller delivers to Buyer releases in accordance with Section 15(h) at the relevant Closing) and 20 shall not equal or exceed, in the aggregate, $3,000,000.

encumbering the Properties being conveyed to Buyer at the relevant Closing, and such releases shall be in form and substance that are reasonably satisfactory to Buyer; and (i) Seller and Buyer shall execute and deliver one or more JOAs, covering the relevant Properties. In addition, at the Supplemental Closing, Seller and Buyer shall execute and deliver an amendment to Exhibit A to this Agreement that adds the descriptions of the Supplemental Leases comprising the Supplemental Properties and lists the Working Interests and Net Revenue Interests of Seller therein, the Net Mineral Acres covered thereby, and the expiration dates thereof.

(a) This Agreement may be terminated by written notice at any time prior to the First Closing: (a) by mutual written consent of Buyer and Seller; (b) by the Party not in material breach or material default of its obligations under this Agreement if, prior to the First Closing Date, the other Party is in material breach or material default of its obligations under this Agreement; (c) by Buyer, at Buyer’s option, if (i) the First Closing does not occur because any of the conditions contained in Section 13 is not fulfilled by Seller or waived by Buyer on or before the First Closing Date, and (ii) all of the conditions set forth in Section 14 have been fulfilled by Buyer on or before the First Closing Date; (d) by Seller, at Seller’s option, if (i) the First Closing does not occur because any of the conditions contained in Section 14 is not fulfilled by Buyer or waived by Seller on or before the First Closing Date, and (ii) all of conditions set forth Section 13 have been fulfilled by Seller on or before the First Closing Date; (e) by Buyer if the First Closing has not occurred by June 1, 2012. In addition, this Agreement shall be deemed to have terminated upon the occurrence of the circumstances described in Section 4(i).

(b) If this Agreement is terminated as provided in this Section 16 prior to the First Closing, all further obligations of the Parties under this Agreement, including all obligations relating to the AMI, shall terminate; provided, however, that: (i) neither Party shall be relieved of any unfulfilled obligation or Liability of such Party under this Agreement that accrued prior to such termination (including any undischarged obligation to pay money) or the consequences of any inaccuracy in or breach by such Party of a representation, warranty, or covenant in this Agreement occurring prior to such termination; and (ii) the Parties shall, in any event, remain bound by and continue to be subject to this Section 16, Section 4(i), Section 18, Section 21, Section 30, and, if termination of this Agreement occurs by operation of Section 4(i), then also Section 9, Section 10, and Section 11, all of which provisions will survive the termination of this Agreement.

(c) If the First Closing occurs, but the Supplemental Closing has not occurred as of the ninetieth (90^th) day after the expiration of the Supplemental Acquisition Period: (i) this Agreement (including the provisions relating to the AMI) shall remain in full force and effect and shall not be terminated; (ii) subject to the last sentence of this Section 16(c), the Supplemental Properties intended to be conveyed to Buyer at the Supplemental Closing shall cease to be subject to the terms of this Agreement; (iii) subject to the last sentence of this Section, Seller shall be entitled to own and hold the oil and gas leases comprising such Supplemental Properties for its own account and at its

sole cost and expense, free and clear of the terms of this Agreement, including those relating to the AMI; and (iv) neither Party shall be relieved of any unfulfilled obligation or Liability of such Party under this Agreement with respect to the Supplemental Properties or the Supplemental Closing that accrued prior to the Supplemental Closing Date specified in Section 2(b) (including any undischarged obligation to pay money) or the consequences of any inaccuracy in or breach by such Party of a representation, warranty, or covenant in this Agreement relating to the Supplemental Properties or the Supplemental Closing occurring prior to such specified Supplemental Closing Date. Notwithstanding the above, in lieu of terminating with regard to such Supplemental Properties and Supplemental Properties (as described in subparts (ii) and (iii) above), Buyer may seek specific performance of the terms of this Agreement (and it is recognized that Buyer would be irreparably harmed by a breach of this Agreement by Seller or the failure of Seller to satisfy such conditions, and, therefore, Buyer shall have the right to, and may, seek injunctive relief, to prevent breaches of the provisions of this Agreement, and shall be entitled to enforce specifically the provisions of this Agreement, in any court of the United States or any state thereof having jurisdiction, in addition to any other remedy to which the parties may be entitled under this Agreement or at law or in equity))

(d) Notwithstanding the above, a Party who is not in breach of its obligations under this Agreement shall have the right, in lieu of terminating this Agreement to specifically enforce the provisions of this Agreement (in such case, the “Enforcing Party”), if, and only to the extent, the following conditions are satisfied: If, (i) (A) as of June 1, 2012, the First Closing has not occurred, or (B), as of the Supplemental Closing Date specified in Section 2(b), the Supplemental Closing has not occurred, but (ii) as of the relevant date, all of the conditions precedent to the obligation of the other Party to close the transactions contemplated herein have been satisfied and fulfilled, and (iii) as of the relevant date, such other Party, nevertheless, refuses to close as required under this Agreement, then the Enforcing Party shall be entitled, in addition to any other remedy to which such Party is entitled under this Section 16 (other than termination) or otherwise in this Agreement, at law, or in equity, to enforce the remedy of specific performance against the other Party refusing to close in any of the courts identified in Section 21. In this regard, it is agreed that the Enforcing Party would be irreparably harmed by a refusal of the other Party to close the transactions contemplated in this Agreement under the circumstances described in this Section 16(d) and, therefore, the Enforcing Party shall have the right to, and may seek, injunctive relief in connection with the enforcement of its right to specific performance under this Section 16(d), as contemplated herein.

(a) From the Execution Date until the First Closing Date with respect to the Initial Properties (or, as the case may be, with regard to the Supplemental Properties, until the Supplemental Closing Date), Buyer shall be afforded the opportunity to examine all records and information (including all title, lease, and land files) in Seller’s possession with respect to Seller’s title to the relevant Leases and to conduct such other title-related investigations as Buyer deems necessary, in its sole discretion. If Buyer determines that any Title Defect (as defined below) exists, then Buyer shall provide written notice of such Title Defect to Seller promptly after the discovery thereof, but in no event later than April 10, 2012, with regard to the Initial Properties (or later than three (3) days prior to the Supplemental Closing Date with regard to the Supplemental Properties). Title Defects discovered by Buyer in its due diligence review of a Lease prior to the applicable Closing Date but not asserted as provided in this Section 19 shall be deemed to have been waived by Buyer (and if not otherwise discovered, Buyer shall not be restricted or prevented from asserting any Claim related thereto under the special warranty of title granted under the Assignment). If Buyer asserts a Title Defect, and Seller does not cure such Title Defect to Buyer’s reasonable satisfaction prior to the applicable Closing Date, then Buyer shall have the following options:

(b) As used in this Agreement, the term “Title Defect” means any Lien, charge, encumbrance, obligation (including contract obligation), defect, irregularity, depth limitation or severance, or other matter (including, without limitation, a discrepancy in Net Revenue Interest) that causes Seller not to have Defensible Title (defined below) in and to any Lease as of the Closing Date applicable to such Lease.

(a) From and after the Execution Date until the First Closing Date with regard to the Initial Leases, and until the Supplemental Closing Date with regard to the Supplemental Leases, Seller shall afford to Buyer and its officers, employees, agents and authorized representatives reasonable access to the lands covered by the Leases to conduct onsite inspections and assessments of such lands in accordance with the terms of this Agreement. During such period, Seller shall also make available to Buyer, upon reasonable notice during normal business hours, personnel of Seller knowledgeable with respect to the Leases and the environmental records applicable thereto in order that Buyer may make such diligent investigation as it considers desirable.

(b) Upon reasonable notice to Seller, Buyer shall have the right to conduct a “Phase I” environmental assessment of all or any portion of the land covered by the Leases in accordance with the applicable standards of the American Society for Testing Materials, or A.S.T.M. (the “Assessment”), to be conducted by a reputable environmental consulting or engineering firm selected by Buyer and approved by Seller (such approval not to be unreasonably withheld), but only to the extent that Seller may grant Buyer the right to conduct the Assessment without violating any obligations to any third Person (provided that Seller shall use its commercially reasonable efforts to obtain any necessary third Person consents to any Assessment conducted by Buyer). The Assessment shall be conducted at the sole cost and expense of Buyer. Buyer shall not be permitted to conduct any sampling, boring, drilling, or other invasive investigative activity with respect to such land (“Invasive Activity”) without the prior written consent of Seller. Buyer shall perform, or shall cause to be performed, the Assessment in accordance with applicable Laws. Seller shall have the right to have its representatives present to observe Buyer’s, or Buyer’s environmental consultant’s, performance of the Assessment. Prior to the First Closing in the case of the Initial Leases and the Supplemental Closing in the case of the Supplemental Leases, unless otherwise required by applicable Law, Buyer shall (and shall cause Buyer’s environmental consultant, if applicable, to) treat confidentially any matters revealed by Buyer’s Assessment and any reports or data generated therefrom subject to and in accordance with the terms of Section 22. If Buyer or Buyer’s environmental consultant becomes legally compelled to disclose any of such environmental information, Buyer shall provide to Seller the notice required under, and Seller shall have the rights provided in, Section 22(e). If (i) one or more Leases is excluded from this Agreement by operation of Section 19(b) or Section 20(d), or (ii) if this Agreement is terminated prior to the First Closing in accordance with Section 16(a), or (iii) if the Supplemental Closing does not occur as provided in Section 16(b), the confidentiality obligations of Buyer (and Buyer’s environmental consultant, if applicable) under this Section 20(b) shall survive such events and remain in full force and effect with respect to all Leases covered by the Assessment but in which Buyer is not assigned its Ownership Percentage pursuant to this Agreement in accordance with the terms of Section 22, and Buyer shall deliver a copy of the final report of the environmental engineer generated from the Assessment of such Leases to Seller at no charge, which

environmental report shall become the sole property of Seller as to such Properties in which the Ownership Percentage is not conveyed to Buyer. Notwithstanding any provision of this Agreement to the contrary, Buyer provide to Seller, without charge, copies of all environmental reports and information generated from the Assessment, except for documents and materials subject to the attorney/client privilege.

(c) For the purposes hereof, “Environmental Laws” means, as the same may have been amended, any federal, state or local Law relating to (i) the control of any potential pollutant or protection of the environment, including air, water or land, (ii) the generation, handling, treatment, storage, disposal or transportation of waste materials, or (iii) the regulation of or exposure to hazardous, toxic or other substances alleged to be harmful, including, but not limited to, the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq.; the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq.; the Federal Water Pollution Control Act, 33 U.S.C. § 1251 et seq.; the Clean Air Act, 42 U.S.C. § 7401 et seq. the Hazardous Materials Transportation Act, 49 U.S.C. § 1471 et seq.; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et seq.; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq.; the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; the Federal Insecticide, Fungicide and Rodenticide Act, 7 U.S.C. § 136 et seq.; the Occupational Safety and Health Act, 29 U.S.C. § 651 et seq.; the Atomic Energy Act, 42 U.S.C. § 2011 et seq.; and all applicable related Law, whether local, state, territorial, or national, of any Governmental Authority having jurisdiction over the Lease(s) in question addressing pollution or protection of human health, safety, natural resources or the environment and all regulations implementing the foregoing. The term “Environmental Laws” includes all judicial and administrative decisions, orders, directives, and decrees issued by a Governmental Authority pursuant to the foregoing.

(d) If, as a result of its investigation pursuant to Section 20(b), Buyer determines that, with respect to any portion of the Leases or the land covered thereby, there exists a violation of an Environmental Law (in each case, an “Environmental Defect”), then on or prior to the applicable Closing Date, Buyer may send Seller notice of each such Environmental Defect. Seller and Buyer shall consult with each other regarding whether to remedy each such Environmental Defect and, if so, the method of remediation, but neither Seller nor Buyer shall have any obligation to the other Party under this Agreement to remedy any such Environmental Defect. If Seller and Buyer agree that such an Environmental Defect should be remedied, the affected Lease(s) shall not be included in the applicable Closing, and shall be held back, in their entirety, and the Purchase Price shall be reduced by the Allocated Value of the Properties affected by the Environmental Defect. Such held back Properties shall be treated in the same manner as the Properties held back under Section 19(a)(ii) for Title Defects, and if timely remedied in accordance with applicable Law, may be treated as additional Supplemental Properties. If Seller and Buyer fail to agree to remedy such an Environmental Defect, and Buyer and Seller do not agree upon any alternative resolution, then Seller or Buyer may elect to exclude the affected Lease(s) from the applicable Closing, whereupon such Lease(s) shall cease to be subject to the terms of this Agreement (including the provisions relating to the AMI), and the Purchase Price payable at the applicable Closing shall be reduced by the full Allocated Value of the Properties corresponding to such excluded Leases.

(a) For purposes of this Agreement, “Confidential Information” means: (i) the terms of this Agreement, including the Purchase Price, as to which Buyer is deemed to be the Disclosing Party and Seller is the Recipient; (ii) the environmental information regarding the Leases obtained by Buyer pursuant to its performance of the Assessment, as to which Seller is deemed to be the Disclosing Party and Buyer is the Recipient; and (iii) the Records, as to which Seller is deemed to be the Disclosing Party and Buyer is the Recipient.

(b) During the term of the confidentiality obligations under this Section 22, Recipient shall have the right to use the Confidential Information solely for the purposes of due diligence, consummating the transaction contemplated herein, and enforcing the terms of this Agreement (“Permitted Uses”). Recipient shall not use Confidential Information for any purposes other than the Permitted Uses.

(c) Recipient shall not disclose, disseminate, or otherwise publish or communicate Confidential Information received hereunder to any third Person without the prior written consent of the Disclosing Party, except (i) in the case of Seller as Recipient, to Petro Capital, and (ii) to the directors, members, managers, partners, officers, employees, and Affiliates of Recipient, as well as Recipient’s financial advisors, bankers, investment bankers, other capital providers, legal counsel, auditors, engineers, and other consultants and representatives (collectively, “Representatives”) who have a “need to know” solely for purposes of the Permitted Uses and who have been advised of the confidentiality obligations herein and have previously agreed to be bound by terms with regard to the Confidential Information. Recipient shall be responsible for the actions of its Representatives. Recipient shall protect the Confidential Information

received hereunder from disclosure to any third Person by using the same degree of care that it uses to prevent the unauthorized disclosure of its own confidential or proprietary information of like nature, but in no event less than a reasonable degree of care.

(d) This Agreement imposes no obligations with respect to information that: (i) was in Recipient’s possession without a duty of confidentiality to the Disclosing Party before receipt from the Disclosing Party; (ii) is or becomes a matter of public knowledge through no act or omission of Recipient; (iii) is rightfully received by Recipient from a third Person without a duty of confidentiality; or (iv) is disclosed by Recipient with the Disclosing Party’s prior written approval or for reasons described in Section 22(e) below.

(e) If Recipient is required to disclose Confidential Information by operation of Law (including applicable stock exchange or quotation system requirements) or under compulsion of judicial process, Recipient will disclose only such information as is legally required by applicable Law or order of a court of competent jurisdiction or other Governmental Authority, and will use reasonable efforts to obtain confidential treatment for any Confidential Information that is so disclosed. Recipient will provide the Disclosing Party as much notice of such possible disclosure as is reasonably practicable prior to disclosure, in order to give the Disclosing Party an opportunity to seek a protective order or take other appropriate action.

(f) In all events, Seller’s confidentiality obligations under this Section 22 with respect to the Purchase Price, and with respect to the terms and provisions Sections 4 and 5 above, shall expire one (1) year after the date of this Agreement. If the First Closing occurs, the confidentiality obligations of Seller with respect to the terms of this Agreement (other than the Purchase Price, and the terms and provisions Sections 4 and 5 above, which shall remain confidential) and of Buyer with respect to the Records pertaining to the Initial Properties shall thereupon terminate. Thereafter, if the Supplemental Closing occurs, the confidentiality obligations of Buyer with respect to the Records pertaining to the Supplemental Properties shall thereupon terminate. If this Agreement is terminated prior to the First Closing, the confidentiality obligations of the Parties with respect to the terms of this Agreement (other than Seller’s obligations with respect to the Purchase Price) shall thereupon terminate, but Buyer’s confidentiality obligations with respect to the Records shall survive and remain in full force and effect for a period of two (2) years after the Execution Date. In all events, the duration of Buyer’s confidentiality obligations with respect to the environmental information obtained by Buyer from the Assessment shall be as set forth in Section 20.

(g) Except as permitted in Section 22 (e), Seller shall not make or cause to be made any public announcement of, or public disclosure pertaining to this Agreement, the terms of this Agreement, or the transactions contemplated hereby without the prior written consent of Buyer. Seller acknowledges that the securities of Buyer (or an Affiliate of Buyer) are publicly traded, and to the extent that this Agreement or the terms hereof may be considered material, the use or sharing of such material, non-public information is restricted under applicable state and federal securities laws.

Either Party may, upon written notice to the other Party, change the address and Person to whom such communications are to be directed.

“Affiliate” means, with respect to a Party, any Person that directly or indirectly controls, is controlled by, or is under common control with, the relevant Party. For purposes of this definition, the term “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, contract, voting trust, membership in management or in the group appointing or electing management, or otherwise through formal or informal arrangements or business relationships.

“Allocated Value” means, with respect to each Lease, the amount set forth on Schedule 31. For purposes of this Agreement, Seller and Buyer agree and stipulate that the Allocated Values set forth in Schedule 31 have been established solely for use in calculating adjustments to the Purchase Price as provided herein, and not for purposes of federal or state income taxation, such Allocated Values being solely for the convenience of the Parties.

“Business Day” means any day other than a Saturday, Sunday, or other day on which commercial banks in Houston, Texas, are required or authorized by Law to be closed.

“Claims” means any and all claims, demands, Liens, notices of non-compliance or violation, notices of liability or potential liability, investigations, actions (whether judicial, administrative, or arbitrational), causes of action, suits, and controversies.

“Commercial Well” means a well capable of producing Hydrocarbons in quantities sufficient to yield a return in excess of operating and production costs and expenses (without taking into account costs of exploration (including land and seismic costs), drilling, testing, hydraulic fracturing, completion and equipping such well for production).

“Disclosing Party” means the Party that discloses Confidential Information to the other Party pursuant to this Agreement.

“Effective Time” means 7:00 a.m., Central Standard or Daylight time, as applicable, on (a) with respect to the Initial Properties, the First Closing Date, and (b) with respect to the Supplemental Properties, the Supplemental Closing Date.

“Governmental Authority” means any governmental or quasi-governmental authority of any federal, state, provincial, county, city, or other political subdivision of the United States, or any foreign country, or any department, agency, commission, court, or other statutory or regulatory body or instrumentality having jurisdiction.

“Indemnity Group” means, for either Party, the Affiliates, officers, directors, managers, members, employees, agents, and representatives of the relevant Party or its Affiliates.

“Knowledge”, when used with reference to either Party, means the actual knowledge of the current members, managers, directors, and officers of such Party, after reasonable investigation an inquiry.

“Laws” means all constitutions, treaties, laws, statutes, ordinances, rules, regulations, permits, orders, decrees of the United States, any foreign country, and any local, state, provincial, or federal political subdivision or agency thereof, as well as all judgments, decrees, orders, and decisions of courts having the effect of law in each such jurisdiction.

“Liabilities” means any and all losses, judgments, damages, liabilities, injuries, costs, expenses, interest, penalties, taxes, fines, obligations, and deficiencies. As used herein, the term “Liabilities” includes, without limitation, reasonable attorneys’ fees and other costs and expenses of any Party receiving indemnification hereunder incident to the investigation and defense of any Claim that results in litigation, or the settlement of any Claim, or the enforcement by any Party receiving indemnification hereunder of the provisions of Section 11, as applicable.

“Lien” means any mortgage, deed of trust, pledge, security interest, encumbrance, lien, or charge of any kind (including any agreement to grant any of the foregoing), any conditional sale or title retention agreement, any lease in the nature thereof, or the filing of or agreement to give any financing statement under the Uniform Commercial Code of any jurisdiction.

“Net Mineral Acres” shall mean, with respect to a particular Lease (or, as the case may be, oil and gas lease attributable to a Mineral Interest), the product of (i) the number of surface acres covered by such Lease (or, as the case may be, such oil and gas lease attributable to a Mineral Interest), multiplied by (ii) the lessor’s percentage interest in the oil and gas mineral estate in the land covered by such Lease (or, as the case may be, such oil and gas lease attributable to a Mineral Interest), multiplied by (iii) the Working Interest held in such Lease.

“Net Revenue Interest” means, with respect to an oil and gas lease, the interest in and to all Hydrocarbons produced and saved from or attributable to such oil and gas lease, after giving effect to all valid royalties, overriding royalties, production payments, net profits interests, carried interests, reversionary interests, and other similar interests constituting burdens upon, measured by, or payable out of Hydrocarbons produced and saved from or attributable to such oil and gas lease.

“Ownership Percentage” means: (a) in all cases, with respect to Buyer, 65%; (b) with respect to Seller, 35% (this assumes the re-assignment of 1% Working Interest from Petro Capital in the Initial Leases, as described herein).

“Person” means any individual, corporation, limited liability company, partnership, trust, unincorporated organization, Governmental Authority, or any other form of entity.

“Property-Related Taxes” means any and all ad valorem, property, severance, generation, conversion, Btu or gas, transportation, utility, gross receipts, privilege, consumption, excise, lease, transaction, and other taxes, franchise fees, governmental charges or fees, licenses, fees, permits, and assessments, or increases therein, and any interest or penalties thereon, other than Transfer Taxes and taxes based on or measured by net income or net worth.

“Recipient” means the Party to whom Confidential Information is disclosed pursuant to this Agreement.

“Records” means all files, records (including, without limitation, land and title records; maps, plats, and surveys; lease, contract, correspondence, operations, environmental, production, accounting, Property-Related Tax, regulatory compliance, and well records and files; and reports to Governmental Authorities) and other information that relates in any way to any of the items listed in Section 1 and are in the possession of Seller.

“Transfer Taxes” means any sales, use, stock, stamp, document, filing, recording, registration, and similar tax or charge, including, without limitation, any interest or penalties thereon.

“Working Interest” means, with respect to an oil and gas lease, the interest of the lessee that is burdened with the obligation to bear and pay the costs and expenses of exploration, drilling, development, maintenance, and operations with respect to such oil and gas lease, without regard to lessor’s royalties, overriding royalties, production payments, net profits interests, and similar burdens upon or payable out of production.

IN WITNESS WHEREOF, the Parties have executed this Agreement as of the Execution Date.

This First Amendment to Purchase and Sale Agreement (this “First Amendment”), is dated as of April 19, 2012, by and between Energy & Exploration Partners, LLC, a Delaware limited liability company (“Seller”), and Halcón Energy Properties, Inc., a Delaware corporation (and f/k/a RWG Energy, Inc.) (“Buyer”). Seller and Buyer are sometimes referred to herein individually as a “Party” and collectively as the “Parties.”

WHEREAS, Buyer and Seller entered into that certain Purchase and Sale Agreement (Non-Producing Properties) dated as of March 5, 2012 (the “Purchase Agreement”); and

WHEREAS, Buyer and Seller desire to amend the Purchase Agreement, as provided herein. Capitalized terms used but not otherwise defined herein shall have the meanings attributed to them in the Purchase Agreement.

NOW, THEREFORE, in consideration of the mutual covenants and conditions set forth herein and in the Purchase Agreement, Buyer and Seller hereby agree as follows:

1. Exhibit A. Exhibit A attached to the Purchase Agreement is hereby deleted in its entirety, and is hereby replaced for all purposes with Exhibit A attached to this First Amendment. The amendments to Exhibit A include (i) supplementing certain recording information and other information regarding the Initial Properties that was missing from the original Exhibit A (and the Initial Properties to be sold at the First Closing shall be identified in Part 1(a) of Exhibit A), and (ii) providing the descriptions and information required for the Supplemental Leases acquired by Seller prior to the Initial Cut Off Date (defined below). Exhibit A shall distinguish between the Initial Properties and such Supplemental Leases (and the Supplemental Leases acquired prior to the Initial Cut Off Date that are to be sold at the Interim Closing shall be as identified in Part 2(a) of Exhibit A); and (iii) identifying those former Initial Leases that will be part of the Properties to be sold at the Interim Closing, as further described in Section 2 of this Amendment below (and identified in Part 2(b) of Exhibit A).

2. Initial Cut Off Date and Interim Properties. The last two sentences of Section 2(a) of the Purchase Agreement are hereby deleted in their entirety, and are hereby replaced for all purposes with the following:

“To the extent any Supplemental Leases are acquired by Seller on or before 5:00 pm, CDT, on April 13, 2012 (“Initial Cut Off Date”), then (i) Seller shall provide a supplement to Exhibit A that shall include the legal description, recording information, and other information relating to such Supplemental Leases that is being provided with regard to the Initial Properties; (ii) subject to all of the other terms and conditions described herein relative to the Initial Properties (with the timetables for notices established herein for the Initial Properties to be deferred fourteen (14) days with regard to the Interim Properties (as hereinafter defined) prior to the Interim Closing (as defined below), except as otherwise specified with regard to notices for Title Defects concerning the Interim Properties, which shall be made no later than 5:00 pm, CDT, on the date that is two (2) days prior to the Interim Closing Date), the Parties shall close (herein the

“Interim Closing”) the sale by Seller to Buyer of the undivided interests set forth in Section 1(a) in and to the Supplemental Leases acquired by Seller prior to the Initial Cut Off Date, together with the other related interests described in clauses (b), (c), (d), and (e) of Section 1 (collectively, the “Interim Properties”), together with those Leases and related interests which were formerly part of the Initial Properties that are now identified on Part 2(b) of Exhibit A as being part of the Supplemental Leases (and which shall be deemed to constitute additional Interim Properties for purposes hereof), on the date that is fourteen (14) days after the First Closing Date (the “Interim Closing Date”), pursuant to the other terms of this Agreement. Notwithstanding the preceding provisions of this Section 2(a), Seller shall be entitled to add to the Interim Properties additional Supplemental Leases acquired after the Initial Cut Off Date if (x) Seller provides to Buyer, no later than three (3) Business Days prior to the Interim Closing Date, notice regarding the Supplemental Leases proposed to be added to the Interim Properties (which notice shall comply with the requirements of clause (i) of the first sentence of this Section 2(a)) and (y) Seller is able to establish, to the reasonable satisfaction of Buyer, that Seller has acquired Defensible Title to such Supplemental Leases. If an oil and gas lease that would otherwise constitute an Initial Lease or an Interim Property for purposes of this Agreement is withheld from, as applicable, the First Closing or the Interim Closing pursuant to Section 19(a)(ii), such oil and gas lease, to the extent it is not ultimately excluded from this Agreement by operation of Section 19(a)(ii), shall be treated, for all purposes hereof, as a Supplemental Lease.”

(a) Sections 3(a) and 3(b) are hereby deleted in their entirety and are replaced for all purposes with the following:

“(a) The total consideration for the sale of the Properties (the “Consideration”) shall be the sum of (i) the Initial Purchase Price, the Interim Purchase Price, and the Supplemental Purchase Price, as defined hereinafter, paid by Buyer to Seller for the Properties conveyed by Seller to Buyer at the First Closing, the Interim Closing, and the Supplemental Closing (collectively, the “Purchase Price”), plus (ii) the Contingent Payment, if any, to be paid in accordance with Section 4 below.

“(b) On the First Closing Date, Buyer shall pay to Seller, as the “Initial Purchase Price”, an amount calculated as described in Exhibit E attached hereto with respect to the Initial Properties actually conveyed by Seller to Buyer at the First Closing. The Initial Purchase Price shall be subject to further adjustment pursuant to Section 17.”

(b) The following provision is added to Section 3 of the Purchase Agreement as new Section 3(c):

“(c) If the Interim Closing occurs, then on the Interim Closing Date, Buyer shall pay to Seller, as the “Interim Purchase Price”, an

amount, calculated in the same manner as the Initial Purchase Price, with respect to the Interim Properties actually conveyed by Seller to Buyer at the Interim Closing, subject to adjustment pursuant to Section 17.

(ii) Except with regard to the defect date described in Section 5 of this First Amendment described below, Sections 4 and 6-30 of the Purchase Agreement are hereby amended to add references to the Interim Properties, the Interim Closing, and the Interim Closing Date as appropriate in conjunction with the references contained in such Sections to the Supplemental Properties, the Supplemental Closing, and the Supplemental Closing Date.

(iii) The definition of “Effective Time” in Section 31 of the Purchase Agreement is hereby deleted in its entirety, and is hereby replaced for all purposes with the following:

4. AMI. Exhibit C attached to the Purchase Agreement is hereby deleted in its entirety, and is hereby replaced for all purposes with Exhibit C attached to this First Amendment.

5. Defect Date. The second sentence of Section 19(a) of the Purchase Agreement is hereby deleted in its entirety, and is hereby replaced for all purposes with the following: “If Buyer determines that any Title Defect (as defined below) exists, then Buyer shall provide written notice of such Title Defect to Seller promptly after the discovery thereof, but in no event later than April 13, 2012, with regard to the Initial Properties (and no later than 5:00 pm, CDT, on the date that is two (2) days prior to the Interim Closing Date with regard to Interim Properties, and no later than 5:00 pm, CDT, on the date that is three (3) days prior to the Supplemental Closing Date with regard to the Supplemental Properties).”

6. Heath Ranch Lease Assignment. It is acknowledged that a Lease to be conveyed at the First Closing (referred to as the Heath Ranch Lease) may have aggregate burdens in excess of an undivided 25% (based on a 100% interest in such Lease), and therefore, this Lease will be conveyed to Buyer pursuant to a separate form of Assignment, Bill of Sale and Conveyance, in substantially the form attached hereto as Attachment 1, whereby any burdens in excess of such aggregate 25% shall be retained by Seller and burden solely the retained interests in such Lease, such that Buyer shall receive not less than an undivided 48.75% Net Revenue Interest attributable to the interests in such Lease assigned and conveyed to Buyer at the First Closing (being 65% of an undivided 75% Net Revenue Interest, assumed for purposes hereof).

7. First Closing Date. In Section 15 of the Purchase Agreement, the definition of the “First Closing Date” is hereby amended to change the reference from April 17, 2012, to say, instead, “April 19, 2012”.

8. Waiver of Certain Purchase Adjustments. Reference is herein made to that certain letter from Seller addressed to the attention of Richard Eicher (with Halcón), received by Buyer on April 15, 2012, and identifying a downward (negative) adjustment to the Purchase Price in the amount of $21,933.12, relating to two Leases which have a primary term expiration date prior to October 17, 2012 (the “April 15 Letter”). Buyer hereby waives the downward (negative) adjustment to the Purchase Price identified in the April 15 Letter.

9. References. All references to the Purchase Agreement in any document, instrument, agreement, or writing delivered pursuant to the Purchase Agreement (as amended hereby) shall hereafter be deemed to refer to the Purchase Agreement as amended hereby.

10. Counterparts. This First Amendment may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile transmission shall be deemed an original signature hereto.

11. Ratification. The Purchase Agreement, as amended hereby, is hereby adopted, ratified, and confirmed by Buyer and Seller.

IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date first written above.

This Second Amendment to Purchase and Sale Agreement (this “Second Amendment”), is dated as of May 10, 2012, by and between Energy & Exploration Partners, LLC, a Delaware limited liability company (“Seller”), and Halcón Energy Properties, Inc., a Delaware corporation (and f/k/a RWG Energy, Inc.) (“Buyer”). Seller and Buyer are sometimes referred to herein, individually, as a “Party” and, collectively, as the “Parties.”

WHEREAS, Buyer and Seller desire additionally to amend the Purchase Agreement in several respects, as provided herein. Capitalized terms used but not otherwise defined herein shall have the meanings attributed to them in the Purchase Agreement.

NOW, THEREFORE, in consideration of the mutual covenants and conditions set forth herein and in the Purchase Agreement, Buyer and Seller hereby agree as follows:

1. Amendment to Section 2 of the Purchase Agreement (Supplemental Properties). Section 2 of the Purchase Agreement is hereby amended as follows:

(a) In the first sentence of Section 2(a), the term “Supplemental Acquisition Period” is redefined as the period from and after the Execution Date and continuing until the date that is ninety (90) days after the First Closing Date.

(b) Section 2(a) is further amended by deleting the last two (2) sentences thereof (the first of which begins with the phrase “To the extent any Supplemental Leases are acquired by Seller …”), and the following provision is substituted therefor:

“To the extent any Supplemental Leases are acquired by Seller after the Initial Cut Off Date and prior to 5:00 pm, CDT, on May 17, 2012 (“Interim Cut Off Date”; and the period between the Initial Cut Off Date and the Interim Cut Off Date is herein referred to as the “Interim Period”), or there exist Supplemental Leases that may have been acquired by Seller after the Execution Date and prior to the Initial Cut Off Date but for which Seller did not yet have enough information to confirm Defensible Title, then (i) Seller shall provide to Buyer a notice (an “Interim Closing Notice”) containing a supplement to Exhibit A that shall include the legal description, recording information, and other information relating to such Supplemental Leases that is being provided with regard to the Initial Properties (and prior to the Interim Cut Off Date, Seller shall provide regular written notices to Buyer, not less than weekly, with such notices

containing lease and summary information regarding the Supplemental Leases acquired to date, in order for Buyer to administer its diligence thereon); (ii) subject to all of the other terms and conditions described herein relative to the Initial Properties (with the timetables for notices established herein for the Initial Properties to be deferred thirty-five (35) days with regard to the First Interim Properties (as hereinafter defined) prior to the First Interim Closing (as defined below), except as otherwise specified with regard to notices for Title Defects concerning the First Interim Properties, which shall be made no later than 5:00 pm, CDT, on the date that is two (2) days prior to the First Interim Closing Date), the Parties shall close (herein the “First Interim Closing”) the sale by Seller to Buyer of the same undivided interests described in Section 1(a) in and to the Supplemental Leases acquired by Seller during such Interim Period, together with the other related interests described in clauses (b), (c), (d), and (e) of Section 1 (collectively, the “First Interim Properties”), together with those Leases and related interests which were formerly part of the Initial Properties that are now identified on Part 2(b) of Exhibit A as being part of the Supplemental Leases (and which shall be deemed to constitute First Interim Properties for purposes hereof), on May 24, 2012 (the “First Interim Closing Date”), pursuant to the other terms of this Agreement. If an oil and gas lease that would otherwise constitute an Initial Lease or a First Interim Property for purposes of this Agreement is withheld from, as applicable, the First Closing or the First Interim Closing pursuant to Section 19(a)(ii), such oil and gas lease, to the extent it is not ultimately excluded from this Agreement by operation of Section 19(a)(ii) or Section 20, shall be treated, for all purposes hereof, as a Supplemental Lease, governed by the terms of Section 2(b) and/or Section 2(c), as applicable.”

“(b) With respect to those Supplemental Leases (if any) that are either (i) acquired by Seller after the Interim Cut Off Date and prior to the expiration of the Supplemental Acquisition Period, or (ii) acquired by Seller during the period between the Execution Date and the Interim Cut Off Date but as to which Seller is unable to confirm Defensible Title prior to the First Interim Closing Date, there shall occur two (2) additional interim closings (each such closing, together with the First Interim Closing, may be referred to as an “Interim Closing”):

Each of the First Interim Closing Date, the Second Interim Closing Date, and the Third Interim Closing Date may be referred to as an “Interim Closing Date”. During the period from and after the First Interim Closing Date until the expiration of the Supplemental Acquisition Period, Seller shall provide to Buyer notices at regular intervals (but no less frequently than weekly) containing copies of the Supplemental Leases acquired to date during such period, together with, as such information becomes available, legal descriptions, lease summary information, and other information required under clause (iii) of the first sentence of Section 2(a), to assist Buyer in performing its due diligence thereon. No later than seven (7) days prior to the Second Interim Closing Date or the Third Interim Closing Date, as applicable, Seller shall provide to Buyer an Interim Closing Notice containing a draft of the supplement to Exhibit A that describes the Supplemental Leases that Seller proposes to include in the relevant Interim Closing, together with any remaining, title-related information acquired by Seller with respect thereto. All other notices provided herein to be given with respect to the Initial Properties in connection with the First Closing shall also be given with respect to the applicable Supplemental Leases in connection with the Second Interim Closing and the Third Interim Closing and shall also be due no later than seven (7) days prior to the relevant Interim Closing Date; provided, however, that the deadline for Buyer’s submission of notices of Title Defects with respect to each such group of Supplemental Leases shall be 5:00 p.m., CDT, on the second day prior to the relevant Interim Closing Date. On each of the Second Interim Closing Date and the Third Interim Closing Date, Seller shall sell and convey to Buyer, on the terms set forth in this Agreement, an undivided interest identical to that set forth in Section 1(a) in and to those Supplemental Leases identified in the Interim Closing Notice given in connection with the relevant Interim Closing Date (or as otherwise agreed to by Buyer) as to which Seller has confirmed Defensible Title, as well as the interests related thereto identical to those described in clauses (b), (c), (d), and (e) of Section 1 (in each case, the “Interim Supplemental Properties”). If a Supplemental Lease included in an Interim Closing Notice is withheld from the Second Interim Closing or the Third Interim Closing pursuant to Section 19(a)(ii), such Supplemental Lease, to the extent it is not excluded from this Agreement by operation of Section 19(a)(ii) or Section 20, may be proposed for inclusion in the next Interim Closing under this Section 2(b) or the Supplemental Closing (as defined below) under Section 2(c), as applicable.

“(c) Any oil, gas, and mineral leases covering lands located within the AMI that are acquired by Seller after the expiration of the Supplemental Acquisition Period shall not constitute Supplemental Leases governed by this Section 2, but shall be governed by the provisions of Section 5. With respect to those Supplemental Leases acquired by Seller after the Interim Cut Off Date and prior to the expiration of the Supplemental Acquisition Period that have not been excluded from this

Agreement by operation of Section 19(a)(ii) or Section 20 and that are not, for any reason, included in either the Second Interim Closing or the Third Interim Closing, there shall occur a final, supplemental closing (the “Supplemental Closing”), which shall occur on August 16, 2012 (the “Supplemental Closing Date”). To the extent that Seller has not already done so prior to the Third Interim Closing Date, Seller shall, as promptly as possible after the Third Interim Closing Date, provide to Buyer copies of such remaining Supplemental Leases, together with legal descriptions, lease summary information, and other information required under clause (iii) of the first sentence of Section 2(a) to assist Buyer in performing its due diligence thereon. No later than seven (7) days prior to the Supplemental Closing Date, Seller shall provide to Buyer a notice (the “Supplemental Closing Notice”) containing a draft of the supplement to Exhibit A that describes the Supplemental Leases that Seller proposes to include in the Supplemental Closing, together with any remaining title-related information acquired by Seller with respect thereto. All other notices provided herein to be given with respect to the Initial Properties in connection with the First Closing shall also be given with respect to the applicable Supplemental Leases in connection with the Supplemental Closing and shall also be due no later than seven (7) days prior to the Supplemental Closing Date; provided, however, that the deadline for Buyer’s submission of notices of Title Defects with respect to such group of Supplemental Leases shall be 5:00 p.m., CDT, on the third day prior to the Supplemental Closing Date. On the Supplemental Closing Date, Seller shall sell and convey to Buyer, on the terms set forth in this Agreement, an undivided interest identical to that set forth in Section 1(a) in and to those Supplemental Leases identified in the Supplemental Closing Notice (or as otherwise agreed to by Buyer) as to which Seller has confirmed Defensible Title, as well as the interests related thereto identical to those described in clauses (b), (c), (d), and (e) of Section 1 (in each case, the “Supplemental Properties”). If a Supplemental Lease is withheld from all of the Interim Closings and the Supplemental Closing pursuant to Section 19(a)(ii), such Supplemental Lease shall thereupon cease to be subject to this Agreement, in accordance with the terms of Section 19(a)(ii).

“(d) For purposes hereof, each Initial Lease and each Supplemental Lease may be referred to herein, individually, as a “Lease” and, collectively, as the “Leases”; and each Initial Property, each First Interim Property, each Interim Supplemental Property, and each Supplemental Property may be referred to herein, individually, as a “Property” and, collectively, as the “Properties.” Except with regard to the Interim Purchase Prices paid by Buyer to Seller pursuant to Section 3(c) and the Supplemental Purchase Price paid by Buyer to Seller pursuant to Section 3(d), Buyer shall have no responsibility for (and Seller, alone, shall bear and pay) any acquisition costs related to the First Interim Properties, the Interim Supplemental Properties, or the Supplemental Properties.”

(d) Current Section 2(c) of the Purchase Agreement is hereby relettered as Section 2(e).

2. Amendments to Section 3 of the Purchase Agreement. Section 3 of the Purchase Agreement is amended in the following respects:

(a) Sections 3(a), 3(b), and 3(c) are hereby deleted in their entirety and are replaced for all purposes with the following:

“(a) The total consideration for the sale of the Properties (the “Consideration”) shall be the sum of (i) the Initial Purchase Price, the Interim Purchase Prices, and the Supplemental Purchase Price, as defined hereinafter, paid by Buyer to Seller for the Properties actually conveyed by Seller to Buyer at the First Closing, the Interim Closings, and the Supplemental Closing (collectively, the “Purchase Price”), plus (ii) the Contingent Payment, if any, to be paid in accordance with Section 4 below.

“(c) With respect to each Interim Closing that occurs hereunder, on each Interim Closing Date, Buyer shall pay to Seller, as the “Interim Purchase Price” payable at such Interim Closing, an amount, calculated in the same manner as the Initial Purchase Price, with respect to the First Interim Properties or the Interim Supplemental Properties, as applicable, actually conveyed by Seller to Buyer at such Interim Closing, subject to adjustment pursuant to Section 17.”

3. Amendments to Sections 6 and 7 of the Purchase Agreement (Representations and Warranties of Seller and Buyer). Sections 6 and 7 of the Purchase Agreement are supplemented and amended to provide that: (a) the representations and warranties of, respectively, Seller and Buyer are also made again, in each case, as of each Interim Closing Date; and (b) any representations and warranties of Seller made in Section 6 with respect to the Properties shall: (i) if made as of the First Interim Closing Date, refer to the Interim Properties; and (ii) if made as of the Second Interim Closing Date or the Third Interim Closing Date, refer to the Interim Supplemental Properties to be conveyed by Seller to Buyer at such Interim Closing.

4. Amendments to Sections 9, 10, and 17 of the Purchase Agreement. Sections 9, 10, and 17 of the Amended Purchase Agreement are hereby amended to add references to the First Interim Properties, the Interim Supplemental Properties, the Interim Closings, and the Interim Closing Dates, as appropriate, in conjunction with the references contained in such Sections to the Supplemental Properties, the Supplemental Closing, and the Supplemental Closing Date.

5. Amendment to Section 12 of the Purchase Agreement (Covenants Prior to Closing). The parenthetical appearing in the second and third lines of Section 12 of the Purchase Agreement is amended to read as follows:

“… (or, as the case may be, with regard to the Interim Properties, until the First Interim Closing Date; with regard to the Interim Supplemental Properties, until the Second Interim Closing Date or the Third Interim Closing Date, as applicable; and with regard to the Supplemental Properties, until the Supplemental Closing Date), …”

6. Amendments to Section 15 of the Purchase Agreement (Closings). Section 15 of the Purchase Agreement is amended in the following respects:

(a) The first, second, and third sentences of Section 15 are amended to read as follows:

“Subject to the terms and conditions of this Agreement, the closing of the sale by Seller and the purchase by Buyer of the Initial Properties pursuant to this Agreement (the “First Closing”) shall occur on April 19, 2012, or such other date as Buyer and Seller may agree upon in writing (the “First Closing Date”), at the offices of Seller, or at such other location as may be selected by the Parties. Each Interim Closing shall occur on the Interim Closing Date established therefor in Section 2(a) or Section 2(b), and the Supplemental Closing shall occur on the Supplemental Closing Date as provided in Section 2(c), also at the offices of Seller, or at such other location as may be selected by the Parties. For purposes of this Agreement, the First Closing, each of the Interim Closings, and the Supplemental Closing may each be referred to, individually, as a “Closing” and, collectively, as the “Closings”; and the First Closing Date, each Interim Closing Date, and the Supplemental Closing Date may each be referred to, individually, as a “Closing Date” and, collectively, as the “Closing Dates”.”

“In addition, at each Interim Closing and the Supplemental Closing, Seller and Buyer shall execute and deliver amendments to, respectively, Exhibit A to this Agreement, Exhibit A to the JOA, and Exhibit A to the Recording Supplement executed in connection with the JOA that add, in each case, the descriptions of the Supplemental Leases comprising the First Interim Properties, the Interim Supplemental Properties, and the Supplemental Properties, as applicable, and lists the Working Interests and Net Revenue Interests of Seller therein, the Net Mineral Acres covered thereby, and the expiration dates thereof.”

7. Amendments to Section 16 of the Purchase Agreement (Termination). Section 16 of the Purchase Agreement is amended in the following respects:

(a) Section 16(c) is deleted in its entirety and the following provision is substituted therefor:

“(c) If the First Closing occurs, but none of the Interim Closings nor the Supplemental Closing has occurred as of the Supplemental Closing Date: (i) this Agreement (including the provisions relating to the AMI) shall remain in full force and effect and shall not be terminated; (ii) subject to the terms of Section 16(d), the First Interim Properties, the Interim Supplemental Properties, and the Supplemental Properties intended to be conveyed to Buyer at the Interim Closings and the Supplemental Closing, as applicable, shall cease to be subject to the terms of this Agreement; (iii) subject to the terms of Section 16(d), Seller shall be entitled to own and hold the oil and gas leases comprising such First Interim Properties, Interim Supplemental Properties, and Supplemental Properties for its own account and at its sole cost and expense, free and clear of the terms of this Agreement, including those relating to the AMI; and (iv) neither Party shall be relieved of any unfulfilled obligation or Liability of such Party under this Agreement with respect to such Properties or the applicable Closing that accrued prior to the Supplemental Closing Date (including any undischarged obligation to pay money) or the consequences of any inaccuracy in or breach by such Party of a representation, warranty, or covenant in this Agreement relating to the First Interim Properties, the Interim Supplemental Properties, or Supplemental Properties or any Interim Closing or the Supplemental Closing occurring prior to or on the Supplemental Closing Date.”

(b) The condition stated in clause (i) of the first sentence of Section 16(d) is amended to read as follows:

“If, (i) (A) as of June 1, 2012, the First Closing has not occurred, or (B), as of an Interim Closing Date, the corresponding Interim Closing has not occurred, or (c) as of the Supplemental Closing Date, the Supplemental Closing has not occurred, but …”

8. Amendments to Section 19 of the Purchase Agreement (Matters Relating to Title). Section 19 of the Purchase Agreement is amended in the following respects:

“If Buyer determines that any Title Defect (as defined below) exists, then Buyer shall provide written notice of such Title Defect to Seller promptly after the discovery thereof, but in no event later than April 13, 2012, with regard to the Initial Properties (and no later than 5:00 pm, CDT, on the date that is two (2) days prior to the relevant Interim Closing Date with regard to the First Interim Properties or the Interim Supplemental Properties identified in the Interim Closing Notice for such Interim Closing, and no later than 5:00 pm, CDT, on the date that is three (3) days prior to the Supplemental Closing Date with regard to the Supplemental Properties).”

(b) The proviso appearing at the end of the first sentence of Section 19(a)(i) is amended to read as follows:

“…; provided, however, that in the case of agreed upon Title Defects asserted with respect to an Initial Property that is not cured to Buyer’s reasonable satisfaction prior to the First Closing or a First Interim Property or an Interim Supplemental Property that is not cured to Buyer’s reasonable satisfaction prior to the applicable Interim Closing Date, then notwithstanding the preceding provisions of this Section 19(a)(i), the provisions of Section 19(a)(ii) and Section 19(a)(iii) shall automatically apply.”

Notwithstanding the provisions of Section 19(a)(i), if a Title Defect affecting an Initial Property, a First Interim Property, or an Interim Supplemental Property is reasonably susceptible to cure, and Seller notifies Buyer in writing prior to the applicable Closing Date that it desires to cure such Title Defect, then (A) the affected Property (or the affected portion thereof, if the Title Defect is of such a nature as to be easily segregated as to only a portion of the affected Property and Defensible Title to the rest of such Property can otherwise be conveyed as contemplated in this Agreement at the applicable Closing, and the Parties can agree on the Title Defect Amount to be applied with regard to the portion to be held back) shall be held back from, as applicable, the First Closing or the relevant Interim Closing; (2) the Initial Purchase Price or the relevant Interim Purchase Price, as applicable, shall be reduced by the applicable Title Defect Amount (or the full Allocated Value of the affected Property, if such Property is held back in its entirety from the relevant Closing); (3) Seller shall have until the Supplemental Closing Date to attempt to cure, to Buyer’s reasonable satisfaction, the relevant Title Defect; (4) if such Title Defect is cured to Buyer’s reasonable satisfaction within such period, the affected Property (or portions thereof) as to which such Title Defect has been cured shall be treated as a First Interim Property, an Interim Supplemental Property, or a Supplemental Property, as the case may be, and conveyed to Buyer at the applicable Closing; and (5) as to those Properties (or portions thereof) as to which Seller is unable to cure such Title Defects to Buyer’s reasonable satisfaction prior to the Supplemental Closing Date, then unless waived by Buyer in writing after Seller has notified Buyer in writing of its inability to cure such Title Defects, Seller shall have no further obligation hereunder to sell, and Buyer shall have no further obligation hereunder to purchase, the affected Properties (or portions thereof) held back from the Closings due to the existence of such uncured Title Defects, and the oil and gas leases comprising such Properties shall thereupon cease to be subject to the terms of this Agreement (including the provisions related to the AMI).

9. Amendments to Section 20 of the Purchase Agreement (Access; Environmental Defects). The time frames set forth in Section 20(a) during which Seller affords Buyer due diligence access to the Leases are amended to run from the Execution Date until: (i) the First Closing Date with respect to the Initial Leases; (ii) the First Interim Closing Date with respect to the First Interim Properties; (iii) the Second Interim Closing Date or the Third Interim Closing Date, as applicable, with respect to the Interim Supplemental Properties; and (iv) the Supplemental Closing Date with respect to the Supplemental Properties. In like manner, Buyer’s confidentiality obligation with respect to the results of the Assessment covering the Leases is amended to continue through: (i) the First Closing Date with respect to the Initial Leases; (ii) the First Interim Closing Date with respect to the First Interim Properties; (iii) the Second Interim Closing Date or the Third Interim Closing Date, as applicable, with respect to the Interim Supplemental Properties; and (iv) the Supplemental Closing Date with respect to the Supplemental Properties. In like manner, the time frame by which Buyer must assert Environmental Defects under Section 20(d) shall be (i) the First Closing Date with respect to the Initial Leases; (ii) the First Interim Closing Date with respect to the First Interim Properties; (iii) the Second Interim Closing Date or the Third Interim Closing Date, as applicable, with respect to the Interim Supplemental Properties; and (iv) the Supplemental Closing Date with respect to the Supplemental Properties.

10. Amendments to Section 31 of the Purchase Agreement (Additional Definitions).

(a) The definition of “Effective Time” in Section 31 of the Purchase Agreement is amended to read as follows:

“Effective Time” means 7:00 a.m., Central Standard or Daylight time, as applicable, on (a) with respect to the Initial Properties, the First Closing Date, (b) with respect to the First Interim Properties, the First Interim Closing Date, (c) with respect to the Interim Supplemental Properties to be conveyed at the Second Interim Closing, the Second Interim Closing Date, (d) with respect to the Interim Supplemental Properties to be conveyed at the Third Interim Closing, the Third Interim Closing Date, and (e) with respect to the Supplemental Properties, the Supplemental Closing Date.

11. References. All references to the Purchase Agreement in any document, instrument, agreement, or writing delivered pursuant to the Purchase Agreement (as amended hereby) shall hereafter be deemed to refer to the Purchase Agreement as amended hereby.

12. Counterparts. This Second Amendment may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile transmission shall be deemed an original signature hereto.

13. Ratification. The Purchase Agreement, as amended hereby, is hereby adopted, ratified, and confirmed by Buyer and Seller.

IN WITNESS WHEREOF, the Parties have executed this Agreement as of the date first written above.

This Third Amendment to Purchase and Sale Agreement (this “Third Amendment”), is dated as of May 24, 2012, by and between Energy & Exploration Partners, LLC, a Delaware limited liability company (“Seller”), and Halcón Energy Properties, Inc., a Delaware corporation (and f/k/a RWG Energy, Inc.) (“Buyer”). Seller and Buyer are sometimes referred to herein, individually, as a “Party” and, collectively, as the “Parties.”

NOW, THEREFORE, in consideration of the mutual covenants and conditions set forth herein and in the Purchase Agreement, Buyer and Seller hereby agree as follows:

1. Exhibit A. Exhibit A attached to the Purchase Agreement is amended to add thereto the descriptions of, and other information required under Section 2(a) of the Purchase Agreement relating to, those Supplemental Leases identified on Exhibit A to this Third Amendment. At the First Interim Closing, Seller shall sell to Buyer, subject to and in accordance with the terms of the Purchase Agreement, an undivided interest identical to that set forth in Section 1(a) of the Purchase Agreement in and to the Supplemental Leases described on Exhibit A to this Third Amendment, together with the interests related thereto identical to those described in clauses (b), (c), (d), and (e) of Section 1 of the Purchase Agreement, which interests in such Supplemental Leases shall constitute the First Interim Properties for all purposes of the Purchase Agreement.

2. Interim Purchase Price. The Interim Purchase Price payable by Buyer to Seller at the First Interim Closing under Section 3(c) of the Purchase Agreement shall be as set forth on Exhibit B to this Third Amendment.

3. References. All references to the Purchase Agreement in any document, instrument, agreement, or writing delivered pursuant to the Purchase Agreement (as amended hereby) shall hereafter be deemed to refer to the Purchase Agreement as amended hereby.

4. Counterparts. This Third Amendment may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile transmission shall be deemed an original signature hereto.

5. Ratification. The Purchase Agreement, as amended hereby, is hereby adopted, ratified, and confirmed by Buyer and Seller.

IN WITNESS WHEREOF, the Parties have executed this Third Amendment as of the date first written above.

This Fourth Amendment to Purchase and Sale Agreement (this “Fourth Amendment”), is dated as of June 21, 2012, by and between Energy & Exploration Partners, LLC, a Delaware limited liability company (“Seller”), and Halcón Energy Properties, Inc., a Delaware corporation (and f/k/a RWG Energy, Inc.) (“Buyer”). Seller and Buyer are sometimes referred to herein, individually, as a “Party” and, collectively, as the “Parties.”

WHEREAS, Buyer and Seller entered into that certain Purchase and Sale Agreement (Non-Producing Properties) dated as of March 5, 2012, as amended by First Amendment to Purchase and Sale Agreement dated as of April 19, 2012, Second Amendment to Purchase and Sale Agreement dated as of May 10, 2012, and Third Amendment to Purchase and Sale Agreement dated as of May 24, 2012, (as so amended, the “Purchase Agreement”); and

NOW, THEREFORE, in consideration of the mutual covenants and conditions set forth herein and in the Purchase Agreement, Buyer and Seller hereby agree as follows:

1. Exhibit A. Exhibit A attached to the Purchase Agreement is amended to add thereto the descriptions of, and other information required under Section 2(a) of the Purchase Agreement relating to, those Supplemental Leases identified on Exhibit A to this Fourth Amendment. At the Second Interim Closing, Seller shall sell to Buyer, subject to and in accordance with the terms of the Purchase Agreement, an undivided interest identical to that set forth in Section 1(a) of the Purchase Agreement in and to the Supplemental Leases described on Exhibit A to this Fourth Amendment, together with the interests related thereto identical to those described in clauses (b), (c), (d), and (e) of Section 1 of the Purchase Agreement, which interests in such Supplemental Leases shall constitute Interim Supplemental Properties for all purposes of the Purchase Agreement.

2. Interim Purchase Price. The Interim Purchase Price payable by Buyer to Seller at the Second Interim Closing under Section 3(c) of the Purchase Agreement shall be as set forth on Exhibit B to this Fourth Amendment.

3. Exhibit C. Exhibit C attached to the Purchase Agreement, which described the AMI, is deleted in its entirety and is replaced by the plat attached to this Fourth Amendment as Exhibit C. Buyer and Seller hereby designate, as the AMI created under the terms of the Purchase Agreement, the outlined area in Madison, Grimes, and Walker Counties, Texas, shown on Exhibit C to this Fourth Amendment, effective as of March 5, 2012.

4. References. All references to the Purchase Agreement in any document, instrument, agreement, or writing delivered pursuant to the Purchase Agreement (as amended hereby) shall hereafter be deemed to refer to the Purchase Agreement as amended hereby.

5. Counterparts. This Fourth Amendment may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile transmission shall be deemed an original signature hereto.

6. Ratification. The Purchase Agreement, as amended hereby, is hereby adopted, ratified, and confirmed by Buyer and Seller.

IN WITNESS WHEREOF, the Parties have executed this Fourth Amendment as of the date first written above.

This Fifth Amendment to Purchase and Sale Agreement (this “Fifth Amendment”), is dated as of July 16, 2012, by and between Energy & Exploration Partners, LLC, a Delaware limited liability company (“Seller”), and Halcón Energy Properties, Inc., a Delaware corporation (and f/k/a RWG Energy, Inc.) (“Buyer”). Seller and Buyer are sometimes referred to herein, individually, as a “Party” and, collectively, as the “Parties.”

WHEREAS, Buyer and Seller entered into that certain Purchase and Sale Agreement (Non-Producing Properties) dated as of March 5, 2012, as amended by First Amendment to Purchase and Sale Agreement dated as of April 19, 2012, Second Amendment to Purchase and Sale Agreement dated as of May 10, 2012, Third Amendment to Purchase and Sale Agreement dated as of May 24, 2012, and Fourth Amendment to Purchase and Sale Agreement dated as of June 21, 2012 (as so amended, the “Purchase Agreement”); and

NOW, THEREFORE, in consideration of the mutual covenants and conditions set forth herein and in the Purchase Agreement, Buyer and Seller hereby agree as follows:

1. Amendments to Section 2 of the Purchase Agreement (Supplemental Properties). Section 2 of the Purchase Agreement is amended in the following respects:

(a) In the first sentence of Section 2(a), the term “Supplemental Acquisition Period” is redefined as the period from and after the Execution Date and continuing until July 31, 2012.

(b) In clause (2) of the first sentence of Section 2(b), the term “Third Interim Closing Date” is redefined as July 31, 2012.

2. References. All references to the Purchase Agreement in any document, instrument, agreement, or writing delivered pursuant to the Purchase Agreement (as amended hereby) shall hereafter be deemed to refer to the Purchase Agreement as amended hereby.

3. Counterparts. This Fifth Amendment may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile transmission shall be deemed an original signature hereto.

4. Ratification. The Purchase Agreement, as amended hereby, is hereby adopted, ratified, and confirmed by Buyer and Seller.

IN WITNESS WHEREOF, the Parties have executed this Fifth Amendment as of the date first written above.

This Sixth Amendment to Purchase and Sale Agreement (this “Sixth Amendment”), is dated as of July 31, 2012, by and between Energy & Exploration Partners, LLC, a Delaware limited liability company (“Seller”), and Halcón Energy Properties, Inc., a Delaware corporation (and f/k/a RWG Energy, Inc.) (“Buyer”). Seller and Buyer are sometimes referred to herein, individually, as a “Party” and, collectively, as the “Parties.”

WHEREAS, Buyer and Seller entered into that certain Purchase and Sale Agreement (Non-Producing Properties) dated as of March 5, 2012, as amended by First Amendment to Purchase and Sale Agreement dated as of April 19, 2012, Second Amendment to Purchase and Sale Agreement dated as of May 10, 2012, Third Amendment to Purchase and Sale Agreement dated as of May 24, 2012, Fourth Amendment to Purchase and Sale Agreement dated as of June 21, 2012, and Fifth Amendment to Purchase and Sale Agreement dated as of July 16, 2012 (as so amended, the “Purchase Agreement”); and

NOW, THEREFORE, in consideration of the mutual covenants and conditions set forth herein and in the Purchase Agreement, Buyer and Seller hereby agree as follows:

1. Exhibit A. Exhibit A attached to the Purchase Agreement is amended to add thereto the descriptions of, and other information required under Section 2(a) of the Purchase Agreement relating to, those Supplemental Leases identified on Exhibit A to this Sixth Amendment. At the Third Interim Closing, Seller shall sell to Buyer, subject to and in accordance with the terms of the Purchase Agreement, an undivided interest identical to that set forth in Section 1(a) of the Purchase Agreement in and to the Supplemental Leases described on Exhibit A to this Sixth Amendment, together with the interests related thereto identical to those described in clauses (b), (c), (d), and (e) of Section 1 of the Purchase Agreement, which interests in such Supplemental Leases shall constitute Interim Supplemental Properties for all purposes of the Purchase Agreement.

2. Interim Purchase Price. The Interim Purchase Price payable by Buyer to Seller at the Third Interim Closing under Section 3(c) of the Purchase Agreement shall be as set forth on Exhibit B to this Sixth Amendment.

4. Counterparts. This Sixth Amendment may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile transmission shall be deemed an original signature hereto.

5. Ratification. The Purchase Agreement, as amended hereby, is hereby adopted, ratified, and confirmed by Buyer and Seller.

IN WITNESS WHEREOF, Seller has executed this Sixth Amendment as of the date first written above.

IN WITNESS WHEREOF, Buyer has executed this Sixth Amendment as of the date first written above.

The parties to this Lease Purchase Agreement (this “Agreement”), dated as of the 5th day of April, 2012 (the “Execution Date”), are HERD PRODUCING COMPANY, INC. (hereinafter referred to as “Seller”), and ENERGY & EXPLORATION PARTNERS, LLC (hereinafter referred to as “Buyer”). Seller and Buyer are sometimes referred to herein individually as a “Party” and collectively as the “Parties”.

FOR VALUABLE CONSIDERATION, the receipt and sufficiency of which are hereby acknowledged, and in consideration of the mutual covenants and benefits herein set forth, Seller and Buyer agree as follows:

(a) Seller is the owner of certain oil and gas leases and the leasehold estates created thereby, as to all lands and depths covered thereby located in Madison and Grimes Counties, Texas, all as more particularly described on Exhibit A hereto (collectively, the “Leases”), Subject to the terms hereof, Seller agrees to sell and convey to Buyer, and Buyer agrees to purchase and pay for, 100% of the Leases.

(b) The consideration payable by Buyer for the Leases shall be Five Million Three Hundred Thousand Dollars ($5,300,000). Should, however, it be determined that Seller holds Defensible Title to less than one hundred percent (100%) but greater than or equal to ninety percent (90%) of the Net Acres shown on Exhibit A, then at the Conveyance Date Seller is obligated to sell the Title-Approved Leases and Buyer is obligated to purchase the Title-Approved Leases for Five Million Three Hundred Thousand Dollars ($5,300,000). Should, however, it be determined that Seller holds Defensible Title to less than ninety percent (90%) but greater than or equal to eighty percent (80%) of the Net Acres shown on Exhibit A, then at the Conveyance Date Seller is obligated to sell the Title-Approved Leases and Buyer is obligated to purchase the Title-Approved Leases for an amount equal to the product of $736.11 per Net Acre (as defined below) multiplied by the number of Net Acres actually covered by the Leases. The term “Net Acre” shall mean, as to each Lease, Seller’s undivided interest in the oil and gas leasehold estate created by the Lease, multiplied by the number of gross acres covered by the Lease, multiplied by the lessor’s undivided interest in the fee mineral estate in the lands covered by the Lease. No later than the Conveyance Date, should, however, it be determined that Seller holds Defensible Title to less than eighty percent (80%) of Net Acres shown on Exhibit A, Seller and Buyer each has the option, but not the obligation, to terminate this Agreement.

(c) At Conveyance Date, Seller shall execute and deliver to Buyer an assignment of 100% of the Title-Approved Leases to be conveyed at such Conveyance Date. The assignment of the Leases (the “Assignment”) shall be in the form of that attached hereto as Exhibit B, shall be effective as of the applicable Conveyance Date, and shall contain no warranty of title.

(a) The purchase and conveyance of the Leases contemplated hereby shall be consummated at a “Closing” covering Title-Approved Leases identified by Buyer pursuant to Article II. Closing shall take place at 11:00 AM CDT on May 15, 2012, or on such other date as may be fixed by mutual agreement of Seller and Buyer at the offices of Buyer in Fort Worth, Texas. Closing shall be conditional and delayed if necessary until Seller receives confirmation that payment has been received into Seller’s designated bank account. Payment to Seller pursuant to this Section 1.2(a) shall be by bank wire transfer of immediately available U.S. funds to an account designated in writing by Seller to Buyer.

(b) Expedited Closing. Notwithstanding anything herein to the contrary, should a well be spudded by Buyer or Buyer affiliate in search of oil and/or gas within the Prospect Area outlined in Exhibit C attached hereto on or before May 1, 2012, the Closing anticipated in Section 1.2(a) may, at the option of Seller upon written notice to Buyer, be expedited to occur within ten (10) days of such an event or, in the alternative, Seller may elect to terminate this Agreement.

1.3 Transfer of Files. Seller will deliver to Buyer, at Buyer’s offices and at Seller’s expense at Closing, all of Seller’s lease files, assignment files, abstracts and title opinions, (in each case, to the extent transferable), and other similar files and records in its possession which directly relate to the Leases. Seller may, at its election, make and retain copies of any and all such files.

(a) Prior to the Closing Date, Seller shall be entitled to create in favor of itself or its assigns (by grant or reservation, as Seller may choose) an overriding royalty interest of up to 5% of 100% of 8/8ths of the oil, gas and casinghead gas produced and marketed under the provisions of the Leases, any extension thereof, and any renewals and/or top leases with the understanding that if the Lease covers less than all of the oil and gas in the described land, the portion of production herein reserved as an overriding royalty shall be reduced proportionately. Provided, however, that in no event shall Seller be entitled to take any action that would cause the Net Revenue Interest in any Lease subject to this Agreement to be less than 75% (based on 100% of 8/8ths of the oil, gas production and casinghead gas produced and marketed under the provisions of Leases, any extensions thereof, and renewals, and/or top leases) on the Conveyance Date. The obligation to pay the overriding royalty required by this Agreement will exist for the life of the Leases, plus any extension, renewals and/or top leases of the Leases. For purposes of this Agreement, any leasehold interest acquired by Buyer, its successors or assigns, within one (1) year following the termination, cancellation or surrender of one or more of the Leases will be deemed an “extension or renewal,” The overriding royalty interest shall be in the form of that attached hereto as Exhibit D, which terms are incorporated herein, and shall be effective as of the applicable Conveyance Date.

(b) In no event shall any of Seller’s overriding royalty which Seller has granted or reserved as provided in Section 1.4(a) bear any part of the costs of production as well as any pre-production or post-production costs, including without limitation costs of lifting, gathering dehydration, compression, separation, delivery, transportation, manufacture, processing, treating or marketing, or for construction, operation or depreciation of any plant or other facility or equipment for processing or treating oil or gas produced from the leased premises or lands pooled therewith. It is the intent of the parties that the provisions of this section are to be fully effective and enforceable and are not to be construed as “surplusage” under the principles set forth in Heritage Resources v. NationsBank, 939 S.W.2d118 (Tex. 1997).

2.1 Title Review. Buyer shall have until five (5) business days preceding the Final Closing Date to examine title to the Leases (the “Review Period”). During the Review Period, Seller will make available to Buyer, for examination at Seller’s office in Tyler, Texas, all lease, title, and other information in any manner related to the Leases and the ownership thereof, and will cooperate with Buyer in Buyer’s efforts to obtain, at Buyer’s expense, such additional information relating to the Leases as Buyer may reasonably desire, to the extent in each case that Seller may do so without violating any obligation of confidence or other contractual commitment of Seller to a third Person. Seller shall permit Buyer, at Buyer’s expense, to inspect and photocopy such information and records at any reasonable time during the Review Period. Seller shall not be obligated to furnish any updated abstracts of title or title opinions or any additional title information not in the possession or control of Seller, but shall cooperate with Buyer in Buyer’s efforts to obtain, at Buyer’s expense, such additional updated title information as Buyer may reasonably deem prudent.

(a) If, during the Review Period, Buyer determines (after all curative work that can reasonably be obtained has been obtained) that Seller does not hold Defensible Title to any Lease (each such deficiency in Defensible Title is herein called a “Title Defect”), Buyer shall provide Seller as hereinafter provided written notice of the Title Defect and the circumstances underlying such Title Defect (including copies of any title opinions or title reports that reflect such Title Defect). Buyer shall provide Seller before 5:00 PM CDT on April 6, 2012, April 13, 2012, April 27, 2012, May 4, 2012, and May 11, 2012, a written weekly Lease Status Report specifying the Leases which have Defensible Title and the Leases which have been identified as having a Title Defect. For each Lease with a Title Defect, the Title Defect will be specified along with appropriate references and supporting documentation establishing the Title Defect. Title Defects not asserted by Buyer in a timely manner under this Section 2.2(a) shall be deemed to have been waived by Buyer.

(b) “Defensible Title” means such title of Seller that: (i) entitles Seller to ownership of 100% of the oil and gas leasehold estate created by, and the working interest in, each Lease; (ii) entitles Seller to not less than the number of Net Acres set forth for any Lease on Exhibit A; however, Seller shall have or shall be deemed to have Defensible Title with respect to the actual number of net mineral acres whether greater than or less than the number

of Net Acres set forth on Exhibit A; (iii) entitles Seller to receive a Net Revenue Interest in each Lease that is not less than the applicable Minimum Net Revenue Interest for the life of each Lease; and (iv) is free and clear specifically of any mortgages, deeds of trust, federal, state, local, county, municipal, material and mechanics liens and quiet title litigation. The existence of one or more of the following objections to title with respect to a Lease shall not constitute the basis for a claim by Buyer that Seller’s title to such Lease is not Defensible Title: (u) objections to title typically cured by reliance on applicable statutes of limitation; (v) lack of evidence of the persons in possession of land; (w) absence of a release or other evidence of termination of any time-expired oil and gas lease as to which more than 10 years has passed since the expiration of its primary term; (x) absence of ratifications of pooling or unit declarations by owners of non-participating royalty interests or unleased mineral interests in non-drillsite tracts of a pooled unit; (y) incomplete estate proceedings of record; and (z) defective acknowledgements.

(c) Seller at its option but not obligation, at its sole cost, shall have until the business day preceding the Closing within which to cure such Title Defect by acquiring oil and gas leases or other title curative that will cause Seller to hold Defensible Title to the affected Lease(s). Buyer will use its best efforts to assist Seller with respect to curing Title Defects.

(d) After the Closing, Seller shall have an option but not the obligation during an additional period of one hundred and eighty days (ISO) within which to cure the Title Defects affecting all Leases excluded from the Closing pursuant to Section 2.2(b). As soon as Seller has cured Titled Defects with respect to the Leases excluded from the Closing pursuant to Section 2.2(b), Seller shall convey to Buyer, effective as of the applicable Conveyance Date, all of the Leases excluded from the Closing pursuant to Section 2.2(b) as to which the applicable Title Defects have been cured by Seller or waived by Buyer (“Cured Leases”), and Buyer shall pay to Seller an amount equal to $736.11 multiplied by the number of Net Acres covered by the Leases thus conveyed to Buyer. If the Cured Leases and the Title-Approved Leases delivered pursuant to Section 1.1 (c) are greater than or equal to ninety percent (90%) of the total Acres shown on Exhibit A, then Buyer shall pay and Seller shall be entitled to receive one hundred percent (100%) of the contemplated proceeds of this agreement totaling Five Million Three Hundred Thousand Dollars ($5,300,000) as total compensation for the Cured Leases and the Title-Approved Leases and no further amount shall be due, owed or payable from Buyer to Seller,

(e) All Leases affected by Title Defects that are not conveyed by Seller to Buyer at the expiration of the additional 180-day curative period shall thereupon cease to be subject to the terms of this Agreement.

3.1 Representations and Warranties. Seller represents and warrants to Buyer as of Execution Date, and again as of the Conveyance Date, as follows:

(a) Seller (i) is a corporation duly organized, validly existing, and in good standing under the laws of the State of Texas and is duly qualified to do business, and is in good standing as a foreign corporation in the State of Texas, (ii) is duly authorized to enter into this Agreement and consummate the transactions contemplated hereby, and (iii) has all requisite power and authority to own and operate its property (including the Leases).

(b) Valid, Binding and Enforceable. This Agreement (and the other instruments delivered pursuant hereto, when executed and delivered, will constitute) constitutes the legal, valid and binding obligation of Seller, enforceable in accordance with its terms, except as limited by bankruptcy or other laws applicable generally to creditor’s rights and as limited by general equitable principles.

(c) Litigation. There are no pending suits, actions, or other proceedings in which Seller is a party (or, to Seller’s knowledge, which have been threatened to be instituted against Seller) which affect the Leases.

(d) Special Warranty of Title. Seller has not and will not convey or encumber any interest in the Leases between the Execution Date and Conveyance Date, except to the extent permitted by Section 1.4.

(e) Neither the execution nor delivery of this Agreement nor the consummation or performance of the transactions contemplated hereby will result in any default under any agreement or instrument to which Seller is a party or by which any of the Leases is bound.

(f) To Seller’s knowledge, none of the Leases (i) are subject to the terms of any preferential right for a third Person to purchase such Lease, a right of first refusal, or any area of mutual interest agreement, (ii) require the consent of any third Person to the valid assignment of such Lease to Buyer, or (iii) have been pooled or unitized.

(g) Seller has not conducted oil and gas exploration, development, or production operations on the Leases, or any lands pooled or unitized therewith.

(h) Seller has filed all Leases of record in Grimes or Madison County and Seller will provide upon request by Buyer a copy of such filed Leases. Seller makes no representation or warranty with respect to the accuracy, correctness and completeness to such copies of the filed Leases.

(i) To Seller’s knowledge and except for items for which an adjustment is made pursuant to Section 2.2 (i) Leases are “paid-up” and require no further lease bonus consideration throughout the remainder of their respective terms, except that the primary terms of certain Leases may be extended with an additional payment; and (ii) all Leases expressly permit pooling.

(j) To Seller’s knowledge there are no outstanding authorities for expenditure or other commitments to make capital expenditures relating to any portion of the Leases that will be binding on Buyer after the Conveyance Date.

(k) To Seller’s knowledge none of the Leases contain any express provision obligating Seller to drill any wells, or contain provisions or conditions (such as continuous drilling clauses but excluding offset drilling obligations) which, if not satisfied, could result in a forfeiture or loss by Seller of all or any part of any Lease.

(1) None of the Leases are subject to a lien or other claim or encumbrance, including, without limitation, any net profits interest, call on production, or obligation to deliver any production from the Leases after the Conveyance Date without the right to be immediately paid for the same which were created by the Seller.

(m) To Seller’s knowledge there are no current active wells located on the Leases.

(n) Seller has not elected not to participate in any operation or activity proposed with respect to any of the Leases that could result in any of Buyer’s interest in any portion of the Leases becoming subject to relinquishment, reassignment, penalty, or forfeiture as a result of such election not to participate in such operation or activity.

(o) Neither Seller, nor any affiliate of Seller, has received, reserved or otherwise obtained any royalty, overriding royalty, net profits interest, production payment, or other burden or encumbrance on any of the Leases that would survive the Closing or otherwise burden any interest in the Leases being conveyed to Buyer at the Closing, insofar as the result thereof would cause the actual Net Revenue Interest in any Lease to be conveyed to Buyer hereunder (calculated based on a 100% of 8/8ths of the oil, gas and casinghead gas produced and marketed under the provisions of the Leases) to fall below 75%.

3.2 Disclaimers. THE EXPRESS REPRESENTATIONS AND WARRANTIES OF SELLER CONTAINED IN SECTION 3.1 ABOVE ARE EXCLUSIVE AND ARE IN LIEU OF ALL OTHER REPRESENTATIONS AND WARRANTIES, EXPRESS, IMPLIED, STATUTORY OR OTHERWISE, AND SELLER EXPRESSLY DISCLAIMS ANY AND ALL SUCH OTHER REPRESENTATIONS AND WARRANTIES. WITHOUT LIMITATION OF THE FOREGOING, THE LEASES SHALL BE CONVEYED PURSUANT HERETO WITHOUT ANY WARRANTY OR REPRESENTATION WHETHER EXPRESS, IMPLIED, STATUTORY OR OTHERWISE, RELATING TO THE CONDITION, QUANTITY, QUALITY, FITNESS FOR A PARTICULAR PURPOSE, CONFORMITY TO THE MODELS OR SAMPLES OF MATERIALS OR MERCHANTABILITY OF ANY EQUIPMENT OR ITS FITNESS FOR ANY PURPOSE, AND, EXCEPT AS PROVIDED OTHERWISE IN THE FIRST SENTENCE OF THIS PARAGRAPH, WITHOUT ANY OTHER EXPRESS, IMPLIED, STATUTORY OR OTHER WARRANTY OR REPRESENTATION WHATSOEVER. BUYER SHALL HAVE INSPECTED, OR WAIVED (AND UPON CLOSING SHALL BE DEEMED TO HAVE WAIVED) ITS RIGHT TO INSPECT, THE LEASES FOR ALL PURPOSES AND SATISFIED ITSELF AS TO THEIR PHYSICAL AND ENVIRONMENTAL CONDITION, BOTH SURFACE AND SUBSURFACE, INCLUDING BUT NOT LIMITED TO CONDITIONS SPECIFICALLY RELATED TO THE PRESENCE, RELEASE OR DISPOSAL OF HAZARDOUSE SUBSTANCES, SOLID WASTES, ASBESTOS AND OTHER MAN MADE FIBERS, OR NATURALLY OCCURRING RADIOACTIVE MATERIALS (“NORM”). BUYER IS RELYING SOLELY UPON ITS OWN INSPECTION OF THE LEASES, AND BUYER SHALL ACCEPT ALL OF THE SAME IN THEIR “AS IS,” “WHERE IS” CONDITION. ALSO

WITHOUT LIMITATION OF THE FOREGOING, SELLER MAXES NO WARRANTY OR REPRESENTATION, EXPRESS, IMPLIED, STATUTORY OR OTHERWISE, AS TO THE ACCURACY OR COMPLETENESS OF ANY DATA, REPORTS, RECORDS, PROJECTIONS, INFORMATION OR MATERIALS NOW, HERETOFORE OR HEREAFTER FURNISHED OR MADE AVAILABLE TO BUYER IN CONNECTION WITH THIS AGREEMENT INCLUDING, WITHOUT LIMITATION, RELATIVE TO PRICING ASSUMPTIONS, OR QUALITY OR QUANTITY OF HYDROCARBON RESERVES (IF ANY) ATTRIBUTABLE TO THE LEASES OR THE ABILITY OR POTENTIAL OF THE LEASES TO PRODUCE HYDROCARBONS OR THE ENVIRONMENTAL CONDITIONS OF THE LEASES OR ANY OTHER MATTERS CONTAINED IN ANY MATERIALS FURNISHED OR MADE AVAILABLE TO BUYER BY SELLER OR BY SELLER’S AGENTS OR REPRESENTATIVES. ANY AND ALL SUCH DATA, RECORDS, REPORTS, PROJECTIONS, INFORMATION AND OTHER MATERIALS (WRITTEN OR ORAL) FURNISHED BY SELLER OR OTHERWISE MADE AVAILABLE OR DISCLOSED TO BUYER ARE PROVIDED BUYER AS A CONVENIENCE AND SHALL NOT CREATE OR GIVE RISE TO ANY LIABILITY OF OR AGAINST SELLER AND ANY RELIANCE ON OR USE OF THE SAME SHALL BE AT BUYER’S SOLE RISK TO THE MAXIMUM EXTENT PERMITTED BY LAW.

4.1 Representations and Warranties. Buyer represents and warrants to Seller Execution Date and the Conveyance Date, as follows:

(a) Buyer (i) is a limited liability company duly formed, validly existing, and in good standing under the Laws of the State of Delaware and is duly qualified or licensed to do business and is in good standing as a foreign limited liability company in each jurisdiction in which the character or location of its assets or properties (whether owned, leased, or licensed) or the nature of its business makes such qualification necessary, (ii) is duly authorized to enter into this Agreement and consummate the transactions contemplated hereby, and (iii) has all requisite power and authority to own and operate its property.

(b) Arrangement for Funds. Buyer has, or has unconditionally arranged for, the funds necessary to purchase the Leases from Seller and will cause the timely availability of such funds for the purposes of consummating the purchase of the Leases in accordance with the terms of this Agreement.

(c) Approvals. Other than requirements (if any) that there be obtained consents to assignment (or waivers of preferential rights to purchase) from third parties, and except for Routine Governmental Approvals, to Buyer’s knowledge, neither the execution and delivery of this Agreement, nor the consummation of the transactions contemplated hereby, nor the compliance with the terms hereof, will result in any default under any agreement to which Buyer is a party, or violate any order, decree, statute, rule or regulation applicable to Buyer

(d) Valid, Binding and Enforceable. This Agreement constitutes the legal, valid and binding obligation of Buyer, enforceable in accordance with its terms, except as limited by bankruptcy or other laws applicable generally to creditor’s rights and as limited by general equitable principles.

(e) No Litigation. There are no pending suits, actions, or other proceedings in which Buyer is a party (or, to Buyer’s knowledge, which have been threatened to be instituted against Buyer) which affect the execution and delivery of this Agreement or the consummation of the transactions contemplated hereby.

(f) Knowledgeable Buyer, No Distribution. Buyer is a knowledgeable purchaser, owner and operator of oil and gas properties, has the ability to evaluate the Leases for purchase, and is acquiring the Leases for its own account and not with the intent to make a distribution in violation of the Securities Act of 1933 as amended or in violation of any other applicable securities laws, rules or regulations.

(g) Waiver of Objections. Buyer acknowledges that it has conducted certain due diligence with respect to the Leases (including, but not limited to, title and environmental), and understands that it has waived upon Closing all objections, if any, it may have had with respect to matters covered by such due diligence, and that it may no longer assert any objections with respect to such matters against Seller in any way.

5.1 Independent Evaluation. Buyer represents and acknowledges that it is knowledgeable of the oil and gas business and of the usual and customary practices of producers such as Seller and that it has had access to the officers and employees of Seller, and the books, records and files of Seller relating to the Leases. In making the decision to enter into this Agreement and consummate the transactions contemplated hereby, Buyer has relied solely on its own independent due diligence investigation of the Leases and upon the representations and warranties made by Seller in Article III of this Agreement.

6.1 Assumption and Indemnification. Buyer shall, on the date of Closing, agree (and, upon the delivery to Buyer of the Assignments, shall be deemed to have agreed), (a) to assume, and to timely pay and perform, all duties, obligations and liabilities relating to the ownership of the Leases regardless of whether the same relate to periods before or after the Closing, and (b) to indemnify and hold Seller (and Seller’s employees, attorneys, contractors and agents) harmless from and against any and all claims, actions, causes of action, liabilities, damages, losses, costs or expenses (including, without limitation, court costs and attorneys’ fees) of any kind or character arising out of or otherwise relating to the ownership and/or operation of the Leases, regardless of whether the same relate to periods before or after the Closing. In connection with (but not in limitation of) the foregoing, it is specifically understood and agreed that such duties, obligations and liabilities include all matters arising out of the condition of the Leases on the date of Closing (including, without limitation, all orders, including conducting

any remediation activities which may be required on or otherwise in connection with activities on the Leases), regardless of whether such condition or the events giving rise to such condition arose or occurred before or after the Closing, and the indemnifications by Buyer provided for in the first sentence of this section shall expressly cover and include such matters. THE FOREGOING ASSUMPTIONS AND INDEMNIFICATIONS SHALL APPLY WHETHER OR NOT SUCH DUTIES, OBLIGATIONS OR LIABILITIES, OR SUCH CLAIMS, ACTIONS, CAUSES OF ACTION, LIABILITIES, DAMAGES, LOSSES, COSTS OR EXPENSES ARISE OUT OF (i) NEGLIGENCE, (INCLUDING SOLE NEGLIGENCE, SINGLE NEGLIGENCE, CONCURRENT NEGLIGENCE, ACTIVE OR PASSIVE NEGLIGENCE, BUT EXPRESSLY NOT INCLUDING GROSS NEGLIGENCE OR WILFUL MISCONDUCT) OF ANY INDEMNIFIED PARTY, OR (ii) STRICT LIABILITY.

6.2 Limitation on Damages. Subject to any limitations on the total amount of indemnification for which either Party is liable hereunder for any breach or non-performance by any Party of any representation, warranty, covenant, or agreement contained in this Agreement, the liability of the obligor shall be limited to direct actual damages only, except to the extent that the obligee is entitled to specific performance or injunctive relief. AS BETWEEN THE PARTIES, NOTWITHSTANDING ANYTHING TO THE CONTRARY IN THIS AGREEMENT, NEITHER SELLER NOR BUYER SHALL BE LIABLE TO THE OTHER PARTY AS THE RESULT OF A BREACH OR A VIOLATION OF ANY REPRESENTATION, WARRANTY, COVENANT, AGREEMENT, OR CONDITION CONTAINED IN THIS AGREEMENT FOR SPECIAL, CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS, OR OTHER BUSINESS INTERRUPTION DAMAGES, IN TORT, IN CONTRACT, UNDER ANY INDEMNITY PROVISION, OR OTHERWISE. WITH RESPECT TO CLAIMS BY THIRD PERSONS, THE INDEMNIFIED PARTY MAY RECOVER FROM THE INDEMNIFYING PARTY ALL COSTS, EXPENSES, OR DAMAGES, INCLUDING, WITHOUT LIMITATION, SPECIAL, CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY, OR INDIRECT DAMAGES, LOST PROFITS, OR OTHER BUSINESS INTERRUPTION DAMAGES, OTHER THAN AND IN ADDITION TO ACTUAL DIRECT DAMAGES PAID OR OWED TO ANY SUCH THIRD PERSON IN SATISFACTION OF CLAIMS WHICH HAVE BEEN LITIGATED AND FINALLY DETERMINED ON APPEAL AS TO WHICH THE INDEMNIFIED PARTY IS ENTITLED TO INDEMNIFICATION HEREUNDER.

7.1 If this Agreement is terminated as provided in this Agreement prior to the Closing Date, all further obligations of the Parties under this Agreement shall terminate; provided, however, that the Parties shall, in any event, remain bound by and continue to be subject to this Section 3.2, Article VI, Section 8.3, and Section 8.6, all of which provisions will survive the termination of this Agreement. If this Agreement is terminated prior to the Closing Date by Seller or Buyer pursuant to Section 1.1(b), neither Party shall have any further liability to the other Party as the result of such termination. If a Party resorts to legal proceedings to enforce

this Agreement or any part thereof, the prevailing Party in such proceedings shall be entitled to recover all costs incurred by such Party, including reasonable attorneys’ fees, in addition to any other relief to which such Party may be entitled.

8.1 No Commissions Owed. Seller and Buyer shall each individually bear the sole responsibility for any broker’s commissions incurred by them relating to this transaction, and shall indemnify the other from and against any and all claims, actions, causes of action, liabilities, damages, losses, costs or expenses (including, without limitation, court costs and attorneys’ fees) of any kind or character arising out of or resulting from any agreement with any broker or finder in connection with this Agreement or the transaction contemplated hereby.

8.2 Certain Information. Buyer will furnish to Seller copies of logs on wells (hereafter drilled) on the Leases or the Leases pooled with other leases; provided that Buyer shall not be obligated to furnish any such log until six (6) months after is it run.

8.3 Deceptive Trade Practices Waiver. To the extent applicable to the transaction contemplated hereby or any portion thereof, Buyer waives Buyer’s rights under the provisions of the Texas Deceptive Trade Practices – Consumer Protection Act, Sections 17.41 et. seq. of the Texas Business and Commerce Code, a law that gives consumers special rights and protections, and any comparable act in any other state in which the Leases are located; Buyer states that, after consultation with an attorney of Buyer’s selection, Buyer voluntarily consents to this waiver.

8.4 No Assignment. Except as provided in Section 1.4, neither party shall have the right to assign its rights under this Agreement, without the prior written consent of the other party first having been obtained.

8.5 Successors and Assigns. This Agreement shall be binding upon and inure to the benefit of the Parties and their respective successors and assigns.

8.6 Notices and Responses. All notices, responses, and other communications required or permitted under this Agreement shall be in writing, and unless otherwise specifically provided, shall be delivered personally, or by certified U.S. mail with return receipt requested, facsimile, electronic mail or delivery service, to the attention of the signatory officer at the address of the signatory Party set forth below, and shall be considered delivered upon the date of receipt. Each Party may specify a change of address by giving notice to the other party in the manner provided in this Section.

8.7 Relationship of the Parties. This Agreement is not intended to create, and shall not be construed to create, a relationship of agency, joint venture, partnership, mining partnership, or other relationship or association for profit between the Parties. The Liabilities of the Parties shall be several, not joint or collective.

8.8 Entire Agreement. This Agreement constitutes the entire agreement and understanding between the Parties, and may not be changed or amended in any way, except with the mutual consent of both Parties, expressed in a written document executed by both Parties.

8.9 CHOICE OF LAW; VENUE. THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED UNDER AND IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, WITHOUT REFERENCE TO CONFLICTS OF LAWS PRINCIPLES THAT MIGHT REFER THE CONSTRUCTION HEREOF TO ANOTHER JURISDICTION. IN THE EVENT OF A DISPUTE INVOLVING THIS AGREEMENT OR ANY OTHER INSTRUMENTS EXECUTED IN CONNECTION HEREWITH, THE PARTIES IRREVOCABLY AGREE THAT VENUE FOR SUCH DISPUTE SHALL LIE IN ANY COURT OF COMPETENT JURISDICTION IN SMITH COUNTY, TEXAS.

8.10 Additional Definitions. In addition to the terms defined elsewhere in this Agreement, the following expressions and terms will have the meanings set forth in this Section unless expressly stated otherwise:

“Conveyance Date” means (a) with respect to those Leases conveyed to Buyer at Closing and (b) with respect to those Leases conveyed to Buyer after the Closing pursuant to Section 2.2(d), the date of execution of the relevant Assignment.

“Minimum Net Revenue Interest” means that no oil and gas Lease offered by Seller shall have less than a seventy five percent (75%) Net Revenue Interest inclusive of all royalty and overriding royalty burdens. However, Seller shall be entitled to reserve unto itself, its successors and/or assigns up to a five percent (5%) overriding royalty interest in the oil and gas Lease(s) described on the attached Exhibit “A” (“Leases”) to the extent that the total burdens, including Lessor’s royalty, does not exceed twenty five percent (25%) based upon one hundred percent (100%) of 8/8ths of the oil, gas, casing head gas and any other hydrocarbon production produced and marketed under the provisions of the Leases. Seller’s ORRI further illustrated in the below table.

“Net Revenue Interest” means, with respect to a Lease, the interest in and to all oil and gas produced and saved from or attributable to such Lease, after giving effect to all valid royalties, overriding royalties, production payments, net profits interests, reversionary interests, and other similar interests constituting burdens upon, measured by, or payable out of oil and gas produced and saved from or attributable to such Lease.

“Title-Approved Leases” means, as of a Conveyance Date, those Leases that are (a) free of Title Defects, or (b) previously affected by Title Defects that, as of such Conveyance Date, have been cured by Seller or Buyer or waived by Buyer.

8.11 Expenses. Except as otherwise specifically provided herein, all fees, costs, and expenses, including, without limitation expenses, fees and costs related to due diligence and title curative work, incurred by Buyer and Seller associated with this Agreement and the other documents executed in connection herewith and in consummating the transactions contemplated by this Agreement shall be paid by the Party incurring the same, including, without limitation, legal and accounting fees, costs, and expenses. All required documentary, filing, and recording fees and expenses in connection with the filing and recording of the Assignment and other instruments required to convey title to the Leases to Buyer shall be borne by Buyer.

8.12 Counterparts. This Agreement may be executed by Seller and Buyer in any number of counterparts, each of which shall be deemed an original instrument, but all of which together shall constitute one and the same instrument, and the delivery of such counterparts may be via facsimile or email, which shall be as effective as hand delivery of original instruments. In the event of such a facsimile execution, the Parties shall execute and deliver each to the other a fully executed original counterpart of this Agreement within thirty (30) days after such facsimile execution hereof; provided, however, that the failure of the Parties to execute such an original counterpart of this Agreement shall not affect or impair the binding character or enforceability of this Agreement.

This CREDIT AGREEMENT, dated as of June 26, 2012, is entered into by and among ENERGY AND EXPLORATION PARTNERS, LLC, a Delaware limited liability company (“Borrower”), the Lenders (defined below) from time to time party hereto and GUGGENHEIM CORPORATE FUNDING, LLC (“GCF”), as administrative agent (in such capacity, “Administrative Agent”).

WHEREAS, Borrower has requested that the Lenders provide certain loans to Borrower, the proceeds of which will be used for, among other things, refinancing of the Assigned Indebtedness and expenditures related to the Development Project; and

NOW, THEREFORE, in consideration of the foregoing recitals, of the representations, warranties, covenants and agreements contained herein, and other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the parties hereto agree as follows:

1.1 Definitions. The following terms used herein, including in the preamble, recitals, exhibits and schedules hereto, shall have the following meanings:

“Adverse Proceeding” means any action, suit, proceeding (whether administrative, judicial or otherwise), governmental investigation or arbitration (whether or not purportedly on behalf of any Credit Party) at law or in equity, or before or by any Governmental Authority, domestic or foreign or other regulatory body or any arbitrator whether pending or, to the best knowledge of Borrower, overtly threatened against or affecting a Credit Party or any Property of a Credit Party.

“AFE” means an authorization for expenditures representing an estimate of work to be performed. AFE’s shall include COPAS overhead or other similar expenses related to any Credit Party’s direct overhead expense for drilling and completion costs of any Oil and Gas Properties.

“Affiliate” means, as applied to any Person, any other Person directly or indirectly controlling, controlled by, or under common control with, that Person. For the purposes of this definition, “control” (including, with correlative meanings, the terms “controlling,” “controlled by” and “under common control with”), as applied to any Person, means the possession, directly or indirectly, of the power (i) to vote ten percent (10%) or more of the Securities having ordinary voting power for the election of directors of such Person, or (ii) to direct or cause the direction of the management and policies of that Person, whether through the ownership of voting securities or by contract or otherwise. Notwithstanding anything to the contrary herein, in no event shall Administrative Agent or any Lender be considered an “Affiliate” of any Credit Party.

“Agreement” means this Credit Agreement, dated as of the date first written above, as it may be amended, supplemented or otherwise modified from time to time and any annexes, exhibits, and schedules to any of the foregoing.

“Approved Counterparty” means Administrative Agent, any Affiliate of Administrative Agent, and any other Person approved by Administrative Agent in its sole discretion.

“Approved Petroleum Engineers” means any independent petroleum engineer reasonably acceptable to Administrative Agent.

“Assigned Indebtedness” means all obligations and indebtedness assigned to Administrative Agent under the Assignment of Liens.

“Assignment Agreement” means an Assignment and Assumption Agreement substantially in the form of Exhibit D, with such amendments or modifications as may be approved by Administrative Agent.

“Assignment of Liens” means that certain Assignment of Note, Liens and Security dated the date hereof among Administrative Agent, Petro Capital XXV, LLC and Borrower.

“Authorized Officer” means, as applied to any Person or the general partner of such Person, any manager, chief executive officer, president, vice president, chief operating officer, chief financial officer or treasurer, in each case, whose signatures and incumbency have been certified to Administrative Agent.

“Available Amount” means, at the time of such determination, an amount equal to the Borrowing Base then in effect less all Loans and other amounts advanced from the Lenders to Borrower pursuant to this Agreement, without giving effect to any repayments of principal therefor. Notwithstanding anything in this Agreement to the contrary, once borrowed, Borrower may not reborrow any amounts that have been repaid.

“Bankruptcy Code” means Title 11 of the United States Code entitled “Bankruptcy,” as now and hereafter in effect, or any successor statute.

“Base Rate” means, for any day, a rate per annum equal to the greater of (i) the Prime Rate in effect on such day and (ii) 5%. Any change in the Base Rate due to a change in the Prime Rate shall be effective on the effective date of such change in the Prime Rate.

“Borrowing Base” means the amount determined under Section 2.16. As of the Closing Date the Borrowing Base is $30,000,000.00.

“Borrowing Request” means a written request by Borrower to the Lenders for Loans pursuant to Section 2.1(b). Such request shall be in the form of Exhibit A and shall be delivered by Borrower accompanied by the information required by Section 2.1(b) or (c), as applicable.

“Business Day” means any day excluding Saturday, Sunday and any day which is a legal holiday under the laws of either the State of New York or the State of Texas or is a day on which banking institutions located in either state are authorized or required by law or other governmental action to close.

“Capital Expenditures” means, in respect of any Person, for any period, the aggregate (determined without duplication) of all exploration and development expenditures and costs that are capital in nature and any other expenditures that are capitalized on the balance sheet of such Person in accordance with GAAP, which, in the case of Borrower, shall include expenditures and costs related to landmen who spend substantially all of their working time acquiring Oil and Gas Properties.

“Capital Lease” means, as applied to any Person, any lease of (or other arrangement conveying the right to use) any property (whether real, personal or mixed) by that Person as lessee (or the equivalent) that, in conformity with GAAP, is or should be accounted for as a capital lease on the balance sheet of that Person.

“Capital Stock” means any and all shares, interests, participations or other equivalents (however designated) of capital stock of a corporation, any and all equivalent ownership interests in a Person (other than a corporation), including partnership interests and membership interests, and any and all warrants, rights or options to purchase or other arrangements or rights to acquire any of the foregoing.

“Cash” means money, currency or a credit balance in any demand or deposit account.

“Cash Equivalents” means, as at any date of determination, (i) marketable securities (a) issued or directly and unconditionally guaranteed as to interest and principal by the United States Government, or (b) issued by any agency of the United States the obligations of which are backed by the full faith and credit of the United States, in each case maturing within one year after such date; (ii) marketable direct obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof, in each case maturing within one year after such date and having, at the time of the acquisition thereof, a rating of at least A-1 from S&P or at least P-1 from Moody’s; (iii) commercial paper maturing no more than one year from the date of creation thereof and having, at the time of the acquisition thereof, a rating of at least A-1 from S&P or at least P-1 from Moody’s; (iv) certificates of deposit or bankers’ acceptances maturing within one year after such date and issued or accepted by any Lender or by any commercial bank organized under the laws of the United States of America or any state thereof or the District of Columbia that (a) is at least “adequately capitalized” (as defined in the regulations of its primary Federal banking regulator), and (b) has Tier 1 capital (as defined in such regulations) of not less than $250,000,000; and (v) shares of any money market mutual fund that (a) has at least ninety five percent (95%) of its assets invested continuously in the types of investments referred to in clauses (i) and (ii) above, (b) has net assets of not less than $500,000,000, and (c) has the highest rating obtainable from either S&P or Moody’s.

“Cash Receipts” means all Cash or Cash Equivalents received by or on behalf of a Credit Party with respect to the following: (a) sales of Hydrocarbons from the Oil and Gas Properties of such Credit Party (including Other Owner Cash Receipts), (b) cash representing operating revenue earned or to be earned by such Credit Party, (c) any net proceeds from Swap Agreements, and (d) any other Cash or Cash Equivalents received from whatever source; provided that, the following shall not constitute “Cash Receipts”: (i) Casualty Proceeds (except to the extent provided in Section 7.3), (ii) proceeds from asset sales and dispositions permitted by Section 6.7 (other than 6.7(a)), (iii) proceeds from any Permitted IPO or other capital raised resulting from the issuance of equity securities by the Borrower, and (iv) advances under the Loans.

“Casualty Proceeds” means amounts actually received by a Credit Party as payments for property damage under property and casualty insurance covering such Credit Party’s Property.

“Casualty Proceeds Account” has the meaning set forth in Section 7.3(c).

“Change of Control” means the occurrence of any of the following events:

(a) (i) prior to the completion of a Permitted IPO, the failure of the Management Holders to collectively control, directly or indirectly, 51% or more of the equity interests in Borrower, or (ii) after the completion of a Permitted IPO, the failure of the Management Holders to collectively control, directly or indirectly, 35% or more of the equity interests in Borrower; or

(b) after the completion of a Permitted IPO, any “person” or “group” (as such terms are used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934, but excluding any employee benefit plan of such person or its subsidiaries, and any person or entity acting in its capacity as trustee, agent or other fiduciary or administrator of any such plan), other than one or more Management Holders, becomes the “beneficial owner” (as defined in Rules 13d-3 and 13d-5 under the Securities Exchange Act of 1934, except that a person or group shall be deemed to have “beneficial ownership” of all securities that such person or group has the right to acquire, whether such right is exercisable immediately or only after the passage of time (such right, an “option right”)), directly or indirectly, of more than 10% of the equity interests in Borrower entitled to vote for members of the board of directors or equivalent governing body of Borrower, determined on a fully-diluted basis (and taking into account all such equity interests that a person or group has the right to acquire pursuant to any option right); or

“Change of Management” means the occurrence of any of the following events: (a) Hunt Pettit is no longer the Chief Executive Officer of Borrower, with the responsibilities such title currently carries, or ceases to devote substantially all of his time to such position, (b) Brian Nelson is no longer the Chief Financial Officer of Borrower, with the responsibilities that such title carries, or ceases to devote substantially all of his time to such position or (c) prior to the completion of a Permitted IPO, any Management Holder shall sell, transfer, assign or convey its Capital Stock to another Person, other than (i) to another Management Holder, (ii) to estates and/or trusts where such Management Holder is either a trustee or a grantor, (iii) to entities wholly-owned by such Management Holder, or (iv) pursuant to the Equity Transaction.

“Closing Date” means the date on which all conditions precedent set forth in Section 3.1 are satisfied or waived.

“Closing Date Certificate” means a Closing Date Certificate substantially in the form of Exhibit E.

“Collateral” means, collectively, all of the real, personal and mixed property (including Capital Stock) on which Liens are purported to be granted pursuant to the Collateral Documents as security for the Obligations.

“Collateral Addition Date” means the earlier of (a) the date that aggregate value of the Oil and Gas Properties not subject to the Lien of the Collateral Documents in favor of Administrative Agent for the benefit of Secured Parties exceeds $1,000,000 and (b) the date that Administrative Agent requests that the Credit Parties cause all Oil and Gas Properties not subject to the Lien of the Collateral Documents to become subject to such Lien. For the purposes of the definition of “Collateral Addition Date” the value of each Oil and Gas Property is the cost to acquire such Oil and Gas Property.

“Collateral Documents” means the Mortgages, each Deposit Account Control Agreement, each document relating to the Lockbox Account and Equity Account, the Pledge and Security Agreement and all other instruments, documents and agreements delivered by or on behalf of any Credit Party pursuant to this Agreement or any of the other Credit Documents, including any amendments to or restatements of any of the foregoing, in order to grant to Administrative Agent, for the benefit of Secured Parties, a Lien on any real, personal or mixed property of that Credit Party as security for the Obligations.

“Collateral Questionnaire” means a certificate in form and substance reasonably satisfactory to Administrative Agent that provides information with respect to the personal or mixed property of each Credit Party.

“Commitment” means, with respect to each Lender, the commitment of such Lender to make Loans hereunder. The amount representing each Lender’s Commitment shall, at any time, not exceed such Lender’s Pro Rata Share of the lesser of (i) the Available Amount determined as of the date on which the requested Loan is to be made and (ii) the Maximum Loan Amount.

“Committed Well Set Funds” means, for any Well Set and subject to Section 2.1(b)(D), Loans approved for such Well Set pursuant to Section 2.1(b)(A).

“Compliance Certificate” means a Compliance Certificate substantially in the form of Exhibit C.

“Contractual Obligation” means, as applied to any Person, any provision of any Security issued by that Person or of any indenture, mortgage, deed of trust, contract, undertaking, agreement or other instrument to which that Person is a party or by which it or any of its Property is bound.

“Core Areas” means the Eaglebine Area, the DJ Basin Area, and the Permian Basin Area.

“Credit Date” means the date of any Loan made hereunder; provided, however, notwithstanding anything in this Agreement to the contrary, in no event shall any Credit Date occur after the Advance Period Expiration Date.

“Credit Document” means any of this Agreement, the Guaranty Agreement, the Notes (if any), the Collateral Documents, the Fee Letter, the Equity Kicker Letter, all assignments, conveyances and other documents related to the Equity Kicker Letter, each ORI Conveyance, any Swap Agreement with an Approved Counterparty, and all other certificates, documents, instruments or agreements executed and delivered by a Credit Party for the benefit of Administrative Agent, or any Lender in connection with any of the foregoing.

“Default” means a condition or event that, after notice or lapse of time or both, would constitute an Event of Default.

“Default Excess” means, with respect to any Defaulting Lender, the excess, if any, of such Defaulting Lender’s Pro Rata Share of the aggregate outstanding principal amount of Loans of all Lenders (calculated as if all Defaulting Lenders (other than such Defaulting Lender) had funded all of their respective Defaulted Loans) over the aggregate outstanding principal amount of all Loans of such Defaulting Lender.

“Default Interest” any interest paid by Borrower with respect to the Obligations in excess of the amount set forth in Section 2.6(a) of the Credit Agreement as result of interest being paid at the Default Rate.

“Default Period” means, with respect to any Defaulting Lender, the period commencing on the date of the applicable Funding Default and ending on the earliest of the following dates: (i) the date on which all Commitments are cancelled or terminated and/or the Obligations are declared or become immediately due and payable, (ii) the date on which (a) the Default Excess with respect to such Defaulting Lender shall have been reduced to zero (whether by the funding by such Defaulting Lender of any Defaulted Loans of such Defaulting Lender), and (b) such Defaulting Lender shall have delivered to Borrower and Administrative Agent a written reaffirmation of its intention to honor its obligations hereunder with respect to its Commitments, and (iii) the date on which Borrower, Administrative Agent and Required Lenders waive all Funding Defaults of such Defaulting Lender in writing.

“Deposit Account Control Agreement” means each Deposit Account Control Agreement executed by Borrower, Administrative Agent and a Deposit Bank, in form and substance reasonably satisfactory to Administrative Agent, pursuant to which such financial institution agrees to take instructions from Administrative Agent as required by such agreement, as it may be amended, supplemented or otherwise modified from time to time.

“Deposit Bank” means (a) with respect to the Lockbox Account and Equity Account, the Lockbox Bank, (b) with respect to the Operating Account, The Frost National Bank, and (c) with respect to any other deposit account, the depository bank at which such account is established.

“Development Project” means the acquisition of oil and gas leases and drilling and completion of oil and gas wells in and the development of Borrower’s Hydrocarbon Interests in the Eaglebine Area in compliance with the terms of the Operating Agreements.

“Direction Letters” means letters substantially in the form of Exhibit F.

“DJ Basin Area” means (a) the following Colorado counties: Weld, Morgan, Adams, Arapahoe, Douglas, Elbert, Larimer, Park, El Paso and Jackson, and (b) the following Wyoming counties: Laramie, Goshen, Converse and Platte.

“Dollars” and the sign “$” mean the lawful money of the United States of America.

“Eaglebine Agreement” means that certain Purchase and Sale Agreement (Non-Producing Properties), dated effective as of March 5, 2012, by and between Borrower and Halcon Energy Properties, Inc. (f/k/a RWG Energy, Inc.), as amended by that certain First Amendment to Purchase and Sale Agreement dated April 19, 2012, that certain Second Amendment to Purchase and Sale Agreement, dated May 10, 2012, that certain Third Amendment to Purchase and Sale Agreement, dated May 24, 2012, and as the same may be amended from time to time upon prior written notice to and consent of Administrative Agent; provided, however, that such consent shall not be required for any amendment that (a) does not amend any financial or economic terms of the Eaglebine Agreement and (b) is not adverse to the Lenders.

“Eaglebine Area” means (a) the following Texas counties: Brazos, Grimes, Madison, Leon, Walker, Houston, Anderson, Cherokee, Angelina, San Augustine, Polk, Tyler, Montgomery, Smith, Rusk, Jasper, Newton, Henderson, Wood, Rains, Van Zandt, Upshur, Hopkins, Franklin, Camp, Gregg, Burleson, Washington, Waller, Austin, Colorado, San Jacinto, Trinity, Nacogdoches, Sabine, Fayette, Lee, Milam, and Robertson, and (b) the following Louisiana parishes: Vernon, Beauregard, Sabine, Rapides, Allen, Evangeline, Jefferson Davis, Avoyelles, St. Landry, Pointe Coupee and West Feliciana.

“Eaglebine Sale” means the sale or disposition, within one hundred twenty (120) days of the Closing Date, of up to 10% of 8/8ths of the working interest in each of the Oil and Gas Properties in the Eaglebine Area for a cash purchase price not less than $7,000 per net mineral acre and for gross cash proceeds of not less than $28,000,000 (or, if less than 10% of 8/8ths is sold or disposed over, a proportionately reduced amount of gross cash proceeds); provided further the cash purchase price may be $6,000 per net mineral acre with a 30% reversionary interest after the purchaser receives a 20% internal rate of return and for gross cash proceeds of not less than $24,000,000 (or, if less than 10% of 8/8ths is sold or disposed over, a proportionately reduced amount of gross cash proceeds).

“Effective Amount” means the aggregate outstanding amount of all principal of, and unpaid interest accrued on, Loans advanced hereunder.

“Eligible Assignee” means (a) any Lender, any Affiliate of any Lender and any Related Fund (any two or more Related Funds being treated as a single Eligible Assignee for all purposes hereof), (b) any commercial bank, insurance company, investment or mutual fund or other entity that is an “accredited investor” (as defined in Regulation D under the Securities Act) and which extends credit or buys loans as one of its businesses, and (c) any other Person (other than a natural Person) approved by Administrative Agent; provided, that no Credit Party nor any Affiliate of a Credit Party shall, in any event, be an Eligible Assignee.

“Employee Benefit Plan” means any “employee benefit plan” as defined in Section 3(3) of ERISA which is or was sponsored, maintained or contributed to by, or required to be contributed by, Borrower or any ERISA Affiliate of Borrower, other than a Multiemployer Plan.

“Employee Overrides” means conveyances of overriding royalty interests granted to certain employees of the Borrower and its Subsidiaries (or affiliates or family members of such employees).

“ENEXP Operating” means Energy & Exploration Partners Operating, LP, a Texas limited partnership.

“ENEXP Operating GP” means Energy & Exploration Partners Operating GP, LLC, a Texas limited liability company.

“Environmental Claim” means any investigation, notice, notice of violation, claim, action, suit, proceeding, demand, abatement order or other order or directive (conditional or otherwise), by any Governmental Authority or any other Person, arising (i) pursuant to or in connection with any actual or alleged violation of any Environmental Law; (ii) in connection with any Hazardous Material or any actual or alleged Hazardous Materials Activity; or (iii) in connection with any actual or alleged damage, injury, threat or harm to health, safety, natural resources or the environment.

“Environmental Laws” means any and all Governmental Requirements pertaining in any way to health, safety the environment or the preservation or reclamation of natural resources, in effect in any and all jurisdictions in which any Credit Party is conducting or at any time has conducted business, or where any Property of any Credit Party is located, including without limitation, the Oil Pollution Act of 1990 (“OPA”), as amended, the Clean Air Act, as amended, the Comprehensive Environmental, Response, Compensation, and Liability Act of 1980 (“CERCLA”), as amended, the Federal Water Pollution Control Act, as amended, the Occupational Safety and Health Act of 1970, as amended, the Resource Conservation and Recovery Act of 1976 (“RCRA”), as amended, the Safe Drinking Water Act, as

amended, the Toxic Substances Control Act, as amended, the Superfund Amendments and Reauthorization Act of 1986, as amended, the Hazardous Materials Transportation Act, as amended, and other environmental conservation or protection Governmental Requirements. The term “oil” shall have the meaning specified in OPA, the terms “hazardous substance” and “release” (or “threatened release”) have the meanings specified in CERCLA, the terms “solid waste” and “disposal” (or “disposed”) have the meanings specified in RCRA and the term “oil and gas waste” shall have the meaning specified in Section 91.1011 of the Texas Natural Resources Code (“Section 91.1011”); provided, however, that (a) in the event either OPA, CERCLA, RCRA or Section 91.1011 is amended so as to broaden the meaning of any term defined thereby, such broader meaning shall apply subsequent to the effective date of such amendment and (b) to the extent the laws of the state or other jurisdiction in which any Property of any Credit Party is located establish a meaning for “oil,” “hazardous substance,” “release,” “solid waste,” “disposal” or “oil and gas waste” which is broader than that specified in either OPA, CERCLA, RCRA or Section 91.1011, such broader meaning shall apply.

“Environmental Permit” means any permit, registration, license, approval, consent, exemption, variance, or other authorization required under or issued pursuant to applicable Environmental Laws.

“Equity Kicker Letter” means that certain letter agreement dated of even date herewith, between Administrative Agent and Borrower, as the same may from time to time be amended, supplemented or otherwise modified, relating to the overriding royalty interest to be conveyed from time to time by Borrower, or any other Credit Party, to Administrative Agent for the benefit of the Lenders in consideration for their Commitment.

“Equity Transaction” means (a) the formation of the Parent, (b) the exchange by all of the Shale Fund Investors of their equity interests in the Shale Fund for equity interests in the Parent not to exceed, in the aggregate, 25% of the equity interests in the Parent, (c) the exchange by the Management Holders of their indirect equity ownership interests in the Shale Fund for equity interests in the Parent, (d) the exchange by the Management Holders and all other holders of equity interests in Borrower of those equity interests for equity interests in the Parent, (e) the exchange by all holders of net profit interests in the Niobrara Assets of those interests for equity interests in the Parent or cash, (f) the exchange of the Management Holders of their equity interests in ENEXP Operating GP and ENEXP Operating for equity interests in the Parent, (g) the contribution by the Parent of the equity interests in the Shale Fund to Borrower, and (h) the liquidation, merger or dissolution of the Shale Fund and its Subsidiaries with or into Borrower (with, in the case of a merger, Borrower being the survivor of such merger).

“ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, and any successor thereto, in each case together with the regulations thereunder.

“ERISA Affiliate” means, as applied to any Person, (i) any corporation which is a member of a controlled group of corporations within the meaning of Section 414(b) of the Internal Revenue Code of which that Person is a member; (ii) any trade or business (whether or not incorporated) which is a member of a group of trades or businesses under common control within the meaning of Section 414(c) of the Internal Revenue Code of which that Person is a member; and (iii) any member of an affiliated service group within the meaning of Section 414(m) or (o) of the Internal Revenue Code of which that Person, any corporation described in clause (i) above or any trade or business described in clause (ii) above is a member. Any former ERISA Affiliate of Borrower shall continue to be considered an ERISA Affiliate of Borrower within the meaning of this definition with respect to the period such entity was an ERISA Affiliate of Borrower and with respect to liabilities arising after such period for which Borrower could be liable under the Internal Revenue Code or ERISA.

“ERISA Event” means (i) a “reportable event” within the meaning of Section 4043 of ERISA and the regulations issued thereunder with respect to any Pension Plan (excluding those for which the provision for 30-day notice to the PBGC has been waived by regulation); (ii) the failure to meet the minimum funding standard of Section 412 of the Internal Revenue Code with respect to any Pension Plan (whether or not waived in accordance with Section 412(d) of the Internal Revenue Code) or the failure to make by its due date a required installment under Section 412(m) of the Internal Revenue Code with respect to any Pension Plan or the failure to make any required contribution to a Multiemployer Plan; (iii) notice of intent to terminate a Pension Plan in a distress termination described in Section 4041(c) of ERISA; (iv) the withdrawal by Borrower or any ERISA Affiliate of Borrower from any Pension Plan with two or more non-related contributing sponsors or the termination of any such Pension Plan resulting in liability to Borrower or any ERISA Affiliate of Borrower pursuant to Section 4063 or 4064 of ERISA; (v) the institution by the PBGC of proceedings to terminate any Pension Plan, or the occurrence of any event or condition which might reasonably constitute grounds under ERISA for the termination of, or the appointment of a trustee to administer, any Pension Plan; (vi) the imposition of liability on Borrower or any ERISA Affiliate of Borrower pursuant to Section 4062(e) or 4069 of ERISA or by reason of the application of Section 4212(c) of ERISA; (vii) the withdrawal of Borrower or any ERISA Affiliate of Borrower in a complete or partial withdrawal (within the meaning of Sections 4203 and 4205 of ERISA) from any Multiemployer Plan if there is any liability or potential liability therefor, or the receipt by Borrower or any ERISA Affiliate of Borrower of notice from any Multiemployer Plan that it is in reorganization or insolvency pursuant to Section 4241 or 4245 of ERISA, or that it intends to terminate or has terminated under Section 4041A or 4042 of ERISA; (viii) the occurrence of an act or omission which could reasonably be expected to give rise to the imposition on Borrower or any ERISA Affiliate of Borrower of fines, penalties, taxes or related charges under Chapter 43 of the Internal Revenue Code or under Section 409, Section 502(c), (i) or (l), or Section 4071 of ERISA in respect of any Employee Benefit Plan; (ix) the incurrence of a material liability (other than for benefits) against any Employee Benefit Plan or the assets thereof, or against Borrower or any ERISA Affiliate of Borrower in connection with any Employee Benefit Plan; (x) receipt from the Internal Revenue Service of notice of the failure of any Pension Plan (or any other Employee Benefit Plan intended to be qualified under Section 401(a) of the Internal Revenue Code) to qualify under Section 401(a) of the Internal Revenue Code, or the failure of any trust forming part of any Pension Plan to qualify for exemption from taxation under Section 501(a) of the Internal Revenue Code; or (xi) the imposition of a Lien pursuant to Section 401(a)(29) or 412(n) of the Internal Revenue Code or pursuant to ERISA with respect to any Pension Plan.

“Event of Default” means each of the conditions or events set forth in Section 8.1.

“Excepted Liens” means: (a) Liens for Taxes, assessments or other governmental charges or levies which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (b) Liens in connection with workers’ compensation, unemployment insurance or other social security, old age pension or public liability obligations which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (c) statutory landlord’s liens, operators’, non-operators’, vendors’, carriers’, warehousemen’s, repairmen’s, mechanics’, suppliers’, workers’, materialmen’s, construction or other like Liens arising by operation of law in the ordinary course of business or incident to the exploration, development, operation and maintenance of the Oil and Gas Properties each of which is in respect of obligations that are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; (d) contractual Liens which arise in the ordinary course of business under operating agreements, joint venture agreements, oil and gas partnership agreements, oil and gas leases, farm-out agreements, division orders, contracts for the sale, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements, overriding royalty agreements, marketing agreements, processing agreements,

development agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or other geophysical licenses, permits or agreements, and other agreements which are usual and customary in the oil and gas business which are not entered into for the purpose of securing borrowed money or deferred consideration and are for claims which are not delinquent or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP, provided that any such Lien referred to in this clause does not materially impair the use of the Property covered by such Lien for the purposes for which such Property is held by the applicable Credit Party or materially impair the value of such Property subject thereto; (e) Liens arising solely by virtue of any statutory or common law provision relating to banker’s liens, rights of set-off or similar rights and remedies and burdening only deposit accounts or other funds maintained with a creditor depository institution, provided that no such deposit account is a dedicated cash collateral account or is subject to restrictions against access by the depositor in excess of those set forth by regulations promulgated by the Board of Governors of the Federal Reserve System and no such deposit account is intended by the applicable Credit Party to provide collateral to the depository institution; (f) easements, restrictions, servitudes, permits, conditions, covenants, exceptions or reservations in any Property of a Credit Party for the purpose of roads, pipelines, transmission lines, transportation lines, for gas, oil, or other minerals, and other like purposes, or for the joint or common use of real estate, rights of way, facilities and equipment, that do not secure any monetary obligations and which in the aggregate do not materially impair the use of such Property for the purposes of which such Property is held by the applicable Credit Party or materially impair the value of such Property subject thereto; and (g) Liens on cash or securities pledged to secure performance of tenders, surety and appeal bonds, government contracts, performance and return of money bonds, bids, trade contracts, leases, statutory obligations, regulatory obligations and other obligations of a like nature incurred in the ordinary course of business; provided further, that Liens described in clauses (a) through (g) shall remain “Excepted Liens” only for so long as no action to enforce such Lien has been commenced and no intention to subordinate the first priority Lien granted in favor of Administrative Agent and the Lenders is to be hereby implied or expressed by the permitted existence of such Excepted Liens.

“Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time, and any successor statute.

“Excluded Taxes” means, with respect to Administrative Agent and any Lender or any other recipient of any payment to be made by or on account of any obligation of a Credit Party hereunder, (a) taxes imposed on or measured by its overall net income (however denominated), and franchise taxes imposed on it (in lieu of net income taxes), by the jurisdiction (or any political subdivision thereof) under the laws of which such recipient is organized or in which its principal office is located or, in the case of any Lender, in which its applicable lending office is located, (b) any branch profits taxes imposed by the United States or any similar tax imposed by any other jurisdiction in which such Credit Party is located and (c) in the case of a Non-U.S. Lender, any federal United States withholding tax that is imposed on amounts payable to such Non-U.S. Lender at the time such Non-U.S. Lender becomes a party hereto (or designates a new lending office) except in each case to the extent that pursuant to Section 2.14 amounts with respect to such taxes were payable to such Non-U.S. Lender’s assignor immediately before such Non-U.S. Lender becoming a party hereto or to such Non-U.S. Lender immediately before it changed its lending office, or is attributable to such Non-U.S. Lender’s failure or inability, other than as a result of a change in law or change in requirements, to comply with Section 2.14(e), and (d) any United States withholding tax that is imposed by FATCA.

“Existing Credit Documents” refers to the “Original Note” as defined in the Assignment of Liens.

“Existing Security Documents” refers to the “Security Documents” as defined in the Assignment of Liens.

“Facility” means the Oil and Gas Properties (including all buildings, fixtures or other improvements located thereon) now, hereafter or heretofore owned, leased, operated or used by a Credit Party or any of its predecessors or Affiliates.

“FATCA” means Sections 1471 through 1474 of the Internal Revenue Code (and any amendments or successor sections thereto that are substantively comparable and not materially more onerous to comply with) and any regulations or official interpretations thereof.

“Fee Letter” means that certain Fee Letter dated as of even date herewith between Borrower and Administrative Agent, as the same may be amended, modified, supplemented or restated from time to time.

“Financial Officer Certification” means, with respect to the financial statements for which such certification is required, the certification of the chief financial officer of Borrower that such financial statements fairly present, in all material respects, the financial condition of Borrower as at the dates indicated and the results of their operations and their cash flows for the periods indicated, in each case in conformity with GAAP applied on a consistent basis, subject, in the case of interim financial statements, to changes resulting from normal audit and year-end adjustments.

“First Priority” means, with respect to any Lien purported to be created in any Collateral pursuant to any Collateral Document, that such Lien is the only Lien to which such Collateral is subject, other than any Permitted Lien.

“Fiscal Year” means the fiscal year of Borrower ending on December 31 of each calendar year.

“GAAP” means United States generally accepted accounting principles in effect as of the date of determination thereof.

“General and Administrative Costs” means normal and customary expenses and costs satisfactory to Administrative Agent, paid in cash, that in accordance with GAAP are classified as general and administrative costs, including consulting fees, salary, bonuses, employee benefits, rent, supplies, travel and entertainment, insurance, accounting, legal, engineering and broker related fees, required to manage the affairs of the Credit Parties; provided, that, to the extent any of the foregoing are capitalized, they shall be included in the definition of General and Administrative Costs (other than expenditures and costs related to landmen employed for the purposes of and who spend substantially all of their time acquiring Oil and Gas Properties and included in the definition of “Capital Expenditures”); provided further, that, all General and Administrative Costs associated with the closing of this Facility and the Equity Transaction and Permitted IPO Expenses shall be excluded from the definition of General and Administrative Costs.

“General and Administrative Costs Cap” means (a) prior to the completion of a Permitted IPO, for any three consecutive months, General and Administrative Costs equal to the sum of $2,000,000 and (b) after the completion of a Permitted IPO, for any three consecutive months, General and Administrative Costs equal to the sum of $2,250,000.

“Governmental Authority” means any federal, state, municipal, national or other government, governmental department, commission, board, bureau, court, agency or instrumentality or political subdivision thereof or any entity or officer exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to any government or any court, in each case whether associated with a state of the United States, the United States, or a foreign entity or government.

“Governmental Authorization” means any permit, license, authorization, plan, directive, approval, entitlement, consent order or consent decree of or from any Governmental Authority.

“Governmental Requirement” means, at any time, any law, statute, code, ordinance, order, determination, rule, regulation, judgment, decree, injunction, franchise, permit, certificate, license, authorization or other directive or requirement (whether or not having the force of law), whether now or hereinafter in effect, including, without limitation, Environmental Laws, energy regulations and occupational, safety and health standards or controls, of any Governmental Authority.

“Gross Proceeds of Production” means the sum of (a) gross proceeds from the sale of Hydrocarbon production attributable to Oil and Gas Properties of any Credit Party and actually received by such Credit Party during any calendar month less Third Party Proceeds for the same calendar month, (b) proceeds which represent bonus and delay rentals attributable to Oil and Gas Properties of any Credit Party and paid to such during such calendar month and (c) proceeds attributable to Swap Contracts actually received by any Credit Party during any calendar month.

“Guarantee” means, with respect to any Person, any obligation, contingent or otherwise, of such Person guaranteeing or having the economic effect of guaranteeing any Indebtedness or other obligation of any other Person in any manner, whether directly or indirectly, and including any obligation of the guarantor, direct or indirect, that is (a) an obligation of such Person the primary purpose or intent of which is to provide assurance to an obligee that the obligation of the obligor thereof will be paid or discharged, or any agreement relating thereto will be complied with, or the holders thereof will be protected (in whole or in part) against loss in respect thereof; or (b) a liability of such Person for an obligation of another through any agreement (contingent or otherwise) (i) to purchase, repurchase or otherwise acquire such obligation or any security therefor, or to provide funds for the payment or discharge of such obligation (whether in the form of loans, advances, stock purchases, capital contributions or otherwise) or (ii) to maintain the solvency or any balance sheet item, level of income or financial condition of another if, in the case of any agreement described under subclauses (i) or (ii) of this clause (b), the primary purpose or intent thereof is as described in clause (a) above.

“Guarantor” means (a) each Subsidiary (other than Borrower) of a Credit Party from time to time that becomes a Guarantor under the Guaranty Agreement pursuant to Section 6.17 and (b) prior to the consummation of the Equity Transaction, the Shale Fund and the Indy Guarantors.

“Guaranty Agreement” means (a) each Subsidiary (other than Borrower) of a Credit Party from time to time that becomes a Guarantor under the Guaranty Agreement pursuant to Section 6.17 and (b) prior to the consummation of the Equity Transaction, the Shale Fund and the Indy Guarantors.

“Hazardous Material” means any substance regulated or as to which liability might arise under any applicable Environmental Law and including, without limitation: (a) any chemical, compound, material, product, byproduct, substance or waste defined as or included in the definition or meaning of “hazardous substance,” “hazardous material,” “hazardous waste,” “solid waste,” “toxic waste,”

“extremely hazardous substance,” “toxic substance,” “contaminant,” “pollutant,” or words of similar meaning or import found in any applicable Environmental Law; (b) petroleum hydrocarbons, petroleum products, petroleum substances, natural gas, oil, oil and gas waste, crude oil, and any components, fractions, or derivatives thereof; and (c) radioactive materials, asbestos containing materials, polychlorinated biphenyls, or radon.

“Hazardous Materials Activity” means any past, current, proposed or threatened activity, event or occurrence involving any Hazardous Materials, including the use, manufacture, possession, storage, holding, presence, existence, location, Release, threatened Release, discharge, placement, generation, transportation, processing, construction, treatment, abatement, removal, remediation, disposal, disposition or handling of any Hazardous Materials, and any corrective action or response action with respect to any of the foregoing.

“Highest Lawful Rate” means the maximum lawful interest rate, if any, that at any time or from time to time may be contracted for, charged, or received under the laws applicable to any Lender which are presently in effect or, to the extent allowed by law, under such applicable laws which may hereafter be in effect and which allow a higher maximum nonusurious interest rate than applicable laws now allow.

“Hydrocarbon Interests” means all rights, titles, interests and estates now or hereafter acquired in and to oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, including any reserved or residual interests of whatever nature.

“Hydrocarbons” means oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate (including natural gas liquids), distillate, liquid hydrocarbons, gaseous hydrocarbons and all products refined or separated therefrom.

“Indebtedness,” as applied to any Person, means, without duplication, (i) all indebtedness for borrowed money; (ii) that portion of obligations with respect to Capital Leases that is properly classified as a liability on a balance sheet in conformity with GAAP; (iii) all obligations of such Person evidenced by notes, bonds or similar instruments or upon which interest payments are customarily paid and all obligations in respect of drafts accepted representing extensions of credit whether or not representing obligations for borrowed money; (iv) any obligation owed for all or any part of the deferred purchase price of property or services (excluding trade payables incurred in the ordinary course of business having a term of less than three (3) months that are not yet more than ninety (90) days old) which purchase price is (a) due more than two (2) months from the date of incurrence of the obligation in respect thereof or (b) evidenced by a note or similar written instrument; (v) all obligations created or arising under any conditional sale or other title retention agreement with respect to property acquired by such person, (vi) all indebtedness secured by any Lien on any property or asset owned or held by that Person regardless of whether the indebtedness secured thereby shall have been assumed by that Person or is nonrecourse to the credit of that Person; (vii) the face amount of any letter of credit or letter of guaranty issued, bankers’ acceptances facilities, surety bond and similar credit transactions for the account of that Person or as to which that Person is otherwise liable for reimbursement of drawings or drafts; (viii) any Guarantee; (ix) all net obligations of such Person in respect of any exchange traded or over the counter derivative transaction, including any Swap Agreement whether entered into for hedging or speculative purposes; (x) all obligations of such Person, contingent or otherwise, to purchase, redeem, retire or otherwise acquire for value any Capital Stock of such Person (A) prior to repayment in full in cash of the Obligations or (B) within five (5) years of the creation of such obligations; and (xi) the undischarged balance of any production payment created by such Person or for the creation of which such Person directly or indirectly received payments. The Indebtedness of any Person shall include the Indebtedness of any partnership or joint venture in which such Person is a general partner or joint venturer, unless such Indebtedness is expressly non-recourse to such Person.

“Indemnified Liabilities” means, collectively, any and all liabilities, obligations, losses, damages (including natural resource damages), penalties, claims (including Environmental Claims), costs (including the costs of any investigation, study, sampling, testing, abatement, cleanup, removal, remediation or other response action necessary to remove, remediate, clean up or abate any Hazardous Materials Activity), expenses and disbursements of any kind or nature whatsoever (including the reasonable fees and disbursements of counsel for Indemnitees in connection with any investigative, administrative or judicial proceeding commenced or threatened by any Person, whether or not any such Indemnitee shall be designated as a party or a potential party thereto, and any reasonable fees or expenses incurred by Indemnitees in enforcing this indemnity), whether direct, indirect or consequential and whether based on any federal, state or foreign laws, statutes, rules or regulations (including securities and commercial laws, statutes, rules or regulations and Environmental Laws), on common law or equitable cause or on contract or otherwise, that may be imposed on, incurred by, or asserted against any such Indemnitee, in any manner relating to or arising out of (i) this Agreement or the other Credit Documents or the transactions contemplated hereby or thereby (including the Lenders’ agreement to make Loans or the use or intended use of the proceeds thereof, or any enforcement of any of the Credit Documents (including any sale of, collection from, or other realization upon any of the Collateral or the enforcement of the Guaranty Agreement)); (ii) the statements contained in any commitment letter or proposal letter delivered by any Lender to Borrower with respect to the transactions contemplated by this Agreement; or (iii) any Environmental Claim against or any Hazardous Materials Activity relating to or arising from, directly or indirectly, any past or present activity, operation, land ownership, or practice of any Credit Party or any of its Affiliates; provided, however, that Indemnified Liabilities shall not include Excluded Taxes.

“Indy I” means Indy Exploration I, LLC, a Texas limited liability company.

“Indy II” means Indy Exploration II, LLC, a Texas limited liability company.

“Indy III” means Indy Exploration III, LLC, a Texas limited liability company.

“Internal Rate of Return” means the discount rate at which the net present value of outflows of funds from a Person and inflows of funds to a Person equals zero, calculated for each such outflow from the date such outflow was made. A Person’s Internal Rate of Return shall be calculated pursuant to the Excel function known as “XIRR” on the basis of the actual number of days elapsed over a 365 or 366-day year, as the case may be.

“Internal Revenue Code” means the Internal Revenue Code of 1986, as amended to the date hereof and from time to time hereafter, and any successor statute.

“Investment” means (i) any direct or indirect purchase or other acquisition by a Credit Party of, or of a beneficial interest in, any of the Securities of any other Person; (ii) any direct or indirect loan, advance or capital contributions by a Credit Party to any other Person, including all indebtedness and accounts receivable from that other Person that are not current assets or did not arise from sales to that other Person in the ordinary course of business; (iii) any direct or indirect Guarantee of any obligations of any other Person (except for Guarantees permitted under Section 6.1); and (iv) any purchase by a Credit Party of all or a significant part of the assets of a business conducted by another Person. The amount of any Investment shall be the original cost of such Investment plus the cost of all additions (whether in cash, Cash Equivalents or Property) thereto minus the amount of all dividends, distributions or redemptions made in respect of such Investment, but without any adjustments for increases or decreases in value, or write-ups, write-downs or write-offs with respect to such Investment.

“Joint Venture” means a joint venture, partnership or other similar arrangement, whether in corporate, partnership or other legal form; provided, in no event shall any corporate Subsidiary of any Person be considered to be a Joint Venture to which such Person is a party.

“Knowledge” means (a) actual knowledge of a responsible officer of any Credit Party charged with responsibility for the matter at issue or in question or (b) knowledge that a prudent responsible officer or employee of any Credit Party charged with responsibility for the matter at issue or in question could reasonably be expected to discover or otherwise become aware of in the course of conducting such Credit Party’s business.

“Lender” means each financial institution listed on the signature pages hereto as a Lender, and any other Person that becomes a party hereto pursuant to an Assignment Agreement other than any such Person that ceases to be a party hereto pursuant to an Assignment Agreement.

“Lien” means any interest in Property securing an obligation owed to, or a claim by, a Person other than the owner of the Property, whether such interest is based on the common law, statute or contract, and whether such obligation or claim is fixed or contingent, and including but not limited to (a) the lien or security interest arising from a mortgage, encumbrance, pledge, security agreement, conditional sale or trust receipt or a lease, consignment or bailment for security purposes or (b) production payments and the like payable out of Oil and Gas Properties. The term “Lien” shall also include easements, restrictions, servitudes, permits, exceptions or reservations that runs with the Property. For the purposes of this Agreement, each Credit Party shall be deemed to be the owner of any Property which it has acquired or holds subject to a conditional sale agreement, or leases under a financing lease or other arrangement pursuant to which title to the Property has been retained by or vested in some other Person in a transaction intended to create a financing.

“Lienable Claims” means, with respect to the group of Oil and Gas Properties indicated, lease operating expenses (other than (a) the expense of re-working or remedial operations as to which consent of co-owners is required, (b) expenses for repairs and maintenance not constituting routine repairs and maintenance, (c) the expense of drilling, deepening, sidetracking, plugging-back, completing, recompleting and/or plugging and abandoning any well, and (d) land and legal expenses not covered by the operator’s fixed overhead charge); unaffiliated third party operator’s fixed overhead charge pursuant to applicable contracts; any ad valorem, severance, gross production and similar taxes (expressly excluding income taxes); operating expenses relating to the gathering and processing of Hydrocarbons from the Oil and Gas Properties; and other expense items, the non-payment of which could result in a contractual and/or statutory lien (as opposed to a judgment lien) against any of such Oil and Gas Properties.

“Loan Exposure” means, with respect to any Lender, as of any date of determination, the outstanding principal amount of the Loans of such Lender.

“Make-Whole Amount” means, with respect to the prepayment, payoff or refinancing of Principal Obligations prior to June 26, 2013, an additional payment that when taken together with (i) all payments applied against the Principal Obligations when received by the Lenders in respect of the Loans as provided in this Agreement plus (ii) all payments applied against the accrued interest (excluding Default Interest) when received by the Lenders in respect of the Principal Obligations as provided in this Agreement plus (iii) all amounts received by the Lenders as Facility Fees as provided in this Agreement and the Fee Letter plus (iv) all proceeds received by the Lenders (or any assignee thereunder) from the ORIs, provide the Lenders a thirty-two and one-half percent (32.5%) Internal Rate of Return on invested capital as though the Principal Obligations were paid off or refinanced on June 26, 2013.

“Management Holders” means, collectively, Hunt Pettit and Brian Nelson and any of their respective family members, descendants, heirs, family trusts or other similar entities or similar arrangements.

“Margin Stock” as defined in Regulation T, U or X of the Board of Governors of the Federal Reserve System as in effect from time to time.

“Marketable Title” means record title and/or provable title evidenced by documentation that is free and clear of Liens (other than Excepted Liens) and from reasonable doubt as to matters of law and fact such that a prudent operator of Oil and Gas Properties, advised of the facts and their legal significance, would willingly accept.

“Material Adverse Change” means any development or event that has had or could reasonably be expected to cause the actual result of operations or prospects of the Credit Parties to materially and adversely deviate from the results forecasted in the Projections.

“Material Adverse Effect” means a material adverse effect on and/or material adverse developments with respect to (i) the business operations, properties, assets, liabilities (actual or contingent), or condition (financial or otherwise) of the Credit Parties taken as a whole; (ii) the ability of any Credit Party to fully and timely perform its Obligations; (iii) the legality, validity, binding effect, or enforceability against a Credit Party of a Credit Document to which it is a party; (iv) Administrative Agent’s Liens (on behalf of itself and the Secured Parties) on the Collateral or the priority of such Liens; or (v) the rights, remedies and benefits available to, or conferred upon, Administrative Agent and any Lender or any Secured Party under any Credit Document.

“Material Contract” means, collectively, (i) any contracts or other arrangements listed on Schedule 4.18(a), (ii) any contract or other arrangement to which any Credit Party is a party (other than the Credit Documents) in which such Credit Party may reasonably be expected to pay or receive from the counterparty thereto at least $150,000.00 in the aggregate during any twelve (12) month period, and (iii) any agreement or instrument evidencing or governing Indebtedness; provided, however, that documents governing the conveyance of the Oil and Gas Properties shall not be included in the definition of “Material Contract”.

“Mineral Interest Conveyance Document” means each document governing the conveyance of the Oil and Gas Properties to the Credit Parties exceeding $300,000 in value.

“Monthly Date” means the first day of each calendar month (or, if such date is not a Business Day, the next Business Day following such day).

“Moody’s” means Moody’s Investor Services, Inc., and any successor thereto.

“Mortgage” means a Mortgage or Deed of Trust in form and substance reasonably satisfactory to Administrative Agent, pursuant to which Borrower, or any other Credit Party, grants Liens on its Oil and Gas Properties to secure the Obligations, as it may be amended, supplemented or otherwise modified from time to time.

“Moss 14-16H Oil and Gas Properties” means the Oil and Gas Properties described on Schedule 1.1 attached hereto.

“Multiemployer Plan” means any Employee Benefit Plan which is a “multiemployer plan” as defined in Section 3(37) of ERISA which is contributed to by, or is required to be contributed to by, Borrower or an ERISA Affiliate of Borrower.

“NAIC” means The National Association of Insurance Commissioners and any successor thereto.

“Niobrara Assets” means certain of the Oil and Gas Properties owned by Borrower and its Subsidiaries in the DJ Basin.

“Non-Principal Obligations” means all liabilities and obligations of every nature of each Credit Party now or hereafter arising under this Agreement and all of the other Credit Documents (other than any ORI Conveyance) whether for principal, interest (including interest which, but for the filing of a petition in bankruptcy with respect to such Credit Party, would have accrued on any Obligation, whether or not a claim is allowed against such Credit Party for such interest in the related bankruptcy proceeding), obligations under Swap Agreements to any Approved Counterparty, fees, expenses, indemnification or otherwise and whether primary, secondary, direct, indirect, contingent, fixed or otherwise (including obligations of performance); provided, however, that “Non-Principal Obligations” expressly excluded any liabilities or obligations of a Credit Party for principal arising under this Agreement or any other Credit Document.

“Non-U.S. Lender” means any Lender that is not a United States Person as such term is defined in Section 7701(a)30 of the Internal Revenue Code.

“Note” means a promissory note in the form of Exhibit B, as it may be amended, supplemented, replaced or otherwise modified from time to time.

“Obligations” means all liabilities and obligations of every nature of each Credit Party now or hereafter arising under this Agreement and all of the other Credit Documents (other than any ORI Conveyance) whether for principal, interest (including interest which, but for the filing of a petition in bankruptcy with respect to such Credit Party, would have accrued on any Obligation, whether or not a claim is allowed against such Credit Party for such interest in the related bankruptcy proceeding), obligations under Swap Agreements to any Approved Counterparty, fees, expenses, indemnification or otherwise and whether primary, secondary, direct, indirect, contingent, fixed or otherwise (including obligations of performance).

“Oil and Gas Properties” means (a) Hydrocarbon Interests; (b) the Properties now or hereafter pooled or unitized with or arising out of Hydrocarbon Interests; (c) all presently existing or future unitization, pooling agreements and declarations of pooled units and the units created thereby (including without limitation all units created under orders, regulations and rules of any Governmental Authority) which may affect all or any portion of the Hydrocarbon Interests; (d) all operating agreements, farmin agreements, farmout agreements, contracts and other agreements, including production sharing contracts and agreements, which relate to any of the Hydrocarbon Interests or the production, sale, purchase, exchange or processing of Hydrocarbons from or attributable to such Hydrocarbon Interests; (e) all Hydrocarbons in and under and which may be produced and saved or attributable to the Hydrocarbon Interests, including all oil in tanks, and all rents, issues, profits, proceeds, products, revenues and other incomes from or attributable to the Hydrocarbon Interests; (f) all tenements, hereditaments, appurtenances and Properties in any manner appertaining, belonging, affixed or incidental to the Hydrocarbon Interests and (g) all Properties, rights, titles, interests and estates described or referred to above, including any and all Property, real or personal, now owned or hereinafter acquired and situated upon, used, held for use or useful in connection with the operating, working or development of any of such Hydrocarbon Interests or Property (excluding drilling rigs, automotive equipment, rental equipment or other personal Property which may be on such premises for the purpose of drilling a well or for other similar temporary uses) and including any and all oil wells, gas wells, injection wells or other wells, buildings, structures, fuel separators, liquid extraction plants, plant compressors, pumps, pumping units, field gathering systems, lateral lines, tanks and tank batteries, fixtures, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, equipment, appliances, tools, implements, cables, wires, towers, casing, tubing and rods, surface leases, rights-of-way, easements and servitudes together with all additions, substitutions, replacements, accessions and attachments to any and all of the foregoing.

“Operating Account” means the operating bank account of Borrower at The Frost National Bank.

“Operating Agreement” means operating agreements or joint operating agreements among or between any Credit Party and other working interest owners.

“Organizational Documents” means (i) with respect to any corporation, its certificate or articles of incorporation or organization, as amended, and its by laws, as amended, (ii) with respect to any limited partnership, its certificate of limited partnership, as amended, and its partnership agreement, as amended, (iii) with respect to any general partnership, its partnership agreement, as amended, and (iv) with respect to any limited liability company, its articles of organization, as amended, and its operating agreement, as amended. In the event any term or condition of this Agreement or any other Credit Document requires any Organizational Document to be certified by a secretary of state or similar governmental official, the reference to any such “Organizational Document” shall only be to a document of a type customarily certified by such governmental official.

“ORI” means the overriding royalty interest to be conveyed from Borrower to Administrative Agent for the benefit of the Lenders, pursuant to an ORI Conveyance.

“ORI Conveyance” means each Overriding Royalty Interest Conveyance by and between Borrower, as grantor, and Administrative Agent, as grantee, for the benefit of the Lenders, required under the Equity Kicker Letter, as it may be amended, supplemented or otherwise modified from time to time.

“Other Owner Cash Receipts” means Cash or Cash Equivalents received by or on behalf of a Credit Party with respect to sales of Hydrocarbons from the Oil and Gas Properties of such Credit Party attributable to another working interest owner, royalty owner, overriding royalty owner or other mineral owner, in each case, that is not a Credit Party.

“Other Taxes” means any and all present or future stamp, registration, recording, filing, transfer, documentary, excise or property Taxes, charges or similar levies arising from any payment made hereunder or from the execution, delivery or enforcement of, or otherwise with respect to or in connection with, any Credit Document.

“Parent” means Energy & Exploration Partners, Inc., a Delaware corporation.

“Patriot Act” means the Uniting and Strengthening America by Providing Appropriate Tools Required to Intercept and Obstruct Terrorism (USA Patriot Act of 2001).

“PBGC” means the Pension Benefit Guaranty Corporation or any successor thereto.

“Pension Plan” means any Employee Benefit Plan which is subject to Section 412 of the Internal Revenue Code or Section 302 of ERISA.

“Permian Basin Area” means the following Texas counties: Hockley, Lubbock, Crosby, Garza, Lynn, Terry, Dawson, Borden, Scurry, Martin, Howard, Mitchell, Nolan, Fisher, Glasscock, Sterling Coke, Upton, Reagan, Irion, Tom Green, Crockett, and Schleicher.

“Permitted IPO” means an underwritten initial public offering of equity securities of the Borrower that is registered under the Securities Act that results in the Borrower’s equity securities being listed on either the New York Stock Exchange or the NASDAQ exchange.

“Permitted IPO Expenses” means general and administrative costs (including fees paid to the Willis Group) directly incurred in connection with the Permitted IPO that Parent plans to complete prior to March 31, 2013.

“Permitted IPO Expenses Cap” means, Permitted IPO Expenses equal to the sum of $2,500,000 plus amounts netted out of gross proceeds of the Permitted IPO at the time of the Permitted IPO or reimbursed out of gross proceeds of the Permitted IPO.

“Permitted Liens” means each of the Liens permitted pursuant to Section 6.3.

“Person” means and includes natural persons, corporations, limited partnerships, general partnerships, limited liability companies, limited liability partnerships, joint stock companies, Joint Ventures, associations, companies, trusts, banks, trust companies, land trusts, business trusts or other organizations, whether or not legal entities, and Governmental Authorities.

“Petro Capital Overrides” means any and all overriding royalty interests hereafter granted to the Petro Entities, or any of them, pursuant to the Petro Capital Letter Agreement.

“Petro Capital Letter Agreement” means the Letter Agreement dated June 26, 2012, among Petro Capital XXV, LLC, Energy & Exploration Partners, LLC, a Delaware limited liability company, Energy & Exploration Partners, LP, a Delaware limited partnership, and North American Shale Investment Fund, LP, a Delaware limited partnership.

“Petro Entities” means, collectively, (a) Petro Capital XXV, LLC, a Texas limited liability company, (b) PetroStone, LLC, a Texas limited liability company, (c) Province Energy, LLC, a Texas limited liability company, (d) 4600 Greenville Building, LP, a Texas limited partnership, (e) Pitts Oil, LLC, a Texas limited liability company, and (f) the successors and assigns of each of the foregoing entities.

“Pledge and Security Agreement” means the Pledge and Security Agreement to be executed by Borrower and each Guarantor in form and substance satisfactory to Administrative Agent, as it may be amended, supplemented or otherwise modified from time to time.

“Prime Rate” means the prime rate published in The Wall Street Journal’s “Money Rates” or similar table. If multiple prime rates are quoted in the table, then the highest prime rate will be the Prime Rate. In the event that the prime rate is no longer published by The Wall Street Journal in the “Money Rates” or similar table, then Administrative Agent may select an alternative published index based upon comparable information as a substitute Prime Rate. Upon the selection of a substitute Prime Rate, the applicable interest rate shall thereafter vary in relation to the substitute index.

“Principal Obligations” means, on any date of determination, the aggregate unpaid principal balance of all Loans under this Agreement.

“Principal Office” means, for Administrative Agent, such Person’s “Principal Office” as set forth on Appendix B, or such other office as such Person may from time to time designate in writing to Borrower, Administrative Agent and each Lender.

“Principal Payment Date” means each of July 1, 2013, October 1, 2013, January 1, 2014, April 1, 2014, July 1, 2014, and December 17, 2014.

“Principal Payment Amount” means, as of each Principal Payment Date, the following amounts:

“Pro Rata Share” means (i) with respect to all payments, computations and other matters relating to the Loan of any Lender, the percentage obtained by dividing (a) the Loan Exposure of that Lender, by (b) the aggregate Loan Exposure of all Lenders; and (ii) with respect to all payments, computations and other matters relating to the Commitment of any Lender, the percentage set forth on Appendix A hereto.

“Property” means any interest in any kind of property or asset, whether real, personal or mixed, or tangible or intangible, including, without limitation, cash, securities, accounts and contract rights.

“Proved Developed Non-Producing Reserves” has the meaning assigned such term in the SPE Definitions.

“Proved Developed Producing Reserves” has the meaning assigned such term in the SPE Definitions.

“Proved Undeveloped Reserves” has the meaning assigned such term in the SPE Definitions.

“Regulation D” means Regulation D of the Board of Governors of the Federal Reserve System, as in effect from time to time.

“Related Agreements” means, collectively, the Operating Agreements, the Mineral Interest Conveyance Documents and the First Amended and Restated Limited Liability Company Agreement of Borrower dated April 13, 2012.

“Related Fund” means, with respect to any Lender that is an investment fund, any other investment fund that invests in commercial loans and that is managed or advised by the same investment advisor as such Lender or by an Affiliate of such investment advisor. With respect to GCF, Related Fund shall also include any swap, special purpose vehicles purchasing or acquiring security interests in collateralized loan obligations or any other vehicle through which GCF may leverage its investments from time to time.

“Release” means any depositing, spilling, leaking, pumping, pouring, placing, emitting, discarding, abandoning, emptying, discharging, migrating, injecting, escaping, leaching, dumping, or disposing.

“Required Lenders” means one or more Lenders having or holding Loan Exposure, and representing more than fifty percent (50%) of the sum of the aggregate Loan Exposure of all Lenders; provided that the Loan Exposure, and portion of the Loans held or deemed held by, any Defaulting Lender shall be excluded for purposes of making a determination of Required Lenders.

“Reserve Report” means each report, in form and substance satisfactory to Administrative Agent and the Required Lenders in their sole discretion (including, without limitation, the use of satisfactory methodologies and risk analyses), setting forth the updated estimates of Proved Developed Producing Reserves, Proved Developed Non-Producing Reserves, Proved Undeveloped Reserves and probable reserves and projected production profiles and overall economics of the Oil and Gas Properties of the Credit Parties, together with a projection of the rate of production and future cash flows as of such date, based on the following pricing assumptions:

(a) oil and gas prices will be determined by Administrative Agent based on Administrative Agent’s then current forward product pricing curve, which prices will be adjusted to reflect location, content and quality differentials, transportation and marketing fees and hedging arrangements then in place;

(b) taking into account each Credit Party’s actual experiences with leasehold operating expenses and other costs in determining projected leasehold operating expenses and other costs; and

“Restricted Payment” means and includes any dividend or other distribution (whether in cash, or other Property, but not securities) with respect to any Capital Stock or other equity interest in Borrower, or any payment (whether in cash or other Property, but not securities), including any sinking fund or similar deposit, on account of the purchase, redemption, retirement, acquisition, cancellation or termination of any such Capital Stock in Borrower or any option, warrant or other right to acquire any such Capital Stock in Borrower.

“S&P” means Standard & Poor’s Ratings Group, a division of The McGraw Hill Corporation, and any successor thereto.

“Secured Parties” means and includes Administrative Agent, each Lender, and each Approved Counterparty under a Swap Agreement.

“Securities” means any stock, shares, partnership interests, voting trust certificates, certificates of interest or participation in any profit-sharing agreement or arrangement, options, warrants, bonds, debentures, notes, or other evidences of indebtedness, secured or unsecured, convertible, subordinated or otherwise, or in general any instruments commonly known as “securities” or any certificates of interest, shares or participations in temporary or interim certificates for the purchase or acquisition of, or any right to subscribe to, purchase or acquire, any of the foregoing.

“Securities Act” means the Securities Act of 1933, as amended from time to time, and any successor statute.

“Shale Fund” means North American Shale Investment Fund, LP, a Delaware limited partnership.

“Solvent” means, with respect to any Credit Party, that as of the date of determination, both (i) (a) the sum of such Credit Party’s debt and liabilities (including contingent liabilities) does not exceed the present fair saleable value of such Credit Party’s present assets; (b) such Credit Party’s capital is not unreasonably small in relation to its business as contemplated on the Closing Date and reflected in the Projections or with respect to any transaction contemplated or undertaken after the Closing Date; and (c)

such Person has not incurred and does not intend to incur, or believe (nor should it reasonably believe) that it will incur, debts beyond its ability to pay such debts as they become due (whether at maturity or otherwise); and (ii) such Person is “solvent” within the meaning given that term and similar terms under applicable laws relating to fraudulent transfers and conveyances. For purposes of this definition, the amount of any contingent liability at any time shall be computed as the amount that, in light of all of the facts and circumstances existing at such time, represents the amount that can reasonably be expected to become an actual or matured liability (irrespective of whether such contingent liabilities meet the criteria for accrual under Statement of Financial Accounting Standard No. 5).

“SPE Definitions” means, with respect to any term, the definition thereof adopted by the Board of Directors, Society for Petroleum Engineers (SPE) Inc., March 1997 as updated in March 2007.

“Special Event” means a (a) Material Adverse Effect or (b) Material Adverse Change.

“Subject Area” means the Oil and Gas Properties now owned or hereafter acquired by any Credit Parties and any related areas, whether related by production, pooling, areas of mutual interest agreements, farmin or farmout agreements, by legal or governmental distinctions or areas being examined by any Credit Party for potential acquisition of Oil and Gas Properties.

“Subsequent Well Set” means each set of four (4) wells drilled and completed in the Eaglebine Area as part of the Development Project subsequent to Well Set 3.

“Subsidiary” means, with respect to any Person, any corporation, partnership, limited liability company, association, joint venture or other business entity of which more than fifty percent (50%) of the total voting power of shares of stock or other ownership interests entitled (without regard to the occurrence of any contingency) to vote in the election of the Person or Persons (whether directors, managers, trustees or other Persons performing similar functions) having the power to direct or cause the direction of the management and policies thereof is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person or a combination thereof; provided, in determining the percentage of ownership interests of any Person controlled by another Person, no ownership interest in the nature of a “qualifying share” of the former Person shall be deemed to be outstanding. Unless otherwise indicated herein, each reference to the term “Subsidiary” shall mean a direct or indirect Subsidiary of Borrower.

“Swap Agreement” means a financial contract whose value is derived from the performance of assets, interest rates, currency exchange rates, or indexes and including swaps, futures, options, caps, floors, collars, forwards, exchanges and various combinations thereof.

“Swap Net Cash Proceeds” means, with respect to any novation, assignment, unwinding, termination, or amendment of any hedge position or any other Swap Agreement by any Credit Party, Cash and Cash Equivalents received by any Credit Party in connection with such transaction after giving effect to any netting agreements.

“Tax” means any present or future tax, levy, impost, duty, assessment, charge, fee, deduction or withholding of any nature and whatever called, by whomsoever, on whomsoever and wherever imposed, levied, collected, withheld or assessed.

“Terrorism Laws” means any of the following (a) Executive Order 13224 issued by the President of the United States, (b) the Terrorism Sanctions Regulations (Title 31 Part 595 of the U.S.

Code of Federal Regulations), (c) the Terrorism List Governments Sanctions Regulations (Title 31 Part 596 of the U.S. Code of Federal Regulations), (d) the Foreign Terrorist Organizations Sanctions Regulations (Title 31 Part 597 of the U.S. Code of Federal Regulations), (e) the Patriot Act (as it may be subsequently codified), (f) all other present and future legal requirements of any Governmental Authority addressing, relating to, or attempting to eliminate, terrorist acts and acts of war and (g) any regulations promulgated pursuant thereto or pursuant to any legal requirements of any Governmental Authority governing terrorist acts or acts of war.

“Third Party Proceeds” means that portion, if any, of proceeds from the sale of Hydrocarbon production from Oil and Gas Properties attributable to the interest of any Person other than a Credit Party if the interest of such Credit Party therein is used in the calculation of Gross Proceeds of Production and if such proceeds are actually received by such Credit Party during any period for which Gross Proceeds of Production is calculated, (including but not limited to royalty interests, overriding royalty interests, net profits interests, production payments and other interests payable out of or measured by production), other than interests in the Oil and Gas Properties conveyed pursuant to the Equity Kicker Letter and each ORI Conveyance; provided, however, that the interest of such other Person is legally vested in such Person or the predecessors in interest to such Person at the time of the acquisition by such Credit Party of such interest.

“UCC” means the Uniform Commercial Code (or any similar or equivalent legislation) as in effect in any applicable jurisdiction.

“Warrant Repurchase” means the repurchase by Borrower of the warrants previously issued by Borrower to Petro Capital XXV, LLC for an amount not to exceed $125,000.

“Well Set” means any of Well Set 1, Well Set 2, Well Set 3, or a Subsequent Well Set.

“Well Set Approval Request” means a written request by Borrower to Administrative Agent for consideration by the Lenders which requests approval of Loans to be made for a particular Well Set, which request shall, subject to compliance by Borrower and its Subsidiaries of any confidentiality on non-disclosure requirements to which Borrower and its Subsidiaries are subject, contain (a) all reserve, geologic, geophysical, title, financial and such other supporting information with respect to such Well Set that is available to Borrower and is reasonably requested by Administrative Agent in order to allow the Lenders to make an informed decision to approve or disapprove such Well Set, (b) a copy of the notice required by Article VI.B.1 of the Operating Agreement entered into in connection with the Eaglebine Agreement, and (c) a representation and warranty by Borrower that it has, or, upon approval of such Well Set Approval Request, will elect to participate in the Well Set covered by such Well Set Approval Request.

“Well Set 1” means the first four (4) wells drilled and completed in the Eaglebine Area as part of the Development Project.

“Well Set 2” means the four (4) wells drilled and completed in the Eaglebine Area as part of the Development Project immediately following Well Set 1.

“Well Set 3” means the four (4) wells drilled and completed in the Eaglebine Area as part of the Development Project immediately following Well Set 2.

1.2 Accounting Terms. Except as otherwise expressly provided herein, all accounting terms not otherwise defined herein shall have the meanings assigned to them in conformity with GAAP. Financial statements and other information required to be delivered by Borrower to Administrative Agent

and/or the Lenders shall be prepared in accordance with GAAP as in effect at the time of such preparation (and delivered together with reconciliation statements, if applicable). For purposes of determining compliance with the financial covenants contained in this Agreement, any election by Borrower to measure an item of Indebtedness using fair value (as permitted by Statement of Financial Accounting Standards No. 159 or any similar accounting standard) shall be disregarded and such determination shall be made as if such election had not been made.

1.3 Interpretation, etc. Any of the terms defined herein may, unless the context otherwise requires, be used in the singular or the plural, depending on the reference. References herein to any Section, Appendix, Schedule or Exhibit shall be to a Section, an Appendix, a Schedule or an Exhibit, as the case may be, hereof unless otherwise specifically provided. The use herein of the word “include” or “including,” when following any general statement, term or matter, shall not be construed to limit such statement, term or matter to the specific items or matters set forth immediately following such word or to similar items or matters, whether or not limiting language (such as “without limitation” or “but not limited to” or words of similar import) is used with reference thereto, but rather shall be deemed to refer to all other items or matters that fall within the broadest possible scope of such general statement, term or matter.

(a) Commitment. Each Lender severally agrees, on the terms and conditions set forth herein, to make Loans to Borrower during the period of time from and after the Closing Date up to the Advance Period Expiration Date, so long as the aggregate amount of such Lender’s Loans outstanding at any time does not exceed such Lender’s Commitment. Once borrowed, Borrower may not reborrow any amounts that have been repaid. The obligation of Borrower to repay the aggregate amount of all Loans made by the Lenders, together with interest accruing in connection therewith, shall be evidenced by this Agreement and the Notes (if any).

Each Lender’s obligation to make Loans in connection with the drilling and completion of wells comprising a Well Set is subject to the completion of the following requirements to the satisfaction of Administrative Agent in its sole discretion:

(A) If the proceeds of the proposed Loans are to be used for the funding of the drilling and completion of wells comprising a Well Set, then Borrower shall deliver a Well Set Approval Request to Administrative Agent for approval by the Required Lenders (which, prior to approval or disapproval by the Required Lenders, shall be supplemented with additional information of the type described in the definition of “Well Set Approval Request” as such information becomes available to Borrower); provided that, no such Well Set Approval Request is required to be submitted for Well Set 1 and such Well Set is hereby deemed approved. Administrative Agent shall promptly thereafter deliver copies of such Well Set Approval Request to the Lenders, and the Lenders shall have ten (10) Business Days (or such longer period as Borrower shall approve) to deliver in writing its approval or disapproval of such request (it being understood that such approval or disapproval is in the Lenders’ sole discretion and if the Required Lenders fail to respond within such time period, the Well Set Approval Request shall be deemed to have been

disapproved). If the Well Set Approval Request is approved, then the Lenders shall, subject to clauses (B) and (D) below and the satisfaction of the conditions precedent set forth in Sections 3.1 and 3.2, as applicable, be obligated to fund all of the amounts required by Section 2.2 applicable to the four wells comprising such Well Set.

(B) On or after the delivery of the Well Set Approval Request, Borrower may deliver one or more Borrowing Requests for Loans to be made in connection with the Well Set covered by such Well Set Approval Request. Each Borrowing Request shall, in addition to the information required to be set forth therein, also be accompanied by AFEs, Joint Interest Billings (JIBs), invoices, and other information reasonably satisfactory to Administrative Agent to evidence or explain the expenditures for which the Loans covered by such Borrowing Request are requested, and to permit Administrative Agent to confirm that such expenditures are for the applicable Well Set to which such Borrowing Request relates. If the Well Set Approval Request to which such Borrowing Request relates has been approved pursuant to clause (A) above, and Borrower has satisfied the conditions precedent in Sections 3.1 and 3.2, as applicable, then the Lenders will advance the Loans covered by a Borrowing Request within fifteen (15) Business Days after receipt of such Borrowing Request and otherwise in accordance with Section 2.3. Notwithstanding the preceding sentence, Borrower may be permitted to submit a Borrowing Request on the Closing Date for the Loans to be made on the Closing Date and, subject to satisfaction or waiver in writing of the conditions set forth in Sections 3.1 and 3.2, the Lenders shall make such Loans on the Closing Date.

(C) To the extent that the making of any Loans under this Section 2.2(b) would cause the Effective Amount to exceed the Borrowing Base then in effect, then the Borrowing Base shall, effective as of the date of the making of such Loans, be increased to an amount equal to such increased Effective Amount.

(D) Notwithstanding the foregoing clause (A) above, (i) if a Well Set Approval Request is approved by the Required Lenders but Borrower fails to submit a Borrowing Request for the first well covered by the Well Set covered by such Well Set Approval Request on or prior to the date that is thirty (30) days after the date such Well Set Approval Request is approved (such date being the “Borrowing Deadline”), then from and after the Borrowing Deadline the Lenders shall no longer be obligated to fund any amounts in connection with such Well Set without the approval of the Required Lenders or (ii) if a Well Set Approval Request is approved by the Required Lenders but Borrower fails to spud all four wells comprising the Well Set covered by such Well Set Approval Request on or prior to the date that is six months after the date such Well Set Approval Request is approved (such date being the “Well Set Deadline”), then from and after the Well Set Deadline the Lenders shall no longer be obligated to fund any additional amounts in connection with such Well Set without the approval of the Required Lenders.

Each Lender’s obligation to make Loans that are not of the type covered by Section 2.1(b) above is subject to approval by Administrative Agent and the Required Lenders in their sole discretion of the proposed use of the Loans requested and completion of the following requirements to the satisfaction of Administrative Agent in its sole discretion:

(A) Borrower shall deliver a Borrowing Request for the proposed Loans together with information reasonably satisfactory to Administrative Agent to evidence or explain the purpose of such Loans.

(B) Upon approval of the Borrowing Request by the Required Lenders, the Lenders will advance the Loans covered by such Borrowing Request within fifteen (15) Business Days after receipt of such Borrowing Request and otherwise in accordance with Section 2.3. Notwithstanding the preceding sentence, the Borrower may be permitted to submit a Borrowing Request on the Closing Date for the Loans to be made on the Closing Date and, subject to satisfaction or waiver in writing of the conditions set forth in Sections 3.1 and 3.2, the Lenders shall make such Loans on the Closing Date.

Notwithstanding the foregoing, the Loans to be made on the Closing Date as provided in Section 2.2(a) are hereby approved and no further approvals are required (other than those required by Sections 3.1 and 3.2).

(a) Closing Date Fundings. The proceeds of the Loans made on the Closing Date shall be used only to:

(A) refinance the Assigned Indebtedness in an amount not to exceed $13,622,471.25;

(B) fund up to 50% of drilling and completion expenditures detailed in AFEs for Well Set 1 delivered on or prior to the Closing Date, the aggregate total of all of such drilling and completion expenditures for Well Set 1 not to exceed $10,000,000 per well, proportionately reduced to equal Borrower’s working interest in such well, which are incurred in connection with the Development Project; provided, however, that Administrative Agent, following written request from Borrower, may increase such amount in its sole discretion to fund up to 50% of cost overruns (and in the event of any such increase, Borrower shall fund the remaining amount of such cost overruns); and

(C) fund working capital, in an amount not to exceed $6,377,528.75; provided, however, that Administrative Agent, following written request from Borrower, may increase such amount in its sole discretion.

(b) Subsequent Fundings. The proceeds of any Loans made after the Closing Date and up to the Advance Period Expiration Date shall only be used to:

(A) fund up to 50% of drilling and completion expenditures detailed in AFEs for Well Set 1 not previously funded on the Closing Date pursuant to Section 2.2(a)(B), the aggregate total of all of such drilling and completion expenditures for Well Set 1 not to exceed $10,000,000 per well, proportionately reduced to equal Borrower’s working interest in such well, which are incurred in connection with the Development Project; provided, however, that Administrative Agent, following written request from Borrower, may increase such amount in its sole discretion to fund up to 50% of cost overruns (and in the event of any such increase, Borrower shall fund the remaining amount of such cost overruns);

(B) fund up to 75% of drilling and completion expenditures detailed in AFEs for the first and second wells of Well Set 2, the aggregate total of all of such drilling and completion expenditures not to exceed $8,000,000 per well, proportionately reduced to equal Borrower’s working interest in such well, and up to 90% of drilling and completion expenditures detailed in AFEs for the third and fourth wells of Well Set 2, the aggregate total of all of such drilling and completion expenditures not to exceed $8,000,000 per well, proportionately reduced to equal Borrower’s working interest in such well, all of which are incurred in connection with the Development Project; provided, however, that Administrative Agent, following written request from Borrower, may increase such amount in its sole discretion to fund up to 75% (in the case of the first and second wells of Well Set 2) and 90% (in the case of the third and fourth wells of Well Set 2) of cost overruns (and in the event of any such increase, Borrower shall fund the remaining amount of such cost overruns);

(C) fund up to 90% of drilling and completion expenditures detailed in AFEs for Well Set 3, the aggregate total of all of such drilling and completion expenditures not to exceed $8,000,000 per well, proportionately reduced to equal Borrower’s working interest in such well which are incurred in connection with the Development Project; provided, however, that Administrative Agent, following written request from Borrower, may increase such amount in its sole discretion to fund up to 90% of cost overruns (and in the event of any such increase, Borrower shall fund the remaining amount of such cost overruns);

(D) fund up to 90% of drilling and completion expenditures detailed in AFEs for each Subsequent Well Set, the aggregate total of all of such drilling and completion expenditures not to exceed $8,000,000 per well, proportionately reduced to equal Borrower’s working interest in such well, which are incurred in connection with the Development Project; provided, however, that Administrative Agent, following written request from Borrower, may increase such amount in its sole discretion to fund up to 90% of cost overruns (and in the event of any such increase, Borrower shall fund the remaining amount of such cost overruns); and

(E) fund other expenditures incurred in connection with the Development Project or otherwise approved by Administrative Agent based upon such information and documentation to be provided by Borrower as may be requested by Administrative Agent, but only for the amounts and purposes set forth in the applicable Borrowing Request.

(a) Subject to Sections 2.1(a), 2.1(b), 2.1(c), 3.1, 3.2 and 6.20, on each Credit Date each Lender shall make a Loan to Borrower in an aggregate principal amount equal to its Pro Rata Share for such Loan of the amount set forth in an approved Borrowing Request, which amount shall not exceed the then unutilized amount of such Lender’s Commitment.

(b) Each Lender shall make the amount of its Loan available to Administrative Agent not later than 12:00 p.m. (New York City time) on the applicable Credit Date by wire transfer of same day funds in Dollars, to an account designated by Administrative Agent. Upon satisfaction or waiver of the conditions precedent specified herein, Administrative Agent shall make the proceeds of such Loans available to Borrower on the applicable Credit Date by causing an amount of same day funds in Dollars equal to the proceeds of all such Loans received by Administrative Agent from the Lenders to be credited to the Operating Account.

(a) Pro Rata Shares. All Loans shall be made by Lenders simultaneously and proportionately to their respective Pro Rata Shares for such Loan, it being understood that no Lender shall be responsible for any default by any other Lender in such other Lender’s obligation to make a Loan requested hereunder and no Commitment of any Lender shall be increased or decreased as a result of a default by any other Lender in such other Lender’s obligation to make a Loan requested hereunder.

(b) Availability of Funds. Unless Administrative Agent shall have been notified by any Lender prior to the applicable Credit Date that such Lender does not intend to make available to Administrative Agent the amount of such Lender’s Loan requested on such Credit Date, Administrative Agent may assume that such Lender has made such amount available to Administrative Agent on such Credit Date and Administrative Agent may, in its sole discretion, but shall not be obligated to, make available to Borrower a corresponding amount on such Credit Date. If such corresponding amount is not in fact made available to Administrative Agent by such Lender, Administrative Agent shall be entitled to recover such corresponding amount on demand from such Lender together with interest thereon, for each day from such Credit Date until the date such amount is paid to Administrative Agent, at the customary rate set by Administrative Agent for the correction of errors among banks for three (3) Business Days and thereafter at the Base Rate. If such Lender does not pay such corresponding amount forthwith upon Administrative Agent’s demand therefor, Administrative Agent shall promptly notify Borrower and Borrower shall immediately pay such corresponding amount to Administrative Agent together with interest thereon, for each day from such Credit Date until the date such amount is paid to Administrative Agent, at the interest rate payable hereunder for Loans.

(a) Register. Administrative Agent shall maintain at its Principal Office a register for the recordation of the names and addresses of the Lenders, the Commitments, approved Borrowing Requests and Loans of each Lender from time to time (the “Register”). The Register shall be available for inspection by Borrower or any Lender at any reasonable time and from time to time upon reasonable prior notice; provided, however, that any Lender may only inspect the Register solely with respect to such Lender’s Commitment. Administrative Agent may record each repayment or prepayment in respect of the principal amount of the Loans, and any such recordation is conclusive and binding on Borrower and each Lender, absent manifest error; provided, failure to make any such recordation, or any error in such recordation, shall not affect any Lender’s Commitment, approved Borrowing Requests, or Borrower’s Obligations. Borrower hereby designates the entity serving as Administrative Agent to serve as Borrower’s agent solely for purposes of maintaining the Register as provided in this Section 2.5.

(b) Notes. If so requested by any Lender by written notice to Borrower (with a copy to Administrative Agent) at least two (2) Business Days prior to the Closing Date, or at any time thereafter, Borrower shall execute and deliver to such Lender (and/or, if applicable and if so specified in such notice, to any Person who is an assignee of such Lender pursuant to Section 10.6) on the Closing Date (or, if such notice is delivered after the Closing Date, promptly after Borrower’s receipt of such notice) a Note to evidence such Loan. This Agreement evidences the obligation of Borrower to repay the Loans and is being executed as a “noteless” credit agreement. However, at the request of any Lender at any time, Borrower agrees that it will prepare, execute and deliver to such Lender a Note payable to such Lender (or, if requested by such Lender, to such Lender and its registered assigns). Thereafter, the Loans evidenced by such Note and interest thereon shall at all times (including after assignment permitted

hereunder) be represented by one or more Notes in such form payable to the payee named therein (or to such payee and its registered assigns). Interest on each Note shall accrue and be due and payable as provided herein.

(a) Except as otherwise set forth herein, each Loan shall bear interest on the unpaid principal amount thereof from the date made through repayment (whether by acceleration or otherwise) at a rate equal to the Base Rate plus ten percent (10%) per annum.

(b) Interest shall be computed on the basis of a year of 365 days (or 366 days in a leap year), in each case for the actual number of days elapsed in the period during which it accrues. In computing interest on any Loan, the date of the making of such Loan shall be included, and the date of payment of such Loan shall be excluded.

(c) Except as otherwise set forth herein, interest on each Loan shall be due and payable by Borrower monthly on each Monthly Date (regardless of whether or not funds are available from the Lockbox Account) commencing with the month following the Closing Date; provided that (i) if amounts in the Lockbox Account are sufficient to pay such interest on the Monthly Date in accordance with Section 2.9(b) such interest shall be paid from the Lockbox Account in accordance with Section 2.9(b), (ii) interest accrued pursuant to Section 2.7 shall be payable on demand and (iii) in the event of any prepayment of any Loan pursuant to Section 2.10, accrued interest on the principal amount prepaid shall be due and payable on the date of such prepayment.

2.7 Default Interest. Upon the occurrence and during the continuance of an Event of Default, the principal amount of all Loans outstanding and, to the extent permitted by applicable law, any interest payments on the Loans or any fees or other amounts owed hereunder, shall thereafter bear interest (including post petition interest in any proceeding under the Bankruptcy Code or other applicable bankruptcy laws) payable on demand at a rate per annum equal to the Base Rate plus twelve percent (12%). Payment or acceptance of the increased rates of interest provided for in this Section 2.7 is not a permitted alternative to timely payment and shall not constitute a waiver of any Event of Default or otherwise prejudice or limit any rights or remedies of Administrative Agent or any Lender.

(a) Borrower shall pay to Administrative Agent for its own account a Facility Fee in the amounts and at the times previously agreed upon in writing by Borrower and Administrative Agent including in the Fee Letter.

(b) Borrower shall pay to Administrative Agent for its own account fees in the amounts and at the times previously agreed upon in writing by Borrower and Administrative Agent including those fees set forth in the Fee Letter.

(a) Principal Repayment. The Principal Obligations are due and payable on each Principal Payment Date in installments equal to Principal Payment Amount for such Principal Payment Date, with a final payment due on the Maturity Date in an amount equal to all Principal Obligations then outstanding. In addition, on the date of the Eaglebine Sale, Borrower shall prepay the Loans by an amount equal to 20% of the gross proceeds from such sale that remain after deducting reasonable and documented transaction costs and expenses incurred and paid by Borrower in connection with the Eaglebine Sale. The prepayment required by the preceding sentence shall be applied to the Principal Obligations in the inverse order of their maturity.

(b) Payments from Lockbox Account. To the extent not otherwise paid by Borrower on or before each Monthly Date, Borrower shall repay all then due and payable Non-Principal Obligations through Administrative Agent disbursing such funds from the Lockbox Account. So long as no Default or Event of Default has occurred and is continuing, any funds that remain in the Lockbox Account after application of the foregoing payments (other than funds necessary to maintain the Interest Reserve (as defined in Section 5.17) and the interest due on the next Monthly Date) shall be disbursed on the 27th day of each month (or next Business Day if such 27th day is not a Business Day) to the Operating Account. Notwithstanding anything in this Agreement to the contrary, in no event shall the Interest Reserve plus an amount necessary to pay the interest due on the next Monthly Date be disbursed from the Lockbox Account without the consent of Administrative Agent.

(c) Notwithstanding anything herein to the contrary, if not paid prior thereto, Borrower hereby unconditionally promises to pay to Administrative Agent for the account of each Lender the then unpaid principal amount of such Lender’s Loans and the accrued and unpaid interest thereon and all unpaid fees and expenses and other amounts owing to Administrative Agent of any Lender related to this Agreement on the Maturity Date.

(a) Borrower shall have the right at any time and from time to time to prepay any Loan in whole or in part, subject to prior notice in accordance with Section 2.10(b), provided that, Borrower shall also pay the Make-Whole Amount if any such prepayment (i) occurs prior to June 26, 2013 and (ii) results, when aggregated with any prior Loan prepayments, in Borrower prepaying greater than fifty percent (50%) of the maximum amount of the Principal Obligations outstanding at any time prior to the date of such prepayment.

(b) Borrower shall notify Administrative Agent in writing of any prepayment hereunder no later than 12:00 noon, New York City time, three (3) Business Days before the date of prepayment. Each such notice shall be irrevocable and shall specify the prepayment date and the principal amount of each Loan or portion thereof to be prepaid. Promptly following receipt of any such notice relating to a Loan, Administrative Agent shall advise the Lenders of the contents thereof. Prepayments shall be accompanied by accrued interest to the extent required by Section 2.6.

(a) All payments by Borrower of principal, interest, fees and other Obligations shall be made in Dollars in same day funds, without, recoupment, setoff, counterclaim or other defense free of any restriction or condition, and delivered to Administrative Agent not later than 12:00 p.m. (New York City time) on the date due to Administrative Agent’s account in New York for the account of Lenders.

(b) Administrative Agent shall promptly distribute to each Lender at such address as such Lender shall indicate in writing, such Lender’s Pro Rata Share of all payments and prepayments of principal and interest due hereunder, together with all other amounts due thereto, including all fees payable with respect thereto, to the extent received by Administrative Agent.

(c) Administrative Agent shall deem any payment by or on behalf of Borrower hereunder that is not made in same day funds prior to 12:00 p.m. (New York City time) to be a non conforming payment. Any such payment shall not be deemed to have been received by Administrative Agent until

the later of (i) the time such funds become available funds, and (ii) the applicable next Business Day. Interest fees shall continue to accrue on any principal as to which a non conforming payment is made until such funds become available funds (but in no event less than the period from the date of such payment to the next succeeding applicable Business Day) at the Default Rate from the date such amount was due and payable until the date such amount is paid in full.

(d) If an Event of Default shall have occurred and not otherwise been waived, and the maturity of the Obligations shall have been accelerated pursuant to Section 8.1, all payments or proceeds received by Administrative Agent hereunder in respect of any of the Obligations shall be applied in accordance with Section 8.2.

2.12 Ratable Sharing. Subject to the provisions of Section 2.15, the Lenders hereby agree among themselves that, except as otherwise provided in the Collateral Documents with respect to amounts realized from the exercise of rights with respect to Liens on the Collateral, if any of them shall, whether by voluntary payment (other than a voluntary prepayment of Loans made and applied in accordance with the terms hereof), through the exercise of any right of set off or banker’s lien, by counterclaim or cross action or by the enforcement of any right under the Credit Documents or otherwise, or as adequate protection of a deposit treated as cash collateral under the Bankruptcy Code, receive payment or reduction of a proportion of the aggregate amount of principal, interest, amounts payable in respect of fees and other amounts then due and owing to such Lender hereunder or under the other Credit Documents (collectively, the “Aggregate Amounts Due” to such Lender) which is greater than the proportion received by any other Lender in respect of the Aggregate Amounts Due to such other Lender, then the Lender receiving such proportionately greater payment shall (a) notify Administrative Agent and each other Lender of the receipt of such payment and (b) apply a portion of such payment to purchase participations (which it shall be deemed to have purchased from each seller of a participation simultaneously upon the receipt by such seller of its portion of such payment) in the Aggregate Amounts Due to the other Lenders so that all such recoveries of Aggregate Amounts Due shall be shared by all Lenders in proportion to the Aggregate Amounts Due to them; provided, if all or part of such proportionately greater payment received by such purchasing Lender is thereafter recovered from such Lender upon the bankruptcy or reorganization of Borrower or otherwise, those purchases to that extent shall be rescinded and the purchase prices paid for such participations shall be returned to such purchasing Lender ratably to the extent of such recovery, but without interest. Borrower expressly consents to the foregoing arrangement and agrees that any holder of a participation so purchased may exercise any and all rights of banker’s lien, set off or counterclaim with respect to any and all monies owing by Borrower to that holder with respect thereto as fully as if that holder were owed the amount of the participation held by that holder.

(a) Compensation For Increased Costs and Taxes. Subject to the provisions of Section 2.14 (which shall be controlling with respect to the matters covered thereby), in the event that any Lender shall determine (which determination shall, absent manifest error, be final and conclusive and binding upon all parties hereto) that any law, treaty or governmental rule, regulation or order, or any change therein or in the interpretation, administration or application thereof (including the introduction of any new law, treaty or governmental rule, regulation or order), or any determination of a court or Governmental Authority, in each case that becomes effective after the date hereof, or compliance by such Lender with any guideline, request or directive issued or made after the date hereof by any central bank or other governmental or quasi governmental authority (whether or not having the force of law): (i) subjects such Lender (or its applicable lending office) to any additional Tax (other than Taxes covered by Section 2.14) with respect to this Agreement or any of the other Credit Documents or any of its obligations hereunder or thereunder or any payments to such Lender (or its applicable lending office) of principal, interest, fees or any other

amount payable hereunder; (ii) imposes, modifies or holds applicable any reserve (including any marginal, emergency, supplemental, special or other reserve), special deposit, compulsory loan, FDIC insurance or similar requirement against assets held by, or deposits or other liabilities in or for the account of, or advances or loans by, or other credit extended by, or any other acquisition of funds by, any office of such Lender; or (iii) imposes any other condition (other than with respect to a Tax matter) on or affecting such Lender (or its applicable lending office) or its obligations hereunder; and the result of any of the foregoing is to increase the cost to such Lender of agreeing to make, making or maintaining Loans hereunder or to reduce any amount received or receivable by such Lender (or its applicable lending office) with respect thereto; then, in any such case, Borrower shall promptly pay to such Lender, upon receipt of the statement referred to in the next sentence, such additional amount or amounts (in the form of an increased rate of, or a different method of calculating, interest or otherwise as such Lender in its sole discretion shall determine) as may be necessary to compensate such Lender for any such increased cost or reduction in amounts received or receivable hereunder; provided, however, that Borrower shall not be obligated for the payment of any such additional amounts to the extent such costs accrued more than 180 days prior to the date Borrower was given such demand. Such Lender shall deliver to Borrower (with a copy to Administrative Agent) a written statement, setting forth in reasonable detail the basis for calculating the additional amounts owed to such Lender under this Section 2.13(a), which statement shall be conclusive and binding upon all parties hereto absent manifest error.

(b) Capital Adequacy Adjustment. In the event that any Lender shall have determined that the adoption, effectiveness, phase in or applicability after the Closing Date of any law, rule or regulation (or any provision thereof) regarding capital adequacy, or any change therein or in the interpretation or administration thereof by any Governmental Authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by any Lender (or its applicable lending office) with any guideline, request or directive regarding capital adequacy (whether or not having the force of law) of any such Governmental Authority, central bank or comparable agency, has or would have the effect of reducing the rate of return on the capital of such Lender or any corporation controlling such Lender as a consequence of, or with reference to, such Lender’s Loans, or participations therein or other obligations hereunder with respect to the Loans to a level below that which such Lender or such controlling corporation could have achieved but for such adoption, effectiveness, phase in, applicability, change or compliance (taking into consideration the policies of such Lender or such controlling corporation with regard to capital adequacy), then from time to time, within five Business Days after receipt by Borrower from such Lender of the statement referred to in the next sentence, Borrower shall pay to such Lender such additional amount or amounts as will compensate such Lender or such controlling corporation on an after tax basis for such reduction. Such Lender shall deliver to Borrower (with a copy to Administrative Agent) a written statement, setting forth in reasonable detail the basis for calculating the additional amounts owed to Lender under this Section 2.13(b), which statement shall be conclusive and binding upon all parties hereto absent manifest error.

(a) Payments to Be Free and Clear. All sums payable by any Credit Party hereunder and under the other Credit Documents shall (except to the extent required by law) be paid free and clear of, and without any deduction or withholding on account of, any Tax imposed, levied, collected, withheld or assessed by or within the United States of America or any political subdivision in or of the United States of America or any other jurisdiction from or to which a payment is made by or on behalf of any Credit Party or by any federation or organization of which the United States of America or any such jurisdiction is a member at the time of payment.

(b) Withholding of Taxes. If any Credit Party or any other Person is required by law to make any deduction or withholding on account of any Tax from any sum paid or payable under any of the

Credit Documents: (i) Borrower shall notify Administrative Agent of any such requirement or any change in any such requirement as soon as Borrower becomes aware of it; (ii) Borrower shall pay any such Tax before the date on which penalties attach thereto, such payment to be made (if the liability to pay is imposed on any Credit Party) for its own account or (if that liability is imposed on Administrative Agent or such Lender, as the case may be) on behalf of and in the name of Administrative Agent or such Lender; (iii) the sum payable by such Credit Party in respect of which the relevant deduction, withholding or payment, is required shall be increased to the extent necessary to ensure that, after the making of that deduction, withholding or payment of all Indemnified Taxes, Administrative Agent or such Lender, as the case may be, receives on the due date and retains a net sum equal to what it would have received and retained had no such deduction, withholding or payment been required or made; and (iv) within thirty (30) days after making any such deduction or withholding, and within thirty (30) days after the due date of payment of any Tax which it is required by clause (ii) above to pay, Borrower shall deliver to Administrative Agent evidence satisfactory to Administrative Agent of such deduction, withholding and payment and of the remittance thereof to the relevant taxing or other authority.

(c) Other Taxes. In addition, the Credit Parties shall pay all Other Taxes to the relevant Governmental Authorities in accordance with applicable law. The Credit Parties shall deliver to Administrative Agent official receipts or other evidence of such payment reasonably satisfactory to Administrative Agent in respect of any Taxes or Other Taxes payable hereunder promptly after payment of such Taxes or Other Taxes.

(d) Indemnification. The Credit Parties shall indemnify Administrative Agent and each Lender, within ten (10) days after written demand therefor, for the full amount of any Indemnified Taxes paid or incurred by such Administrative Agent or such Lender, as the case may be, relating to, arising out of, or in connection with any Credit Document or any payment or transaction contemplated hereby or thereby, whether or not such Indemnified Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate from the relevant Lender or Administrative Agent, setting forth in reasonable detail the basis and calculation of such Indemnified Taxes shall be conclusive, absent manifest error.

(e) Evidence of Exemption From U.S. Withholding Tax. Each Non-U.S. Lender shall deliver to Administrative Agent for transmission to Borrower, on or prior to the Closing Date (in the case of each Lender listed on the signature pages hereof on the Closing Date) or on or prior to the date of the Assignment Agreement pursuant to which it becomes a Lender (in the case of each other Lender), and at such other times as may be necessary in the determination of Borrower or Administrative Agent (each in the reasonable exercise of its discretion), (i) two original copies of Internal Revenue Service Form W-8BEN, W-8IMY or W-8ECI (or any successor forms), properly completed and duly executed by such Lender, and such other documentation required under the Internal Revenue Code and reasonably requested by Borrower to establish that such Lender is not subject to deduction or withholding of United States federal income tax with respect to any payments to such Lender of principal, interest, fees or other amounts payable under any of the Credit Documents or is subject to deduction or withholding at a reduced rate, or (ii) if such Lender is not a “bank” or other Person described in Section 881(c)(3) of the Internal Revenue Code and cannot deliver Internal Revenue Service Form W-8ECI pursuant to clause (i) above, a Certificate Regarding Non Bank Status together with two original copies of Internal Revenue Service Form W-8BEN (or any successor form), properly completed and duly executed by such Lender, and such other documentation required under the Internal Revenue Code and reasonably requested by Borrower to establish that such Lender is not subject to deduction or withholding of United States federal income tax with respect to any payments to such Lender of interest payable under any of the Credit Documents. Each Lender required to deliver any forms, certificates or other evidence with respect to United States federal income tax withholding matters pursuant to this Section 2.14(e) hereby agrees, from time to time after the initial delivery by such Lender of such forms, certificates or other evidence,

whenever a lapse in time or change in circumstances renders such forms, certificates or other evidence obsolete or inaccurate in any material respect, that such Lender shall promptly deliver to Administrative Agent for transmission to Borrower two new original copies of Internal Revenue Service Form W-8BEN, W-8IMY or W-8ECI, or a Certificate Regarding Non Bank Status and two original copies of Internal Revenue Service Form W-8BEN (or any successor form), as the case may be, properly completed and duly executed by such Lender, and such other documentation required under the Internal Revenue Code and reasonably requested by Borrower to confirm or establish that such Lender is not subject to deduction or withholding of United States federal income tax with respect to payments to such Lender under the Credit Documents or is subject to deduction or withholding at a reduced rate, or notify Administrative Agent and Borrower of its inability to deliver any such forms, certificates or other evidence. In addition, any Lender, if requested by Borrower, shall deliver such other documentation prescribed by applicable law or reasonably requested by Borrower as will enable Borrower to determine whether or not such Lender is subject to backup withholding or information reporting requirements. Nothing in this Section 2.14 shall be construed to require a Lender, Administrative Agent or Participant to provide any forms or documentation that it is not legally entitled to provide.

(f) In the case of a Lender that would be subject to withholding tax imposed by FATCA on payments made hereunder or under the other Credit Documents if such Lender fails to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Internal Revenue Code, as applicable), such Lender shall provide such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Internal Revenue Code) and such additional documentation reasonably requested by Borrower as may be necessary for Borrower to comply with its obligations under FATCA, to determine that such Lender has complied with such Lender’s obligations under FATCA, or to determine the amount to deduct and withhold from any such payments.

2.15 Defaulting Lenders. Anything contained herein to the contrary notwithstanding, in the event that any Lender, other than at the direction or request of any regulatory agency or authority, defaults (a “Defaulting Lender”) in its obligation to fund (a “Funding Default”) any Loan (a “Defaulted Loan”), then (a) during any Default Period with respect to such Defaulting Lender, such Defaulting Lender shall be deemed not to be a “Lender” for purposes of voting on any matters (including the granting of any consents or waivers) with respect to any of the Credit Documents except as provided in the next sentence; and (b) to the extent permitted by applicable law, until such time as the Default Excess with respect to such Defaulting Lender shall have been reduced to zero, (i) any voluntary prepayment of the Loans shall, if Administrative Agent so directs at the time of making such voluntary prepayment, be applied to the Loans of other Lenders as if such Defaulting Lender had no Loans outstanding and the Loan Exposure of such Defaulting Lender were zero, and (ii) any mandatory prepayment of the Loans shall automatically be applied to the Loans of other Lenders (but not to the Loans of such Defaulting Lender) as if such Defaulting Lender had funded all Defaulted Loans of such Defaulting Lender, it being understood and agreed that Borrower shall be entitled to retain any portion of any mandatory prepayment of the Loans that is not paid to such Defaulting Lender solely as a result of the operation of the provisions of this clause (b). No Commitment of any Lender shall be extended, increased or otherwise affected, and, except as otherwise expressly provided in this Section 2.15, performance by Borrower of its obligations hereunder and the other Credit Documents shall not be excused or otherwise modified as a result of any Funding Default or the operation of this Section 2.15. The rights and remedies against a Defaulting Lender under this Section 2.15 are in addition to other rights and remedies which Borrower may have against such Defaulting Lender with respect to any Funding Default and which Administrative Agent or any Lender may have against such Defaulting Lender with respect to any Funding Default.

(a) Scheduled Borrowing Base Determinations. Subject to Section 2.16(c), at all times prior to the Maturity Date the Effective Amount shall not exceed the Borrowing Base then in effect (it being understood that failure to comply with this sentence shall not constitute a Default or Event of Default, but instead the Borrower shall be subject to the requirements of such Section 2.16(c)). The initial Borrowing Base hereunder shall be $30,000,000.00 until redetermined as set forth on Appendix A and this Section 2.16 (each, a “Scheduled Borrowing Base Determination”). The Borrowing Base shall be redetermined by Administrative Agent and the Lenders in their sole discretion, and effective as of the date set forth in such notice of redetermination. The Borrowing Base shall represent the determination by Administrative Agent and the Lenders, in their sole discretion, of the loan value assigned to the proved Oil and Gas Properties evaluated in the most recently delivered Reserve Report and such other credit factors (including without limitation the assets, liabilities, cash flow, current Swap Agreements, business, properties, prospects, management and ownership of the Credit Parties) which Administrative Agent and the Lenders in their sole discretion deem significant. In connection with each redetermination of the Borrowing Base, Administrative Agent shall recommend to the Lenders a new Borrowing Base and Administrative Agent and the Lenders in their sole discretion shall (by unanimous agreement in the case of Borrowing Base increases and by agreement of Administrative Agent and the Required Lenders in the case of no change or decreases in the Borrowing Base) establish the redetermined Borrowing Base. If Administrative Agent and all the Lenders (for an increase) or Administrative Agent and the Required Lenders (for no change or a decrease), as the case may be, cannot agree on a Borrowing Base amount, the amount shall remain unchanged until such time as Administrative Agent and all Lenders (for an increase) or Administrative Agent and the Required Lenders (for no change or a decrease), as the case may be, can agree on a new Borrowing Base amount. Such redetermination shall be given by notice to Borrower by the dates specified on Appendix A, or as soon thereafter as is reasonably practicable. If Borrower does not furnish the Reserve Reports or all such other information and data by the date required, Administrative Agent and the Lenders may nonetheless determine a new Borrowing Base. Notwithstanding any of the foregoing and unless a Special Event has occurred and is continuing, (i) there shall be no Scheduled Borrowing Base Determination until the first anniversary of the Closing Date and (ii) no Scheduled Borrowing Base Determination shall cause Borrower to not receive Committed Well Set Funds.

(b) Administrative Agent and Lenders’ Discretion. Administrative Agent and the Lenders shall have no obligation to determine the Borrowing Base at any particular amount, either in relation to the Maximum Loan Amount or otherwise. Furthermore, Borrower acknowledges that Administrative Agent and the Lenders have no obligation to increase the Borrowing Base and may reduce the Borrowing Base in accordance with Section 2.16(a), in either case, at any time pursuant to Section 2.16(a) and (d) or as a result of any circumstance and that any increase in the Borrowing Base is subject to the sole discretion of each of Administrative Agent and the Lenders.

(c) Mandatory Prepayments of Loans. If after giving effect to any Borrowing Base redetermination, the Effective Amount shall exceed the Borrowing Base, then Borrower shall, within thirty (30) days after notice by Administrative Agent to Borrower, exercise either one or a combination of the following: (i) prepay the amount by which the Effective Amount exceeds the Borrowing Base on such date; or (ii) prepay the amount by which the Effective Amount exceeds the Borrowing Base in four (4) equal successive monthly payments commencing sixty (60) days following Administrative Agent’s notice to Borrower; or (iii) provide a Reserve Report prepared by an independent engineer and reasonably acceptable to Administrative Agent covering additional unencumbered assets not previously evaluated in the most recently delivered Reserve Report having sufficient value and character (as determined by Administrative Agent and the Required Lenders in their sole and absolute discretion) that when added to the Collateral will cause the Borrowing Base to equal or exceed the Effective Amount and within fifteen (15) days after notification of its election to exercise such option grant a Lien on such assets.

(d) Special Borrowing Base Determination. In addition to Scheduled Borrowing Base Determinations pursuant to Section 2.16(a), Administrative Agent and Borrower may each request a special redetermination once between each April 30 and the following October 31 and between each October 31 and the following April 30 (“Special Borrowing Base Determination”). In the event Borrower requests a Special Borrowing Base Determination, Borrower shall deliver written notice of such request to Administrative Agent with sufficient copies for each Lender which shall include: (i) Reserve Report(s) prepared by an Approved Petroleum Engineer as of a date not more than thirty (30) calendar days prior to the date of such request (provided, however, that upon consent of Administrative Agent in its sole discretion, such Reserve Report may be an internally prepared Reserve Report), (ii) such other information as Administrative Agent shall reasonably request, and (iii) the amount of the Borrowing Base requested by Borrower to become effective. Likewise, in the event Administrative Agent exercises its option for a Special Borrowing Base Determination, upon written request and notification by Administrative Agent to Borrower, Borrower shall furnish the information described above within thirty (30) days of such request. Administrative Agent and the Lenders shall redetermine the Borrowing Base in accordance with the procedures set forth in Section 2.16(a), which redetermined Borrowing Base shall then be the effective Borrowing Base until further redetermination or adjustment. Notwithstanding any of the foregoing and unless a Special Event has occurred and is continuing, (i) there shall be no Special Borrowing Base Determination requested by the Administrative Agent until the first anniversary of the Closing Date and (ii) no Special Borrowing Base Determination shall cause Borrower to not receive Committed Well Set Funds.

(e) Other Borrowing Base Adjustments. In the event any advance of Loans approved for Well Set 1 pursuant to Section 2.2(a)(B) and Section 2.2(b)(A), Well Set 2 pursuant Section 2.2(b)(B), Wells Set 3 pursuant to Section 2.2(b)(C), or any Subsequent Well Set pursuant to Section 2.2(b)(D) causes the Committed Well Set Funds to be advanced at such time to exceed the Available Amount, then the Borrowing Base shall be automatically increased to an amount necessary to cause such advance not to exceed the Available Amount. Notwithstanding anything in this Agreement to the contrary, in no event shall the foregoing adjustment pursuant to this Section 2.16(e) permit the amount of Loans advanced hereunder, without giving effect to any repayment, to exceed the Maximum Loan Amount. For the avoidance of doubt, upon the occurrence of any prepayment or repayment of Loans under this Agreement, the Borrowing Base shall be reduced by the amount of such prepayment or repayment; provided, however, that, notwithstanding anything in this Agreement to the contrary, no such reduction shall result in Borrower not receiving funds relating to a Well Set Approval Request that has been approved pursuant to Section2.1(b)(A).

3.1 Closing Date. The obligation of each Lender to make any Loan on the Closing Date is subject to the satisfaction, or waiver by Administrative Agent and the Required Lenders, or the Lenders, as applicable, in accordance with Section 10.5 in their sole and absolute discretion of the following conditions on or before the Closing Date:

(a) Credit Documents, etc. Administrative Agent shall have received sufficient copies of each Credit Document duly executed and delivered by each applicable Credit Party and each Lender, to which it is a party.

(b) Related Agreements. Administrative Agent shall have received an executed copy of each Related Agreement (other than the Mineral Interest Conveyance Documents) and all schedules, exhibits and annexes thereto.

(c) Organizational Documents; Incumbency. Administrative Agent shall have received (i) sufficient copies of each Organizational Document of each Credit Party, as applicable, and, to the extent applicable, certified as of a recent date by the appropriate governmental official; (ii) signature and incumbency certificates of the officers of such Person executing the Credit Documents to which it is a party; (iii) resolutions of the Board of Directors or similar governing body of each Credit Party approving and authorizing the execution, delivery and performance of this Agreement and the other Credit Documents executed on the date hereof to which it is a party or by which it or its assets may be bound as of the Closing Date, certified as of the Closing Date by its secretary or an assistant secretary as being in full force and effect without modification or amendment; and (iv) a good standing certificate from the applicable Governmental Authority of each Credit Party’s jurisdiction of incorporation, organization or formation and in each jurisdiction in which it is qualified as a foreign corporation or other entity to do business, each dated a recent date prior to the Closing Date.

(d) Organizational and Capital Structure. The organizational structure and capital structure of the Credit Parties shall be as set forth on Schedule 4.2 and Schedule 4.3. Administrative Agent shall have received evidence reasonably satisfactory to it that (i) the Management Holders own not less than fifty-one percent (51%) of the issued and outstanding Capital Stock of Borrower and (ii) concurrent with the closing of this Agreement, no Credit Party owns any equity interest in ENEXP, LP, a Texas limited partnership or have any contractual liabilities (other than contractual liabilities arising under the Limited Partnership Agreement of ENEXP, LP) with respect to such entity (for the avoidance of doubt, Borrower is permitted to dispose of such equity interest and make, in connection with the disposition of such equity interest, a one-time payment of up to $150,000 to the Management Holders for the purpose of paying litigation costs of such entity).

(e) Borrowing Request. Administrative Agent shall have received an executed Borrowing Request.

(f) Governmental Authorizations and Consents. Each Credit Party shall have obtained all Governmental Authorizations and all consents of other Persons, in each case that are necessary or advisable in connection with the transactions contemplated by the Credit Documents and the Related Agreements and each of the foregoing shall be in full force and effect and in form and substance reasonably satisfactory to Administrative Agent. All applicable waiting periods shall have expired without any action being taken or threatened by any competent authority which would restrain, prevent or otherwise impose adverse conditions on the transactions contemplated by the Credit Documents or the Related Agreements or the financing thereof and no action, request for stay, petition for review or rehearing, reconsideration, or appeal with respect to any of the foregoing shall be pending, and the time for any applicable agency to take action to set aside its consent on its own motion shall have expired.

(g) Title and First Priority Lien on Oil and Gas Properties. Subject to Section 3.3(a), satisfactory review of title information to evidence Marketable Title with respect to the Oil and Gas Properties of the Credit Parties. In order to create in favor of Administrative Agent, for the benefit of the Secured Parties, a valid and, subject to any filing and/or recording referred to herein, perfected First Priority security interest on such Oil and Gas Properties of the Credit Parties as Administrative Agent may request, and Administrative Agent shall have received from each Credit Party, as applicable:

(A) The Assignment of Liens, duly executed and notarized and in proper form and sufficient counterparts for recording in all appropriate places in all applicable jurisdictions;

(B) The Mortgages, executed and notarized and in proper form and sufficient counterparts for recording in all appropriate places in all applicable jurisdictions, encumbering such Oil and Gas Properties; and

(C) Direction Letters signed by each applicable Credit Party addressed to purchasers of such Credit Party’s production for such Oil and Gas Properties directing all proceeds to be paid into the Lockbox Account.

(h) Personal Property Collateral. In order to create in favor of Administrative Agent, for the benefit of the Secured Parties, a valid, perfected First Priority security interest in all personal property of the Credit Parties subject to Article 8 and 9 of the UCC (except for Excluded Assets (as defined in the Pledge and Security Agreement)), Administrative Agent shall have received from each Credit Party, as applicable:

(A) evidence satisfactory to Administrative Agent of the compliance by each Credit Party of its respective obligations under the Collateral Documents to which it is a party (including its obligations to deliver originals of securities, instruments and chattel paper and any agreements governing deposit and/or securities accounts as provided therein);

(B) A completed Collateral Questionnaire dated the Closing Date and executed by an Authorized Officer of each Credit Party, together with all attachments contemplated thereby, including (A) the results of a recent search, by a Person reasonably satisfactory to Administrative Agent, of all effective UCC financing statements (or equivalent filings) made with respect to any personal or mixed property of any Credit Party in the jurisdictions specified in the Collateral Questionnaire, together with copies of all such filings disclosed by such search, and (B) UCC statements (or similar documents) for filing in all applicable jurisdictions as may be necessary to (i) terminate any effective UCC financing statements (or equivalent filings) disclosed in such search (other than any such financing statements in respect of Permitted Liens) and (ii) assign any effective UCC financing statements with respect to the Assigned Indebtedness;

(C) evidence that each Credit Party shall have taken or caused to be taken any other action, executed and delivered or caused to be executed and delivered any other agreement, document and instrument and made or caused to be made any other filing and recording (other than as set forth herein) reasonably required by Administrative Agent.

(i) Environmental Reports. Administrative Agent shall have received reports and other information, in form, scope and substance reasonably satisfactory to Administrative Agent, regarding environmental matters relating to the Oil and Gas Properties of the Credit Parties.

(j) Financial Statements; Projections; Accounts Payable. Lenders shall have received from Borrower the Pro Forma Balance Sheet, Borrower’s audited financial statements dated December 31, 2011, Borrower’s unaudited financial statements dated April 30, 2012, the Projections and a detailed schedule of Borrower’s accounts payable, including, without limitation, Borrower’s future lease payments.

(k) Evidence of Insurance. Subject to Section 3.3(c), Administrative Agent shall have received certified copies of all insurance policies and a certificate from Borrower’s insurance broker or other evidence satisfactory to it that all insurance required to be maintained pursuant to Section 5.5 is in full force and effect, together with endorsements naming Administrative Agent, for the benefit of Secured Parties, as additional insured and loss payee thereunder to the extent required under Section 5.5.

(l) Opinions of Counsel to Credit Parties. Administrative Agent shall have received originally executed copies of the favorable written opinions of counsel for the Credit Parties and the favorable written opinions of local counsel for the Credit Parties in each jurisdiction in which any Credit Party is a registered organization under the UCC or required to grant a Mortgage, each dated as of the Closing Date and covering such matters as Administrative Agent may reasonably request and otherwise in form and substance reasonably satisfactory to Administrative Agent (and each Credit Party hereby instructs such counsel to deliver such opinions to Administrative Agent and Lenders).

(m) Fees. Borrower shall have paid all reasonable and documented fees and other amounts due and payable on the Closing Date (including the reasonable and documented fees and expenses of consultants and legal counsel).

(n) Closing Date Certificate. Borrower shall have delivered to Administrative Agent a Closing Date Certificate, together with all attachments thereto.

(o) No Litigation. There shall not exist any action, suit, investigation, litigation or proceeding or other legal or regulatory developments, pending or threatened in any court or before any arbitrator or Governmental Authority that, in the reasonable opinion of Administrative Agent, singly or in the aggregate, materially impairs any of the transactions contemplated by the Credit Documents, or that could reasonably be expected to have a Material Adverse Effect.

(p) Due Diligence. Other than changes occurring in the ordinary course of business, no information or materials are or should have been available to any Credit Party as of the Closing Date that are materially inconsistent with the material previously provided to Administrative Agent for its due diligence review of the Credit Parties. Administrative Agent shall be satisfied with all agreements relating to the Oil and Gas Properties of the Credit Parties, including operating agreements, marketing agreements, transportation agreements and processing agreements. Administrative Agent shall be satisfied with the potential plugging and abandonment liabilities associated with the Oil and Gas Properties of the Credit Parties, including the bonding or collateralization obligations of the Credit Parties associated therewith. Administrative Agent shall be satisfied with the results of complete background checks on management.

(q) No Material Adverse Effect. Since January 1, 2012, no event, circumstance or change shall have occurred that has caused or evidences, either in any case or in the aggregate, a Material Adverse Effect.

(r) ORI Documents. Administrative Agent shall have received from Borrower duly executed counterparts of the Equity Kicker Letter and the ORI Conveyance.

(s) Equity Investment. Administrative Agent shall have received evidence satisfactory to it that Borrower has deposited into the Equity Account an amount equal to the positive difference between (i) $11,000,000 minus (ii) 50% of the amounts paid by the Credit Parties or their Affiliates in respect of the Well Sets on or before the Closing Date.

(t) Other Documentation. Administrative Agent shall have received all other documents and instruments which Administrative Agent may reasonably request.

Each Lender, by delivering its signature page to this Agreement and funding a Loan on the Closing Date, shall be deemed to have acknowledged receipt of, and consented to and approved, each Credit Document and each other document required to be approved by the Required Lenders or Lenders, as applicable on the Closing Date.

3.2 Conditions to Each Credit Extension. The obligation of each Lender to make any Loan on any Credit Date, including the Closing Date, is subject to the satisfaction, or waiver in accordance with Section 10.5, of the following conditions precedent:

(a) the Loans requested on such Credit Date shall not exceed the aggregate Commitments for the Lenders;

(b) as of such Credit Date, the representations and warranties contained herein and in the other Credit Documents shall be true and correct in all material respects on and as of that Credit Date to the same extent as though made on and as of that date, except to the extent such representations and warranties specifically relate to an earlier date, in which case such representations and warranties shall have been true and correct on and as of such earlier date;

(c) Administrative Agent shall have approved the proposed Loan, in its sole discretion, and the use of proceeds thereunder to fund the Development Project as detailed in AFEs, joint interest billings, invoices and other documentation submitted with the relevant Borrowing Request, in detail and substance satisfactory to Administrative Agent in its sole discretion;

(d) as of such Credit Date, no event shall have occurred and be continuing or would result from the extension of credit hereunder or the Liens on the Collateral that would constitute an Event of Default or a Default or a Material Adverse Effect;

(e) in the event any Loans made on such Credit Date fund drilling and completion expenditures pursuant to Sections 2.1(b) or 2.1(c), Administrative Agent shall have received from Borrower duly executed counterparts of the ORI Conveyance required under the Equity Kicker Letter; and

(f) in the event of any acquisition of Oil and Gas Properties funded, in whole or in part, by Loans made on such Credit Date, Administrative Agent shall: (i) be satisfied that, other than payment of the purchase price thereunder, Borrower and all other parties to such acquisition of Oil and Gas Properties, shall have satisfied all conditions precedent to such acquisition (except such conditions precedent that are waived with the consent of Administrative Agent), (ii) have received duly executed lien releases and UCC termination statements for all properties to be acquired pursuant to such acquisition, in form and substance reasonably satisfactory to Administrative Agent, (iii) have received satisfactory title information sufficient to, in Administrative Agent’s sole discretion, provide evidence of Marketable Title with respect to the Oil and Gas Properties to be acquired pursuant to such acquisition, (iv) have received a certificate from an Authorized Officer of Borrower certifying that Borrower or the applicable Credit Party is concurrently consummating such acquisition in accordance with all applicable laws and the terms of the acquisition documents and is acquiring all of the Oil and Gas Properties contemplated by such acquisition documents with an exhibit attached to such certificate representing the Oil and Gas Properties to be acquired by Borrower or the applicable Credit Party on such Credit Date and (v) if such Credit Date is a Collateral Addition Date, Administrative Agent shall have received from Borrower or the applicable Credit Party duly executed counterparts of or supplements to the Collateral Documents in connection with the Oil and Gas Properties to be acquired.

Administrative Agent or any Lender shall be entitled, but not obligated to, request and receive, prior to the making of any Loan, additional information reasonably satisfactory to the requesting party confirming the satisfaction of any of the foregoing if, in the good faith judgment of Administrative Agent or such Lender such request is warranted under the circumstances.

3.3 Post-Closing Conditions to Each Credit Extension. The obligation of each Lender to make any Loan on any Credit Date (other than the Closing Date), is subject to the satisfaction, or waiver in accordance with Section 10.5, of the following post-closing conditions:

(a) Within fifteen (15) Business Days after the Closing Date, satisfactory review by Administrative Agent of title information to evidence Marketable Title with respect to the Oil and Gas Properties of the Credit Parties in the DJ Basin Area;

(b) On the date of the consummation of the Equity Transaction, Parent, ENEXP Operating, and ENEXP Operating GP shall become a party to the Guaranty Agreement and Pledge and Security Agreement and executed other documents described in Section 3.1 as requested by Administrative Agent; and

(c) To the extent not satisfied by Borrower on or prior to the Closing Date pursuant to Section 3.1(k), within thirty (30) days after the Closing Date, Administrative Agent shall have received certified copies of all insurance policies and a certificate from Borrower’s insurance broker or other evidence satisfactory to it that all insurance required to be maintained pursuant to Section 5.5 is in full force and effect, together with endorsements naming Administrative Agent, for the benefit of Secured Parties, as additional insured and loss payee thereunder to the extent required under Section 5.5.

In order to induce Administrative Agent and the Lenders to enter into this Agreement and to make each Loan to be made thereby, Borrower hereby represents and warrants to Administrative Agent and each Lender, on the Closing Date and on each Credit Date, that the following statements are true and correct:

4.1 No Default. No event has occurred and is continuing which constitutes a Default.

4.2 Organization; Requisite Power and Authority; Qualification. Each Credit Party (a) is duly organized, validly existing and in good standing under the laws of its jurisdiction of organization, which as of the Closing Date is as identified in Schedule 4.2, (b) has all requisite power and authority to own its Properties, to operate its Oil and Gas Properties for which it is the operator, to carry on its business as now conducted and as proposed to be conducted, to enter into the Credit Documents to which it is a party and to carry out the transactions contemplated thereby and to make the borrowings hereunder, and (c) is qualified to do business and in good standing in every jurisdiction where its real property assets are located and wherever necessary to carry out its business and operations, which as of the Closing Date is as identified in Schedule 4.2.

4.3 Capital Stock and Ownership. The Capital Stock of Borrower has been duly authorized and validly issued and is fully paid and non-assessable. Except as set forth on Schedule 4.3, as of the date hereof, there is no existing option, warrant, call, right, commitment or other agreement to which Borrower is a party requiring, and there is no membership interest or other Capital Stock of Borrower outstanding which upon conversion or exchange would require, the issuance by Borrower of any additional membership interests or other Capital Stock of Borrower or other Securities convertible into,

exchangeable for or evidencing the right to subscribe for or purchase, a membership interest or other Capital Stock of Borrower. Schedule 4.3 sets forth a true, complete and correct list as of the Closing Date of the name of each Credit Party and indicates its ownership (by holder and percentage interest) and type of entity, and the number and class of authorized and issued Capital Stock of such Credit Party as of the Closing Date. Except as set forth on Schedule 4.3, as of the Closing Date, the Credit Parties have no Subsidiaries and have no equity investments in any other entities.

4.4 Due Authorization. The execution, delivery and performance of the Credit Documents and the consummation of the transactions contemplated thereby have been duly authorized by all necessary action on the part of each Credit Party that is a party thereto.

4.5 No Conflict. The execution, delivery and performance by the Credit Parties of the Credit Documents to which such Credit Party is a party and the consummation of the transactions contemplated by the Credit Documents by such Credit Party thereto do not and will not (a) violate any provision of any law or any governmental rule or regulation applicable to such Credit Party, any of the Organizational Documents of any Credit Party, or any order, judgment or decree of any court or other agency of government binding on any Credit Party; (b) conflict with, result in a breach of or constitute (with due notice or lapse of time or both) a default under any Contractual Obligation of such Credit Party; (c) result in or require the creation or imposition of any Lien upon any of the properties or assets of such Credit Party (other than Permitted Liens); (d) result in any default, noncompliance, suspension, revocation, impairment, forfeiture or nonrenewal of any permit, license, authorization or approval applicable to such Credit Party’s operations or any Credit Party’s Properties or (e) require any approval of stockholders, members or partners or any approval or consent of any Person under any Contractual Obligation of such Credit Party, except for such approvals or consents which will be obtained on or before the Closing Date and disclosed in Schedule 4.5, and except (in any case under the preceding clauses (a), (b), (d) and (e) herein) where such violation, conflict, result or requirement, individually or in the aggregate, would not reasonably be expected to have a Material Adverse Effect.

4.6 Governmental Consents. The execution, delivery and performance by the Credit Parties of the Credit Documents to which they are parties and the consummation of the transactions contemplated by the Credit Documents to which such Credit Party is a party do not require any registration with, consent or approval of, or notice to, or other action to, with or by, any Governmental Authority except for (a) filings and recordings with respect to the Collateral to be made, or otherwise delivered to Administrative Agent for filing and/or recordation, as of the Closing Date, (b) filings necessary to maintain perfection of the Collateral, (c) routine filings related to such Credit Party and the operating of its business, and (d) such filings as may be necessary in connection with the Administrative Agent’s or the Lenders’, as the case may be, exercise of remedies hereunder.

4.7 Binding Obligation. Each Credit Document has been duly executed and delivered by each Credit Party that is a party thereto and is the legally valid and binding obligation of such Credit Party, enforceable against such Credit Party in accordance with its respective terms, except as may be limited by bankruptcy, insolvency, reorganization, moratorium or similar laws relating to or limiting creditors’ rights generally or by equitable principles relating to enforceability (whether enforcement is sought in equity or at law).

4.8 Financial Information. The unaudited pro forma balance sheet of Borrower as at Closing Date (including the notes thereto) (the “Pro Forma Balance Sheet”), a copy of which has heretofore been furnished to each Lender, has been prepared giving effect (as if such events had occurred on such date) to the Loans to be made on the Closing Date and the use of proceeds thereof and the payment of fees and expenses in connection with the foregoing in accordance with GAAP. The Pro Forma Balance Sheet has been prepared based on the best information available to Borrower as of the

date of delivery thereof, and presents fairly on a pro forma basis the financial position of Borrower as at May 31, 2012, assuming that the events specified in the preceding sentence had actually occurred at such date. As of the Closing Date, Borrower has no contingent liability or liability for taxes, long term lease or unusual forward or long term commitment including under any farmin, exploration or other development agreement which in any such case is material in relation to the business, operations, properties, assets, condition (financial or otherwise) or prospects of Borrower. Borrower’s audited financial statements dated January 1, 2012, and Borrower’s unaudited financial statements dated April 30, 2012, copies of which have heretofore been furnished to each Lender, have been prepared in accordance with GAAP.

4.9 Projections. On and as of the Closing Date, the projections of Borrower for the period of Fiscal Year 2012 through and including Fiscal Year 2013, including monthly projections for each month during the Fiscal Year in which the Closing Date takes place (the “Projections”), are based on good faith estimates and assumptions made by the management of Borrower and as of the Closing Date, management of Borrower believed that the Projections are reasonable and attainable (it being understood that estimates are subject to significant uncertainties and contingencies, that no assurances can be given that any projections will be attained and that variances from actual results may be material).

4.10 No Material Adverse Change. As of the Closing Date there has been no development or event that has had or could reasonably be expected to cause the actual result of operations or prospects of the Credit Parties to materially and adversely deviate from the results forecasted in the Projections.

4.11 Adverse Proceedings, etc. There are no Adverse Proceedings, individually or in the aggregate, that (a) relate to any Credit Document or the transactions contemplated hereby or (b) could reasonably be expected to have a Material Adverse Effect. No Credit Party is (i) in violation of any applicable laws, or (ii) subject to or in default with respect to any final judgments, writs, injunctions, decrees, rules or regulations of any court or any federal, state, municipal or other governmental department, commission, board, bureau, agency or instrumentality, domestic or foreign, except in each case as could not reasonably be expected to have a Material Adverse Effect.

4.12 Payment of Taxes. Except as otherwise permitted under Section 5.3, all tax returns and reports of the Credit Parties required to be filed have been timely filed, and all taxes shown on such tax returns to be due and payable and all assessments, fees and other governmental charges upon the Credit Parties and upon their properties, assets, income, businesses and franchises which are due and payable have been paid when due and payable. Borrower knows of no proposed tax assessment against any Credit Party which is not being actively contested by such Credit Party, as applicable, in good faith and by appropriate proceedings; provided, such reserves or other appropriate provisions, if any, as shall be required in conformity with GAAP shall have been made or provided therefor. Borrower is, and has been since its inception, treated as an association taxed as a corporation for federal income tax purposes.

(a) Each Credit Party has good and Marketable Title to its Oil and Gas Properties and good title to all its personal Properties (or a valid leasehold interest with respect to all leasehold interests in other real or personal property), in each case, free and clear of all Liens other than Permitted Liens. After giving full effect to the Permitted Liens, the Credit Parties, taken as a whole, own a working interest and net revenue interest in production attributable to the Hydrocarbon Interests as reflected on Schedule 4.13 which, in the event a Reserve Report has been delivered pursuant to this Agreement, is consistent with the most recently delivered Reserve Report, and the ownership of such Properties shall not in any material respect obligate the Credit Parties to bear the costs and expenses relating to the maintenance, development and operations of each such Property in an amount in excess of its working interest in each Property on Schedule 4.13 that is not offset by a corresponding proportionate increase in the Credit Parties’ net revenue interest in such Property.

(b) Each Credit Party’s Oil and Gas leases and other material leases and agreements necessary for the conduct of the business of such Credit Party are valid and subsisting, in full force and effect, and there exists no default or event or circumstance which with the giving of notice or the passage of time or both would give rise to a default under any such lease or leases, except for such defaults, events, or circumstances which individually or in the aggregate, would not reasonably be expected to have a Material Adverse Effect.

(c) For each Credit Party’s Oil and Gas Properties where such Credit Party, or an Affiliate, is the operator, the rights and such Properties presently owned, leased or licensed by such Credit Party including, without limitation, all easements and rights of way, include all rights and Properties necessary to permit such Credit Party, or such Affiliate, to conduct its business for such Properties. To Borrower’s Knowledge, for each Credit Party’s Oil and Gas Properties where another party is the operator, the rights and such Properties presently owned, leased or licensed by such Credit Party, or such operator, including, without limitation, all easements and rights of way, include all rights and Properties necessary to permit such Credit Party, or such operator, to conduct its business for such Properties.

(d) Except as set forth on Schedule 4.13, there are no preferential rights to purchase or consents to assign affecting any Credit Party’s Oil and Gas Properties that would be triggered by any Credit Party granting any Lien in any Collateral Document or making any ORI Conveyance.

4.14 Maintenance of Properties. Each Credit Party has, or in respect of non-operated Oil and Gas Properties has caused the operator to have, maintained, operated and developed in a good and workmanlike manner the Oil and Gas Properties of such Credit Party, except as could not reasonably be expected to have a Material Adverse Effect, in conformity with all Government Requirements and in conformity with the provisions of all leases, subleases or other contracts comprising a part of the Hydrocarbon Interests and other contracts and agreements forming a part of the Oil and Gas Properties of such Credit Party. Specifically in connection with the foregoing, and except as in each case could not reasonably be expected to have a Material Adverse Effect, (i) no Oil and Gas Property of any Credit Party is subject to having allowable production reduced below the full and regular allowable (including the maximum permissible tolerance) because of any overproduction (whether or not the same was permissible at the time) and (ii) none of the wells comprising a part of the Oil and Gas Properties of any Credit Party is deviated from the vertical more than the maximum permitted by Government Requirements, and such wells are, in fact, bottomed under and are producing from, and the well bores are wholly within, the Oil and Gas Properties.

4.15 Gas Imbalances, Prepayments. Except as set forth on Schedule 4.15 or as reflected in the most recently delivered Reserve Report, or the certificate delivered therewith, on a net basis there are no gas imbalances (other than those imbalances which (a) occur in the ordinary course of business and (b) do not, in the aggregate exceed 2% of the value of the proven developed producing natural gas reserves shown in the most recently delivered Reserve Report), take or pay or other prepayments which would require the Credit Parties, to deliver Hydrocarbons produced from the Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor. Except as set forth in Schedule 4.15, no Oil and Gas Property of any Credit Party is subject to any “take or pay”, gas imbalances or other similar arrangement (i) which can be satisfied in whole or in part by the production or transportation of gas from other properties or (ii) as a result of which production from any Oil and Gas Property of any Credit Party may be required to be delivered to one or more third parties without payment (or without full payment) therefor as a result of payments made, or other actions taken, with respect to other properties. No Oil and Gas Property of any Credit Party is subject at the present time to any regulatory refund obligation and, to the best of Borrower’s knowledge, no facts exist which might cause the same to be imposed.

4.16 Environmental Matters. Except for such matters as set forth on Schedule 4.16 or as reasonably could not reasonably be expected to have a Material Adverse Effect:

(a) the Oil and Gas Properties of each Credit Party and operations thereon are, and within all applicable statute of limitation periods have been, in compliance with all applicable Environmental Laws;

(b) each Credit Party has obtained all Environmental Permits required for its operations and that of its Properties, with all such Environmental Permits being currently in full force and effect, and no Credit Party has received any written notice or otherwise has knowledge that any such existing Environmental Permit will be revoked or that any application for any new Environmental Permit or renewal of any existing Environmental Permit will be protested or denied;

(c) there are no claims, demands, suits, orders, inquiries, or proceedings concerning any violation of, or any liability (including as a potentially responsible party) under, any applicable Environmental Laws that is pending or, to any Credit Party’s knowledge, threatened against any Credit Party or any of the Oil and Gas Properties of any Credit Party or as a result of any operations at such Properties;

(d) there has been no Release or, to Borrower’s knowledge, threatened Release, of Hazardous Materials at, on, under or from any Credit Party’s Properties, there are no investigations, remediations, abatements, removals, or monitorings of Hazardous Materials required under applicable Environmental Laws at such Properties and, to the knowledge of Borrower, none of such Properties are adversely affected by any Release or threatened Release of a Hazardous Material originating or emanating from any other real property;

(e) no Credit Party has received any written notice asserting an alleged liability or obligation under any applicable Environmental Laws with respect to the investigation, remediation, abatement, removal, or monitoring of any Hazardous Materials at, under, or Released or threatened to be Released from any real properties offsite such Credit Party’s Properties and, to Borrower’s knowledge, there are no conditions or circumstances that would reasonably be expected to result in the receipt of such written notice;

(f) there has been no exposure of any Person or property to any Hazardous Materials as a result of or in connection with the operations and businesses of any of the Oil and Gas Properties of any Credit Party that would reasonably be expected to form the basis for a claim for damages or compensation and, to Borrower’s knowledge, there are no conditions or circumstances that would reasonably be expected to result in the receipt of notice regarding such exposure; and

(g) each Credit Party has provided to the Lenders complete and correct copies of all environmental site assessment reports, investigations, studies, analyses, and correspondence on environmental matters (including matters relating to any alleged non-compliance with or liability under Environmental Laws) that are in such Credit Party’s possession or control and relating to Oil and Gas Properties of such Credit Party or operations thereon.

4.17 No Defaults. No Credit Party is in default in the performance, observance or fulfillment of any of the obligations, covenants or conditions contained in any of its material Contractual Obligations, and no condition exists which, with the giving of notice or the lapse of time or both, could constitute such a default. No condition exists which would require a Credit Party to repurchase, redeem, prepay, or

defease (or the segregation of funds with respect to any of the foregoing) in connection with any indenture, note, credit agreement or instrument pursuant to which any Indebtedness is outstanding or by which such Credit Party or any of their Properties is bound.

4.18 Material Contracts; Operating Agreements. Schedule 4.18(a) contains a true, correct and complete list of all the Material Contracts (other than oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases) and Operating Agreements of the Credit Parties in effect on the Closing Date. On the Closing Date, all Material Contracts and the Operating Agreements are in full force and effect and no defaults of any Credit Party party thereto or, to Borrower’s knowledge, of any other party thereto, currently exist thereunder (other than as described in Schedule 4.18(a)). Schedule 4.18(b) contains a true, correct and complete list of all the Material Contracts (other than oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases) and Operating Agreements requiring consent from the counterparty thereto, or payment of any fee or sum to the counterparty thereto, prior to an assignment to Administrative Agent or a Lender pursuant to a foreclosure action or that would otherwise prohibit, restrict or hinder Administrative Agent or the Lenders, or any successor in interest to Administrative Agent or any Lender, from foreclosing upon such contract or agreement.

4.19 Governmental Regulation. No Credit Party is subject to regulation under the Federal Power Act or the Investment Company Act of 1940 or under any other federal or state statute or regulation which may limit its ability to incur Indebtedness or which may otherwise render all or any portion of the Obligations unenforceable. No Credit Party is a “registered investment company” or a company “controlled” by a “registered investment company” or a “principal underwriter” of a “registered investment company” as such terms are defined in the Investment Company Act of 1940.

4.20 Margin Stock. No Credit Party is engaged in the business of extending credit for the purpose, whether immediate, incidental or ultimate, of purchasing or carrying any Margin Stock. No part of the proceeds of the Loans made hereunder will be used to purchase or carry any such Margin Stock or to extend credit to others for the purpose of purchasing or carrying any such Margin Stock or for any purpose that violates, or is inconsistent with, the provisions of Regulation T, U or X of the Board of Governors of the Federal Reserve System.

4.21 Employee Matters. No Credit Party or its employees, agents and representatives have committed any material unfair labor practice as defined in the National Labor Relations Act. There has not been and is (a) no unfair labor practice charge or complaint pending against any Credit Party, or to the best knowledge of Borrower, threatened against any Credit Party, before the National Labor Relations Board or any other Governmental Authority and no grievance or arbitration proceeding arising out of or under any collective bargaining agreement or similar agreement that is so pending against any Credit Party or to the best knowledge of Borrower, threatened against any Credit Party, (b) no labor dispute, strike, lockout, slowdown or work stoppage in existence or, to Borrower’s Knowledge, threatened against, involving or affecting any Credit Party, (c) no labor union, labor organization, trade union or works council that represents or claims to represent any Credit Party’s employees, and none have made a pending demand for recognition or certification, and there are no representation or certification proceedings or petitions seeking a representation proceeding presently pending or threatened to be brought or filed with the National Labor Relations Board or any other Governmental Authority, (d) no union representation question existing with respect to any of the employees of any Credit Party and no labor union organizing activity with respect to any employees of any Credit Party that is taking place, to Borrower’s Knowledge, and (e) no settlement agreement, order, conciliation agreement, letter of commitment, deficiency letter, decision, awards finding or consent decree with any present or former employee or applicant for employment, labor union or other employee representative, or any governmental agency or arbitrator relating to claims of unfair labor practices, employment discrimination, or other claims with respect to employment or labor practices and policies.

4.22 Employee Benefit Plans. Borrower and its ERISA Affiliates are in compliance with all applicable provisions and requirements of ERISA and the Internal Revenue Code and the regulations and published interpretations thereunder with respect to each Employee Benefit Plan, and have performed all their obligations under each Employee Benefit Plan. Each Employee Benefit Plan which is intended to qualify under Section 401(a) of the Internal Revenue Code either (i) is a prototype plan entitled to rely on the opinion letter issued by the IRS as to the qualified status of such plan under Section 401 of the Code to the extent provided in Revenue Procedure 2005-16, or (ii) has received a favorable determination letter from the Internal Revenue Service indicating that such Employee Benefit Plan is so qualified and nothing has occurred subsequent to the issuance of such determination letter which would cause such Employee Benefit Plan to lose its qualified status. No liability to the PBGC (other than required premium payments) or the Internal Revenue Service has been or is expected to be incurred by Borrower or any of its ERISA Affiliates with respect to any Employee Benefit Plan except as could not reasonably be expected to have a Material Adverse Effect. No ERISA Event has occurred or is reasonably expected to occur. Except to the extent required under Section 4980B of the Internal Revenue Code or similar state laws, or otherwise funded entirely by the participants thereof, no Employee Benefit Plan provides health or welfare benefits (through the purchase of insurance or otherwise) for any retired or former employee of Borrower or any of its ERISA Affiliates. The present value of the aggregate benefit liabilities under each Pension Plan sponsored, maintained or contributed to by Borrower or any of its ERISA Affiliates (determined as of the end of the most recent plan year on the basis of the actuarial assumptions specified for funding purposes in the most recent actuarial valuation for such Pension Plan), did not exceed the aggregate current value of the assets of such Pension Plan by $100,000.00. As of the most recent valuation date for each Multiemployer Plan for which the actuarial report is available, the potential liability of Borrower and its ERISA Affiliates for a complete or partial withdrawal from such Multiemployer Plan (within the meaning of Section 4203 or Section 4205 of ERISA), when aggregated with such potential liability for a complete or partial withdrawal from all Multiemployer Plans, is an amount that could not reasonably be expected to exceed $50,000.00. Borrower and each ERISA Affiliate of Borrower have complied with the requirements of Section 515 of ERISA with respect to each Multiemployer Plan and are not in material “default” (as defined in Section 4219(c)(5) of ERISA) with respect to payments to a Multiemployer Plan.

4.23 Certain Fees. No broker’s or finder’s fee or commission, other than those set forth on Schedule 4.23, will be payable with respect hereto or any of the transactions contemplated hereby.

4.24 Solvency. Each Credit Party is and, after giving effect to any Loan by such Credit Party on any date on which this representation and warranty is made, will be, Solvent.

4.25 Compliance with Statutes, etc. Each Credit Party is in compliance with its Organizational Documents and in all material respects with all material applicable Governmental Requirements in respect of the conduct of its business and the ownership of its property.

4.26 Disclosure. No representation or warranty of any Credit Party contained in any Credit Document and none of the reports, financial statements or other documents, certificates or written statements furnished to Lenders by or on behalf of Borrower for use in connection with the transactions contemplated hereby or by any Credit Document contains any untrue statement of a material fact or omits to state a material fact necessary in order to make the statements contained herein or therein not misleading as of the time when made or delivered in light of the circumstances in which the same were made. Any projections and pro forma financial information contained in such materials are based upon good faith estimates and assumptions believed by Borrower to be fair and accurate at the time made.

There are no agreements, instruments and corporate or other restrictions to which any Credit Party is subject that have not been disclosed herein or in such other documents, certificates and statements furnished to Lenders for use in connection with the transactions contemplated hereby (it being understood that estimates are subject to significant uncertainties and contingencies, that no assurances can be given that any projections will be attained and that variances from actual results may be material).

(a) Each Credit Party is in compliance, in all material respects, with the Terrorism Laws.

(b) No part of the proceeds of the Loans will be used, directly or indirectly, for any payments to any governmental official or employee, political party, official of a political party, candidate for political office, or anyone else acting in an official capacity in violation of the United States Foreign Corrupt Practices Act of 1977, as amended.

(c) No part of the proceeds from the making of Loans hereunder will be used, directly or indirectly, (i) for any payments to any governmental official or employee, political party, official of a political party, candidate for political office, or anyone else acting in an official capacity, in order to obtain, retain or direct business or obtain any improper advantage, in violation of the United States Foreign Corrupt Practice Act of 1977, as amended, assuming in all cases that such Act applies to Borrower or (ii) in connection with any investment in, or any transactions or dealings with, any Blocked Person.

(d) To Borrower’s actual knowledge after making due inquiry, no Credit Party (i) is under investigation by any governmental authority for, or has been charged with, or convicted of, money laundering, drug trafficking, terrorist-related activities or other money laundering predicate crimes under any applicable law (collectively, “Anti-Money Laundering Laws”), (ii) has been assessed civil penalties under any Anti-Money Laundering Laws or (iii) has had any of its funds seized or forfeited in any action under any Anti-Money Laundering Laws.

(e) Borrower has taken reasonable measures appropriate to the circumstances to ensure that Borrower and each other Credit Party is and will continue to be in compliance with all current and future Anti-Money Laundering Laws and anti-corruption laws and regulations that are applicable to (i) Borrower or such Credit Party or (ii) any holder of the Obligations under this Credit Agreement or a Note that could be affected by the failure of Borrower or any Credit Party to comply with any such Anti-Money Laundering Laws or any anti-corruption laws and regulations.

4.28 Insurance. The properties of each Credit Party are adequately insured with financially sound and reputable insurers and in such amounts, with such deductibles and covering such risks and otherwise on terms and conditions as are customarily carried or maintained by Persons of established reputation of similar size and engaged in similar businesses and such insurance complies with the requirements of an Operating Agreement and of Section 5.5. Schedule 4.28 sets forth a list of all insurance maintained by or on behalf of each Credit Party as of the Closing Date. All such policies are in full force and effect, all premiums with respect thereto covering all periods up to and including the date of the closing have been paid, and no notice of cancellation or termination has been received with respect to any such policy. Such policies are sufficient for compliance with all Governmental Requirements and all agreements to which any Credit Party is a party; are valid, outstanding and enforceable policies; provide adequate insurance coverage for the assets and operations of such Credit Party in at least such amounts and against at least such risks (but including in any event public liability) as are usually insured against in the same general area by companies engaged in the same or a similar business; will remain in full force and effect through the respective dates set forth in Schedule 4.28 without the payment of additional

premiums; and will not in any way be affected by, or terminate or lapse by reason of, the transactions contemplated by this Agreement and the Credit Documents. No Credit Party has been refused any insurance with respect to its assets or operations, nor has it been limited below usual and customary policy limits, by an insurance carrier to which it has applied for any insurance or with which it has carried insurance during the last three years. Administrative Agent has been named as additional insured in respect of such liability insurance policies and Administrative Agent has been named as loss payee with respect to property loss insurance.

4.29 Security Interest in Collateral. The provisions of this Agreement and the Collateral Documents create legal and valid Liens on all the Collateral in favor of Administrative Agent, for the benefit of the Secured Parties, and in the case of Collateral which may be perfected by filing a financing statement, when financing statements in appropriate form are filed in the appropriate office, such Liens constitute perfected and continuing Liens on the Collateral, securing the Obligations, enforceable against the applicable Credit Party and all third parties, except as such enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or similar laws relating to or limiting creditors’ rights generally or by equitable principles relating to enforceability (whether enforcement is sought in equity or at law), and having priority over all other Liens on the Collateral except in the case of Excepted Liens, to the extent any such Excepted Liens would have priority over the Liens in favor of Administrative Agent pursuant to any applicable law.

4.30 Affiliate Transactions. Except as set forth on Schedule 6.9, as of the date of this Agreement, the Credit Parties are in compliance with the requirements of Section 6.9. Each Affiliate of a Credit Party who is an operator under any Operating Agreement shall have executed and delivered a subordination agreement to Administrative Agent, in form and substance reasonably satisfactory to Administrative Agent.

4.31 Permits, etc. Each Credit Party has and is in compliance with, all Governmental Authorizations required for such Person lawfully to own, lease, manage or operate, or to acquire, each business currently owned, leased, managed or operated, or to be acquired, by such Person. No condition exists or event has occurred which, in itself or with the giving of notice or lapse of time or both, would result in the suspension, revocation, impairment, forfeiture or non-renewal of any such Governmental Authorization, and there is no claim that any thereof is not in full force and effect. No such lack of compliance described in the first sentence of this paragraph, and no such condition or event (and subsequent suspension, revocation, impairment, forfeiture or non-renewal) described in the second sentence of this paragraph may result in a decrease in production.

4.32 Marketing of Production. Except for contracts listed and in effect on the date hereof on Schedule 4.32, and thereafter either disclosed in writing to Administrative Agent or included in the most recently delivered Reserve Report and approved by Administrative Agent (with respect to all of which contracts Borrower represents that it or, the Credit Party party thereto, is receiving a price for all production sold thereunder which is computed substantially in accordance with the terms of the relevant contract and are not having deliveries curtailed substantially below the subject Property’s delivery capacity), no material agreements exist that are not cancelable on 60 days notice or less without penalty or detriment for the sale of production from any Credit Party’s Hydrocarbons (including, without limitation, calls on or other rights to purchase, production, whether or not the same are currently being exercised) that (i) pertain to the sale of production at a fixed price and (ii) have a maturity or expiry date of longer than six (6) months from the Closing Date. No proceeds from the sale of any Credit Party’s interests in Hydrocarbons from its Oil and Gas Properties are currently being held in suspense by such purchaser or any other Person. Except as set forth in Schedule 4.32, none of the Oil and Gas Properties of any Credit Party are subject to any contractual or other arrangement whereby payment for production therefrom is to be deferred for a substantial period of time after the month in which such production is delivered (i.e., in

the case of oil, not in excess of 60 days, and in the case of gas, not in excess of 90 days). No production is being sold after the Closing Date except to purchasers of production who have been instructed to pay proceeds thereof to the Lockbox Account.

4.33 Names and Places of Business. Each Credit Party has not, during the five years preceding the Closing Date, had, been known by, or used any other trade or fictitious name, except as disclosed in Schedule 4.33. The chief executive office and principal place of business of each Credit Party as of the Closing Date is located at the address of Borrower set out in Schedule 4.33. Except as indicated in Schedule 4.33, no Credit Party has had any other office or place of business prior to the Closing Date. Each Credit Party’s jurisdiction of organization, name as listed in the public records of its jurisdiction of organization, organizational identification number in its jurisdiction of organization, and Federal Taxpayer Identification Number is stated on Schedule 4.33 (or as set forth in a notice delivered pursuant to this Agreement).

4.34 Improved Real Estate. The Collateral does not include any “buildings” (as defined under Section 4000 et. seq. of the National Flood Insurance Reform Act of 1994, as amended) that are necessary to operating such Collateral for the exploration and production of oil and gas.

4.35 Assigned Indebtedness. There are no defaults or events of default in existence on or prior to the Closing Date under the Existing Credit Documents or Existing Security Documents. The Assigned Indebtedness is refinanced and replaced by the Loans hereunder and the Existing Credit Documents are amended and restated by this Agreement, and all obligations under this Agreement are in renewal, extension and modification, but not novation or discharge, of the Assigned Indebtedness. All of the Existing Security Documents are in full force and effect prior to giving effect to the Assignment of Liens and this Agreement, and after the Closing Date, the Existing Security Documents, and the Liens and lien priority created thereunder, remain in full force and effect as amended and restated by the Mortgages and Pledge and Security Agreement, respectively.

Borrower hereby agrees that, so long as any Commitment is in effect and until payment in full of all Obligations, Borrower shall perform, and shall cause each other Credit Party to perform, all covenants in this Article V.

Unless otherwise provided below, Borrower will deliver to Administrative Agent and Lenders:

(a) Drilling Reports. Upon request by Administrative Agent, reports on active field operations, including but not limited to any drilling, completions, well workovers, installation, modification or repair of surface facilities and flowlines, and pipeline hookups, including a “daily drilling report”, as applicable, and information related to pipe depth, completion percentage, updated spud date or date of first production (as applicable) and such other information as may be reasonably requested, in form and substance satisfactory to Administrative Agent.

(b) Monthly Reports. As soon as available, and in any event within ten (10) Business Days after the end of each month (commencing with the first full month after the Closing Date), a detailed working capital report in a form satisfactory to Administrative Agent, including: (i) a statement of cash flows for the prior calendar month, detailing the monthly expenditures during such month (including lease operating expenses and capital expenditures), (ii) a list of account balances as of the end of such month

(with age detail), (iii) a report containing reasonably detailed determinations of Gross Proceeds of Production and General and Administrative Costs for the prior month, (iv) a report summarizing the gross volume of sales and actual production related to cash receipts for such prior month from all of the Oil and Gas Properties of the Credit Parties and prices received for such production, the related severance, gross production, occupation, excise, sales, recording, ad valorem, gathering and other similar taxes, if any, deducted from gross proceeds during such prior month, and production or take or pay imbalances, (v) a schedule of the Credit Parties’ accounts payable, including future lease payments related to Oil and Gas Properties, including but not limited to delay rental payments and bonus payments, (vi) a schedule of Mineral Interest Conveyance Documents that have been terminated, materially amended, or entered into during such month, along with a written statement describing such event and, if applicable, an explanation of any actions being taken with respect there to, and, upon request of Administrative Agent, copies of such material amendments or new contracts, and (vii) such other information as may be reasonably requested by Administrative Agent.

(c) Quarterly Financial Statements. As soon as available, and in any event within sixty (60) days after the end of each Fiscal Quarter of each Fiscal Year starting with the Fiscal Quarter ended June 30, 2012, the balance sheet of Borrower as at the end of such Fiscal Quarter and the related statements of income, stockholders’ equity and cash flows of Borrower for such Fiscal Quarter and for the period from the beginning of the then current Fiscal Year to the end of such Fiscal Quarter, and (in the case of financial statements delivered with respect to Fiscal Quarters following the second Fiscal Quarter in 2013 and in later years) setting forth in each case in comparative form the corresponding figures for the corresponding periods of the previous Fiscal Year, all in reasonable detail, together with a Financial Officer Certification with respect thereto.

(d) Annual Financial Statements. As soon as available, but in any event in accordance with then applicable law and not later than one hundred and twenty (120) days after the end of each Fiscal Year, Borrower’s audited balance sheet and related statements of operations, owner’s equity and cash flows as of the end of and for such year, and (in the case of financial statements delivered with respect to 2013 and later Fiscal Years) setting forth in each case in comparative form the figures for the previous Fiscal Year, all reported on by independent certified public accountants approved by the Lenders (without a “going concern” or like qualification or exception and without any qualification or exception as to the scope of such audit) to the effect that such financial statements present fairly in all material respects the financial condition and results of operations of Borrower in accordance with GAAP consistently applied.

(e) Compliance Certificate. Together with each delivery of financial statements of Borrower pursuant to Sections 5.1(c) and 5.1(d), a duly executed and completed Compliance Certificate.

(f) Statements of Reconciliation after Change in Accounting Principles. If there is any change in accounting principles and policies (or the application thereof), of the financial statements of Borrower from the statements first delivered pursuant to Section 5.1(c) or 5.1(d), the statements delivered after the date of the change will include those statements required by GAAP for such change.

(g) Notice of Default. Prompt written notice, but in no event later than five (5) Business Days of (i) any condition or event that constitutes a Default or an Event of Default or that notice has been given to any Credit Party with respect thereto; (ii) any Person giving any notice to any Credit Party or taking any other action with respect to any event or condition set forth in Section 8.1(b); or (iii) the occurrence of any event or change that has caused or evidences, either in any case or in the aggregate, a Material Adverse Effect, which notice shall be accompanied by a certificate of such Person specifying the nature and period of existence of such condition, event or change, or specifying the notice given and action taken by any such Person and the nature of such claimed Event of Default, Default, default, event or condition, and what action Borrower or any other Credit Party has taken, is taking and proposes to take with respect thereto.

(h) Notice of Litigation. Prompt written notice, but in no event later than five (5) Business Days of (i) the institution of, or threat of, any Adverse Proceeding not previously disclosed in writing by Borrower to Lenders, or (ii) any development in any Adverse Proceeding that, in the case of either clause (i) or (ii) if adversely determined, could be reasonably expected to have a Material Adverse Effect, or seeks to enjoin or otherwise prevent the consummation of, or to recover any damages or obtain relief as a result of, the transactions contemplated hereby, or which arises in respect of any material Indebtedness of any Credit Party or alleges any criminal misconduct by any Credit Party together in each case with such other information as may be reasonably available to any Credit Party to enable Lenders and their counsel to evaluate such matters.

(i) ERISA. (i) Promptly, but in no event later than five (5) Business Days following Borrower’s obtaining knowledge of the occurrence of or the forthcoming occurrence of any ERISA Event, a written notice specifying the nature thereof, what action Borrower or any of its ERISA Affiliates has taken, is taking or proposes to take with respect thereto and, when known, any action taken or threatened by the Internal Revenue Service, the Department of Labor or the PBGC with respect thereto; and (ii) with reasonable promptness, copies of (1) each Schedule B (Actuarial Information) to the annual report (Form 5500 Series) filed by Borrower or any of its ERISA Affiliates with the Internal Revenue Service with respect to each Pension Plan; (2) all notices received by Borrower or any of its ERISA Affiliates from a Multiemployer Plan sponsor concerning an ERISA Event; and (3) copies of such other documents or governmental reports or filings relating to any Employee Benefit Plan as Administrative Agent shall reasonably request.

(j) Insurance Report. As soon as practicable and in any event by the last day of each Fiscal Year, a report in form and substance reasonably satisfactory to Administrative Agent outlining all material insurance coverage maintained as of the date of such report by Borrower and all material insurance coverage planned to be maintained by Borrower in the immediately succeeding Fiscal Year.

(k) Notice of Change in Board of Managers. Promptly, but in no event later than five (5) Business Days of the occurrence of such change, written notice of any change in the board of managers of Borrower.

(l) Notice Regarding Material Contracts and Related Agreements. Promptly, and in any event within five (5) Business Days (i) after any Material Contract or Related Agreement (other than a Mineral Interest Conveyance Document) of any Credit Party is terminated or amended or (ii) any new Material Contract or Related Agreement (other than a Mineral Interest Conveyance Document) is entered into, a written statement describing such event, with copies of such material amendments or new contracts, delivered to Administrative Agent, and an explanation of any actions being taken with respect thereto.

(m) Environmental Reports and Audits. Promptly, but in no event later than five (5) Business Days following receipt thereof, copies of all environmental audits and reports with respect to environmental matters at any Facility or which relate to any environmental liabilities of any Credit Party which relate to a matter that could reasonably be expected to have a Material Adverse Effect.

(A) On the dates set forth in Appendix A, a Reserve Report prepared as of the dates set forth therein concerning the Oil and Gas Properties of the Credit Parties.

The “Third Party Report” referenced in Appendix A must be prepared by one or more Approved Petroleum Engineers, and the “Internal Report” referenced in Appendix A shall be prepared by a Person whose petroleum engineering qualifications are reasonably acceptable Administrative Agent, and such Person or a Responsible Officer shall certify such Reserve Report has been prepared in accordance with the procedures used in the Third Party Report. Administrative Agent or Required Lenders may (at their expense so long as no Default or Event of Default then exists) request additional Reserve Reports from time to time prepared by such Approved Petroleum Engineers. Each Reserve Report shall distinguish (or shall be delivered together with a certificate from a Responsible Officer which distinguishes) those Oil and Gas Properties treated in the report which are a Credit Party’s Oil and Gas Properties from those properties treated in the report which are not a Credit Party’s Oil and Gas Properties; and

(B) With the delivery of each Reserve Report, Borrower shall provide to Administrative Agent and the Lenders a certificate from a Responsible Officer certifying that to his Knowledge and in all material respects: (A) the information (other than projections or estimates) contained in the Reserve Report and any other information delivered in connection therewith is true and correct, (B) each Credit Party owns good and Marketable Title to its Oil and Gas Properties evaluated in such Reserve Report and such Properties are free of all Liens except for Excepted Liens, (C) except as set forth on an exhibit to the certificate, on a net basis there are no gas imbalances, take or pay or other prepayments in excess of the volume specified in Section 4.15 with respect to its Oil and Gas Properties evaluated in such Reserve Report which would require any Credit Party to deliver Hydrocarbons either generally or produced from such Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor, (D) none of the Credit Parties’ Oil and Gas Properties have been sold since the date of the last Reserve Report except as disclosed to Administrative Agent, (E) attached to the certificate is a list of all marketing agreements entered into subsequent to the later of the date hereof or the most recently delivered Reserve Report, (F) attached to the certificate is a list of all Persons purchasing Hydrocarbons from the Credit Parties, (G) attached to the certificate is a list of all Oil and Gas Properties acquired since the date of the last Reserve Report and (H) the projections and estimates contained in the Reserve Report are made in good faith and based on reasonable assumptions.

(o) Tax Returns. As soon as practicable and in any event within five (5) Business Days following the filing thereof, copies of each material tax return filed by or on behalf of Borrower.

(p) Swap Agreements. Within ten (10) Business Days after the end of each calendar month (and at any other time upon prior written request by Administrative Agent), a report as of the end of such calendar month detailing all Swap Agreements and corresponding hedge arrangements then in effect on such date, including the notional volumes, fixed prices, tenor and other data reasonably required by Administrative Agent related thereto.

(q) Violations of Terrorism Laws. Promptly (i) if any Credit Party obtains knowledge that any Credit Party or any Person which owns, directly or indirectly, any Capital Stock of any Credit Party, or any other holder at any time of any direct or indirect equitable, legal or beneficial interest therein is the subject of any of the Terrorism Laws, such Credit Party will notify Administrative Agent and (ii) upon the request of any Lender, such Credit Party will provide any information such Lender believes is reasonably necessary to be delivered to comply with the Patriot Act.

(r) Subject Area Information. Borrower will provide access to any Lender, promptly upon such Lender’s written request from time to time, to such information in its possession not subject to any obligations of confidentiality relating to the Subject Area and any of the Credit Parties’ Oil and Gas Properties, including, without limitation, (a) all options to acquire additional Oil and Gas Properties and all other contracts relating to the Subject Area, (b) detailed maps of the Subject Area, (c) title materials relating to the prospects in the Subject Area, and (d) AFEs, drilling reports, well tests, or completion reports relating to any wells for any prospects located within any of the Subject Area. Promptly upon such Lender’s written request, Borrower will furnish copies of any such information to the extent that it is reasonable do so.

(s) Title Opinions. Upon the request of Administrative Agent, Borrower shall provide to Administrative Agent copies of such division order title opinions or such other title information in form and substance reasonably satisfactory to the Lenders, evidencing the applicable Credit Party’s Marketable Title to any of the Oil and Gas Properties to which Proved Developed Producing Reserves are attributed.

(t) Information Regarding Credit Parties. Prompt prior written notice (and in any event within ten (10) days prior thereto) of any change (i) in any Credit Party’s corporate name or in any trade name used to identify such Person in the conduct of its business or in the ownership of its Properties, (ii) in the location of any Credit Party’s chief executive office or principal place of business, (iii) in any Credit Party’s identity or corporate structure or in the jurisdiction in which such Person is incorporated or formed, (iv) in any Credit Party’s jurisdiction of organization or such Person’s organizational identification number in such jurisdiction of organization, and (v) in any Credit Party’s federal taxpayer identification number.

(A) If requested by Administrative Agent, promptly after submission to any Governmental Authority, all documents and information furnished to such Governmental Authority in connection with any investigation of any Credit Party (other than any routine inquiry), as permitted by applicable law;

(B) Promptly upon receipt thereof, copies of all financial reports submitted to any Credit Party by its auditors in connection with any audit of the books thereof; and

(C) Such other information and data with respect to any Credit Party as from time to time may be requested by Administrative Agent.

Notwithstanding the foregoing, Administrative Agent may, in its sole discretion and upon written request from Borrower, provide a grace period of up to (30) thirty days in connection with any of the requirements set forth herein.

5.2 Existence; Conduct of Business. Each Credit Party will do or cause to be done all things necessary to preserve, renew and keep in full force and effect such Credit Party’s legal existence and the rights, licenses, permits, privileges and franchises material to the conduct of such Credit Party’s business and maintain, if necessary, such Credit Party’s qualification to do business in each other jurisdiction in which Oil and Gas Properties of such Credit Party are located or such Credit Party’s ownership of any Properties requires such qualification.

5.3 Payment of Taxes and Claims. Each Credit Party will pay all Taxes imposed upon it or any of its properties or assets or in respect of any of its income, businesses or franchises before any penalty or fine accrues thereon, and all claims (including claims for labor, services, materials and

supplies) for sums that have become due and payable and that by law have or may become a Lien upon any of its properties or assets, prior to the time when any penalty or fine shall be incurred with respect thereto; provided, no such Tax or claim need be paid if it is being contested in good faith by appropriate proceedings promptly instituted and diligently conducted, so long as (a) adequate reserve or other appropriate provision, as shall be required in conformity with GAAP shall have been made therefor, and (b) in the case of a Tax or claim which has or may become a Lien against any of the Collateral, such contest proceedings conclusively operate to stay the sale of any portion of the Collateral to satisfy such Tax or claim. No Credit Party will file or consent to the filing of any consolidated income tax return with any Person (other than with Borrower and its Subsidiaries, if any).

5.4 Operation and Maintenance of Properties. Borrower and each other Credit Party, at its own expense, will:

(a) operate its Oil and Gas Properties and other material Properties or cause such Oil and Gas Properties and other material Properties to be operated in a reasonably prudent manner in accordance with the practices of the industry and in compliance with all applicable contracts and agreements and, in compliance with all material Governmental Requirements, including, without limitation, applicable proration requirements and Environmental Laws, and all applicable laws, rules and regulations of every other Governmental Authority from time to time constituted to regulate the development and operation of its Oil and Gas Properties and the production and sale of Hydrocarbons and other minerals therefrom;

(b) keep and maintain all Property material to the conduct of its business and all of its Oil and Gas Properties in good working order and condition, ordinary wear and tear excepted, including, without limitation, all material equipment, machinery and facilities;

(c) make reasonably and customary efforts to promptly pay and discharge, or cause to be paid and discharged, all delay rentals, royalties, expenses and indebtedness accruing under the leases or other agreements affecting or pertaining to its Oil and Gas Properties and do all other things necessary to keep unimpaired their rights with respect thereto and prevent any forfeiture thereof or default thereunder;

(d) make reasonable and customary efforts to promptly perform or cause to be performed, in accordance with industry standards, the obligations required by each and all of the assignments, deeds, leases, sub-leases, contracts and agreements affecting its interests in its Oil and Gas Properties and other material Properties;

(e) to the extent any Property is not operated by a Credit Party, the applicable Credit Party’s obligations under this Section 5.4 shall be limited to the use of reasonable efforts to cause the operator to comply with this Section 5.4; and

(f) each Credit Party shall subordinate in favor of Administrative Agent for the benefit of the Lenders any contractual or statutory Liens held by such Credit Party as an operator or co-working interest owner under joint operating agreements or similar contractual arrangements with respect to such Credit Party’s share of the expense of exploration, development and operation of oil, gas and mineral leasehold or fee interests jointly owned with others and operated by any Credit Party.

5.5 Insurance. Each Credit Party will maintain or cause to be maintained, with financially sound and reputable insurers, such casualty insurance, public liability insurance, and third party property damage insurance with respect to liabilities, losses or damage in respect of the assets, properties and businesses of such Credit Party as are customarily carried or maintained under similar circumstances by Persons of established reputation of similar size and engaged in similar businesses, in each case in such amounts (giving effect to self insurance which comports with the requirements of this Section 5.5 and

provided that adequate reserves therefor are maintained in accordance with GAAP), with such deductibles, covering such risks and otherwise on such terms and conditions as shall be customary for such Persons and any other insurance required by an Operating Agreement. Each such policy of insurance shall (A) name Administrative Agent, on behalf of Secured Parties as an additional insured thereunder as its interests may appear, and (B) in the case of each casualty insurance policy, contain a loss payable clause or endorsement, reasonably satisfactory in form and substance to Administrative Agent, that names Administrative Agent and each Lender as the loss payee under such casualty insurance policy and provides for at least thirty (30) days’ prior written notice to Administrative Agent of any modification or cancellation of such policy and that no act or default of any Credit Party or any other Person shall affect the right of Administrative Agent to recover under such policy or policies in case of loss or damage.

5.6 Books and Records; Inspections. Each Credit Party will, (a) keep adequate books of record and account of all dealings and transactions in relation to its business and activities and (b) permit any representatives designated by Administrative Agent or any Lender (including employees of Administrative Agent, any Lender or any consultants, accountants, lawyers and appraisers retained by Administrative Agent) to visit and inspect any of its properties, to inspect, copy and take extracts from its financial and accounting records, and to discuss its affairs, finances and accounts with its and their officers and independent accountants, all upon reasonable notice and at such reasonable times during normal business hours (so long as no Default or Event of Default has occurred and is continuing) and as often as may reasonably be requested and by this provision such Credit Party authorizes such accountants to discuss with Administrative Agent and any Lender and such representatives the affairs, finances and accounts of the Credit Parties. Each Credit Party acknowledges that Administrative Agent, after exercising its rights of inspection, may prepare and distribute to the Lenders certain reports pertaining to the Credit Parties’ assets for internal use by Administrative Agent and the Lenders. After the occurrence and during the continuance of any Event of Default, each Credit Party shall provide Administrative Agent and each Lender with access to its customers and suppliers.

5.7 Lenders Meetings; Syndication. Borrower will, upon the request of Administrative Agent or the Required Lenders, (a) participate in a meeting of Administrative Agent and Lenders at such time as may be agreed to by Borrower and Administrative Agent and (b) assist Administrative Agent in the acceptable syndication of the Commitments hereunder, including, but not limited to: (i) making representatives of Borrower available to participate at informational meetings with potential lenders, (ii) using best efforts to cause the syndication effort to benefit from existing credit relationships of Borrower and (iii) providing Administrative Agent with all information deemed necessary by it for successful syndication of the Commitments hereunder.

5.8 Compliance with Laws. Except for any noncompliance which could not reasonably be expected to have a Material Adverse Effect, each Credit Party will comply, and shall use reasonable efforts to cause all other Persons, if any, on or occupying any Facilities operated by a Credit Party or its Affiliate to comply, with the requirements of all applicable Governmental Requirements. Each Credit Party shall take all reasonable and necessary actions to ensure that no portion of the Loans will be used, disbursed or distributed for any purpose, or to any Person, directly or indirectly, in violation of any of the Terrorism Laws and shall take all reasonable and necessary action to comply in all material respects with all Terrorism Laws with respect thereto.

(a) Each Credit Party shall at its sole expense: (i) comply, and shall cause its Properties and operations to comply with all applicable Environmental Laws, (ii) not dispose of or otherwise release, any oil, oil and gas waste, hazardous substance, or solid waste on, under, about or from any of such Credit

Party’s Properties or any other Property to the extent caused by such Credit Party’s operations except in compliance with applicable Environmental Laws, (iii) timely obtain or file, all notices, permits, licenses, exemptions, approvals, registrations or other authorizations, if any, required under applicable Environmental Laws to be obtained or filed in connection with the operation or use of such Credit Party’s Properties, (iv) promptly commence and diligently prosecute to completion, any assessment, evaluation, investigation, monitoring, containment, cleanup, removal, repair, restoration, remediation or other remedial obligations (collectively, the “Remedial Work”) in the event any Remedial Work is required or reasonably necessary under applicable Environmental Laws because of or in connection with the actual or suspected past, present or future disposal or other release of any oil, oil and gas waste, hazardous substance or solid waste on, under, about or from any of such Credit Party’d Properties, and (v) establish and implement such procedures as may be necessary to continuously determine and assure that such Credit Party’s obligations under this Section 5.9 are timely and fully satisfied.

(b) Borrower will promptly, but in no event later than five (5) Business Days of the occurrence of a triggering event, notify Administrative Agent and the Lenders in writing of any threatened action, investigation or inquiry by any Governmental Authority or any threatened demand or lawsuit by any landowner or other third party against any Credit Party’s Properties of which Borrower or any other Credit Party has knowledge in connection with any Environmental Laws (excluding routine testing and corrective action) if Borrower or any other Credit Party reasonably anticipates that such action will result in liability (whether individually or in the aggregate) in excess of $50,000, not fully covered by insurance, subject to normal deductibles.

(c) With respect to any event described in Section 5.9(b), or if an Event of Default has occurred and is continuing, or if Administrative Agent reasonably believes that any Credit Party has breached any representation, warranty or covenant related to environmental matters:

(A) Administrative Agent and its representatives shall have the right, but not the obligation or duty, to enter the Facilities at reasonable times for the purposes of observing the Facilities to the extent any Credit Party can obtain access for them under the terms of an Operating Agreement. Such access shall include, at the reasonable request of Administrative Agent, access to relevant documents and employees of any Credit Party and to such Credit Party’s outside representatives, to the extent necessary to obtain necessary information related to the event at issue. If an Event of Default has occurred and is continuing, such Credit Party shall conduct such tests and investigations on the Facilities or relevant portion thereof, as requested by Administrative Agent, including the preparation of a Phase I Report or such other sampling or analysis as determined to be necessary under the circumstances by a qualified environmental engineer or consultant. If an Event of Default has occurred and is continuing, and if such Credit Party does not undertake such tests and investigations in a reasonably timely manner following the request of Administrative Agent, Administrative Agent may hire an independent engineer, at Borrower’s expense, to conduct such tests and investigations. Administrative Agent will make reasonable efforts to conduct any such tests and investigations so as to avoid interfering with the operation of the Facility

(B) Unless prevented by the terms of an Operating Agreement, any observations, tests or investigations of the Facilities by or on behalf of Administrative Agent shall be solely for the purpose of protecting the Lenders security interests and rights under the Credit Documents. The exercise of Administrative Agent’s rights under this Section 5.9(c)(B) shall not constitute a waiver of any default of any Credit Party or impose any liability on Administrative Agent or any of the Lenders. In no event will any observation, test or investigation by or on behalf of Administrative Agent be a

representation that Hazardous Materials are or are not present in, on or under any of the Facilities, or that there has been or will be compliance with any Environmental Law and Administrative Agent shall not be deemed to have made any representation or warranty to any party regarding the truth, accuracy or completeness of any report or findings with regard thereto. Neither any Credit Party nor any other party is entitled to rely on any observation, test or investigation by or on behalf of Administrative Agent. Administrative Agent and the Lenders owe no duty of care to protect any Credit Party or any other party against, or to inform any Credit Party or any other party of, any Hazardous Materials or any other adverse condition affecting any of the Facilities. Administrative Agent may, in its sole discretion, disclose to any Credit Party, or to any other party if so required by law, any report or findings made as a result of, or in connection with, its observations, tests or investigations. If a request is made of Administrative Agent to disclose any such report or finding to any third party, then Administrative Agent shall endeavor to give Borrower prior notice of such disclosure and afford Borrower the opportunity to object or defend against such disclosure at its own and sole cost; provided, that the failure of Administrative Agent to give any such notice or afford Borrower the opportunity to object or defend against such disclosure shall not result in any liability to Administrative Agent. Borrower acknowledges that it may be obligated to notify relevant Governmental Authorities regarding the results of any observation, test or investigation disclosed to such Person, and that such reporting requirements are site and fact-specific and are to be evaluated by such Person without advice or assistance from Administrative Agent.

If counsel to any Credit Party reasonably determines that provision to Administrative Agent of a document otherwise required to be provided pursuant to this Section 5.9 (or any other provision of this Agreement or any other Credit Document relating to environmental matters) would jeopardize an applicable attorney-client or work product privilege pertaining to such document, then such Credit Party shall not be obligated to deliver such document to Administrative Agent but shall provide Administrative Agent with a notice identifying the author and recipient of such document and generally describing the contents of the document. Upon request of Administrative Agent, such Credit Party shall take all reasonable steps necessary to provide Administrative Agent with the factual information contained in any such privileged document.

5.10 Additional Oil and Gas Properties. On each Collateral Addition Date, each Credit Party shall take all such actions and execute and deliver, or cause to be executed and delivered, all such mortgages, documents, instruments, agreements, opinions and certificates similar to those described in Sections 3.1(g), and 3.1(h), including new Direction Letters to purchasers of production, with respect to the Oil and Gas Properties not subject to the Lien of the Collateral Documents that Administrative Agent shall reasonably request to create in favor of Administrative Agent, for the benefit of the Secured Parties (in the case of a Lien), a valid and, subject to any filing and/or recording referred to herein, and a perfected First Priority security interest in all such Oil and Gas Properties (subject only to Excepted Liens of the type described in clause (a) to (d) and (f) of the definition thereof, but subject to the provisos at the end of such definition).

5.11 Further Assurances. At any time or from time to time upon the request of Administrative Agent, each Credit Party will, at its expense, promptly execute, acknowledge and deliver such further documents and do such other acts and things as Administrative Agent may reasonably request in order to effect fully the purposes of the Credit Documents, including providing Lenders with any information reasonably requested pursuant to Section 10.20. In furtherance and not in limitation of the foregoing, each Credit Party shall take such actions as Administrative Agent may reasonably request from time to time to ensure that the Obligations are guarantied by the Guarantors and are secured by

substantially all of the assets of the Credit Parties. Each Credit Party hereby authorizes Administrative Agent to file one or more financing or continuation statements, and amendments thereto, relative to all or any part of the Collateral.

5.12 Leases and Contracts; Performance of Obligations. Except to the extent a Credit Party reasonably determines that it is prudent not to do so (and without regard or consideration to any ORI), and except where failure to do so could not reasonably be expected to have a Material Adverse Effect, such Credit Party will maintain in full force and effect all oil, gas or mineral leases, contracts, servitudes and other agreements forming a part of any Oil and Gas Property of such Credit Party, to the extent the same cover or otherwise relate to such Oil and Gas Property. Each Credit Party will properly and timely pay all rents, royalties and other payments due and payable under any such leases, contracts, servitudes and other agreements, or under the Permitted Liens, or otherwise attendant to its ownership or operation of any Oil and Gas Property. Each Credit Party will promptly notify Administrative Agent of any claim (or any conclusion by such Credit Party) that such Credit Party is obligated to account for any royalties, or overriding royalties or other payments out of production, on a basis (other than delivery in kind) less favorable to such Credit Party than proceeds received by such Credit Party (calculated at the well) from sale of production. To the extent a Credit Party or its Affiliate is not the operator of any Property, the obligation of each Credit Party under this Section 5.12 shall be limited to the use of reasonable efforts to cause the operator to comply with this Section 5.12.

5.13 Lockbox Account and Equity Account; Operating Account. Before the Closing Date, (a) Borrower and Administrative Agent shall have established at Borrower’s expense the Lockbox Account and Equity Account with the Lockbox Bank in accordance with Section 7.1 and (b) Borrower shall have caused the Operating Account to become subject to a Deposit Account Control Agreement.

5.14 Deposit Accounts. In the event that any Credit Party establishes a deposit account other than the Lockbox Account, Equity Account or Operating Account, such Credit Party will, prior to transferring any funds to such account, execute a Deposit Account Control Agreement and grant in favor of Administrative Agent all the rights necessary to deposit, withdraw or otherwise manage and control the deposit account.

(a) On or before the delivery to Administrative Agent of each date set forth in Appendix A (whether or not a Reserve Report is actually delivered), Borrower will deliver title information in form and substance reasonably acceptable to Administrative Agent covering enough of the Oil and Gas Properties of the Credit Parties that were not previously evaluated by Administrative Agent, so that Administrative Agent shall have received together with title information previously delivered to Administrative Agent, satisfactory title information, including that the Credit Parties have Marketable Title thereto, on at least 80% of the total value of the Oil and Gas Properties of the Credit Parties, as determined by the Administrative Agent.

(b) If at any time Administrative Agent notifies any Credit Party that title defects or exceptions exist with respect to such Credit Party’s Oil and Gas Properties, such Credit Party shall, within thirty (30) days of such notice from Administrative Agent, either (i) cure any such title defects or exceptions (including defects or exceptions as to priority) which are not Permitted Liens raised by such information to the extent reasonably necessary to provide Marketable Title, (ii) substitute acceptable properties with no title defects or exceptions except for Permitted Liens having an equivalent value and Marketable Title in favor of such Credit Party or (iii) deliver title information in form and substance acceptable to Administrative Agent so that Administrative Agent shall have received, together with title information previously delivered to Administrative Agent, satisfactory title information on at least 80% of the value of the Oil and Gas Properties of the Credit Parties as determined by the Administrative Agent.

(c) If any Credit Party is unable to cure any title defect requested by Administrative Agent to be cured within the 30-day period or Borrower does not comply with the requirements to provide acceptable title information and Marketable Title covering 80% of the value of the Oil and Gas Properties of the Credit Parties as determined by Administrative Agent, such default shall not be a Default, but instead Administrative Agent and/or the Required Lenders shall have the right to exercise the following remedy in their sole discretion from time to time, and any failure to so exercise this remedy at any time shall not be a waiver as to future exercise of the remedy by Administrative Agent or the Required Lenders. To the extent that Administrative Agent or the Required Lenders are not satisfied with title to any Oil and Gas Properties of such Credit Party after the 30-day period has elapsed, or if such title defect is incapable of being cured upon notice of such title defect to such Credit Party, such unacceptable Oil and Gas Properties shall not count toward the 80% requirement, and Administrative Agent may send a notice to Borrower and the Lenders that the then outstanding Borrowing Base shall be reduced by an amount as determined by the Required Lenders to cause the Credit Parties to be in compliance with the requirement to provide acceptable title information and Marketable Title on 80% of the value of the Oil and Gas Properties of the Credit Parties. This new Borrowing Base shall become effective immediately after receipt of such notice. To the extent that a reduction in the Borrowing Base under this Section 5.15(c) causes the Effective Amount to exceed the Borrowing Base, Borrower shall comply with all of the terms of Section 2.16(c).

5.16 Swap Agreements. Within five (5) Business Days after the first date for which three (3) wells have been online and producing for sixty (60) days, the Credit Parties will keep and maintain Swap Agreements in place on terms and conditions approved by and satisfactory to Administrative Agent that (a) are for twenty-four (24) months in tenor on a rolling quarterly basis and (b) cover no less than 40% and no more than 90% of the notional volumes of Hydrocarbons anticipated to be produced from the Credit Parties’ then existing proved developed producing reserves; provided that, (y) within five (5) Business Days after the first date for which five (5) wells have been online and producing for sixty (60) days, the minimum percentage referenced above shall be 50% and (z) within five (5) Business Days after the first date for which ten (10) wells have been online and producing for sixty (60) days, the minimum percentage referenced above shall be 60%; provided further that, all put options entered into by the Credit Parties shall be excluded for purposes of determining compliance with the maximum limit above. Each Swap Agreement must be with an Approved Counterparty. No Credit Party shall sell, terminate, execute, amend or modify any Swap Agreement if such action results in Swap Net Cash Proceeds, unless such action is approved by Administrative Agent in writing or such Swap Net Cash Proceeds are paid to the Lenders as a prepayment of the Obligations hereunder.

5.17 Interest Reserve. Pursuant to Section 2.9(b), a reserve equal to one month’s interest payment on the Obligations shall be retained in the Lockbox Account at all times (the “Interest Reserve”).

Borrower hereby covenants and agrees that, so long as any Commitment is in effect and until payment in full of all Obligations, Borrower shall perform, and shall cause each other Credit Party to perform, all covenants in this Article VI.

6.1 Indebtedness. No Credit Party shall, directly or indirectly, create, incur, assume or guaranty, or otherwise become or remain directly or indirectly liable with respect to any Indebtedness, except:

(b) performance guaranties in the ordinary course of business and consistent with industry practices of the obligations of suppliers, customers, franchisees and licensees of the Credit Parties;

(d) Indebtedness in the form of obligations for the deferred purchase price of property or services incurred in the ordinary course of business which are being contested in good faith by appropriate proceedings and for which adequate reserves in accordance with GAAP have been established;

(f) Indebtedness owing in connection with the financing of insurance premiums in the ordinary course of business;

(g) Indebtedness consisting of sureties or bonds provided to any Governmental Authority or other Person and assuring payment of continent liabilities of any Credit Party in connection with the operation of the Oil and Gas Properties, including with respect to plugging, facility removal and abandonment of the Oil and Gas Properties;

(h) Indebtedness described in clauses (iv) and (v) of the definition of “Indebtedness” and incurred in connection with any Credit Party’s acquisition of oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, not to exceed. at any time, in the aggregate, $2,000,000;

(j) Indebtedness of Borrower or any Subsidiary of Borrower owing to Borrower or to any other Subsidiary of Borrower; provided that such Indebtedness is (y) consented to by Administrative Agent and (z) subordinated to the Obligations on terms acceptable to Administrative Agent in its sole discretion.

6.2 Use of Proceeds. No part of the proceeds of any Loan will be used, whether directly or indirectly, for any purpose that (i) entails a violation of any law, including Regulations T, U and X of the Board of Governors of the Federal Reserve System and (ii) not permitted under Section 2.2.

6.3 Liens. No Credit Party shall, directly or indirectly, create, incur, assume or permit to exist any Lien on or with respect to any property or asset of any kind (including any document or instrument in respect of goods or accounts receivable and any Security) of such Credit Party, whether now owned or hereafter acquired, or any income or profits therefrom, or file or permit the filing of, or permit to remain in effect, any financing statement or other similar notice of any Lien with respect to any such property, asset, income or profits under the UCC of any State or under any similar recording or notice statute, except (“Permitted Liens”):

(b) Liens in favor of Administrative Agent for the benefit of Secured Parties granted pursuant to any Credit Document;

(e) Liens arising out of judgments, attachments or awards not resulting in an Event of Default and which are being contested in good faith on appeal or proceedings for review and in respect of which there shall be secured a subsisting stay of execution pending such appeal or proceedings and for which adequate reserves in accordance with GAAP shall be maintained;

(f) Liens arising out of conditional sale, title retention, consignment or similar arrangements for the sale of goods entered into by any Credit Party in the ordinary course of business, consistent with past practices of such Credit Party and as customary in the oil and gas industry;

(g) licenses of intellectual property granted by any Credit Party in the ordinary course of business and not interfering in any material respect with the ordinary conduct of business of such Credit Party not exceeding $250,000 in the aggregate;

(h) purchase money Liens and Liens in connection with Capital Leases, in each case upon or in any equipment acquired or held by any Credit Party in the ordinary course of business; provided that the Indebtedness secured by such Liens (i) was incurred solely for the purpose of financing the acquisition of such equipment, and does not exceed the aggregate purchase price of such equipment, (ii) is secured only by such equipment and not by any other assets of such Credit Party, (iii) is not increased in amount, and (iv) does not exceed $250,000 in the aggregate; and

(i) other Liens not exceeding $100,000 in the aggregate (other than liens for borrowed money).

6.4 Negative Pledge Agreements; Dividend Restrictions. No Credit Party will create, incur, assume or suffer to exist any contract, agreement or understanding (other than this Agreement and the Collateral Documents) that in any way prohibits or restricts the granting, conveying, creation or imposition of any Lien on any of its Property in favor of Administrative Agent and the Lenders, or encumbers or limits any sale or transfer of such Property following a foreclosure, or restricts any Person from paying dividends or making distributions to Borrower or any Guarantor, or which requires the notice to (other than customary notices required under oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases) or, consents of other Persons in connection therewith (other than consents required under oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases that are set forth on Schedule 6.4 hereto, which such schedule of consents shall be updated as necessary on each Additional Collateral Date without the necessity of amending this Agreement).

6.5 Restricted Payments. Borrower shall not declare or make, or agree to pay or agree to pay or make, directly or indirectly, any Restricted Payment, return any capital to its shareholders or members or make any distribution of its Property in respect of its Capital Stock other than (a) stock dividends and other similar non-cash payments, (b) the repurchase of certain net profits overriding royalty interests from certain existing investors in the Niobrara Assets for aggregate consideration not to exceed $3,500,000, and (c) the Warrant Repurchase.

6.6 Investments. No Credit Party shall, directly or indirectly, make or own any Investment in any Person, including without limitation any Joint Venture, except:

(b) trade and customer accounts receivable which are for goods furnished or services rendered in the ordinary course of business and are payable in accordance with customary trade terms;

(c) creation of any additional Subsidiaries of any Credit Party in compliance with Section 6.17 and, upon consent of Administrative Agent, additional debt or equity investments in any such Subsidiary;

(d) Investments consisting of, or related to, drilling partnership arrangements so long as (i) such drilling partnership arrangements are documented through a joint operating agreement, participation agreement, exploration agreement, development agreement or similar agreement, (ii) any Oil and Gas Properties of the Credit Parties utilized in such arrangements remain subject to the Liens in favor of the Administrative Agent, and (iii) such arrangements only cover Oil and Gas Properties located in the Core Areas

(g) the repurchase of certain net profits interests contemplated by Section 6.5(b); and

(h) Investments of Borrower in any Subsidiary of Borrower and Investments of any Subsidiary of Borrower in Borrower or in another Subsidiary of Borrower.

6.7 Fundamental Changes; Disposition of Assets. No Credit Party shall enter into any transaction of merger or consolidation, or liquidate, wind up or dissolve itself (or suffer any liquidation or dissolution), or convey, farm-out, sell, lease or sub lease (as lessor or sublessor), exchange, transfer or otherwise dispose of, in one transaction or a series of transactions, all or any part of its business, assets or property of any kind whatsoever, whether real, personal or mixed and whether tangible or intangible, whether now owned or hereafter acquired, or acquire by purchase or otherwise the business, property or fixed assets of, or stock or other evidence of beneficial ownership of, any Person or any division or line of business or other business unit of any Person, except (a) the sale of Hydrocarbons in the ordinary course of business, (b) sales and other dispositions of Oil and Gas Properties, provided that the consent of Administrative Agent and Required Lenders is obtained for any sale or series of related sales of Oil and Gas Properties if the aggregate proceeds of all such sales are greater than $100,000.00 since the most recent Borrowing Base redetermination under Section 2.16, (c) the sale or other disposition of Properties that are damaged, destroyed, worn out, or obsolete or that have only salvage value, (d) dispositions of Properties pursuant to the Eaglebine Agreement, (e) the Eaglebine Sale, so long as Borrower makes the prepayment required by Section 2.9(a), (f) the Equity Transaction, (g) dispositions of the Moss 14-16H Oil and Gas Properties, so long as after giving effect to such dispositions, the Credit Parties shall collectively own 7.4165% of the net revenue interest and 9.2709% of the working interest attributable to such Oil and Gas Properties, (h) dispositions of Property between or among a Subsidiary of Borrower and Borrower or between or among Subsidiaries of Borrower; (i) the merger of a Subsidiary of Borrower with and into Borrower or another Subsidiary of Borrower (except that, with respect to any such merger or consolidation involving Borrower, Borrower must be the surviving entity) and (j) dispositions of the Employee Overrides and Petro Capital Overrides, so long as after giving effect to such dispositions (but prior to giving effect to the ORIs conveyed pursuant to the Equity Kicker Letter), the Credit Parties shall

collectively own, with respect to the Eaglebine Area and Permian Basin Area, at least 75%, and, with respect to the DJ Basin Area, at least 80%, of the net revenue interest (proportionately reduced) attributable to the working interest owned by such Credit Parties with respect to the Oil and Gas Properties burdened by such overriding royalty interests; provided, however, that the foregoing minimum net revenue interest requirements shall not apply to (y) Oil and Gas Properties marked with an asterisk on Schedule 4.13 and (z) any Oil and Gas Property that has its net revenue interest reduced below such requirements solely as a result of a Petro Capital Override swap under the Petro Capital Letter Agreement, so long as (I) another Oil and Gas Property identical in acreage size has a corresponding increase in net revenue interest and (II) Employee Overrides are not granted as to such increase in net revenue interest.

6.8 Sales and Lease Backs. No Credit Party shall, directly or indirectly, become or remain liable as lessee or as a guarantor or other surety with respect to any lease of any property (whether real, personal or mixed), whether now owned or hereafter acquired, which such Credit Party (a) has sold or transferred or is to sell or to transfer to any other Person or (b) intends to use for substantially the same purpose as any other property which has been or is to be sold or transferred by such Credit Party to any Person in connection with such lease.

6.9 Transactions with Shareholders and Affiliates. No Credit Party shall, directly or indirectly, enter into or permit to exist any transaction (including the purchase, sale, lease or exchange of any property or the rendering of any service) with any holder of five percent (5%) or more of any class of Capital Stock of Borrower or with any Affiliate of Borrower or of any such holder except those transactions (a) that exist at Closing and are disclosed on Schedule 6.9 hereto, (b) that are between two or more Credit Parties and are on terms that are fair and reasonable and no less favorable to such Credit Parties than would be obtained in a comparable arm’s length transaction with a Person that is not a a Credit Party, or (c) are approved in advance by the Required Lenders. For the avoidance of doubt, the following are not “transactions” referred to in the previous sentence: (i) salary, employee benefits and compensation and (ii) transactions between any Credit Party and any Affiliate operator pursuant to the terms and conditions of an operating agreement between such Credit Party and such Affiliate operator that is satisfactory to Administrative Agent.

6.10 Conduct of Business. No Credit Party will make any material change in the principal line of business in which is it is engaged as of the date hereof and reasonable extensions thereof.

6.11 Fiscal Year. Borrower shall not change its Fiscal Year end from December 31 without the prior written consent of Administrative Agent, such consent not to be unreasonably withheld.

6.12 Amendments to Organizational Agreements, Operating Agreements, Material Contracts. No Credit Party shall, without the consent of Administrative Agent, (a) amend or permit any amendments to its Organizational Documents, except (i) pursuant to the Equity Transaction and (ii) any other amendments not adverse to the Lenders; or (b) enter into, or amend or permit any amendments to, or terminate or waive any provision of any Operating Agreement or Material Contract, except any amendment that (i) does not amend any financial or economic terms of such Operating Agreement or Material Contract and (ii) is not adverse to the Lenders.

6.13 Prepayments of Certain Indebtedness. No Credit Party shall, directly or indirectly, voluntarily purchase, redeem, defease or prepay any principal of, premium, if any, interest or other amount payable in respect of any Indebtedness prior to its scheduled maturity in excess of $250,000 in the aggregate per year.

6.14 Gas Imbalances, Take-or-Pay or Other Prepayments. No Credit Party will allow gas imbalances (other than those imbalances which (a) occur in the ordinary course of business and (b) do not, in the aggregate, exceed 2% of the value of the proved developed producing natural gas reserves of the Credit Parties taken as a whole), take-or-pay or other prepayments with respect to the Oil and Gas Properties of such Credit Party that would require such Credit Party to deliver Hydrocarbons at some future time without then or thereafter receiving full payment therefor.

6.15 Sale or Discount of Receivables. Except for receivables obtained by a Credit Party in the ordinary course of business or the settlement of joint interest billing accounts in the ordinary course of business or discounts granted to settle collection of accounts receivable or the sale of defaulted accounts arising in the ordinary course of business in connection with the compromise or collection thereof and not in connection with any financing transaction, no Credit Party will discount or sell (with or without recourse) any of its notes receivable or accounts receivable.

6.16 Eligible Expenditures; General and Administrative Costs. No Credit Party shall make any Capital Expenditures (other than Capital Expenditures related to landmen who spend substantially all of their working time acquiring Oil and Gas Properties) or incur material costs associated with the acquisition of Oil and Gas Properties or the exploration and development of the Credit Parties’ Oil and Gas Properties (excluding normal lease operating expenses and excluding Capital Expenditures and material costs to be paid with proceeds of Loans), except that the Credit Parties may make any Capital Expenditure (or incur any such material costs) so long as (a) such Capital Expenditure or material cost is being made in respect of the acquisition or development of assets in one of the Core Areas and (b) after giving effect to such Capital Expenditure or material cost, the amount of Borrower’s Cash or Cash Equivalents (excluding Cash or Cash Equivalents in the Lockbox Account or Equity Account) is equal to or greater than $7,000,000; provided, however, that Section 6.16(b) shall not apply to any Oil and Gas Properties acquired by Borrower in the AMI (as defined in the Eaglebine Agreement) pursuant to Section 2 of the Eaglebine Agreement on or prior to August 31, 2012, and sold and conveyed (pursuant to the terms of the Eaglebine Agreement) to Buyer (as defined in the Eaglebine Agreement) on or prior to August 31, 2012. At no time shall the Credit Parties’ collective General and Administrative Costs exceed the General and Administrative Costs Cap; provided that, if the Eaglebine Sale shall have occurred, Borrower shall be permitted to pay on a one-time basis bonus payments to its employees and consultants in an aggregate amount not to exceed $1,000,000. The Credit Parties’ collective Permitted IPO Expenses shall not exceed the Permitted IPO Expenses Cap.

6.17 Subsidiaries. No Credit Party will create, acquire or allow to exist any Subsidiary of such Credit Party unless Administrative Agent has consented (for the avoidance of doubt, Administrative Agent has consented to the Equity Transaction) and such Credit Party has pledged all of the Capital Stock of such Subsidiary pursuant to the Pledge and Security Agreement, and the Subsidiary has become a party to the Guaranty Agreement and the Pledge and Security Agreement, become a Guarantor and executed other documents described in Article 3 as requested by Administrative Agent. Upon consummation of the Equity Transaction, Parent, ENEXP Operating, and ENEXP Operating GP shall each become a party to the Guaranty Agreement and Pledge and Security Agreement.

6.18 Restrictions Upon Alienability. No Credit Party will enter into Material Contracts or other agreements affecting such Credit Party’s Oil and Gas Properties that would prohibit, restrict or hinder Administrative Agent or any Lender, or any successor in interest to Administrative Agent or any Lender, from foreclosing upon such contract or agreement.

6.19 Maximum Loan Amount. Borrower will not permit the amount of Loans advanced hereunder, without giving effect to any repayment, to exceed the Maximum Loan Amount.

6.20 Change of Management. Borrower will not permit a Change of Management to occur.

7.1 Lockbox Account and Equity Account. Borrower shall maintain at Borrower’s expense a non interest-bearing account (the “Lockbox Account”) under Administrative Agent’s exclusive control with Fifth Third Bank (the “Lockbox Bank”) which is subject to a Deposit Account Control Agreement specifying that the Lockbox Bank shall comply with all instructions it receives from Administrative Agent with respect to the Lockbox Account without further consent from Borrower; provided that, unless and until an Event of Default shall have occurred and be continuing, the Administrative Agent shall, in accordance with Section 2.9(b), remit all amounts contained in the Lockbox Account to the Borrower’s Operating Account after application of such funds to the other priority items set forth in such Section 2.9(b). All Cash Receipts to be received by the Credit Parties shall be deposited in the Lockbox Account, and Borrower shall, and shall cause each Credit Party to, direct (and hereby agrees to direct or cause to direct, as applicable) each payor of any Cash Receipts now and in the future to make payment to such Lockbox Account. Borrower hereby irrevocably appoints Administrative Agent as its attorney-in-fact (and such appointment shall be deemed to be coupled with an interest so long as any Loans or Obligations remain outstanding) to address any Direction Letter or letter-in-lieu of division order executed by Borrower or any other Credit Party it may hold and deliver or have delivered any such letter to any Person purchasing Hydrocarbons from the Oil and Gas Properties of any Credit Party that is not then directing payment for such Hydrocarbons to the Lockbox Account. Administrative Agent acknowledges and agrees that it does not presently and shall not in the future claim, create or attempt to create any lien on or security interest in any Other Owner Cash Receipts and hereby waives, disclaims and relinquishes any such lien or security interest. Borrower shall maintain at Borrower’s expense a non interest-bearing account to hold the funds required pursuant to Section 3.1(s) (the “Equity Account”) under Administrative Agent’s exclusive control (but subject to the remittance obligations specified below) with the Lockbox Bank which is subject to a Deposit Account Control Agreement specifying that, upon request of any Credit Party, Administrative Agent shall instruct Lockbox Bank to remit amounts owing by the Credit Parties to fund AFEs for drilling and completing wells and seismic costs under or in respect of the Eaglebine Agreement or transactions evidenced thereby to the appropriate payee promptly upon request by such Credit Party (which remittance shall occur even if a Default or Event of Default shall have occurred and be continuing).

7.2 Notices, Direction Letters, Deposits of Cash Receipt. Immediately following execution of this Agreement, each Credit Party shall direct all Persons that owe or are expected to owe Cash Receipts to such Credit Party to forward all such amounts directly to the Lockbox Account. Borrower hereby irrevocably appoints Administrative Agent as its attorney-in-fact (such appointment being coupled with an interest) for sending any such notice to any Person who is or may become obligated to make any payment of Cash Receipts to any Credit Party. With respect to Cash Receipts received directly by a Credit Party, such Credit Party shall within five (5) Business Days of receipt cause all such amounts to be deposited in the Lockbox Account. If any Credit Party has knowledge that any Person is in receipt of Cash Receipts that would otherwise be properly deposited in the Lockbox Account, such Credit Party shall promptly notify such Person and Administrative Agent in writing of such circumstance and shall direct such Person to deposit, or cause to be deposited, all such amounts in the Lockbox Account.

(a) All Casualty Proceeds (for collateral purposes) are hereby assigned by Borrower and each other Credit Party to Administrative Agent, and Borrower or such Credit Party, as applicable, shall have the right to collect any such payments.

(b) In the event of any casualty the Casualty Proceeds with respect to which are $50,000 or less, subject to the requirements of any Operating Agreement, such Casualty Proceeds shall be deposited into the Lockbox Account and shall be made available for use by the applicable Credit Party to pay or recover the costs of restoring, repairing, or replacing the affected Property. To the extent not so used within twelve (12) months of the date of such casualty, such Credit Party’s interest in such Casualty Proceeds shall be deemed to be Cash Receipts received within such 12^th month (and the interest of any joint interest owners in such Casualty Proceeds shall be released to such owners).

(c) In the event of any casualty the Casualty Proceeds with respect to which are greater than $50,000, subject to the requirements of any Operating Agreement, (i) the applicable Credit Party shall deposit such Casualty Proceeds upon receipt into an account to be established at the Lockbox Bank controlled by Administrative Agent (the “Casualty Proceeds Account”), (ii) such Credit Party shall deliver within thirty (30) days, a written report from an engineering firm acceptable to Administrative Agent describing the nature of the casualty, the nature of any restoration required, and a good faith estimate of the cost of such restoration, and (iii) the proceeds shall be disbursed from the Casualty Proceeds Account for such restoration in accordance with procedures reasonably determined by the Lenders consistent with construction loan funding principles. Notwithstanding the foregoing, if such Casualty Proceeds are greater than $1,500,000, and if the Lenders in their sole discretion determine that the remediation is not in their best interests, given the cost of such restoration and the effect such restoration would have on the amount and timing of repayment of the Loans, then the Lenders may apply the applicable Credit Party’s interest in such Casualty Proceeds to the prepayment of the outstanding principal balance and accrued interest of the Loans and the other Indebtedness, whether or not such Indebtedness is then due and payable (and shall release any joint interest owner’s interest in such Casualty Proceeds to such owner).

8.1 Events of Default. If any one or more of the following conditions or events shall occur:

(a) Failure to Make Payments When Due. Failure by Borrower to pay (i) when due the principal of any Loan whether at stated maturity, by acceleration or otherwise; (ii) when due any installment of principal of any Loan, by mandatory prepayment or otherwise; or (iii) when due any interest on any Loan or any fee or any other amount due hereunder.

(b) Default in Other Agreements. (i) Failure of any Credit Party to pay when due any principal of or interest on or any other amount payable in respect of one or more items of Indebtedness (other than Indebtedness referred to in Section 6.1(a)) in an individual principal amount of $100,000 or more or with an aggregate principal amount of $200,000 or more; or (ii) breach or default by any Credit Party with respect to (1) any other material term of one or more items of Indebtedness in the individual or aggregate principal amounts referred to in clause (i) above, or (2) any loan agreement, mortgage, indenture or other agreement relating to such item(s) of Indebtedness if the effect of such breach or default is to cause, or to permit the holder or holders of that Indebtedness (or a trustee on behalf of such holder or holders), to cause, that Indebtedness to become or be declared due and payable (or subject to a compulsory repurchase or redemption) or to require the prepayment, redemption, repurchase or defeasance of, or to cause such Credit Party to make any offer to prepay, redeem, repurchase or defease such Indebtedness, prior to its stated maturity or the stated maturity of any underlying obligation, as the case may be; or

(c) Breach of Certain Covenants. Failure of any Credit Party to perform or comply with any term or condition contained in Section 5.1(g), Section 5.2 (other than the obligation to maintain its qualification to do business), or Article VI or failure to timely deposit or direct the relevant Person to timely deposit Cash Receipts or Casualty Proceeds into the relevant account in accordance with Article VII; or

(d) Breach of Representations, etc. Any representation, warranty, certification or other statement made or deemed made by any Credit Party in any Credit Document or in any statement or certificate at any time given by any Credit Party in writing pursuant hereto or thereto or in connection herewith or therewith shall be false in any material respect as of the date made or deemed made; or

(e) Defaults Under Credit Documents. Any Credit Party shall default in the performance of or compliance with any covenant, condition or agreement contained herein or any of the Credit Documents (other than those referred to in Section 8.1(a), Section 8.1(b), Section 8.1(c) or Section 8.1(d)), and such default shall not have been remedied or waived within thirty (30) days (or, in the case of the covenants in Section 5.1 (other than Section 5.1(g)), fifteen (15) days) after the earlier of (i) the date an officer of such Credit Party becomes aware or reasonably should have become aware of such default, or (ii) receipt by Borrower of notice from Administrative Agent or any Lender of such default; provided however, for purposes of Section 2.7, payment of Default Interest shall begin to accrue as of the date of such default; or

(f) Involuntary Bankruptcy; Appointment of Receiver, etc. (i) A court of competent jurisdiction shall enter a decree or order for relief in respect of any Credit Party in an involuntary case under the Bankruptcy Code or under any other applicable bankruptcy, insolvency or similar law now or hereafter in effect, which decree or order is not stayed; or any other similar relief shall be granted under any applicable federal or state law and is not stayed; or (ii) an involuntary case shall be commenced against any Credit Party under the Bankruptcy Code or under any other applicable bankruptcy, insolvency or similar law now or hereafter in effect; or a decree or order of a court having jurisdiction in the premises for the appointment of a receiver, liquidator, sequestrator, trustee, custodian or other officer having similar powers over such Credit Party, or over all or a substantial part of its property, shall have been entered; or there shall have occurred the involuntary appointment of an interim receiver, trustee or other custodian of any Credit Party for all or a substantial part of its property; or a warrant of attachment, execution or similar process shall have been issued against any substantial part of the property of such Credit Party, and any such event described in this clause (ii) shall continue for sixty (60) days without having been dismissed, bonded or discharged; or

(g) Voluntary Bankruptcy; Appointment of Receiver, etc. (i) Any Credit Party shall have an order for relief entered with respect to it or shall commence a voluntary case under the Bankruptcy Code or under any other applicable bankruptcy, insolvency or similar law now or hereafter in effect, or shall consent to the entry of an order for relief in an involuntary case, or to the conversion of an involuntary case to a voluntary case, under any such law, or shall consent to the appointment of or taking possession by a receiver, trustee or other custodian for all or a substantial part of its property; or any Credit Party shall make any assignment for the benefit of creditors; or (ii) any Credit Party shall be unable, or shall fail generally, or shall admit in writing its inability, to pay its debts as such debts become due; or the board of directors (or similar governing body) of any Credit Party (or any committee thereof) shall adopt any resolution or otherwise authorize any action to approve any of the actions referred to herein or in Section 8.1(f); or

(h) Judgments and Attachments. Any money judgment, writ or warrant of attachment or similar process involving (i) in any individual case an amount in excess of $100,000 or (ii) in the aggregate at any time an amount in excess of $200,000 (in either case to the extent not fully covered by insurance (less any deductible) complying with the requirements of this Agreement as to which a solvent and unaffiliated insurance company has not acknowledged coverage) shall be entered or filed against any Credit Party or any of their respective assets and shall remain undischarged, unvacated, unbonded or unstayed for a period of thirty (30) days (or in any event later than the date that enforcement proceedings shall have been commenced by any creditor upon such judgment order or five (5) days prior to the date of any proposed sale thereunder); or

(i) Dissolution. Any order, judgment or decree shall be entered against any Credit Party decreeing the dissolution or split up of such Credit Party and such order shall remain undischarged or unstayed for a period in excess of thirty (30) days; or

(j) Employee Benefit Plans. (i) There shall occur one or more ERISA Events which individually or in the aggregate results in or could reasonably be expected to result in liability of Borrower or any ERISA Affiliate of Borrower in excess of $100,000 during the term hereof; or (ii) there exists any fact or circumstance that reasonably could be expected to result in the imposition of a Lien or security interest under Section 401(a)(29) or 412(n) of the Internal Revenue Code or under ERISA which could have a Material Adverse Effect; or

(l) Guaranties, Collateral Documents and other Credit Documents. At any time after the execution and delivery thereof, (i) any Guarantee under the Guaranty Agreement for any reason, other than the satisfaction in full of all Obligations, shall cease to be in full force and effect (other than in accordance with its terms) or shall be declared to be null and void, or any Guarantor shall repudiate its obligations thereunder, (ii) this Agreement or any Collateral Document ceases to be in full force and effect (other than by reason of a release of Collateral in accordance with the terms hereof or thereof or the satisfaction in full of the Obligations in accordance with the terms hereof) or shall be declared null and void, or, Administrative Agent shall not have or shall cease to have a valid and perfected Lien in any Collateral purported to be covered by the Collateral Documents with the priority required by the relevant Collateral Document unless such Lien is made valid and perfected on or before ten (10) Business Day after the earlier to occur of notice thereof to any Credit Party by Administrative Agent or any Credit Party becoming aware thereof, in each case for any reason other than the failure of Administrative Agent or any Secured Party to take any action within its control, or (iii) any Credit Party shall contest the validity or enforceability of any Credit Document in writing or deny in writing that it has any further liability, including with respect to future advances by Lenders, under any Credit Document to which it is a party; or

(m) Licenses, Permits, etc. (i) Any Governmental Authority revokes or fails to renew any license, permit or franchise of any Credit Party and such revocation or failure results in a Material Adverse Effect, (ii) any Credit Party for any reason loses any license, permit or franchise and such loss results in a Material Adverse Effect, (iii) any Credit Party suffers the imposition of any restraining order, escrow, suspension or impound of funds in connection with any proceeding (judicial or administrative) with respect to any license, permit or franchise; and such Default remains unremedied for a period of thirty (30) days after the earlier of (I) the date upon which a Authorized Officer knew or reasonably should have known of such Default and (II) the date upon which written notice thereof is given to Borrower by Administrative Agent and such imposition of such restraining order, escrow, suspension, or impound results in a Material Adverse Effect; or

(n) Related Agreements and Material Contracts. Any Credit Party or any Person party to a Related Agreement or Material Contract fails to duly observe, perform or comply with any Related Agreement or Material Contract or any term or condition of such agreements, and such failure is not remedied within the applicable grace period (if any) provided in such agreement or instrument or such agreement ceases to be in full force and effect prior to its stated termination date, and in each case such event results in a Material Adverse Effect; or

(o) Eaglebine Agreement. The JOA (as defined in the Eaglebine Agreement) shall terminate prior to the receipt by Borrower of the Contingent Payment (as defined in the Eaglebine Agreement); or

(p) Change of Management. A Change of Management shall occur and, in the case of a departing person, such Person is not replaced within thirty (30) days of his departure by a Person acceptable to Administrative Agent in its sole discretion; or

(r) Equity Transaction. The Equity Transaction does not occur on or prior to July 31, 2012.

THEN, (1) upon the occurrence of any Event of Default described in Section 8.1(f) or 8.1(g), automatically, and (2) upon the occurrence of any other Event of Default, upon notice to Borrower by Administrative Agent, (A) the Commitments, if any, of each Lender having such Commitments shall terminate; (B) the unpaid principal amount of and accrued interest on the Loans and all other Obligations shall immediately become due and payable, in each case without presentment, demand, protest or other requirements of any kind, all of which are hereby expressly waived by each Credit Party; and (C) Administrative Agent may enforce any and all Liens and security interests created pursuant to Collateral Documents.

8.2 Application of Proceeds. Upon the occurrence and during the continuance of an Event of Default, all proceeds in the Lockbox Account and Equity Account and all amounts realized from the liquidation or other disposition of the Collateral or otherwise received, shall be distributed in the following order of priority and to the extent funds remain available:

(a) payment or reimbursement of that portion of the Obligations constituting fees, expenses and indemnities payable to Administrative Agent (or its agents or counsel) in its capacity as such;

(b) pro rata to payment or reimbursement of that portion of the Obligations constituting fees, expenses and indemnities payable to the Lenders;

(d) pro rata to payment of principal outstanding on the Loans and that portion of the Obligations constituting amounts owing or to be owing to any Approved Counterparty under any Swap Agreements permitted under this Agreement, including termination amounts;

(f) any excess, after all of the Obligations shall have been indefeasibly paid in full in cash, shall be paid to Borrower or as otherwise required by any Governmental Requirement.

8.3 Resignation of Operator. In addition to all rights and remedies under this Agreement, any other Credit Document, at law and in equity, if any Event of Default shall occur and Administrative Agent, or its designee or representative, shall exercise any remedies under the Collateral Documents with respect to any portion of the Mortgaged Property (as defined in each Mortgage) (or any Credit Party shall transfer any Mortgaged Properties “in lieu of” foreclosure), Administrative Agent and the Lenders shall have the right to request that any operator of any Mortgaged Properties which is either a Credit Party or an Affiliate of a Credit Party resign as operator under the joint operating agreement applicable thereto; and no later than sixty (60) days after receipt by a Credit Party of any such request, such Credit Party or its Affiliate shall resign (or cause such other party to resign) as operator of such Mortgaged Properties.

9.1 Appointment of Administrative Agent. GCF is hereby appointed Administrative Agent hereunder and under the other Credit Documents and each Lender hereby authorizes GCF, in such capacity, to act as its agent in accordance with the terms hereof and the other Credit Documents. Administrative Agent hereby agrees to act upon the express conditions contained herein and the other Credit Documents, as applicable. The provisions of this Article IX are solely for the benefit of Administrative Agent and the Lenders and no Credit Party shall have any rights as a third party beneficiary of any of the provisions thereof. In performing its functions and duties hereunder, Administrative Agent shall act solely as an agent of the Lenders and does not assume and shall not be deemed to have assumed any obligation towards or relationship of agency or trust with or for any Credit Party.

9.2 Powers and Duties. Each Lender irrevocably authorizes Administrative Agent to take such action on such Lender’s behalf and to exercise such powers, rights and remedies and perform such duties hereunder and under the other Credit Documents as are specifically delegated or granted to Administrative Agent by the terms hereof and thereof, together with such actions, powers, rights and remedies as are reasonably incidental thereto. Administrative Agent shall have only those duties and responsibilities that are expressly specified herein and in the other Credit Documents. Administrative Agent may exercise such powers, rights and remedies and perform such duties by or through its agents or employees. Administrative Agent shall not have or be deemed to have, by reason hereof or any of the other Credit Documents, a fiduciary relationship in respect of any Lender; and nothing herein or any of the other Credit Documents, expressed or implied, is intended to or shall be so construed as to impose upon Administrative Agent any obligations in respect hereof or any of the other Credit Documents except as expressly set forth herein or therein.

(a) No Responsibility for Certain Matters. Administrative Agent shall not be responsible to any Lender for the execution, effectiveness, genuineness, validity, enforceability, collectability or sufficiency hereof or any other Credit Document or for any representations, warranties, recitals or statements made herein or therein or made in any written or oral statements or in any financial or other statements, instruments, reports or certificates or any other documents furnished or made by Administrative Agent to the Lenders or by or on behalf of any Credit Party to Administrative Agent or any Lender in connection with the Credit Documents and the transactions contemplated thereby or for the financial condition or business affairs of any Credit Party or any other Person liable for the payment of any Obligations, nor shall Administrative Agent be required to ascertain or inquire as to the performance or observance of any of the terms, conditions, provisions, covenants or agreements contained in any of the Credit Documents or as to the use of the proceeds of the Loans or as to the existence or possible existence of any Event of Default or Default or to make any disclosures with respect to the foregoing. Anything contained herein to the contrary notwithstanding, Administrative Agent shall not have any liability arising from confirmations of the amount of outstanding Loans.

(b) Exculpatory Provisions. Administrative Agent shall not, nor shall any of its officers, partners, directors, employees or agents be liable to Lenders for any action taken or omitted by any agent under or in connection with any of the Credit Documents except to the extent caused by Administrative Agent’s gross negligence or willful misconduct as determined by a court of competent jurisdiction in a final, nonappealable order. Administrative Agent shall be entitled to refrain from any act or the taking of any action (including the failure to take an action) in connection herewith or any of the other Credit Documents or from the exercise of any power, discretion or authority vested in it hereunder or thereunder unless and until Administrative Agent shall have received instructions in respect thereof from the Required Lenders (or such other Lenders as may be required to give such instructions under Section 10.5). Without prejudice to the generality of the foregoing, (i) Administrative Agent shall be entitled to rely, and shall be fully protected in relying, upon any communication, instrument or document believed by it to be genuine and correct and to have been signed or sent by the proper Person or Persons, and shall be entitled to rely and shall be protected and free from liability in relying on opinions and judgments of attorneys (who may be attorneys for the Credit Parties), accountants, experts and other professional advisors selected by it; and (ii) no Lender shall have any right of action whatsoever against Administrative Agent as a result of Administrative Agent acting or (where so instructed) refraining from acting hereunder or any of the other Credit Documents in accordance with the instructions of the Required Lenders (or such other Lenders as may be required to give such instructions under Section 10.5).

(c) Notice of Default. Administrative Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Event of Default, except with respect to Events of Default in the payment of principal, interest and fees required to be paid to Administrative Agent for the account of the Lenders, unless Administrative Agent shall have received written notice from a Lender or Borrower referring to this Agreement, describing such Default or Event of Default and stating that such notice is a “notice of default.” Administrative Agent will notify the Lenders of its receipt of any such notice. Administrative Agent shall take such action with respect to any such Default or Event of Default as may be directed by the Required Lenders in accordance with Article VIII; provided, however, that unless and until Administrative Agent has received any such direction, Administrative Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default or Event of Default as it shall deem advisable or in the best interest of the Lenders.

9.4 Administrative Agent Entitled to Act as Lender. The agency hereby created shall in no way impair or affect any of the rights and powers of, or impose any duties or obligations upon, Administrative Agent in its individual capacity as a Lender hereunder. With respect to its participation in the Loans, Administrative Agent shall have the same rights and powers hereunder as any other Lender and may exercise the same as if it were not performing the duties and functions delegated to it hereunder, and the term “Lender” shall, unless the context clearly otherwise indicates, include Administrative Agent in its individual capacity. Administrative Agent and its Affiliates may accept deposits from, lend money to, own securities of, and generally engage in any kind of banking, trust, financial advisory or other business with any Credit Party or any of its Affiliates as if it were not performing the duties specified herein, and may accept fees and other consideration from any Credit Party for services in connection herewith and otherwise without having to account for the same to Lenders.

(a) Each Lender represents and warrants that it has made its own independent investigation of the financial condition and affairs of the Credit Parties, without reliance upon Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, in

connection with Loans hereunder and that it has made and shall continue to make its own appraisal of the creditworthiness of the Credit Parties. Administrative Agent shall not have any duty or responsibility, either initially or on a continuing basis, to make any such investigation or any such appraisal on behalf of Lenders or to provide any Lender with any credit or other information with respect thereto, whether coming into its possession before the making of the Loans or at any time or times thereafter, and Administrative Agent shall not have any responsibility with respect to the accuracy of or the completeness of any information provided to Lenders.

(b) Each Lender hereby acknowledges and agrees that Haynes and Boone, LLP is solely counsel to the Guggenheim Corporate Funding, LLC, in its capacity as Administrative Agent.

(c) Each Lender, by delivering its signature page to this Agreement and the funding of Loans, shall be deemed to have acknowledged receipt of, and consented to and approved, each Credit Document and each other document required to be approved by Administrative Agent, Required Lenders or Lenders, as applicable on the Closing Date or as of the date of funding of such Loans.

9.6 Right to Indemnity. Each Lender, in proportion to its Pro Rata Share, severally agrees to indemnify Administrative Agent, its Affiliates and their respective officers, partners, directors, trustees, employees, representatives and agents (each, an “Indemnitee Agent Party”), to the extent that such Indemnitee Agent Party shall not have been reimbursed by any Credit Party, for and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses (including counsel fees and disbursements) or disbursements of any kind or nature whatsoever which may be imposed on, incurred by or asserted against such Indemnitee Agent Party in exercising its powers, rights and remedies or performing its duties hereunder or under the other Credit Documents or otherwise in its capacity as such Indemnitee Agent Party in any way relating to or arising out of this Agreement or the other Credit Documents, IN ALL CASES, WHETHER OR NOT CAUSED BY OR ARISING, IN WHOLE OR IN PART, OUT OF THE COMPARATIVE, CONTRIBUTORY, OR SOLE NEGLIGENCE OF SUCH AGENT; provided, no Lender shall be liable for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from such Indemnitee Agent Party’s gross negligence or willful misconduct as determined by a court of competent jurisdiction in a final, nonappealable order. If any indemnity furnished to any Indemnitee Agent Party for any purpose shall, in the opinion of such Indemnitee Agent Party, be insufficient or become impaired, such Indemnitee Agent Party may call for additional indemnity and cease, or not commence, to do the acts indemnified against until such additional indemnity is furnished; provided, in no event shall this sentence require any Lender to indemnify any Indemnitee Agent Party against any liability, obligation, loss, damage, penalty, action, judgment, suit, cost, expense or disbursement in excess of such Lender’s Pro Rata Share thereof; and provided, further, this sentence shall not be deemed to require any Lender to indemnify any Indemnitee Agent Party against any liability, obligation, loss, damage, penalty, action, judgment, suit, cost, expense or disbursement described in the proviso in the immediately preceding sentence.

(a) Administrative Agent may resign at any time by giving thirty (30) days’ prior written notice thereof to Lenders and Borrower. Upon any such notice of resignation, the Required Lenders shall have the right, with the written consent of Borrower (not to be unreasonably withheld) if no Event of Default has occurred and is continuing, to appoint a successor Administrative Agent. If no successor shall have been so appointed by the Required Lenders and shall have accepted such appointment within thirty (30) days after the retiring Administrative Agent gives notice of its resignation, then the retiring Administrative Agent may, on behalf of the Lenders, appoint a successor Administrative Agent from among the Lenders. Upon the acceptance of any appointment as Administrative Agent hereunder by a

successor Administrative Agent, that successor Administrative Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent and the retiring Administrative Agent shall promptly (i) transfer to such successor Administrative Agent all sums, Securities and other items of Collateral held under the Collateral Documents, together with all records and other documents necessary or appropriate in connection with the performance of the duties of the successor Administrative Agent under the Credit Documents, and (ii) execute and deliver to such successor Administrative Agent such amendments to financing statements, and take such other actions, as may be necessary or appropriate in connection with the assignment to such successor Administrative Agent of the security interests created under the Collateral Documents, whereupon such retiring Administrative Agent shall be discharged from its duties and obligations hereunder. After any retiring Administrative Agent’s resignation hereunder as Administrative Agent and Administrative Agent, the provisions of this Article IX shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Administrative Agent hereunder.

(b) Notwithstanding anything herein to the contrary, Administrative Agent may assign its rights and duties as Administrative Agent hereunder to an Affiliate of GCF without the prior written consent of, or prior written notice to, Borrower or the Lenders; provided that Borrower and the Lenders may deem and treat such assigning Administrative Agent as Administrative Agent for all purposes hereof, unless and until such assigning Administrative Agent provides written notice to Borrower and the Lenders of such assignment. Upon such assignment such Affiliate shall succeed to and become vested with all rights, powers, privileges and duties as Administrative Agent hereunder and under the other Credit Documents.

(c) Administrative Agent may perform any and all of its duties and exercise its rights and powers under this Agreement or under any other Credit Document by or through any one or more sub-agents appointed by Administrative Agent. Administrative Agent and any such sub-agent may perform any and all of its duties and exercise its rights and powers by or through their respective Affiliates. The exculpatory, indemnification and other provisions of Section 9.6 and this Section 9.7 shall apply to any of the Affiliates of Administrative Agent and shall apply to their respective activities in connection with the syndication of the credit facilities provided for herein as well as activities as Administrative Agent. All of the rights, benefits and privileges (including the exculpatory and indemnification provisions) of Section 9.6 and this Section 9.7 shall apply to any such sub-agent and to the Affiliates of any such sub-agent, and shall apply to their respective activities as sub-agent as if such sub-agent and Affiliates were named herein. Notwithstanding anything herein to the contrary, with respect to each sub-agent appointed by Administrative Agent, (i) such sub-agent shall be a third party beneficiary under this Agreement with respect to all such rights, benefits and privileges (including exculpatory and rights to indemnification) and shall have all of the rights, benefits and privileges of a third party beneficiary, including an independent right of action to enforce such rights, benefits and privileges (including exculpatory rights and rights to indemnification) directly, without the consent or joinder of any other Person, against any or all of the Credit Parties and the Lenders, (ii) such rights, benefits and privileges (including exculpatory rights and rights to indemnification) shall not be modified or amended without the consent of such sub-agent, and (iii) such sub-agent shall only have obligations to Administrative Agent and not to any Credit Party, Lender or any other Person and no Credit Party, the Lenders or any other Person shall have the rights, directly or indirectly, as a third party beneficiary or otherwise, against such sub-agent.

(a) Administrative Agent under Collateral Documents. Each Lender hereby further irrevocably authorizes Administrative Agent, on behalf of and for the benefit of the Lenders, to be the agent for and representative of Lenders with respect to the Collateral and the Collateral Documents. Subject to Section 10.5, without further written consent or authorization from Lenders, Administrative

Agent may execute any documents or instruments necessary to (i) release any Lien encumbering any item of Collateral that is the subject of a sale or other disposition of assets permitted hereby or to which the Required Lenders (or such other Lenders as may be required to give such consent under Section 10.5) have otherwise consented, or (ii) release any Guarantor from a Guaranty Agreement with respect to which the Required Lenders (or such other Lenders as may be required to give such consent under Section 10.5) have consented.

(b) Right to Realize on Collateral and Enforce Guaranty. Anything contained in any of the Credit Documents to the contrary notwithstanding, each Credit Party, Administrative Agent and each Lender hereby agree that (i) no Lender shall have any right individually to realize upon any of the Collateral or to enforce the Guaranty Agreement, it being understood and agreed that all powers, rights and remedies hereunder may be exercised solely by Administrative Agent, on behalf of Lenders in accordance with the terms hereof and all powers, rights and remedies under the Collateral Documents may be exercised solely by Administrative Agent, and (ii) in the event of a foreclosure by Administrative Agent on any of the Collateral pursuant to a public or private sale, Administrative Agent or any Lender may be the purchaser of any or all of such Collateral at any such sale and Administrative Agent, as agent for and representative of Secured Parties (but not any Lender or Lenders in its or their respective individual capacities unless Required Lenders shall otherwise agree in writing) shall be entitled, for the purpose of bidding and making settlement or payment of the purchase price for all or any portion of the Collateral sold at any such public sale, to use and apply any of the Obligations as a credit on account of the purchase price for any collateral payable by Administrative Agent at such sale.

(a) Delivery of Communications. Each Credit Party hereby agrees, unless directed otherwise by Administrative Agent or unless the electronic mail address referred to below has not been provided by Administrative Agent to such Credit Party that it will provide to Administrative Agent all information, documents and other materials that it is obligated to furnish to Administrative Agent or to the Lenders pursuant to the Credit Documents, including all notices, requests, financial statements, financial and other reports, certificates and other information materials, but excluding any such communication that (i) relates to the payment of any principal or other amount due under this Agreement prior to the scheduled date therefor, (ii) provides notice of any Default under this Agreement or any other Credit Document or (iii) is required to be delivered to satisfy any condition precedent to the effectiveness of this Agreement and/or any Loan or other extension of credit hereunder (all such non-excluded communications being referred to herein collectively as “Communications”), by transmitting the Communications in an electronic/soft medium that is properly identified in a format acceptable to Administrative Agent to an electronic mail address as directed by Administrative Agent. In addition, each Credit Party agrees to continue to provide the Communications to Administrative Agent or the Lenders, as the case may be, in the manner specified in the Credit Documents but only to the extent requested by Administrative Agent.

(b) Platform. Each Credit Party further agrees that Administrative Agent may make the Communications available to the Lenders by posting the Communications on an electronic transmission system (the “Platform”).

(c) No Warranties as to Platform. THE PLATFORM IS PROVIDED “AS IS” AND “AS AVAILABLE.” THE INDEMNITEES DO NOT WARRANT THE ACCURACY OR COMPLETENESS OF THE COMMUNICATIONS OR THE ADEQUACY OF THE PLATFORM AND EXPRESSLY DISCLAIM LIABILITY FOR ERRORS OR OMISSIONS IN THE COMMUNICATIONS. NO WARRANTY OF ANY KIND, EXPRESS, IMPLIED OR STATUTORY, INCLUDING ANY WARRANTY OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, NON-INFRINGEMENT OF THIRD PARTY RIGHTS OR FREEDOM FROM VIRUSES

OR OTHER CODE DEFECTS IS MADE BY THE INDEMNITEES IN CONNECTION WITH THE COMMUNICATIONS OR THE PLATFORM. IN NO EVENT SHALL THE INDEMNITEES HAVE ANY LIABILITY TO ANY LENDER OR ANY OTHER PERSON FOR DAMAGES OF ANY KIND, WHETHER OR NOT BASED ON STRICT LIABILITY AND INCLUDING DIRECT OR INDIRECT, SPECIAL, INCIDENTAL OR CONSEQUENTIAL DAMAGES, LOSSES OR EXPENSES (WHETHER IN TORT, CONTRACT OR OTHERWISE) ARISING OUT OF ADMINISTRATIVE AGENT’S TRANSMISSION OF COMMUNICATIONS THROUGH THE INTERNET, EXCEPT TO THE EXTENT THE LIABILITY OF ANY INDEMNITEES IS FOUND IN A FINAL, NONAPPEALABLE ORDER BY A COURT OF COMPETENT JURISDICTION TO HAVE RESULTED PRIMARILY FROM SUCH INDEMNITEE’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

(d) Delivery Via Platform. Administrative Agent agrees that the receipt of the Communications by Administrative Agent at its electronic mail address set forth in Appendix B shall constitute effective delivery of the Communications to Administrative Agent for purposes of the Credit Documents. Each Lender agrees that receipt of notice to it (as provided in the next sentence) specifying that the Communications have been posted to the Platform shall constitute effective delivery of the Communications to such Lender for purposes of the Credit Documents. Each Lender agrees to notify Administrative Agent in writing (including by electronic communication) from time to time of such Lender’s electronic mail address to which the foregoing notice may be sent by electronic transmission and that the foregoing notice may be sent to such electronic mail address.

(e) No Prejudice to Notice Rights. Nothing herein shall prejudice the right of Administrative Agent or any Lender to give any notice or other communication pursuant to any Credit Document in any other manner specified in such Credit Document.

9.10 Proofs of Claim. The Lenders and Borrower hereby agree that after the occurrence of an Event of Default pursuant to Sections 8.1(f) or (g), in case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding relative to any Credit Party, Administrative Agent (irrespective of whether the principal of any Loan shall then be due and payable as herein expressed or by declaration or otherwise and irrespective of whether Administrative Agent shall have made any demand on any of Borrower or any of the Guarantors) shall be entitled and empowered, by intervention in such proceeding or otherwise:

(a) to file and prove a claim for the whole amount of principal and interest owing and unpaid in respect of the Loans and any other Obligations that are owing and unpaid and to file such other papers or documents as may be necessary or advisable in order to have the claims of the Lenders, Administrative Agent (including any claim for the reasonable compensation, expenses, disbursements and advances of the Lenders, Administrative Agent and their agents and counsel and all other amounts due Lenders, Administrative Agent and other agents hereunder) allowed in such judicial proceeding; and

(b) to collect and receive any moneys or other property payable or deliverable on any such claims and to distribute the same; and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Lender to make such payments to Administrative Agent and, in the event that Administrative Agent shall consent to the making of such payments directly to the Lenders, to pay to Administrative Agent any amount due for the reasonable compensation, expenses, disbursements and advances of Administrative Agent and its agents and counsel, and any other amounts due Administrative Agent and other agents hereunder. Nothing herein contained shall be deemed to authorize Administrative Agent to authorize or consent to or accept or adopt on behalf of any Lender any plan of reorganization, arrangement, adjustment or composition affecting the Obligations or the rights of any Lenders or to authorize Administrative Agent to vote in respect of the claim of any Lender in any such proceeding. Further, nothing contained in this Section 9.10

shall affect or preclude the ability of any Lender to (i) file and prove such a claim in the event that Administrative Agent has not acted within ten (10) days prior to any applicable bar date and (ii) require an amendment of the proof of claim to accurately reflect such Lender’s outstanding Obligations.

9.11 Swap Agreement Fees. Administrative Agent and its Affiliates shall not charge a fee greater than $1.00 per barrel of oil and $0.10 per Mcf of natural gas for any sale, termination, execution, amendment or modification of any Swap Agreement.

10.1 Notices. Unless otherwise specifically provided herein, any notice or other communication herein required or permitted to be given to a Credit Party, or Administrative Agent, shall be sent to such Person’s address as set forth on Appendix B or in the other relevant Credit Document, and in the case of any Lender, the address as indicated on Appendix B or otherwise indicated to Administrative Agent in writing. Each notice hereunder shall be in writing and may be personally served, telexed or sent by telefacsimile or United States mail or courier service and shall be deemed to have been given when delivered in person or by courier service and signed for against receipt thereof, upon receipt of telefacsimile or telex, or three Business Days after depositing it in the United States mail with postage prepaid and properly addressed; provided, no notice to Administrative Agent shall be effective until received by Administrative Agent. Any approval by a Lender or Administrative Agent under this Agreement may be given by e-mail, which shall be effective on the date it is delivered.

10.2 Expenses. Whether or not the transactions contemplated hereby shall be consummated, Borrower agrees to pay promptly within ten (10) days after written demand therefor, (a) all the actual and reasonable costs and expenses of preparation of the Credit Documents and any consents, amendments, waivers or other modifications thereto; (b) the reasonable fees, expenses and disbursements of counsel to Administrative Agent (including allocated costs of internal counsel) in connection with the negotiation, preparation, execution and administration of the Credit Documents and any consents, amendments, waivers or other modifications thereto and any other documents or matters requested by any Credit Party; (c) all reasonable actual costs and expenses of creating and perfecting Liens in favor of Administrative Agent, for the benefit of Secured Parties pursuant hereto, including filing and recording fees, expenses and amounts owed pursuant to Section 2.14(c) and (d), search fees, title insurance premiums and fees, expenses and disbursements of counsel to Administrative Agent and of counsel providing any opinions that Administrative Agent or Required Lenders may request in respect of the Collateral or the Liens created pursuant to the Collateral Documents; (d) all the actual costs and fees, expenses and disbursements of any auditors, accountants, consultants or appraisers whether internal or external; (e) all reasonable actual costs and expenses (including the fees, expenses and disbursements of counsel (including allocated costs of internal counsel) and of any appraisers, consultants, advisors and agents employed or retained by Administrative Agent and its counsel) in connection with the administration of this facility, including preservation of any of the Collateral; (f) all other reasonable actual costs and expenses incurred by Administrative Agent in connection with the syndication of the Loans and Commitments and the negotiation, preparation and execution of the Credit Documents and any consents, amendments, waivers or other modifications thereto and the transactions contemplated thereby; and (g) after the occurrence of a Default or an Event of Default, all costs and expenses, including attorneys’ fees (including allocated costs of internal counsel) and costs of settlement, incurred by Administrative Agent and Lenders in enforcing any Obligations of or in collecting any payments due from any Credit Party hereunder or under the other Credit Documents by reason of such Default or Event of Default (including in connection with the sale of, collection from, or other realization upon any of the Collateral or the enforcement of the Guaranty Agreement) or in connection with any refinancing or restructuring of the credit arrangements provided hereunder in the nature of a “work out” or pursuant to any insolvency or bankruptcy cases or proceedings.

(a) In addition to the payment of expenses pursuant to Section 10.2, whether or not the transactions contemplated hereby shall be consummated, each Credit Party agrees to defend (subject to Indemnitees’ selection of counsel), indemnify, pay and hold harmless, Administrative Agent and each Lender, their Affiliates and their respective officers, partners, directors, trustees, employees, representatives and agents of Administrative Agent and each Lender (each, an “Indemnitee”), from and against any and all Indemnified Liabilities, IN ALL CASES, WHETHER OR NOT CAUSED BY OR ARISING, IN WHOLE OR IN PART, OUT OF THE COMPARATIVE, CONTRIBUTORY, OR SOLE NEGLIGENCE OF ADMINISTRATIVE AGENT, ANY LENDER OR ANY AFFILIATE OF ADMINISTRATIVE AGENT OR ANY LENDER; provided, no Credit Party shall have any obligation to any Indemnitee hereunder with respect to any Indemnified Liabilities to the extent such Indemnified Liabilities arise from the gross negligence or willful misconduct of that Indemnitee, as determined by a court of competent jurisdiction in a final, nonappealable order. To the extent that the undertakings to defend, indemnify, pay and hold harmless set forth in this Section 10.3 may be unenforceable in whole or in part because they are violative of any law or public policy, the applicable Credit Party shall contribute the maximum portion that it is permitted to pay and satisfy under applicable law to the payment and satisfaction of all Indemnified Liabilities incurred by Indemnitees or any of them. WITHOUT LIMITATION OF THE FOREGOING, IT IS THE INTENTION OF EACH CREDIT PARTY AND EACH CREDIT PARTY AGREES THAT THE FOREGOING INDEMNITIES SHALL APPLY TO EACH INDEMNITEE WITH RESPECT TO LOSSES, CLAIMS, DAMAGES, PENALTIES, LIABILITIES AND RELATED EXPENSES (INCLUDING WITHOUT LIMITATION, ALL EXPENSES OF LITIGATION OR PREPARATION THEREFOR), WHICH IN WHOLE OR IN PART ARE CAUSED BY OR ARISE OUT OF THE NEGLIGENCE OF SUCH (AND/OR ANY OTHER) INDEMNITEE.

(b) To the extent permitted by applicable law, no Credit Party shall assert, and each Credit Party hereby waives, any claim against the Lenders, Administrative Agent and their respective Affiliates, directors, employees, attorneys or agents, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) (whether or not the claim therefor is based on contract, tort or duty imposed by any applicable legal requirement) arising out of, in connection with, as a result of, or in any way related to, this Agreement or any Credit Document or any agreement or instrument contemplated hereby or thereby or referred to herein or therein, the transactions contemplated hereby or thereby, any Loan or the use of the proceeds thereof or any act or omission or event occurring in connection therewith, and each Credit Party hereby waives, releases and agrees not to sue upon any such claim or any such damages, whether or not accrued and whether or not known or suspected to exist in its favor.

10.4 Set Off. In addition to any rights now or hereafter granted under applicable law and not by way of limitation of any such rights, upon the occurrence of any Event of Default each Lender and its respective Affiliates is hereby authorized by each Credit Party at any time or from time to time subject to the consent of Administrative Agent, without notice to any Credit Party or to any other Person (other than Administrative Agent), any such notice being hereby expressly waived, to set off and to appropriate and to apply any and all deposits (general or special, including Indebtedness evidenced by certificates of deposit, whether matured or unmatured, but not including trust accounts (in whatever currency)) and any other Indebtedness at any time held or owing by such Lender to or for the credit or the account of any Credit Party (in whatever currency) against and on account of the obligations and liabilities of any Credit Party to such Lender hereunder, and under the other Credit Documents, including all claims of any nature

or description arising out of or connected hereto or with any other Credit Document, irrespective of whether or not (a) such Lender shall have made any demand hereunder, (b) the principal of or the interest on the Loans or any other amounts due hereunder shall have become due and payable pursuant to Article II and although such obligations and liabilities, or any of them, may be contingent or unmatured or (c) such obligation or liability is owed to a branch or office of such Lender different from the branch or office holding such deposit or obligation or such Indebtedness.

(a) Required Lenders’ Consent. Subject to Sections 10.5(b) and 10.5(c), no amendment, modification, termination or waiver of any provision of the Credit Documents, or consent to any departure by any Credit Party therefrom, shall in any event be effective without the written concurrence of (i) in the case of this Agreement, Administrative Agent and the Required Lenders or (ii) in the case of any other Credit Document, Administrative Agent and, if the Required Lenders are party thereto, Administrative Agent, with the consent of the Required Lenders.

(b) Affected Lenders’ Consent. Without the written consent of each Lender (other than a Defaulting Lender) that would be affected thereby, no amendment, modification, termination, or consent shall be effective if the effect thereof would:

(C) reduce the rate of interest on any Loan of such Lender (other than any amendment to the definition of “Default Rate,” which change may be effected by consent of the Required Lenders, and any waiver of any increase in the interest rate applicable to any Loan pursuant to Section 2.6) or any fee payable hereunder;

(E) amend, modify, terminate or waive any provision of this Section 10.5(b) or Section 10.5(c);

(G) release any of the Collateral not permitted to be transferred pursuant to Section 6.7 or any of the Guarantors from the Guaranty Agreement or the Pledge and Security Agreement, except as expressly provided in the Credit Documents; or

(H) consent to the assignment or transfer by any Credit Party of any of its rights and obligations under any Credit Document.

(c) Other Consents. No amendment, modification, termination or waiver of any provision of the Credit Documents, or consent to any departure by any Credit Party therefrom, shall:

(A) increase the Commitment of any Lender over the amount thereof then in effect without the consent of such Lender; provided, no amendment, modification or waiver of any condition precedent, covenant, Default or Event of Default shall constitute an increase in the Commitment of any Lender; or

(B) amend, modify, terminate or waive any provision of Article IX as the same applies to Administrative Agent, or any other provision hereof as the same applies to the rights or obligations of Administrative Agent, in each case without the consent of Administrative Agent.

Notwithstanding anything to the contrary herein, no Defaulting Lender shall have any right to approve or disapprove any amendment, modification, waiver or consent hereunder, except that the Commitment of such Lender may not be increased or extended without the consent of such Lender.

(d) Execution of Amendments, etc. Administrative Agent may, but shall have no obligation to, with the concurrence of any Lender, execute amendments, modifications, waivers or consents on behalf of such Lender. Any waiver or consent shall be effective only in the specific instance and for the specific purpose for which it was given. No notice to or demand on any Credit Party in any case shall entitle any Credit Party to any other or further notice or demand in similar or other circumstances. Any amendment, modification, termination, waiver or consent effected in accordance with this Section 10.5 shall be binding upon each Lender at the time outstanding, each future Lender and, if signed by a Credit Party, on such Credit Party.

(a) Generally. This Agreement shall be binding upon the parties hereto and their respective successors and assigns and shall inure to the benefit of the parties hereto and the successors and assigns of Lenders. No Credit Party’s rights or obligations hereunder nor any interest therein may be assigned or delegated by any Credit Party without the prior written consent of all Lenders (and any attempted assignment or transfer by any Credit Party without such consent shall be null and void). Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby and, to the extent expressly contemplated hereby, Affiliates of Administrative Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b) Register. Borrower, Administrative Agent and Lenders shall deem and treat the Persons listed as Lenders in the Register as the holders and owners of the corresponding Commitments and Loans listed therein for all purposes hereof, and no assignment or transfer of any such Commitment or Loan shall be effective, in each case, unless and until an Assignment Agreement effecting the assignment or transfer thereof shall have been delivered to and accepted by Administrative Agent and recorded in the Register as provided in Section 10.6(e). Prior to such recordation, all amounts owed with respect to the applicable Commitment or Loan shall be owed to the Lender listed in the Register as the owner thereof, and any request, authority or consent of any Person who, at the time of making such request or giving such authority or consent, is listed in the Register as a Lender shall be conclusive and binding on any subsequent holder, assignee or transferee of the corresponding Commitments or Loans. Solely for the purposes of maintaining the Register and for tax purposes only Administrative Agent shall be deemed to be acting on behalf of the Credit Parties.

(c) Right to Assign. Each Lender shall have the right at any time to sell, assign or transfer all or a portion of its rights and obligations under this Agreement, including all or a portion of its Commitment or Loans owing to it or other Obligations (provided, however, that each such assignment shall be of a uniform, and not varying, percentage of all rights and obligations under and in respect of any Loan and any related Commitments):

(A) to any Person meeting the criteria of clause (a) of the definition of the term of “Eligible Assignee” upon the giving of notice to Borrower and Administrative Agent; and

(B) to any Person otherwise constituting an Eligible Assignee with the consent of Administrative Agent and, so long as no Default or Event of Default has occurred and is continuing, Borrower (such consent of Borrower not to be unreasonably withheld or delayed); provided, that (i) except in the case of an assignment of all of a Lender’s Commitments and Loans, such assigning Lender shall retain a minimum of $1,000,000 in Commitments and (ii), each such assignment pursuant to this Section 10.6(c)(B) shall be in an aggregate amount of not less than (A) $1,000,000 (or such lesser amount as may be agreed to by Borrower and Administrative Agent or as shall constitute the aggregate amount of the Commitments and Loans of the assigning Lender) with respect to the assignment of the Commitments and Loans and (B) $1,000,000 (or such lesser amount as may be agreed to by Borrower and Administrative Agent or as shall constitute the aggregate amount of the Loans of the assigning Lender) with respect to the assignment of Loans.

(d) Mechanics. The assigning Lender and the assignee thereof shall execute and deliver to Administrative Agent an Assignment Agreement, together with such forms, certificates or other evidence, if any, with respect to United States federal income tax withholding matters as the assignee under such Assignment Agreement may be required to deliver to Administrative Agent pursuant to Section 2.14(e).

(e) Notice of Assignment. Upon its receipt and acceptance of a duly executed and completed Assignment Agreement, any forms, certificates or other evidence required by this Agreement in connection therewith, Administrative Agent shall record the information contained in such Assignment Agreement in the Register, shall give prompt notice thereof to Borrower and shall maintain a copy of such Assignment Agreement.

(f) Representations and Warranties of Assignee. Each Lender, upon execution and delivery hereof or upon executing and delivering an Assignment Agreement, as the case may be, represents and warrants as of the Closing Date or as of the applicable Effective Date (as defined in the applicable Assignment Agreement) that (i) it is an Eligible Assignee; (ii) it has experience and expertise in the making of or investing in commitments or loans such as the applicable Commitments or Loans, as the case may be; and (iii) it will make or invest in, as the case may be, its Commitments or Loans for its own account in the ordinary course of its business and without a view to distribution of such Commitments or Loans within the meaning of the Securities Act or the Exchange Act or other federal securities laws (it being understood that, subject to the provisions of this Section 10.6, the disposition of such Commitments or Loans or any interests therein shall at all times remain within its exclusive control).

(g) Effect of Assignment. Subject to the terms and conditions of this Section 10.6, as of the “Effective Date” specified in the applicable Assignment Agreement: (i) the assignee thereunder shall have the rights and obligations of a “Lender” hereunder to the extent such rights and obligations hereunder have been assigned to it pursuant to such Assignment Agreement and shall thereafter be a party hereto and a “Lender” for all purposes hereof; (ii) the assigning Lender thereunder shall, to the extent that rights and obligations hereunder have been assigned thereby pursuant to such Assignment Agreement, relinquish its rights (other than any rights which survive the termination hereof under Section 10.8) and be released from its obligations hereunder (and, in the case of an Assignment Agreement covering all or the remaining portion of an assigning Lender’s rights and obligations hereunder, such Lender shall cease to be a party hereto; provided, anything contained in any of the Credit Documents to the contrary notwithstanding, such assigning Lender shall continue to be entitled to the benefit of all indemnities

hereunder as specified herein with respect to matters arising out of the prior involvement of such assigning Lender as a Lender hereunder); (iii) the Commitments shall be modified to reflect the Commitment of such assignee and any Commitment of such assigning Lender, if any; and (iv) if any such assignment occurs after the issuance of any Note hereunder, the assigning Lender shall, upon the effectiveness of such assignment or as promptly thereafter as practicable, surrender its applicable Notes to Administrative Agent for cancellation, and thereupon Borrower shall issue and deliver new Notes, if so requested by the assignee and/or assigning Lender, to such assignee and/or to such assigning Lender, with appropriate insertions, to reflect the new Commitments and/or outstanding Loans of the assignee and/or the assigning Lender.

(h) Participations. Each Lender shall have the right at any time to sell one or more participations to any Person (other than Borrower or any of its respective Affiliates) in all or any part of its Commitments, Loans or in any other Obligation. The holder of any such participation (a “Participant”), other than an Affiliate of the Lender granting such participation, shall not be entitled to require such Lender to take or omit to take any action hereunder except with respect to any amendment, modification or waiver that would (i) extend the final scheduled maturity of any Loan or Note in which such Participant is participating, or reduce the rate or extend the time of payment of interest or fees thereon (except any amendment to the definition of “Default Rate” or in connection with a waiver of applicability of any post default increase in interest rates) or reduce the principal amount thereof, or increase the amount of the Participant’s participation over the amount thereof then in effect (it being understood that a waiver of any Default or Event of Default or of a mandatory reduction in the Commitment shall not constitute a change in the terms of such participation, and that an increase in any Commitment or Loan shall be permitted without the consent of any Participant if the Participant’s participation is not increased as a result thereof), (ii) consent to the assignment or transfer by any Credit Party of any of its rights and obligations under this Agreement, or (iii) release all or substantially all of the Collateral under the Collateral Documents or all or substantially all of the Guarantors from the Guaranty Agreement or the Pledge and Security Agreement (in each case, except as expressly provided in the Credit Documents) supporting the Loans hereunder in which such Participant is participating. Borrower agrees that each Participant shall be entitled, through the participating Lender, to the benefits of Sections 2.13 and 2.14 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to clause (c) of this Section (subject to the requirements and limitations of those Sections); provided, a Participant shall not be entitled to receive any greater payment under Section 2.13 or 2.14 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with Borrower’s prior written consent or to the entitlement to a greater payment results from a change in laws after the date such Participant became a Participant. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 10.4 as though it were a Lender, provided such Participant agrees to be subject to Section 2.12 as though it were a Lender. Each Lender that sells a participation shall, acting solely for this purpose as an agent of Borrower, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Loans or other obligations under the Credit Documents (the “Participant Register”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register (including the identity of any Participant or any information relating to a Participant’s interest in any commitments, loans, letters of credit or its other obligations under any Credit Document) to any Person except to the extent that such disclosure is necessary to establish that such commitment, loan, letter of credit or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. For the avoidance of doubt, Administrative Agent (in its capacity as Administrative Agent) shall have no responsibility for maintaining a Participant Register.

(i) Certain Other Assignments. In addition to any other assignment permitted pursuant to this Section 10.6, any Lender may assign, pledge and/or grant a security interest in, all or any portion of its Loans, the other Obligations owed by or to such Lender, and its Notes (if any) to secure obligations of such Lender including, but not limited to, any Federal Reserve Bank as collateral security pursuant to Regulation A of the Board of Governors of the Federal Reserve System and any operating circular issued by such Federal Reserve Bank; provided, no Lender, as between Borrower and such Lender, shall be relieved of any of its obligations hereunder as a result of any such assignment and pledge, and provided, further, in no event shall the applicable Federal Reserve Bank, pledgee or trustee be considered to be a “Lender” or be entitled to require the assigning Lender to take or omit to take any action hereunder.

10.7 Survival of Representations, Warranties and Agreements. All representations, warranties and agreements made herein shall survive the execution and delivery hereof and the making of any Loans. Notwithstanding anything herein or implied by law to the contrary, the agreements of each Credit Party set forth in Sections 2.13, 2.14, 10.2, and 10.3 and the agreements of Lenders set forth in Sections 9.3(b) and 9.6 shall survive the payment of the Loans and the reimbursement of any amounts drawn thereunder, and the termination hereof.

10.8 No Waiver; Remedies Cumulative. No failure or delay on the part of Administrative Agent or any Lender in the exercise of any power, right or privilege hereunder or under any other Credit Document shall impair such power, right or privilege or be construed to be a waiver of any default or acquiescence therein, nor shall any single or partial exercise of any such power, right or privilege preclude other or further exercise thereof or of any other power, right or privilege. The rights, powers and remedies given to Administrative Agent and each Lender hereby are cumulative and shall be in addition to and independent of all rights, powers and remedies existing by virtue of any statute or rule of law or in any of the other Credit Documents or any of the Swap Agreements. Any forbearance or failure to exercise, and any delay in exercising, any right, power or remedy hereunder shall not impair any such right, power or remedy or be construed to be a waiver thereof, nor shall it preclude the further exercise of any such right, power or remedy.

10.9 Marshaling; Payments Set Aside. Neither Administrative Agent nor any Lender shall be under any obligation to marshal any assets in favor of any Credit Party or any other Person or against or in payment of any or all of the Obligations. To the extent that any Credit Party makes a payment or payments to Administrative Agent or the Lenders (or to Administrative Agent, on behalf of the Lenders), or Administrative Agent or the Lenders enforce any security interests or exercise their rights of setoff, and such payment or payments or the proceeds of such enforcement or setoff or any part thereof are subsequently invalidated, declared to be fraudulent or preferential, set aside and/or required to be repaid to a trustee, receiver or any other party under any bankruptcy law, any other state or federal law, common law or any equitable cause, then, to the extent of such recovery, the obligation or part thereof originally intended to be satisfied, and all Liens, rights and remedies therefor or related thereto, shall be revived and continued in full force and effect as if such payment or payments had not been made or such enforcement or setoff had not occurred.

10.10 Severability. In case any provision in or obligation hereunder or any Note or other Credit Document shall be invalid, illegal or unenforceable in any jurisdiction, the validity, legality and enforceability of the remaining provisions or obligations, or of such provision or obligation in any other jurisdiction, shall not in any way be affected or impaired thereby.

10.11 Obligations Several; Independent Nature of Lenders’ Rights. The obligations of Lenders hereunder are several and no Lender shall be responsible for the obligations or Commitment of any other Lender hereunder. Nothing contained herein or in any other Credit Document, and no action taken by Lenders pursuant hereto or thereto, shall be deemed to constitute Lenders as a partnership, an

association, a joint venture or any other kind of entity. The amounts payable at any time hereunder to each Lender shall be a separate and independent debt, and each Lender shall be entitled to protect and enforce its rights arising out hereof and it shall not be necessary for any other Lender to be joined as an additional party in any proceeding for such purpose.

10.12 Headings. Section headings herein are included herein for convenience of reference only and shall not constitute a part hereof for any other purpose or be given any substantive effect.

10.13 APPLICABLE LAW. THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND SHALL BE CONSTRUED AND ENFORCED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

(a) Arbitration. Any dispute shall be resolved by binding, nonappealable arbitration (except as set forth in (e) below) in accordance with the terms of this Agreement. A “dispute” shall mean any action, dispute, claim or controversy of any kind, whether in contract or tort, statutory or common law, legal or equitable, now existing or hereafter arising under or in connection with, or in any way pertaining to, any of the Credit Documents, or any past, present or future extensions of credit and other activities, transactions or obligations of any kind related directly or indirectly to any of the Credit Documents, including without limitation, any of the foregoing arising in connection with the exercise of any self-help, ancillary or other remedies pursuant to any of the Credit Documents. Any party may by summary proceedings bring an action in court to compel arbitration of a dispute. Any party who fails or refuses to submit to arbitration following a lawful demand by any other party shall bear all costs and expenses incurred by such other party in compelling arbitration of any dispute.

(b) Governing Rules. Arbitration proceedings shall be administered by the American Arbitration Association (“AAA”) or such other administrator as the parties shall mutually agree upon in accordance with the AAA commercial arbitration rules. All disputes submitted to arbitration shall be resolved in accordance with the Federal Arbitration Act (Title 9 of the United States Code), notwithstanding any conflicting choice of law provision in any of the Credit Documents. The arbitration shall be conducted at a location in New York selected by the AAA or other administrator. If there is any inconsistency between the terms hereof and any such rules, the terms and procedures set forth herein shall control. All statutes of limitation applicable to any dispute shall apply to any arbitration proceeding. All discovery activities shall be expressly limited to matters directly relevant to the dispute being arbitrated. Judgment upon any award rendered in an arbitration may be entered in any court having jurisdiction; provided however, that nothing contained herein shall be deemed to be a waiver by any party that is a Lender of the protections afforded to it under 12 U.S.C. 91 or any similar applicable state law.

(c) No Waiver; Provisional Remedies, Self-Help and Foreclosure. No provision hereof shall limit the right of any party to exercise self-help remedies such as set-off, foreclosure against or sale of any real or personal property collateral or security, or to obtain provisional or ancillary remedies, including without limitation injunctive relief, sequestration, attachment, garnishment or the appointment of a receiver, from a court of competent jurisdiction before, after or during the pendency of any arbitration or other proceeding. The exercise of any such remedy shall not waive the right of any party to compel arbitration hereunder. All statutes of limitations and defenses based upon passage of time applicable to any dispute (including any counterclaim or setoff) shall be interrupted by the filing of the arbitration and suspended while the arbitration is pending.

(d) Arbitrator Qualifications and Powers; Awards. Arbitrators must be active members of the New York State Bar for a minimum of fifteen (15) years with expertise in the substantive laws applicable to the subject matter of the dispute. Arbitrators are empowered to resolve disputes by summary rulings in response to motions filed prior to the final arbitration hearing. Arbitrators (i) shall resolve all disputes in accordance with the substantive law of the state of New York, (ii) may grant any remedy or relief that a court of the state of New York could order or grant within the scope hereof and such ancillary relief as is necessary to make effective any award, and (iii) shall have the power to award recovery of all costs and fees, to impose sanctions and to take such other actions as they deem necessary to the same extent a judge could pursuant to the Federal Rules of Civil Procedure, the New York Rules of Civil Procedure or other applicable law. Any dispute in which the amount in controversy is $5,000,000 or less shall be decided by a single arbitrator who shall not render an award of greater than $5,000,000 (including damages, costs, fees and expenses). By submission to a single arbitrator, each party expressly waives any right or claim to recover more than $5,000,000. Any dispute in which the amount in controversy exceeds $5,000,000 shall be decided by majority vote of a panel of three arbitrators; provided however, that all three arbitrators must actively participate in all hearings and deliberations. Any award by the arbitrator or the arbitrators, as the case may be, shall be in writing and set forth the reasons for the award and shall include an award for costs of the prevailing party.

(e) Selection of Arbitrators. If the dispute requires a single arbitrator, such arbitrator may be selected by mutual agreement of the parties, or, if the parties are unable to agree on an arbitrator within thirty (30) days from the delivery of notice of the dispute and election to initiate arbitration (the “Arbitration Election”), the arbitrator shall be selected by the AAA office in New York, New York with due regard for the criteria set forth above and input from the parties. If the dispute requires three arbitrators, then each party shall select a qualified arbitrator within thirty (30) days of delivery of Arbitration Election and provide prompt notice to the other party of its selection. If either party fails for any reason to name an arbitrator within the thirty (30) day period, the arbitrator for such party’s account shall be selected by the AAA office in New York, New York within sixty (60) days from the delivery of the Arbitration Election, with due regard for the selection criteria set forth below and input from the parties. The two arbitrators so chosen shall select a third arbitrator within thirty (30) days after the selection of the second arbitrator. If the two arbitrators are unable to agree on a third arbitrator within thirty (30) days from appointment of the second arbitrator, then a third arbitrator shall be selected by the AAA office in New York, New York, with due regard for the selection criteria set forth above and input from the parties and the two other arbitrators. The AAA shall select the third arbitrator not later than thirty (60) days from appointment of the second arbitrator. In the event AAA should fail to select the third arbitrator within sixty (60) days from the appointment of the second arbitrator, then either Party may petition the Chief Judge of the United States District Court for the Southern District of New York to select the third arbitrator, with due regard for the selection criteria set forth above and input from the parties and the two other arbitrators.

(f) Miscellaneous. To the maximum extent practicable, the AAA, the arbitrators and the parties shall take all action required to conclude any arbitration proceeding within 180 days of the selection of the arbitrator, in the case of a sole arbitrator, or the selection of the third arbitrator, in the case of three arbitrators. No arbitrator or other party to an arbitration proceeding may disclose the existence, content or results thereof, except for disclosures of information by a party required in the ordinary course of its business, by applicable law or regulation, or to the extent necessary to exercise any judicial review rights set forth herein. If more than one agreement for arbitration by or between the parties potentially applies to a dispute, the arbitration provision most directly related to the Credit Documents or the subject matter of the dispute shall control. This arbitration provision shall survive termination, amendment or expiration of any of the Credit Documents or any relationship between the parties.

10.15 WAIVER OF JURY TRIAL. EACH OF THE PARTIES HERETO HEREBY AGREES TO WAIVE ITS RESPECTIVE RIGHTS TO A JURY TRIAL OF ANY CLAIM OR CAUSE OF ACTION BASED UPON OR ARISING HEREUNDER OR UNDER ANY OF THE OTHER CREDIT DOCUMENTS OR ANY DEALINGS BETWEEN THEM RELATING TO THE SUBJECT MATTER OF THIS LOAN TRANSACTION OR THE LENDER/BORROWER RELATIONSHIP THAT IS BEING ESTABLISHED. THE SCOPE OF THIS WAIVER IS INTENDED TO BE ALL ENCOMPASSING OF ANY AND ALL DISPUTES THAT MAY BE FILED IN ANY COURT AND THAT RELATE TO THE SUBJECT MATTER OF THIS TRANSACTION, INCLUDING CONTRACT CLAIMS, TORT CLAIMS, BREACH OF DUTY CLAIMS AND ALL OTHER COMMON LAW AND STATUTORY CLAIMS. EACH PARTY HERETO ACKNOWLEDGES THAT THIS WAIVER IS A MATERIAL INDUCEMENT TO ENTER INTO A BUSINESS RELATIONSHIP, THAT EACH HAS ALREADY RELIED ON THIS WAIVER IN ENTERING INTO THIS AGREEMENT, AND THAT EACH WILL CONTINUE TO RELY ON THIS WAIVER IN ITS RELATED FUTURE DEALINGS. EACH PARTY HERETO FURTHER WARRANTS AND REPRESENTS THAT IT HAS REVIEWED THIS WAIVER WITH ITS LEGAL COUNSEL AND THAT IT KNOWINGLY AND VOLUNTARILY WAIVES ITS JURY TRIAL RIGHTS FOLLOWING CONSULTATION WITH LEGAL COUNSEL. THIS WAIVER IS IRREVOCABLE, MEANING THAT IT MAY NOT BE MODIFIED EITHER ORALLY OR IN WRITING (OTHER THAN BY A MUTUAL WRITTEN WAIVER SPECIFICALLY REFERRING TO THIS SECTION 10.15 AND EXECUTED BY EACH OF THE PARTIES HERETO), AND THIS WAIVER SHALL APPLY TO ANY SUBSEQUENT AMENDMENTS, RENEWALS, SUPPLEMENTS OR MODIFICATIONS HERETO OR ANY OF THE OTHER CREDIT DOCUMENTS OR TO ANY OTHER DOCUMENTS OR AGREEMENTS RELATING TO THE LOANS MADE HEREUNDER. IN THE EVENT OF LITIGATION, THIS AGREEMENT MAY BE FILED AS A WRITTEN CONSENT TO A TRIAL BY THE COURT.

10.16 Confidentiality. Each Lender shall hold all non-public information regarding the Credit Parties and their businesses and obtained by such Lender pursuant to the requirements hereof in accordance with such Lender’s customary procedures for handling confidential information of such nature and shall only use such information in connection with the administration of its Loans hereunder and each ORI, it being understood and agreed by each Credit Party that, in any event, a Lender may make (i) disclosures of such information to Affiliates of such Lender and to their directors, officers, employees, agents and advisors (and to other persons authorized by a Lender or Administrative Agent to organize, present or disseminate such information in connection with disclosures otherwise made in accordance with this Section 10.16) (it being understood that the Persons to whom such disclosure is made, if not already subject to an obligation of confidentiality, will be informed of the confidential nature of such information and instructed to keep such information confidential), (ii) disclosures of such information reasonably required by any bona fide or potential assignee, transferee or participant in connection with the contemplated assignment, transfer or participation by such Lender of any Loans or any participations therein or by any direct or indirect contractual counterparties (or the professional advisors thereto) in Swap Agreements (provided, such assignees, transferees, or participants and such counterparties and advisors are advised of and agree to be bound by the provisions of this Section 10.16), (iii) disclosure to any rating agency when required by it, provided that, prior to any disclosure, such rating agency shall undertake in writing to preserve the confidentiality of any confidential information relating to the Credit Parties received by it from Administrative Agent or any Lender, (iv) disclosures to any Lender’s financing sources (including limited partners or shareholders), provided that prior to any disclosure, such financing source is informed of the confidential nature of the information and if not already subject to an obligation of confidentiality, agrees to be bound by the provisions of this Section 10.16), (v) disclosure of information which (A) becomes publicly available other than as a result of a breach of this Section 10.16 or (B) becomes available to Administrative Agent or any Lender on a non-confidential basis from a source other than a Credit Party, (vi) disclosures required or requested by any governmental agency or representative thereof or by the NAIC or pursuant to legal or judicial process and (vii) if an Event of

Default has occurred and is continuing disclosures of such information to the extent such Lenders may reasonably determine such delivery and disclosure to be necessary and appropriate in the enforcement or for the protection of the rights and remedies under this Agreement; provided, unless specifically prohibited by applicable law or court order, each Lender shall make reasonable efforts to notify Borrower of any request by any governmental agency or representative thereof (other than any such request in connection with any examination of the financial condition or other routine examination of such Lender by such governmental agency) for disclosure of any such non-public information prior to disclosure of such information. Notwithstanding the foregoing, on or after the Closing Date, Administrative Agent may, at its own expense, issue news releases and publish “tombstone” advertisements and other announcements relating to this transaction in newspapers, trade journals and other appropriate media.

10.17 Usury Savings Clause. Notwithstanding any other provision herein, the aggregate interest rate charged or agreed to be paid with respect to any of the Obligations, including all charges or fees in connection therewith deemed in the nature of interest under applicable law shall not exceed the Highest Lawful Rate. If the rate of interest (determined without regard to the preceding sentence) under this Agreement at any time exceeds the Highest Lawful Rate, the outstanding amount of the Loans made hereunder shall bear interest at the Highest Lawful Rate until the total amount of interest due hereunder equals the amount of interest which would have been due hereunder if the stated rates of interest set forth in this Agreement had at all times been in effect. In addition, if when the Loans made hereunder are repaid in full the total interest due hereunder (taking into account the increase provided for above) is less than the total amount of interest which would have been due hereunder if the stated rates of interest set forth in this Agreement had at all times been in effect, then to the extent permitted by law, Borrower shall pay to Administrative Agent an amount equal to the difference between the amount of interest paid and the amount of interest which would have been paid if the Highest Lawful Rate had at all times been in effect. Notwithstanding the foregoing, it is the intention of Lenders and Borrower to conform strictly to any applicable usury laws. Accordingly, if any Lender contracts for, charges, or receives any consideration which constitutes interest in excess of the Highest Lawful Rate, then any such excess shall be cancelled automatically and, if previously paid, shall at such Lender’s option be applied to the outstanding amount of the Loans made hereunder or be refunded to Borrower. In determining whether the interest contracted for, charged, or received by Administrative Agent or a Lender exceeds the Highest Lawful Rate, such Person may, to the extent permitted by applicable law, (a) characterize any payment that is not principal as an expense, fee, or premium rather than interest, (b) exclude voluntary prepayments and the effects thereof, and (c) amortize, prorate, allocate, and spread in equal or unequal parts the total amount of interest, throughout the contemplated term of the Obligations hereunder.

10.18 Counterparts. This Agreement may be executed in any number of counterparts, each of which when so executed and delivered shall be deemed an original, but all such counterparts together shall constitute but one and the same instrument.

10.19 Effectiveness. This Agreement shall become effective upon the execution of a counterpart hereof by each of the parties hereto and receipt by Borrower and Administrative Agent of written or telephonic notification of such execution and authorization of delivery thereof.

10.20 Patriot Act. Each Lender and Administrative Agent (for itself and not on behalf of any Lender) hereby notifies Borrower that pursuant to the requirements of the Patriot Act, it is required to obtain, verify and record information that identifies Borrower, which information includes the name and address of Borrower and other information that will allow such Lender or Administrative Agent, as applicable, to identify Borrower in accordance with the Patriot Act.

10.21 Disclosure. Each Credit Party and each Lender hereby acknowledges and agrees that Administrative Agent and/or its Affiliates from time to time may hold investments in, and make other loans to, or have other relationships with any of the Credit Parties and their respective Affiliates.

10.22 Appointment for Perfection. Each Lender hereby appoints each other Lender as its agent for the purpose of perfecting Liens, for the benefit of Administrative Agent and the Lenders, in assets which, in accordance with Article 9 of the UCC or any other applicable law can be perfected only by possession. Should any Lender (other than Administrative Agent) obtain possession of any such Collateral, such Lender shall notify Administrative Agent thereof, and, promptly upon Administrative Agent’s request therefor shall deliver such Collateral to Administrative Agent or otherwise deal with such Collateral in accordance with Administrative Agent’s instructions.

10.23 Advertising and Publicity. No Credit Party shall issue or disseminate to the public (by advertisement, including without limitation any “tombstone” advertisement, press release or otherwise), submit for publication or otherwise cause or seek to publish any information describing the credit or other financial accommodations made available by Lenders pursuant to this Agreement and the other Credit Documents without the prior written consent of Administrative Agent. Nothing in the foregoing shall be construed to prohibit any Credit Party from making any submission or filing which it is required to make by applicable law or pursuant to judicial process; provided, that, (i) such filing or submission shall contain only such information as is necessary to comply with applicable law or judicial process and (ii) unless specifically prohibited by applicable law or court order, such Credit Party shall promptly notify Administrative Agent of the requirement to make such submission or filing and provide Administrative Agent with a copy thereof.

10.24 Performance on a Credit Party’s Behalf. If any Credit Party fails to pay any taxes, insurance premiums, expenses, attorneys’ fees or other amounts it is required to pay under any Credit Document, Administrative Agent may pay the same. Borrower shall immediately reimburse Administrative Agent for any such payments and each amount paid by Administrative Agent shall constitute an Obligation owed hereunder which is due and payable on the date such amount is paid by Administrative Agent.

10.25 Tax Provisions. Borrower, Administrative Agent and each Lender agree that (i) the Loans made on the Closing Date (the “Initial Loans”) and the related shares of the ORI conveyed in connection with such Initial Loans constitute “Investment Units” as that term is defined in section 1273(c)(2) of the Code, (ii) the “issue price” of a Lender’s Investment Unit as defined in section 1273(b)(2) of the Code is equal to the amount of such Lender’s Initial Loan, (iii) the fair market value of the ORI is $50,000, and (iv) the issue price of a Lender’s Initial Loan for purposes of computing interest accruals is equal to the amount of the Lender’s Initial Loan reduced by such Lender’s ORI Share. A Lender’s “ORI Share” means the amount which is equal to the fair market value of all ORIs, as set forth in (iii), above, multiplied by the percentage specified for such Lender in Part 2 of Appendix A. None of Borrower, Administrative Agent or Lenders shall take any position inconsistent with the foregoing on any report, return claim for refund or other filing for federal, state or other tax purposes unless all such parties agree otherwise or as otherwise may be required (to the satisfaction of all such parties, each in its reasonable discretion) by applicable law. All computations under this Section 10.25 shall be made by Administrative Agent and shall be provided to Borrower as necessary to enable Borrower to timely comply with its tax reporting obligations.

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first written above.

Pursuant to the Credit Agreement dated as of June 26, 2012 (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”) between Energy & Exploration Partners, LLC, a Delaware limited liability company, as the Borrower (the “Borrower”), Guggenheim Corporate Funding, LLC, as administrative agent (the “Administrative Agent”) for the lenders that are or become a party thereto (the “Lenders”), and such Lenders, the Borrower hereby requests an advance in the amount of $ on . Attached hereto is the information required to be provided with this request pursuant to the terms of Sections 2.1(b) and 3.2 of the Credit Agreement.

All capitalized terms not otherwise defined herein shall have the meanings specified in the Credit Agreement. The undersigned, being an Authorized Officer of the Borrower, DOES HEREBY CERTIFY to the Lenders and the Administrative Agent, to the extent not otherwise waived in accordance with Section 10.5 of the Credit Agreement, that:

1. After giving effect to the Loan requested hereunder, (i) the aggregate principal amount of all Loans advanced under the Agreement will not exceed the Borrowing Base in effect through such date, (ii) the Available Amount, without giving effect to this Loan is $ and (iii) after giving effect to this Loan, the Available Amount is $ .

2. As of the date of this Borrowing Request, the representations and warranties contained in the Credit Agreement and in the other Credit Documents are and will be true and correct in all material respects to the same extent as though made on the date hereof, except to the extent such representations and warranties specifically relate to an earlier date, in which case such representations and warranties are true and correct on and as of such earlier date.

3. As of the date of this Borrowing Request, no event has occurred and is continuing or would result from the consummation of the applicable Loan requested hereunder that would constitute an Event of Default or a Default.

The Administrative Agent or any Lender shall be entitled, but not obligated to, request and receive, prior to the making of any Loan hereunder, additional information confirming the satisfaction of any of the foregoing if, in the judgment of the Administrative Agent or such Lender, such request is warranted under the circumstances.

FOR VALUE RECEIVED, the undersigned, Energy & Exploration Partners, LLC, a Delaware limited liability company (“Maker”), promises to pay to the order of [Lender] (herein called “Payee”, which term shall herein in every instance refer to any owner or holder of this Note) the sum of [AMOUNT], or so much thereof as may be advanced to Maker by Payee from time to time, together with interest on the principal hereof outstanding until maturity, said principal and interest being payable in lawful money of the United States of America as more particularly provided in that certain Credit Agreement dated June 26, 2012, between Maker, Guggenheim Corporate Funding, LLC, as administrative agent (the “Administrative Agent”) for the lenders that are or become a party thereto (the “Lenders”) and the Lenders (as such may be amended or restated from time to time, the “Credit Agreement”). Capitalized terms used, but not otherwise defined, herein shall have the meaning given such terms in the Credit Agreement.

Maker may prepay this Note in whole or in part as provided in the Credit Agreement. All prepayments hereunder, whether designated as payments of principal or interest, shall be applied in accordance with the Credit Agreement.

Maker and any and all sureties, guarantors and endorsers of this Note and all other parties now or hereafter liable hereon, severally waive grace, demand, presentment for payment, protest, notice of any kind (including, but not limited to, notice of dishonor, notice of protest, notice of intention to accelerate and notice of acceleration) and diligence in collecting and bringing suit against any party hereto and agree (i) to all extensions and partial payments, with or without notice, before or after maturity, (ii) to any substitution, exchange or release of any security now or hereafter given for this Note, (iii) to the release of any party primarily or secondarily liable hereon, and (iv) that it will not be necessary for Payee, in order to enforce payment of this Note, to first institute or exhaust Payee’s remedies against Maker or any other party liable therefor or against any security for this Note.

If any sum payable under this Note or under the Credit Agreement is not paid when due (whether the same becomes due by acceleration or otherwise) and this Note is placed in the hands of an attorney for collection or enforcement of this Note or the Credit Agreement, or if this Note is collected through any legal proceedings, including, but not limited to suit, probate, insolvency or bankruptcy proceedings, Maker agrees to pay all reasonable out of pocket attorneys’ fees and all reasonable out of pocket expenses of collection and costs of court in accordance with the Credit Agreement.

Regardless of any provision contained in this Note or any other Credit Document executed or delivered in connection therewith, Payee shall never be deemed to have contracted for or be entitled to receive, collect or apply as interest on this Note (whether termed interest herein or deemed to be interest by judicial determination or operation of law), any amount in excess of the Highest Lawful Rate, and, in the event that Payee ever receives, collects or applies as interest any such excess, such amount which would be excessive interest shall be applied to the reduction of the unpaid principal balance of this Note, and, if the principal balance of this Note is paid in full, any remaining excess shall forthwith be paid to Maker. In determining whether or not the interest paid or payable under any specific contingency exceeds the Highest Lawful Rate, Maker and Payee shall, to the maximum extent permitted under applicable law, (a) characterize any non-principal payment (other than payments which are expressly designated as interest payments hereunder) as an expense or fee rather than as interest, (b) exclude voluntary pre-payments and the effect thereof, and (c) spread the total amount of interest throughout the entire contemplated term of this Note so that the interest rate is uniform throughout such term; provided that if this Note is paid and performed in full prior to the end of the full contemplated term hereof, and if the

interest received for the actual period of existence thereof exceeds the Highest Lawful Rate, if any, then Payee or any holder hereof shall refund to Maker the amount of such excess, or credit the amount of such excess against the aggregate unpaid principal balance of all advances made by Payee or any holder hereof under this Note at the time in question.

Maker warrants that this Note is executed solely for business or commercial purposes, other than agricultural purposes and warrants that it is not a consumer lending transaction primarily for personal, family or household purposes.

Any check, draft, money order or other instrument given in payment of all or any portion hereof may be accepted by Payee and handled in collection in the customary manner, but the same shall not constitute payment hereunder or diminish any rights of Payee except to the extent that actual cash proceeds of such instrument are unconditionally received by Payee.

Except to the extent required by federal law, this Note shall be governed by and construed under the laws of the State of New York.

The undersigned hereby certifies that he/she is the of Energy & Exploration Partners, LLC (the “Borrower”), and that as such he/she is authorized to execute this certificate on behalf of the Borrower.

With reference to the Credit Agreement dated as of June 26, 2012 (together with all amendments, restatements, supplements or other modifications thereto being the “Credit Agreement”) among the Borrower, Guggenheim Corporate Funding, LLC, as administrative agent (the “Administrative Agent”) for the lenders that are or become a party thereto (the “Lenders”), and such Lenders, the undersigned represents and warrants as follows (each capitalized term used herein having the same meaning given to it in the Credit Agreement unless otherwise specified):

(a) The representations and warranties of the Borrower contained in Article IV of the Credit Agreement and in the other Credit Documents and otherwise made in writing by or on behalf of the Borrower pursuant to the Credit Agreement and the other Credit Documents were true and correct when made, and are repeated at and as of the time of delivery hereof and are true and correct in all material respects at and as of the time of delivery hereof, except to the extent (i) such representations and warranties are expressly limited to an earlier date or (ii) the Lenders have expressly consented in writing to the contrary[, or (iii) set forth on Schedule I attached hereto].

(b) The Borrower has performed and complied with all agreements and conditions contained in the Credit Agreement and in the other Credit Documents required to be performed or complied with by it prior to or at the time of delivery hereof. [or specify non-performance/non-compliance and describe]

(c) Since 20 , no change has occurred, either in any case or in the aggregate, in the condition, financial or otherwise, of the Borrower or any Subsidiary which could reasonably be expected to have a Material Adverse Effect. [or specify event]

(d) There exists no Default or Event of Default. [or specify Default/Event of Default and describe]

This Assignment and Acceptance (this “Assignment and Acceptance”) is dated as of the Effective Date set forth below and is entered into by and between [the][each]¹ Assignor identified in item 1 below ([the][each, an] “Assignor”) and [the][each]² Assignee identified in item 2 below ([the][each, an] “Assignee”). [It is understood and agreed that the rights and obligations of [the Assignors][the Assignees]³ hereunder are several and not joint.]⁴ Capitalized terms used but not defined herein shall have the meanings given to them in the Credit Agreement identified below (as amended to date, the “Credit Agreement”), receipt of a copy of which is hereby acknowledged by [the][each] Assignee. The Standard Terms and Conditions set forth in Annex 1 attached hereto are hereby agreed to and incorporated herein by reference and made a part of this Assignment and Acceptance as if set forth herein in full.

For an agreed consideration, [the][each] Assignor hereby irrevocably sells and assigns to [the Assignee][the respective Assignees], and [the][each] Assignee hereby irrevocably purchases and assumes from [the Assignor][the respective Assignors], subject to and in accordance with the Standard Terms and Conditions and the Credit Agreement, as of the Effective Date inserted by the Administrative Agent as contemplated below (i) all of [the Assignor’s][the respective Assignors’] rights and obligations in [its capacity as a Lender][their respective capacities as Lenders] under the Credit Agreement and any other documents or instruments delivered pursuant thereto to the extent related to the amount and percentage interest identified below of all of such outstanding rights and obligations of [the Assignor][the respective Assignors] under the respective facilities identified below (including without limitation the Letters of Credit and guarantees included in such facilities) and (ii) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of [the Assignor (in its capacity as a Lender)][the respective Assignors (in their respective capacities as Lenders)] against any Person, whether known or unknown, arising under or in connection with the Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned by [the][any] Assignor to [the][any] Assignee pursuant to clauses (i) and (ii) above being referred to herein collectively as [the][an] “Assigned Interest”). Each such sale and assignment is without recourse to [the][any] Assignor and, except as expressly provided in this Assignment and Acceptance, without representation or warranty by [the][any] Assignor.

Effective Date: , 20 [TO BE INSERTED BY ADMINISTRATIVE AGENT AND WHICH SHALL BE THE EFFECTIVE DATE OF RECORDATION OF TRANSFER IN THE REGISTER THEREFOR.]

1.1 Assignor[s]. [The][Each] Assignor (a) represents and warrants that (i) it is the legal and beneficial owner of [the][the relevant] Assigned Interest, (ii) [the][such] Assigned Interest is free and clear of any lien, encumbrance or other adverse claim and (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Acceptance and to consummate the transactions contemplated hereby; and (b) assumes no responsibility with respect to (i) any statements, warranties or representations made in or in connection with the Credit Agreement or any other Loan Document, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any collateral thereunder, (iii) the financial condition of the Borrower, any of its Subsidiaries or Affiliates or any other Person obligated in respect of any Loan Document or (iv) the performance or observance by the Borrower, any of its Subsidiaries or Affiliates or any other Person of any of their respective obligations under any Loan Document.

1.2. Assignee[s]. [The][Each] Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Acceptance and to consummate the transactions contemplated hereby and to become a Lender under the Credit Agreement, (ii) it meets all the requirements to be an assignee under Section 10.6 of the Credit Agreement (subject to such consents, if any, as may be required under Section 10.6 of the Credit Agreement), (iii) from and after the Effective Date, it shall be bound by the provisions of the Credit Agreement as a Lender thereunder and, to the extent of [the][the relevant] Assigned Interest, shall have the obligations of a Lender thereunder, (iv) it is sophisticated with respect to decisions to acquire assets of the type represented by the Assigned Interest and either it, or the Person exercising discretion in making its decision to acquire the Assigned Interest, is experienced in acquiring assets of such type, (v) it has received a copy of the Credit Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements delivered pursuant to Section 5.1 thereof, as applicable, and such other documents and information as it deems appropriate to make its own credit analysis and decision to enter into this Assignment and Acceptance and to purchase [the][such] Assigned Interest, (vi) it has, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Assignment and Acceptance and to purchase [the][such] Assigned Interest, and (vii) if it is a Non-U.S. Lender, attached to the Assignment and Acceptance is any documentation required to be delivered by it pursuant to the terms of the Credit Agreement, duly completed and executed by [the][such] Assignee; and (b) agrees that (i) it will, independently and without reliance upon the Administrative Agent, [the][any] Assignor or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.

2. Payments. From and after the Effective Date, the Administrative Agent shall make all payments in respect of [the][each] Assigned Interest (including payments of principal, interest, fees and other amounts) to [the][the relevant] Assignee whether such amounts have accrued prior to, on or after the Effective Date. The Assignor[s] and the Assignee[s] shall make all appropriate adjustments in payments by the Administrative Agent for periods prior to the Effective Date or with respect to the making of this assignment directly between themselves.

3. General Provisions. This Assignment and Acceptance shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns. This Assignment and Acceptance may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Assignment and Acceptance by electronic transmission shall be effective as delivery of a manually executed counterpart of this Assignment and Acceptance. This Assignment and Acceptance shall be governed by, and construed in accordance with, the law of the State of New York.

I am the of Energy & Exploration Partners, LLC, a Delaware limited liability company (the “Company”).

Pursuant to Section 3.1(n) of that certain Credit Agreement, dated as of June 26, 2012 (as it may be amended, supplemented or otherwise modified, the “Credit Agreement”; the capitalized terms not otherwise defined herein shall have the meanings specified in the Credit Agreement), by and among the Company, the Lenders party thereto from time to time and Guggenheim Corporate Funding, LLC, as Administrative Agent, the Company requests that Lenders provide loans to the Company.

I have reviewed the terms of Articles III and IV of the Credit Agreement and the definitions and provisions contained in such Credit Agreement relating thereto, and in my opinion I have made, or have caused to be made under my supervision, such examination or investigation as is necessary to enable me to express an informed opinion as to the matters referred to herein.

Based upon such review and examination described in the preceding paragraph, I certify, on behalf of the Company, that as of the date hereof:

(i) as of the Closing Date, the representations and warranties contained in each of the Credit Documents (including but not limited to the Credit Agreement) are true, correct and complete in all material respects on and as of the Closing Date to the same extent as though made on and as of such date, except to the extent such representations and warranties specifically relate to an earlier date, in which case such representations and warranties are true, correct and complete in all respects on and as of such earlier date;

(ii) as of the Closing Date, no injunction or other restraining order shall have been issued and no hearing to cause an injunction or other restraining order to be issued is pending or noticed with respect to any action, suit or proceeding seeking to enjoin or otherwise prevent the consummation of, or to recover any damages or obtain relief as a result of, the borrowing contemplated hereby and by the Credit Documents; and

(iii) as of the Closing Date, no event has occurred and is continuing or would result from the consummation of the borrowing contemplated hereby that would constitute an Event of Default or a Default.

Attached as Annex A hereto are [financial statements] and the Projections described in Section 4.9 of the Credit Agreement, which are based upon good faith estimates and assumptions believed by the Borrower to be reasonable at the time made and as of the Closing Date.

ENERGY & EXPLORATION PARTNERS, LLC, as Mortgagor (“Mortgagor”), has executed the mortgages and financing statements described on Exhibit A attached hereto (as may be amended, supplemented or otherwise modified from time to time, collectively, the “Mortgage”) for the benefit of GUGGENHEIM CORPORATE FUNDING, LLC, as administrative agent for the Lenders referenced in the Mortgage (“Administrative Agent”), granting a mortgage on and a security interest in, and pledging those certain properties and certain specified interests of Mortgagor in said properties (the “Pledged Properties”) described in the Mortgage to secure certain obligations also described in the Mortgage. Enclosed on Exhibit A is a copy of the Mortgage covering the Pledged Properties.

Exhibit B attached hereto lists the properties which are subject to the Mortgage for which you are accounting to Mortgagor and the decimal interest in production heretofore paid to Mortgagor with respect to its interest in each given property.

Pursuant to the assignment of production provision in the Mortgage, Mortgagor transferred and assigned all of its interests in the Pledged Properties to Administrative Agent. Therefore, Mortgagor hereby authorizes and instructs you that all future payments attributable to Mortgagor’s interest in the Pledged Properties, which would otherwise be paid to Mortgagor, should be made by wire transfer, pursuant to the following wire instructions:

until notified in writing by Administrative Agent to discontinue such payments. Also, Mortgagor hereby requests that you change your records to reflect that Administrative Agent is entitled to the proceeds of production attributable to the Pledged Properties.

In consideration of your acceptance of this Letter-in-Lieu of Transfer Order, Administrative Agent and Mortgagor agree as follows:

1. Mortgagor has heretofore executed Transfer or Division Orders to you covering each of the properties referred to in Exhibit B attached to this letter. This letter is being executed

by the undersigned in lieu of execution of separate Transfer or Division Orders. With respect to proceeds from the sale of oil, gas and other hydrocarbons as to which you account hereunder, Administrative Agent agrees that it will be bound by the terms, conditions, warranties and covenants of all such Transfer or Division Orders heretofore executed by Mortgagor now in force, with the same effect as though it had executed the originals thereof; provided, however, the aggregate liability of Administrative Agent with respect to any warranty, representation, covenant or indemnification contained therein or in this letter shall be limited to an amount equal to the amounts disbursed by you to Administrative Agent hereunder.

2. Mortgagor hereby agrees that you are relieved of any responsibility in connection with the application of the proceeds paid by you to Administrative Agent as hereinabove specified and payment made by you to Administrative Agent shall be binding and conclusive as between you and Mortgagor.

In the absence of a question about the enclosed schedule, you are respectfully requested to make disbursement to Administrative Agent as instructed herein and NOT TO SUSPEND OR DELAY any payments by virtue of the assignment of production from Mortgagor to Administrative Agent. Should you require additional documentation prior to implementing the manner of disbursement requested herein, notwithstanding the warranties and indemnifications contained hereinabove, please suspend disbursements to Mortgagor, pending execution of such additional documentation as you may reasonably require.

In order that we may have a record evidencing your acceptance of this Letter-in-Lieu of Transfer Order, we request that you execute one copy of this letter in the space provided below and return the same to Administrative Agent in the enclosed self-addressed envelope.

THIS FIRST AMENDMENT TO CREDIT AGREEMENT (this “Amendment”) is entered into effective as of July 11, 2012, by and among ENERGY & EXPLORATION PARTNERS, LLC, a Delaware limited liability company (“Borrower”), the Lenders (defined below) party hereto and GUGGENHEIM CORPORATE FUNDING, LLC, as administrative agent under the Credit Agreement (defined below) (in such capacity, “Administrative Agent”).

WHEREAS, Borrower, Administrative Agent and the Lenders party hereto desire to amend the Credit Agreement as set forth herein; and

WHEREAS, Borrower, Administrative Agent and the Lenders party hereto, subject to the terms and conditions set forth herein, have agreed to so amend the Credit Agreement.

NOW, THEREFORE, for and in consideration of the mutual covenants and agreements contained herein, and for other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the parties to this Amendment hereby agree as follows:

SECTION 1. Terms Defined in Credit Agreement. As used in this Amendment, except as may otherwise be provided herein, all capitalized terms that are defined in the Credit Agreement shall have the same meaning herein as therein, all of such terms and their definitions being incorporated herein by reference.

SECTION 2. Amendments to Credit Agreement. Subject to the conditions precedent set forth in Section 3 hereof, the Credit Agreement is hereby amended as follows:

(a) Section 1.1 of the Credit Agreement is amended by inserting the following new definitions in proper alphabetical order:

“AMI 2 Agreement” means that certain AMI Agreement Woodbine Phase II Area, dated effective as of January 1, 2012, by and between Halcón Energy Properties, Inc. and Borrower, as the same may be amended from time to time upon prior written notice to and consent of Administrative Agent; provided, however, that such consent shall not be required for any amendment that (a) does not amend any financial or economic terms of the AMI 2 Agreement and (b) is not adverse to the Lenders.

“AMI 2 Account” means bank account number 650052833 of Borrower at Frost Bank.

(b) The definition of “Cash Receipts” in Section 1.1 of the Credit Agreement is amended and restated in its entirety as follows:

operating revenue earned or to be earned by such Credit Party, (c) any net proceeds from Swap Agreements, and (d) any other Cash or Cash Equivalents received from whatever source; provided that, the following shall not constitute “Cash Receipts”: (i) Casualty Proceeds (except to the extent provided in Section 7.3), (ii) proceeds from asset sales and dispositions permitted by Section 6.7 (other than 6.7(a)), (iii) proceeds from any Permitted IPO or other capital raised resulting from the issuance of equity securities by the Borrower, (iv) advances under the Loans, and (v) Cash or Cash Equivalents received from Halcón Energy Properties, Inc. to fund Acquisition Costs (as defined in the AMI 2 Agreement) pursuant to Section 4(a) of the AMI 2 Agreement received prior to the closing of such acquisition or that are Advanced Funds (as defined in the AMI 2 Agreement).

“provided, however, that with respect to any Oil and Gas Properties acquired pursuant to the AMI 2 Agreement, this Section 5.10 shall only apply to the Credit Parties’ interest in such Oil and Gas Properties after giving effect to all assignments to HALCÓN (as defined in the AMI 2 Agreement) required under the AMI 2 Agreement.”

(d) Section 5.14 of the Credit Agreement is amended and restated in its entirety as follows:

“5.14 Deposit Accounts. In the event that any Credit Party establishes a deposit account other than the Lockbox Account, Equity Account, Operating Account, or AMI 2 Account, such Credit Party will, prior to transferring any funds to such account, execute a Deposit Account Control Agreement and grant in favor of Administrative Agent all the rights necessary to deposit, withdraw or otherwise manage and control the deposit account.”

(e) Section 6.7(d) of the Credit Agreement is amended and restated in its entirety as follows:

“(d) dispositions of Properties pursuant to the Eaglebine Agreement or AMI 2 Agreement,”

(f) The proviso at the end of the first sentence of Section 6.16 of the Credit Agreement is amended and restated in its entirety as follows:

“provided, however, that Section 6.16(b) shall not apply to (i) any Oil and Gas Properties acquired by Borrower in the AMI (as defined in the Eaglebine Agreement) pursuant to Section 2 of the Eaglebine Agreement on or prior to August 31, 2012, and sold and conveyed (pursuant to the terms of the Eaglebine Agreement) to Buyer (as defined in the Eaglebine Agreement) on or prior to August 31, 2012, (ii) any Oil and Gas Properties acquired by Borrower in the AMI (as defined in the AMI 2 Agreement) pursuant to Section 5(a) of the AMI 2 Agreement exclusively with Advanced Funds in the AMI 2 Account pursuant to the terms of the AMI 2 Agreement, and (iii) any Oil and Gas Properties acquired by Borrower in the AMI (as defined in the AMI 2 Agreement) for which HALCÓN (as defined in the AMI 2 Agreement) funds 100% of the Acquisition Costs (as defined in the AMI 2 Agreement) prior to the closing of such acquisition pursuant to Section 4(a) of the AMI 2 Agreement.”

(g) The Credit Agreement is amended by adding a new Section 6.21 to read as follows:

“6.21 AMI 2 Account. Notwithstanding anything in this Agreement to the contrary, in no event shall any Credit Party transfer any funds, Cash, Cash Equivalents or other asset to the AMI 2 Account or permit any Cash Receipts to be deposited into the AMI 2 Account.”

SECTION 3. Conditions of Effectiveness. The obligation of Administrative Agent and the Lenders party hereto to amend the Credit Agreement as provided herein is subject to the fulfillment of the following conditions precedent:

(a) Borrower and the Required Lenders shall have delivered to Administrative Agent multiple duly executed counterparts of this Amendment;

(b) Administrative Agent shall have received a fully executed copy of the AMI 2 Agreement (as defined in Section 2(a) of this Amendment) and all schedules, exhibits and annexes thereto;

(e) Administrative Agent shall have received all fees and expenses provided in Section 6 hereof.

SECTION 4. Representations and Warranties. Borrower represents and warrants to Administrative Agent and the Lenders, with full knowledge that Administrative Agent and the Lenders are relying on the following representations and warranties in executing this Amendment, as follows:

(a) It has the organizational power and authority to execute, deliver and perform this Amendment, and all organizational action on the part of it requisite for the due execution, delivery and performance of this Amendment has been duly and effectively taken.

(b) The Credit Agreement, as amended hereby, the Credit Documents and each and every other document executed and delivered in connection therewith or herewith, to which it is a party, constitute the legal, valid and binding obligation of it, enforceable against it in accordance with their respective terms.

(c) This Amendment does not and will not violate any provisions of any of Borrower’s Organizational Documents or any contract, agreement, instrument or requirement of any Governmental Authority to which it is subject. Its execution of this Amendment will not result in the creation or imposition of any lien upon any of its properties other than those permitted by the Credit Agreement, as amended hereby.

(d) Execution, delivery and performance of this Amendment does not require the consent or approval of any other Person, including, without limitation, any regulatory authority or governmental body of the United States of America or any state thereof or any political subdivision of the United States of America or any state thereof.

(e) No Default or Event of Default will exist, and all of the representations and warranties contained in the Credit Agreement, as amended hereby, and all instruments and documents executed pursuant thereto or contemplated thereby are true and correct in all material respects on and as of this date other than those which have been disclosed to Administrative Agent in writing (except to the extent such representations and warranties expressly refer to an earlier or other date, in which case they shall be true and correct in all material respects as of such earlier or other date).

(f) Except to the extent expressly set forth herein to the contrary, nothing in this Section 4 is intended to amend any of the representations or warranties contained in the Credit Agreement, as amended hereby, or the Credit Documents.

(a) Upon the effectiveness hereof, on and after the date hereof, each reference in the Credit Agreement to “this Agreement,” “hereunder,” “hereof,” “herein,” or words of like import, shall mean and be a reference to the Credit Agreement as amended hereby.

(b) Except as specifically amended by this Amendment, the Credit Agreement shall remain in full force and effect and is hereby ratified and confirmed.

SECTION 6. Cost, Expenses and Taxes. Borrower agrees, in connection with this Amendment, to make all payments required under Section 10.2 of the Credit Agreement pursuant to the terms thereof.

SECTION 7. Extent of Amendment. Except as otherwise expressly provided herein, the Credit Agreement, as amended hereby, and the other Credit Documents are not amended, modified or affected by this Amendment. Borrower hereby ratifies and confirms that (i) except as expressly amended hereby, all of the terms, conditions, covenants, representations, warranties and all other provisions of the Credit Agreement remain in full force and effect, (ii) each of the other Credit Documents are and remain in full force and effect in accordance with their respective terms, and (iii) the Collateral is unimpaired by this Amendment.

SECTION 8. Grant and Affirmation of Security Interest. Borrower hereby confirms and agrees that any and all Liens or Collateral now or hereafter held by Administrative Agent, for the benefit of and as representative of the Lenders, as security for payment and performance of the Obligations, are hereby renewed and carried forth to secure payment and performance of all of the Obligations.

SECTION 9. Claims. As additional consideration to the execution, delivery, and performance of this Amendment by the parties hereto and to induce Administrative Agent and the Lenders to enter into this Amendment, Borrower represents and warrants that it does not know of any defenses, counterclaims or rights of setoff to the payment of any Obligations of Borrower or any Guarantor to Administrative Agent or any Lender.

SECTION 10. Execution and Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute but one and the same instrument. Delivery of an executed counterpart of this Amendment by facsimile or electronic mail shall be equally as effective as delivery of a manually executed counterpart of this Amendment.

SECTION 11. Governing Law. This Amendment shall be governed by and construed in accordance with the laws of the State of New York, except to the extent that federal laws of the United States of America apply.

SECTION 12. Headings. Section headings in this Amendment are included herein for convenience and reference only and shall not constitute a part of this Amendment for any other purpose.

SECTION 13. NO ORAL AGREEMENTS. THE RIGHTS AND OBLIGATIONS OF EACH OF THE PARTIES TO THE CREDIT DOCUMENTS SHALL BE DETERMINED SOLELY FROM WRITTEN AGREEMENTS, DOCUMENTS, AND INSTRUMENTS, AND ANY PRIOR ORAL AGREEMENTS BETWEEN SUCH PARTIES ARE SUPERSEDED BY AND MERGED INTO SUCH WRITINGS. THE CREDIT AGREEMENT, AS AMENDED HEREBY,

AND THE OTHER WRITTEN CREDIT DOCUMENTS EXECUTED BY BORROWER, ADMINISTRATIVE AGENT AND/OR ANY LENDER PARTY TO THE CREDIT AGREEMENT REPRESENT THE FINAL AGREEMENT BETWEEN SUCH PARTIES, AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS BY SUCH PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN SUCH PARTIES.

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorized officers effective as of the day and year first above written.

You have advised us that Borrower requests that Administrative Agent and the Lenders consent to Borrower completing the Equity Transaction on a date after July 31, 2012, but no later than August 31, 2012 (the “Equity Transaction Time Frame”).

As evidenced by this Consent Letter (this “Letter”), Administrative Agent and the Lenders hereby consent to the Equity Transaction occurring in the Equity Transaction Time Frame (the “Specified Consent”). Notwithstanding anything herein to the contrary, the Equity Transaction shall not occur any later than August 31, 2012.

Except as specifically consented to herein, all of the terms and conditions of the Credit Agreement and the other Loan Documents are, and remain, in full force and effect in accordance with their respective terms.

This Letter does not imply any obligation on the part of Administrative Agent or the Lenders, and neither Administrative Agent nor the Lenders shall be obligated, at any time, to grant further amendments, modifications, consents, or waivers.

The consent contained in this Letter is expressly limited to the Specified Consent, as further limited herein. Neither this Letter, nor any other actions taken by, or any inaction on the part of, Administrative Agent or the Lenders, shall be deemed to be (i) a waiver of any Default or Event of Default which exists or may exist hereafter, except as expressly provided herein, or (ii) a waiver of (or an agreement to forbear from exercising) any rights or remedies that Administrative Agent or the Lenders have pursuant to the Credit Agreement and applicable law by reason of any Default or Event of Default.

This Letter may be executed in any number of counterparts and all of such counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of a copy of this Letter by electronic mail in “portable document format” (“.pdf”) form, or by any other electronic means intended to preserve the original graphic and pictorial appearance hereof, will have the same effect as physical delivery of this Letter bearing the original signature.

THIS LETTER, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.

Please confirm that the foregoing is in accordance with your understanding by signing and returning to us the enclosed copy of this Letter, which shall become a binding agreement upon our receipt.

1. This is the Equity Kicker Letter (this “Agreement”) defined and referred to in that certain Credit Agreement dated of even date herewith by and among Energy & Exploration Partners, LLC (“Borrower”), Guggenheim Corporate Funding, LLC, as Administrative Agent (“Administrative Agent”) for the lenders from time to time party thereto (the “Lenders”), and the Lenders (as such Credit Agreement is from time to time amended, supplemented, restated or otherwise modified, the “Credit Agreement”). Capitalized terms used herein, but not defined herein, shall have the meanings assigned to such terms in the Credit Agreement.

2. As partial consideration for the respective Commitment of each Lender, so long as any of the Obligations are outstanding (other than customary indemnity obligations with respect to which no amounts are currently due), Borrower agrees to, and shall cause each Subsidiary to, convey to Administrative Agent for the pro-rata benefit of the Lenders an overriding royalty interest (the “ORI”) in each lease now owned (as more particularly described on Exhibit A hereto) or hereafter acquired by Borrower, other than as set forth in Paragraph 9(a)(iv), in the Eaglebine Area (as defined in the Credit Agreement) as to all depths (the “Leases”), subject to Paragraph 9 below. The ORI shall be comprised of:

(a) until the Total Return Date (defined below), an overriding royalty interest equal to the Applicable ORI Percentage (defined below), proportionately reduced to Borrower’s and its Subsidiaries’ working interest in the Leases; and

(b) upon the Total Return Date, the ORI granted in clause (a), above, shall be automatically reduced to an overriding royalty interest equal to the TRD ORI Percentage, proportionately reduced to Borrower’s and its Subsidiaries’ working interest in the Leases.

Upon repayment in full of the Obligations (other than customary indemnity obligations with respect to which no amounts are currently due), Borrower shall have no further obligation to grant or convey, and neither Administrative Agent nor any Lender shall be entitled to, any further conveyance of ORI, other than as may have been earned hereunder on or prior to the date of such repayment.

For the purpose of this Agreement, the following terms used herein shall have the following meanings:

“Applicable ORI Percentage” means, on any date, the lesser of (a) an undivided five percent (5%) and (b) an amount equal to (i) an undivided five percent (5%) multiplied by (ii) the Total Funded Wells (defined below) on such date divided by twelve (12).

“Default Interest” any interest paid by Borrower with respect to the Obligations in excess of the amount set forth in Section 2.6(a) of the Credit Agreement as result of interest being paid at the Default Rate.

“Internal Rate of Return” means the discount rate at which the net present value of outflows of funds from a Person and inflows of funds to a Person equals zero, calculated for each such outflow from the date such outflow was made. A Person’s Internal Rate of Return shall be calculated pursuant to the Excel function known as “XIRR” on the basis of the actual number of days elapsed over a 365 or 366-day year, as the case may be.

“Total Funded Wells” means the lesser of (a) twelve (12) wells and (b) the number of wells with respect to which the Lenders have funded their share of drilling and completion expenditures set forth in Sections 2.2(a)(B), 2.2(b)(A), 2.2(b)(B) and 2.2(b)(C) of the Credit Agreement; provided, however, for the purposes of this definition (i) in the event Borrower does not make a Well Set Approval Request for Well Set 2 or Well Set 3 prior to the Advance Period Expiration Date, all such wells in each such Well Set shall be treated as having been funded by the Lenders, (ii) in the event the Required Lenders approved a Well Set and Borrower does not provide the Lenders the opportunity to make an Advance for any or all of the wells in such Well Set, each such well shall be treated as having been funded by the Lenders, and (iii) in the event Borrower makes a Well Set Approval Request for Well Set 2 and the Required Lenders do not approve such Well Set Approval Request, then no wells in Well Set 2 or Well Set 3 shall be treated as having been funded by the Lenders.

“Total Return Date” means the date on which (i) all payments applied against the Principal Obligations when received by the Lenders in respect of the Loans as provided in the Credit Agreement plus (ii) all payments applied against the accrued interest (excluding Default Interest) when received by the Lenders in respect of the Obligations as provided in the Credit Agreement plus (iii) all amounts received by the Lenders as Facility Fees as provided in the Credit Agreement and the Fee Letter plus (iv) all proceeds received by the Lenders (or any assignee thereunder) from the ORIs provide the Lenders a thirty-two and one-half percent (32.5%) Internal Rate of Return on invested capital.

“TRD ORI Percentage” means on and after the Total Return Date, (i) one-half percent (0.5%) multiplied by (ii) the Total Funded Wells on the Total Return Date divided by twelve (12).

3. All of such ORI conveyances described in Paragraph 2 of this Agreement shall be (a) substantially in the form of Exhibit B attached hereto, (b) effective as of June 1, 2012, as to such Leases presently owned by Borrower and its Subsidiaries, and as to any future Leases, as of the effective date under which Borrower or its Subsidiary, as applicable, acquires such Leases and (c) executed by Borrower and its Subsidiaries, as applicable, and delivered to Administrative Agent (in the number of counterparts as requested by Administrative Agent) contemporaneously herewith as to such Leases presently owned by Borrower and its Subsidiaries and hereafter, on any Collateral Addition Date.

4. Upon each increase in the number of Total Funded Wells (as described in the definition of “Total Funded Wells”), Borrower or its Subsidiary, as applicable, will convey to Administrative Agent such additional quantum of the overriding royalty interest in the Leases then owned so that the ORI is equal to the Applicable ORI Percentage. Upon the occurrence of the Total Return Date, Administrative Agent will reconvey to Borrower such quantum of the ORI so that the ORI is reduced to the TRD ORI Percentage.

5. Borrower shall pay or reimburse Administrative Agent and/or the Lenders for the reasonable cost and expense of preparation and recording all such conveyances made pursuant to this Agreement.

6. All obligations of Borrower and its Subsidiaries hereunder shall survive repayment of the Obligations evidenced by the Credit Agreement. It is the intention of the parties hereto that the obligations under this Agreement not be construed as violating any applicable law regarding the rule against perpetuities, the suspension of the absolute power of alienation, or other rules regarding the vesting or duration of estates, and this Agreement shall be construed as not violating any such applicable law to the extent the same can be so construed consistent with the intent of the parties. In the event, however, that any provision hereof is determined to violate any such applicable law, then such provision shall nevertheless be effective for the maximum period (but not longer than the maximum period) permitted by any such applicable law that will result in no violation. To the extent such maximum period is permitted to be determined by reference to “lives in being”, Borrower and Administrative Agent for itself and on behalf of the Lenders agree that “lives in being” shall refer to the lifetime of the last to die of the now living lineal descendants of the late Joseph P. Kennedy (the father of the late President of the United States of America).

7. This Agreement shall be governed by and construed in accordance with the laws of the State of Texas, without reference to laws that would direct the application of the laws of another jurisdiction.

(a) At any time on or after the Total Return Date, on or before ten (10) days prior to the date on which Borrower proposes to sell, assign, transfer, or convey all or any portion of the Leases to a third person, Borrower shall send to Administrative Agent written notice thereof, which notice shall contain the unadjusted purchase price that the third party proposes to pay for such Leases (or portion thereof) and allocation of the purchase price the third party assigns to the ORI. In such notice Borrower may elect to cause Administrative Agent and Lenders to join in any such sale, assignment, transfer, or conveyance, subject to Paragraph 8(c). If Borrower does not so elect, Administrative Agent shall, for a period of ten (10) days thereafter, have the right to elect in writing to join in any such transaction. Failure of Administrative Agent to so elect shall be conclusively deemed to have elected not to join in any such transaction.

(b) If Borrower elects to cause Administrative Agent and the Lenders to join in such transaction or if Administrative Agent, on behalf of the Lenders, elects to join in any such transaction, Administrative Agent, on behalf of the Lenders, shall be entitled to a portion of the proceeds of such transaction equal to the allocation of the purchase price the third party purchaser assigns to the ORI, subject to Paragraph 8(c)

(c) In the event that Borrower elects to cause Administrative Agent and Lenders to join in any such sale, assignment, transfer, or conveyance and Administrative Agent does not agree with the allocation of the purchase price the third party purchaser assigns to the ORI and/or does not agree that the assigned purchase price represents the reasonable fair market value of the

ORI, Administrative Agent may refer the dispute to RBC Richardson Barr, Scotia Waterous, Jefferies Randall & Dewey or, if none of these firm is able or willing to serve, a nationally-recognized independent oil and gas advisory firm mutually acceptable to both Administrative Agent and Borrower (the “Appraiser”), for review and final determination by arbitration. The Appraiser’s determination shall be made within fifteen (15) Business Days after submission of the matters in dispute and shall be final and binding on Borrower and Administrative Agent, without right of appeal. In determining the appropriate allocation of the purchase price and/or whether the assigned purchase price represents the reasonable fair market value of the ORI, the Appraiser shall be bound by the terms of this Agreement and the terms of the ORI; provided, however, that, except as specifically set forth in this Paragraph 8(c), the Parties do not intend to impose any particular procedures upon the Appraiser, it being the desire and direction of the Parties that any such disagreement shall be resolved as expeditiously and inexpensively as is reasonably practicable. The Appraiser shall act as an expert for the limited purpose described in this Paragraph 8(c), and may not award damages, interest or penalties to any person with respect to any matter. Borrower and Administrative Agent shall bear their own legal fees and other costs of presenting its case. Borrower shall bear one half and Administrative Agent shall bear one half of the costs and expenses of the Appraiser. Notwithstanding anything to the contrary herein, in no event shall Administrative Agent be required to accept a purchase price for the ORI that is less than the reasonable fair market value of the ORI (as determined by the Appraiser).

(d) Notwithstanding anything to the contrary herein, the foregoing rights shall not apply to:

(i) a mortgage, pledge, hypothecate, or grant of a security interest in all or any portion of the Subject Assets (including assignments of production executed as a further security for the debt);

(ii) the grant of an overriding royalty interest, net profits interests, or production payment; or

(iii) disposal of the Leases by (A) merger, reorganization, consolidation, change of control (including a sale of stock or interests); (B) transfer of an interest to an Affiliate; or (C) conveyance due to a non-consent election under any joint operating agreement, unit agreement, unit operating agreement, or similar agreement.

(e) This Section 8 shall be a covenant running with the Leases and the lands covered thereby and shall be binding upon Borrower, Administrative Agent, and the Lenders, and their respective successors and assigns.

(a) It is the intent of the Parties that Borrower and its Subsidiaries may, in certain cases, sell, swap, exchange, assign, convey, transfer, or otherwise dispose of (a “Transfer”) Leases to a third person free of the burden of the ORI and with proportionate reduction of the ORI to the interests retained by Borrower and its Subsidiaries. In connection with the foregoing:

(i) With respect to a Transfer of the Leases marked with a number sign (#) on Schedule 4.13 to the Credit Agreement (the “Group 1 Leases”), the ORI shall not

burden the Leases (or interests therein) Transferred, or to be Transferred, to a third party, and the ORI shall not be proportionately reduced to the percentage interest in the applicable Leases retained by Borrower and its Subsidiaries;

(ii) With respect to a Transfer of any Lease (or portion thereof) to Halcon Energy Properties, Inc. (f/k/a RWG Energy, Inc.) (“Halcon”) or its Affiliates, other than a Group 1 Lease, whether pursuant to the Eaglebine Agreement or any other agreement (whether or not now in existence) with Halcon and its Affiliates that is similar to the Eaglebine Agreement, the ORI shall not burden the Leases (or interests therein) Transferred and, except with respect to any Lease owned by Borrower or any Subsidiary on the date of this Agreement that is not subject to the Eaglebine Agreement, the ORI shall be proportionately reduced to the percentage interest therein retained by Borrower and its Subsidiaries.

(iii) With respect to a Transfer of any Lease (or portion thereof), other than (A) the Transfer of a Group 1 Lease or (B) the Transfer of any Lease (or interest therein) to Halcon or its Affiliates as described in Paragraphs 9(a)(ii) and 9(a)(iv), the ORI shall not burden the Leases (or interests therein) Transferred, or to be transferred, and the ORI shall be proportionately reduced to percentage interests therein retained by Borrower and its Subsidiaries; provided, however, that, (y) until the occurrence of the Total Return Date, the ORI shall not be reduced to less than 2.5% of 8/8ths and (z) on and after the occurrence of the Total Return Date, the ORI shall not be reduced to less than 0.25% of 8/8ths. For the avoidance of doubt, in no event shall any ORI that has been proportionately reduced pursuant to Paragraph 9(a)(ii) be proportionately reduced pursuant to this Paragraph 9(a)(iii).

(iv) Notwithstanding anything to the contrary herein, the ORI shall not burden, or be conveyed or conveyable with respect to, any Lease or other interest acquired with funds advanced by Halcon or its Affiliates, but shall be conveyed as to any wellbore interests in such Leases owned by Borrower or its Subsidiaries while any of the Obligations are outstanding (other than customary indemnity obligations with respect to which no amounts are currently due).

(b) Each Party shall, without further consideration, and promptly upon request, execute such documents and instruments as may be reasonably requested by the other Party (or, with respect to Borrower and its Subsidiaries, any purchaser of the applicable Leases or real property rights (or interests therein)), to effectuate the provisions of this Agreement (including Paragraph 9 hereof).

10. Except with respect to the Transfer of all of Borrower’s or any Subsidiary’s interest in a Lease, no Transfer of a Lease shall relieve Borrower or such Subsidiary of liability for any payments to be made with respect to the ORI burdening the portion (if any) of such Lease retained by Borrower.

11. Please confirm your agreement with the terms of this Agreement by signing and returning to Administrative Agent an executed counterpart of this Agreement.

THIS FIRST AMENDMENT TO EQUITY KICKER LETTER (this “Amendment”) is entered into effective as of July 11, 2012, by and between ENERGY & EXPLORATION PARTNERS, LLC, a Delaware limited liability company (“Borrower”) and GUGGENHEIM CORPORATE FUNDING, LLC, as administrative agent under the Credit Agreement (defined below) (in such capacity, “Administrative Agent”).

WHEREAS, Borrower, Administrative Agent and the lenders party thereto from time to time (the “Lenders”) entered into that certain Credit Agreement dated as of June 26, 2012, as amended by that certain First Amendment to Credit Agreement (the “First Amendment”) dated of even date herewith (as further amended, modified or restated from time to time, the “Credit Agreement”);

WHEREAS, in connection with the Credit Agreement, Borrower and Administrative Agent entered into that certain Equity Kicker Letter dated as of June 26, 2012 (as amended, modified or restated from time to time, the “Agreement”);

WHEREAS, Borrower and Administrative Agent desire to amend the Agreement as set forth herein; and

WHEREAS, Borrower and Administrative Agent, subject to the terms and conditions set forth herein, have agreed to so amend the Agreement.

SECTION 1. Terms Defined in Agreement. As used in this Amendment, except as may otherwise be provided herein, all capitalized terms that are defined in the Agreement shall have the same meaning herein as therein, all of such terms and their definitions being incorporated herein by reference.

SECTION 2. Amendment to Agreement. Subject to the conditions precedent set forth in Section 3 hereof, Paragraph 9(a)(iv) of the Agreement is hereby amended and restated in its entirety as follows:

“(iv) Notwithstanding anything to the contrary herein, the ORI shall not burden, or be conveyed or conveyable with respect to, any Lease or other interest acquired with funds advanced by Halcon or its Affiliates (including pursuant to the AMI 2 Agreement), but shall be conveyed as to any wellbore interests in such Leases owned by Borrower or its Subsidiaries after giving effect to all assignments to Halcon required by the AMI 2 Agreement, if applicable, while any of the Obligations are outstanding (other than customary indemnity obligations with respect to which no amounts are currently due).”

SECTION 3. Conditions of Effectiveness. The obligation of Administrative Agent to amend the Agreement as provided herein is subject to the fulfillment of the following conditions precedent:

(a) Borrower shall have delivered to Administrative Agent multiple duly executed counterparts of this Amendment; and

(b) Administrative Agent shall have received a fully executed copy of the AMI 2 Agreement (as defined in Section 2(a) of the First Amendment) and all schedules, exhibits and annexes thereto.

SECTION 4. Representations and Warranties. Borrower represents and warrants to Administrative Agent, with full knowledge that Administrative Agent is relying on the following representations and warranties in executing this Amendment, as follows:

(b) The Agreement, as amended hereby, and each and every other document executed and delivered in connection therewith or herewith, to which it is a party, constitute the legal, valid and binding obligation of it, enforceable against it in accordance with their respective terms.

(a) Upon the effectiveness hereof, on and after the date hereof, each reference in the Agreement to “this Agreement,” “hereunder,” “hereof,” “herein,” or words of like import, shall mean and be a reference to the Agreement as amended hereby.

(b) Except as specifically amended by this Amendment, the Agreement shall remain in full force and effect and is hereby ratified and confirmed.

SECTION 6. Extent of Amendment. Except as otherwise expressly provided herein, the Agreement, as amended hereby, is not amended, modified or affected by this Amendment. Borrower hereby ratifies and confirms that except as expressly amended hereby, all of the terms, conditions, covenants, representations, warranties and all other provisions of the Agreement remain in full force and effect.

SECTION 7. Execution and Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed and delivered shall be deemed to be an original and all of which taken together shall constitute but one and the same instrument. Delivery of an executed counterpart of this Amendment by facsimile or electronic mail shall be equally as effective as delivery of a manually executed counterpart of this Amendment.

SECTION 8. Governing Law. This Amendment shall be governed by and construed in accordance with the laws of the State of New York, except to the extent that federal laws of the United States of America apply.

SECTION 9. Headings. Section headings in this Amendment are included herein for convenience and reference only and shall not constitute a part of this Amendment for any other purpose.

SECTION 10. NO ORAL AGREEMENTS. THE RIGHTS AND OBLIGATIONS OF EACH OF THE PARTIES TO THE AGREEMENT SHALL BE DETERMINED SOLELY FROM WRITTEN AGREEMENTS, DOCUMENTS, AND INSTRUMENTS, AND ANY PRIOR ORAL AGREEMENTS BETWEEN SUCH PARTIES ARE SUPERSEDED BY AND MERGED INTO SUCH WRITINGS. THE AGREEMENT, AS AMENDED HEREBY, AND THE OTHER WRITTEN DOCUMENTS EXECUTED BY BORROWER, ADMINISTRATIVE AGENT AND/OR ANY LENDER IN CONNECTION THEREWITH REPRESENT THE FINAL AGREEMENT BETWEEN SUCH PARTIES, AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS BY SUCH PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN SUCH PARTIES.

We consent to the use in this Registration Statement on Form S-1 of Energy & Exploration Partners, Inc. of our reports dated August 1, 2012, relating to our audits of the consolidated financial statements, appearing in the Prospectus, which is part of this Registration Statement.

We also consent to the reference to our firm under the caption “Experts” in the Prospectus.


Large accelerated filer	¨		Accelerated filer	¨

Non-accelerated filer	x	(Do not check if a smaller reporting company)	Smaller reporting company	¨



Title of Each Class of Securities to Be Registered	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee
Common Stock, par value $0.01 per share	$	$


	Per Share	Total
Public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses to Company	$	$


Assumed initial public offering price per share		$
Pro forma net tangible book value per share as of March 31, 2012 (after giving effect to the Pro Forma Transactions)
Increase per share attributable to new investors in this offering	$

As adjusted pro forma net tangible book value per share after giving effect to the Pro Forma Transactions and this offering
Dilution in pro forma net tangible book value per share to new investors in this offering		$


	Obligations and Commitments Due By Period
	Total		2012		2013 to 2014		2015 to 2016		2017 & Beyond
	(in thousands)
Petro Capital note⁽¹⁾	$	15,000	$	15,000	$	—	$	—	$	—
Contractual lease payments		396		199		197		—		—

Total contractual obligations	$	15,396	$	15,199	$	197	$	—	$	—


PROSPECTUS SUMMARY			1
RISK FACTORS			14
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			35
USE OF PROCEEDS			37
DIVIDEND POLICY			37
CAPITALIZATION			38
DILUTION			39
SELECTED COMBINED FINANCIAL DATA			40
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			42
BUSINESS			55
MANAGEMENT			72
EXECUTIVE COMPENSATION			77
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			79
CORPORATE REORGANIZATION			80
PRINCIPAL STOCKHOLDERS			82
DESCRIPTION OF CAPITAL STOCK			83
SHARES ELIGIBLE FOR FUTURE SALE			87
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS TO NON-U.S. HOLDERS			89
UNDERWRITING			92
LEGAL MATTERS			98
EXPERTS			98
WHERE YOU CAN FIND MORE INFORMATION			98
INDEX TO FINANCIAL STATEMENTS			F-1
GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS			A-1


	As of March 31, 2012
	Historical		Pro Forma		Pro Forma As Adjusted
	(in thousands)
Cash and cash equivalents	$	3,513	$	34,269

Long-term debt, including current maturities⁽¹⁾		14,978		21,471
Members’/stockholders’ equity:
Equity		3,282		—
Common stock, $0.01 par value; 900,000 shares authorized, shares and shares issued and outstanding (Pro Forma and Pro Forma As Adjusted, respectively)		—		—
Paid-in capital		—		28,739

Total members’/stockholders’ equity		3,282		28,739

Total capitalization	$	18,260	$	50,210	$


Payment Date		Principal Payment
July 1, 2013		1/6 of the then outstanding principal amount

October 1, 2013		1/5 of the then outstanding principal amount

January 1, 2013		1/4 of the then outstanding principal amount

April 1, 2014		1/3 of the then outstanding principal amount

July 1, 2014		1/2 of the then outstanding principal amount

December 17, 2014		All amounts outstanding


	Undeveloped Acres				Developed Acres				Total				% of Acreage Held-by- Production
	Gross		Net		Gross		Net		Gross		Net		% of Acreage Held-by- Production
Eaglebine		43,414		15,236		—		—		43,414		15,236		0.0	%
Wolfcamp		13,109		13,109		—		—		13,109		13,109		0.0	%
Niobrara		16,916		16,915		39		16		16,955		16,931		0.1	%

Total⁽¹⁾		73,438		45,260		39		16		73,477		45,276		0.0	%


	2012					2013					2014					2015 and thereafter
	Gross		Net			Gross		Net			Gross		Net			Gross		Net
Eaglebine		249		87			6,799		2,380			15,677		5,914			20,688		6,855
Wolfcamp		—		—			—		—			11,178		11,178			1,931		1,931
Niobrara		—		—			—		—			655		655			16,299		16,276

Total⁽¹⁾		249		87			6,799		2,380			27,511		17,747			39,918		25,062

% of total				0	%				5	%				39	%				55	%


	Capital Expenditure Budget July 1, 2012 - December 31, 2013
	Net Wells		(in millions)
Drilling & Completion:
Eaglebine		25	$	144
Wolfcamp		11	$	87
Niobrara		15	$	10

Drilling & Completion Total		51	$	242
Leasehold Acquisition:
Eaglebine			$	10
Wolfcamp			$	10
Niobrara			$	5

Leasehold Acquisition Total			$	25
Other:
Eaglebine Seismic			$	4

Other Total			$	4

Total		51	$	271


Name	Age		Position
B. Hunt Pettit		42	Director, President and Chief Executive Officer
Brian C. Nelson		42	Executive Vice President and Chief Financial Officer
David L. Patty, Jr.		42	Executive Vice President—Land and Business Development
Lawrence B. Van Ingen		59	Executive Vice President—Geology
Tom D. McNutt		43	Executive Vice President, General Counsel and Corporate Secretary


Name and Principal Position	Salary		Bonus		All Other Compensation		Total
B. Hunt Pettit	$	40,000	$	—	$	—	$	40,000
President and Chief Executive Officer

Lawrence B. Van Ingen	$	67,000	$	—	$	—	$	67,000
Executive Vice President—Geology

Brian C. Nelson	$	64,375	$	—	$	—	$	64,375
Executive Vice President and Chief Financial Officer


	Shares of Common Stock Beneficially Owned Prior to this Offering		Shares of Common Stock Beneficially Owned After this Offering
Name of Beneficial Owner	Number	Percentage	Number	Percentage
*5% Holders*
Oso+Toro Multistrategy Fund Series Interest of the SALI Multiseries Fund II 3(C1) LP⁽¹⁾
Oso+Toro Multistrategy Fund (Tax Exempt) Segregated Portfolio of the SALI Multiseries Fund SPC Ltd⁽¹⁾
*Directors and Named Executive Officers*
B. Hunt Pettit
Lawrence B. Van Ingen
Brian C. Nelson
*All directors and executive officers as a group* (5 persons)


Underwriter		Number of Shares
Canaccord Genuity Inc.
Johnson Rice & Company L.L.C.

Total


Canaccord Genuity		Johnson Rice & Company L.L.C.


	Page
Energy & Exploration Partners, Inc.
Unaudited Pro Forma Combined and Condensed Financial Statements:
Introduction		F-3
Unaudited Pro Forma Combined and Condensed Statement of Operations for the Year Ended December 31, 2011		F-5
Unaudited Pro Forma Combined and Condensed Statement of Operations for the Three Months Ended March 31, 2012		F-6
Unaudited Pro Forma Combined and Condensed Statement of Financial Position as of March 31, 2012		F-7
Notes to Unaudited Pro Forma Combined and Condensed Financial Statements		F-8
Financial Statement as of July 31, 2012:
Report of Independent Registered Public Accounting Firm		F-9
Statement of Financial Position		F-10
Notes to Financial Statement		F-11

Energy & Exploration Partners, LLC
Energy & Exploration Partners, LP
Energy & Exploration Partners Operating, LP, and
Energy & Exploration Partners Operating GP, LLC
Combined Financial Statements as of December 31, 2011 and 2010 and for the Years Ended December 31, 2011, and 2010:
Report of Independent Registered Public Accounting Firm		F-12
Combined Statements of Financial Position		F-13
Combined Statements of Operations		F-14
Combined Statements of Changes in Equity		F-15
Combined Statements of Cash Flows		F-16
Notes to Combined Financial Statements		F-17

Unaudited Combined Financial Statements as of March 31, 2012 and 2011 and for the Three Months Ended March 31, 2012 and 2011:
Combined Statements of Financial Position		F-26
Combined Statements of Operations		F-27
Combined Statements of Changes in Equity		F-28
Combined Statements of Cash Flows		F-29
Notes to Combined Financial Statements		F-30

North American Shale Investment Fund GP, LP
North American Shale GP, LLC, and
North American Shale Investment Advisors, LLC
Combined and Consolidated Financial Statements as of December 31, 2011 and for the period of inception (February 1, 2011) to December 31, 2011:
Report of Independent Registered Public Accounting Firm		F-35
Combined and Consolidated Statement of Assets and Liabilities		F-36
Combined and Consolidated Statement of Operations		F-37
Combined and Consolidated Statement of Changes in Net Assets		F-38
Combined and Consolidated Statement of Cash Flows		F-39
Combined and Consolidated Schedule of Investments		F-40
Notes to the Combined and Consolidated Financial Statements		F-41

Unaudited Combined and Consolidated Financial Statements as of March 31, 2012 and for the Three Months ended March 31, 2012:
Combined and Consolidated Statement of Assets and Liabilities		F-46
Combined and Consolidated Statement of Operations		F-47


Combined and Consolidated Statement of Changes in Net Assets			F-48
Combined and Consolidated Statement of Cash Flows			F-49
Combined and Consolidated Schedule of Investments			F-50
Combined and Consolidated Supplemental Schedule of Investments			F-51
Notes to the Combined and Consolidated Financial Statements			F-52


	Combined ENXP Historical			Combined and Consolidated NASIF Historical			Pro Forma Adjustments					Energy & Exploration Partners, Inc. As Adjusted
REVENUES	$	1,129		$	—		$	(1,129	)	(h	)	$	—

OPERATING EXPENSES		2,333			135			(556	)	(h	)		1,912


LOSS FROM OPERATIONS		(1,204	)		(135	)		(573	)				(1,912	)

OTHER INCOME (EXPENSE)
Other income		21			—			—					21
Other expense					—			(140	)	(c	)		(140	)
Interest income		4			—			—					4
Interest expense		(270	)		—			(3,599	)	(e	)		(3,869	)
Gain on sale of assets		—			—			573		(h	)		6,727
								6,154		(d	)
Unrealized gain on investments		—			20,683			(20,683	)	(b	)		—

Total other income (expense)		(245	)		20,683			(17,695	)				2,743

INCOME (LOSS) BEFORE INCOME TAX EXPENSE		(1,449	)		20,548			(18,268	)				831

INCOME TAX EXPENSE		(29	)		—			(288	)	(i	)		(317	)

Net Income (Loss)	$	(1,478	)	$	20,548		$	(18,556	)			$	514


	Combined ENXP Historical		Combined and Consolidated NASIF Historical		Pro Forma Adjustments			Energy & Exploration Partners, Inc. As Adjusted
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,513	$	58	$	28,762	(d)	$	34,269
						1,936	(e)
Accounts receivable		35		34		(34	) (g)		35
Investments		—		28,905		(28,905	) (b)		—
Other current assets		1,072		—		3,660	(e)		4,732

Total current assets		4,620		28,997		5,419			39,036

PROPERTY, PLANT, AND EQUIPMENT		27,748		—		(12,434	) (d)		15,314

LONG-TERM ASSETS		189		—		602	(e)		791

Total Assets	$	32,557	$	28,997	$	(6,413	)	$	55,141

LIABILITIES, EQUITY AND NET ASSETS
LIABILITIES
Accounts payable, accrued and other liabilities	$	1,046	$	30	$	106	(c,g)	$	1,182
Warrant liability		125		—		(125	) (e)		—
Deposit for investments		13,126		—		(10,382	) (b)		2,744

Total current liabilities		14,297		30		(10,401	)		3,926

Deferred tax liability		—		—		1,005	(f)		1,005
Note payable, net of discount		14,978		—		6,493	(e)		21,471

Total liabilities		29,275		30		(2,903	)		26,402

EQUITY AND NET ASSETS
Equity		3,282		—		(18,295	) (a)		—
						(140	) (c)
						16,328	(d)
						(170	) (e)
						(1,005	) (f)
Noncontrolling interest equity		—		28,967		(28,967	) (b)		—
Common stock, par value		—		—		—	(a)		—
Additional Paid in Capital		—		—		18,295	(a)		28,739
						10,444	(b)

Total equity		3,282		28,967		(3,510	)		28,739

Total liabilities and equity	$	32,557	$	28,997	$	(6,413	)	$	55,141


TOTAL ASSETS	$	—

STOCKHOLDER’S EQUITY
STOCKHOLDER’S EQUITY:
Common stock, $0.01 par, 900,000 shares authorized, 0 shares issued and outstanding	$	10
Preferred Stock, $0.01 par, 100,000 shares authorized, 0 shares issued and outstanding		—
Paid-in capital		990
Stock subscription receivable		(1,000	)

Total stockholder’s equity	$	—


	December 31,
	2011			2010
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,333		$	2,565
Debt service deposits		700			—
Accounts receivable		4			514
Prepaid expenses		24			—

Total current assets		6,061			3,079

PROPERTY, PLANT, AND EQUIPMENT
Undeveloped oil and natural gas leasehold interests		21,578			3,617
Overriding royalty interests		30			32
Furniture, fixtures and equipment		104			43
Accumulated depreciation		(71	)		(43	)

Net property, plant, and equipment		21,641			3,649

LONG-TERM ASSETS
Loan origination fees, net		177			—
Long-term deposits		25			—

Total long-term assets		202			—

Total assets	$	27,904		$	6,728

LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	65		$	—
Accounts payable—related party		34			23
Accrued liabilities		140			13
Warrant liability		125			—
Deposit for investments		2,192			359
Deposit for investments—related party		10,934			664
Other liabilities		15			—

Total current liabilities		13,505			1,059

NOTE PAYABLE, NET OF DISCOUNT		9,928			—

Total liabilities		23,433			1,059

COMMITMENTS AND CONTINGENCIES (Note 6)

EQUITY		4,471			5,669

Total liabilities and equity	$	27,904		$	6,728


	For the Year Ended December 31,
	2011			2010
REVENUES
Sale of leasehold interests	$	1,129		$	44,324

OPERATING EXPENSES
Cost of leasehold interests sold		556			38,285
Abandoned leasehold interests		679			—
General and administrative		1,069			1,858
Depreciation		29			43

Total operating expenses		2,333			40,186

INCOME (LOSS) FROM OPERATIONS		(1,204	)		4,138

OTHER INCOME (EXPENSE)
Other income		21			—
Interest income		4			3
Interest expense		(270	)		—

Total other income (expense)		(245	)		3
INCOME (LOSS) BEFORE STATE INCOME TAX EXPENSE		(1,449	)		4,141

STATE INCOME TAX EXPENSE		(29	)		(12	)

NET INCOME (LOSS)	$	(1,478	)	$	4,129


	(in thousands)
Face value of note payable	$	10,000
Debt services deposits		(700	)
Loan origination fees		(234	)

Total net cash received from note payable	$	9,066


	(in thousands)
Beginning balance	$	—
Addition of detachable warrant		(125	)

Ending balance	$	(125	)


	As of December 31, 2011		Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	(in thousands)
Detachable warrants	$	125	$	—	$	—	$	125


	Office		Furniture		Total
	(in thousands)
2012	$	192	$	50	$	242
2013		197		—		197

	$	389	$	50	$	439



	As of March 31, 2012			As of December 31, 2011
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,513		$	5,333
Debt service deposit		1,029			700
Accounts receivable		35			4
Prepaid expenses		43			24

Total current assets		4,620			6,061

PROPERTY, PLANT, AND EQUIPMENT
Undeveloped oil and natural gas leasehold interests		27,226			21,578
Proved properties		392			—
Overriding royalty interests		30			30
Furniture, fixtures, and equipment		189			104
Accumulated depreciation		(89	)		(71	)

Net property, plant, and equipment		27,748			21,641

LONG-TERM ASSETS
Loan origination fees, net		148			177
Long-term deposits		41			25

Total long-term assets		189			202

Total assets	$	32,557		$	27,904


LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	495		$	65
Accounts payable—related parties		73			34
Accrued liabilities		466			140
Warrant liability		125			125
Deposit for investments		2,192			2,192
Deposit for investments—related party		10,934			10,934
Other liabilities		12			15

Total current liabilities		14,297			13,505

NOTE PAYABLE, NET OF DISCOUNT		14,978			9,928

Total liabilities		29,275			23,433
EQUITY		3,282			4,471

Total liabilities and equity	$	32,557		$	27,904


	FOR THE THREE MONTHS ENDED MARCH 31,
	2012			2011
REVENUES
Oil and natural gas sales	$	30		$	—

OPERATING EXPENSES
General and administrative		675			189
Depreciation and depletion		18			4

Total operating expenses		693			193

LOSS FROM OPERATIONS		(663	)		(193	)

OTHER INCOME (EXPENSE)
Interest income		2			1
Interest expense		(512	)		—
Gain on sale of assets		4			563

Total other income (expense)		(506	)		564

INCOME (LOSS) BEFORE STATE INCOME TAX EXPENSE		(1,169	)		371

STATE INCOME TAX EXPENSE		(20	)		(4	)

NET INCOME (LOSS)	$	(1,189	)	$	367


	March 31, 2012 (Unaudited)		December 31, 2011
	(in thousands)
Niobrara	$	10,798	$	10,769
Eaglebine		13,434		7,815
Wolfcamp		2,950		2,950
Van Cleve		44		44

Total	$	27,226	$	21,578


Beginning balance	$	(125	)
Change in the fair value of detachable warrant		—

Ending balance	$	(125	)


	As of March 31, 2012		Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	(in thousands)
Detachable warrants	$	125	$	—	$	—	$	125


ASSETS
ASSETS
Cash	$	64
Accounts receivable—related party		34
Investments		31,065

Total assets	$	31,163


LIABILITIES AND NET ASSETS
LIABILITIES
Accounts payable and accrued liabilities	$	15

Total liabilities		15

COMMITMENTS AND CONTINGENCIES (Note 7)

NET ASSETS
Net assets attributable to controlling interests		—
Net assets attributable to noncontrolling interests		31,148

Total net assets		31,148

Total liabilities and net assets	$	31,163


EXPENSES
General and administrative	$	135

Total operating expenses		135

LOSS BEFORE UNREALIZED GAIN ON INVESTMENTS		(135	)

Unrealized gain on investments		20,683

NET INCOME	$	20,548

NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	$	20,548

NET INCOME ATTRIBUTABLE TO CONTROLLING INTERESTS	$	—


	Controlling Interest		Noncontrolling Interests		Total Net Assets
NET ASSETS, February 1, 2011 (inception)	$	—	$	—	$	—

CONTRIBUTIONS		—		10,600		10,600

NET INCOME		—		20,548		20,548

NET ASSETS, December 31, 2011	$	—	$	31,148	$	31,148


CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	20,548
Adjustments to reconcile net income to net cash used in operating activities:
Unrealized gain on investments		(20,683	)
Change in operating assets and liabilities:
Accounts receivable—related party		(34	)
Accounts payable and accrued liabilities		15

Net cash used in operating activities		(154	)

CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of investment assets		(10,382	)

Net cash used in investing activities		(10,382	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from contributions		10,600

Net cash provided by financing activities		10,600

NET INCREASE IN CASH AND CASH EQUIVALENTS		64

CASH AND CASH EQUIVALENTS, beginning of period		—

CASH AND CASH EQUIVALENTS, end of period	$	64