Energy & Exploration Partners S-1 IPO registration

As filed with the Securities and Exchange Commission on September 10, 2012

Registration No. 333-            

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Energy & Exploration Partners, Inc.

(Exact name of registrant as specified in its charter)

Delaware	1311	80-0839466
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

Two City Place, Suite 1700

100 Throckmorton

Fort Worth, Texas 76102

(817) 789-6712

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Tom D. McNutt

Executive Vice President, General Counsel

and Corporate Secretary

Two City Place, Suite 1700

100 Throckmorton

Fort Worth, Texas 76102

(817) 789-6712

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Charles H. Still, Jr. Bracewell & Giuliani LLP 711 Louisiana Street, Suite 2300 Houston, Texas 77002 (713) 221-3309 Kirk Tucker William S. Moss III Mayer Brown LLP 700 Louisiana, Suite 3400 Houston, Texas 77002 (713) 238-3000

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.

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.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) 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.  ¨

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):

Large accelerated filer  ¨	Accelerated filer  ¨	Non-accelerated filer  þ	Smaller reporting company  ¨
		(Do not check if a smaller reporting company)

CALCULATION OF REGISTRATION FEE

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	$	275,000,000	$	31,515

(1) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

(2) Includes shares of common stock issuable upon exercise of the underwriters’ option to purchase additional shares of common stock.

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 and the selling stockholders 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.

Subject to Completion dated September 10, 2012

PROSPECTUS

             Shares

Energy & Exploration Partners, Inc.

Common Stock

We are offering              shares of our common stock and the selling stockholders are offering              shares of our common stock. We will not receive any proceeds from the sale of our common stock by the selling stockholders. 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 15 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.

	Per Share	Total
Public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses, to us	$	$
Proceeds to selling stockholders(1)	$	$

(1) Expenses associated with this offering, other than underwriting discounts, will be paid by us.

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.

The underwriters expect to deliver the shares of common stock on or about                      2012.

Canaccord Genuity Johnson Rice & Company L.L.C.

The date of this prospectus is                      2012.

TABLE OF CONTENTS

PROSPECTUS SUMMARY	1
RISK FACTORS	15
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS	36
USE OF PROCEEDS	38
DIVIDEND POLICY	38
CAPITALIZATION	39
DILUTION	40
SELECTED COMBINED FINANCIAL DATA	41
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	43
BUSINESS	57
MANAGEMENT	77
EXECUTIVE COMPENSATION	84
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	87
PRINCIPAL AND SELLING STOCKHOLDERS	90
DESCRIPTION OF CAPITAL STOCK	91
SHARES ELIGIBLE FOR FUTURE SALE	94
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS TO NON-U.S. HOLDERS	96
UNDERWRITING	99
LEGAL MATTERS	105
EXPERTS	105
WHERE YOU CAN FIND MORE INFORMATION	105
INDEX TO FINANCIAL STATEMENTS	F-1
GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS	A-1

You should rely only on the information contained in this document and any free writing prospectus we provide you. We, the selling stockholders and the underwriters have not authorized anyone to provide you with additional or different information. We, the selling stockholders 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.

Dealer Prospectus Delivery Obligation

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.

Industry and Market Data

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 43,012 net acres as of August 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 12,826 net acres in our Eaglebine core area. Recently we have entered into two agreements with a subsidiary of Halcón Resources Corporation, or Halcón, and one agreement with a subsidiary of Constellation Energy Commodities Group, Inc., or Constellation, related to the Eaglebine. These agreements, which are described further under “—Our Core Areas—Eaglebine” below, provided for our conveyance of operated working interests in substantially all of our Eaglebine acreage and established two areas of mutual interest, which we refer to as AMI #1 and AMI #2. We also signed a purchase and sale agreement on September 10, 2012 to acquire 57,275 net acres in the Eaglebine with an operated 100% working interest from subsidiaries of Chesapeake Energy Corporation, or Chesapeake, for $125 million, subject to customary purchase price adjustments. We refer to this transaction as the Chesapeake acquisition and expect to close in the fourth quarter of 2012. This agreement is described further under “—Our Core Areas—Eaglebine” below. In addition to our acreage in the Eaglebine, we have 13,254 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, including the acreage we expect to acquire in the Chesapeake acquisition, could contain a total of 1,254 net drilling locations, of which a majority 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 August 31, 2012 and the acreage we will acquire in the Chesapeake acquisition, and our drilling capital budget from July 1, 2012 to December 31, 2013. We have also

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budgeted estimated capital expenditures of $26 million for leasehold acquisitions (excluding the Chesapeake acquisition) 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 Wells		(in millions)
Eaglebine:
Current Eaglebine(2):
Horizontal Woodbine/Eagle Ford		12,826		120		107		16	$	111
Vertical Lower Cretaceous		12,826		160		80		5	$	15
Total		12,826				187		21	$	126
Chesapeake Eaglebine Acquisition(3):
Horizontal Woodbine/Eagle Ford		57,275		120		477		21	$	147
Vertical Lower Cretaceous		57,275		160		358		—	$	—
Total		57,275				835		21	$	147
Total Eaglebine		70,101				1,022		42	$	273
Wolfcamp(4):
Horizontal Wolfcamp		13,254		160		83		11	$	87
Horizontal Cline		13,254		160		83		—	$	—
Total Wolfcamp		13,254				166		11	$	87
Niobrara(4):
Horizontal Niobrara		16,350		320		51		—	$	—
Vertical Codell/Niobrara		581		40		15		15	$	10
Total Niobrara		16,931				66		15	$	10
Total (including the Chesapeake acquisition)(5)		100,287				1,254		68	$	370

⁽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⁾  25% non-operated working interest in AMI #1, 15% non-operated working interest in AMI #2, and 100% operated working interest outside AMIs.

⁽³⁾  100% operated working interest. 17,990 net acres are subject to AMI #1 and AMI #2 and may be conveyed to Halcón and Constellation if they elect to purchase their pro rata working interest. Information in this table and elsewhere in this prospectus regarding net acreage, potential net drilling locations, and net wells to be drilled with respect to the Chesapeake acquisition does not give effect to the potential conveyance of net acreage to Halcón or Constellation. For additional information regarding the Chesapeake acquisition, including certain terms of the purchase and sale agreement, see “Business—Chesapeake Acquisition.”

⁽⁴⁾  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.

⁽⁵⁾  Certain totals may not add due to rounding.

Our Core Areas

Eaglebine

As of August 31, 2012, we owned 12,826 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

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current 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. The majority of the leases associated with the Chesapeake acquisition are within the first two years of their three-year primary term and generally provide for two year extension options. Giving effect to the Chesapeake acquisition, we estimate that we have 1,022 net drilling locations in the Eaglebine. Through the end of 2013, we plan to drill 37 net horizontal wells and 5 net vertical wells and have budgeted $273 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. 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 August 31, 2012. In the final closing under the agreement scheduled for September 2012, we estimate that we will convey to Halcón a 65% operated working interest in an additional 7,911 net acres (5,142 net to Halcón) for approximately $7.7 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 net acre conveyed to Halcón, or an estimated total of $29.9 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, 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 29,851 net acres for total proceeds of $74.6 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 purchase and sale 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 August 31, 2012, we had acquired 3,105 net acres in AMI #2 of which we expect to convey 2,484 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.

In August 2012, we entered into a purchase and sale agreement with Constellation and sold a 10% non-operated working interest in our Eaglebine acreage in AMI #1 and a 5% non-operated working interest in AMI #2 for $6,500 per net acre. Pursuant to the first closing under this agreement, we conveyed 3,801 net acres in AMI#1 to Constellation for $24.7 million and received $0.8 million as reimbursement for Constellation’s 10% share of the Covington #1H well described below. The final closing under this agreement is scheduled for September 2012, and we estimate that we will convey 928 net acres in AMI #1 and 160 net acres in AMI #2 to Constellation for total consideration of $7.1 million plus $1.7 million as reimbursement for subsequent Eaglebine wells. Following the final closings with both Halcón and Constellation in September 2012, we will retain a 25% working interest in AMI #1 and a 15% working interest in AMI #2. For future acquisitions,

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Constellation can elect to participate in AMI #1 or AMI #2 by paying its pro-rata 10% share of all acreage costs in AMI #1 and its pro-rata 5% share of all acreage costs plus $100 per net mineral acre in AMI #2. In addition to the cash proceeds received from both closings, if Constellation achieves a 20% internal rate of return, it will reconvey 30% of the working interest it holds in wells and acreage in both AMI #1 and AMI #2 back to us.

In September 2012, we entered into a purchase and sale agreement with Chesapeake to acquire a 100% working interest in Chesapeake’s 57,275 net undeveloped acres in the Eaglebine for $125 million, subject to customary purchase price adjustments. The closing date for this transaction is scheduled for October 31, 2012, but we may extend the closing date to a date not later than December 14, 2012 for an additional $3 million payment. The 57,275 net acres, which are located in Madison, Grimes, Leon, Robertson, and Houston Counties, would increase our total Eaglebine position to 70,101 net acres. We are required to offer our partners, Halcón and Constellation, their pro rata working interest in acreage that we acquire in AMI #1 and AMI #2. If Halcón and Constellation elect to purchase their pro rata working interest in AMI #1 and AMI #2, we would expect to convey approximately 17,990 net acres (16,509 net to Halcón and 1,480 net to Constellation) out of the 57,275 net acres, thereby leaving us with 39,285 net acres from this transaction and a total of 52,112 net acres in the Eaglebine. If Halcón elects to purchase its pro rata working interest, Halcón would be the operator on the AMI #1 and AMI #2 acreage. Information in this prospectus regarding net acreage, potential net drilling locations, and net wells to be drilled with respect to the Chesapeake acquisition does not give effect to the potential conveyance of net acreage to Halcón or Constellation. For additional information regarding the Chesapeake acquisition, including certain terms of the purchase and sale agreement, see “Business—Chesapeake Acquisition.”

We commenced drilling our first Halcón-operated well in AMI #1, the Covington #1H in which we have a 25% 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 sidetracked and drilled the well laterally for 1,000 feet and plan to complete the well with a four stage hydraulic fracture stimulation in the Woodbine formation. We anticipate this well will commence production before the end of September 2012.

We added a second drilling rig to our Eaglebine acreage in August 2012 and commenced drilling our second Halcón-operated well in AMI #1, the Charles M. Baker #1H, in which we have a 25% non-operated working interest. We plan to drill the lateral to 6,000 feet and complete the well with a 30 plus stage hydraulic fracture stimulation in the Eagle Ford Shale. We anticipate this well will commence production before the end of the fourth quarter of 2012.

We commenced drilling our third Halcón-operated well in AMI #1, the WD Smith #1H, in which we have a 25% non-operated working interest, in September 2012. We plan to drill the lateral to 5,850 feet and complete the well with a 25 plus stage hydraulic fracture stimulation in the Eagle Ford Shale. We anticipate this well will commence production before the end of the fourth 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 with average estimated ultimate recoveries, or EURs, of 400,000 to 500,000 boe per well and initial 30-day average production of 400 to 1,200 boe/d per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur or the results we will achieve from our wells.

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,

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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 228 filed in 2012 through August 31 in the Eaglebine. According to estimates prepared by Baker Hughes Incorporated, there were 20 rigs operating in the Eaglebine as of August 31, 2012.

Wolfcamp

As of August 31, 2012, we owned 13,254 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 166 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 with average EURs of 420,000 to 570,000 boe per well and initial 30-day average production of 525 to 600 boe/d per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur or the results we will achieve from our wells.

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 88 filed in 2012 through August 31 in Lynn, Lubbock, Hockley, and Terry Counties, Texas, which offset our acreage position. According to estimates prepared by Baker Hughes, there were 511 rigs operating in the Permian Basin as of August 31, 2012.

Niobrara

As of August 31, 2012, we owned 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

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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 with average EURs of 250,000 to 500,000 boe per well and initial 30-day average production of 300 to 600 boe/d per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur or the results we will achieve from our wells.

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 1,408 filed in 2012 through August 31 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 46 rigs operating in the Denver-Julesburg Basin as of August 31, 2012.

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. We plan to drill 42 net wells and spend $273 million through 2013 in the Eaglebine alone. In addition, we plan to drill 11 net wells and spend $87 million in the Wolfcamp, and we plan to drill 15 net wells and spend $10 million in the Niobrara, through the end of 2013. We believe our 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 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. On our operated acreage, 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. As of September 2, 2012, the credit facility had a borrowing base of $25 million, and we had $17.9

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million in outstanding borrowings. 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 June 30, 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.    Giving effect to the Chesapeake acquisition, we expect to have accumulated a total of 100,287 net acres 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, although such activity may not be indicative of our future operations. We believe that lease terms in our three core areas allow us enough time to conduct our internal geologic analysis and drill wells needed for the majority of our acreage to be held by production based on our current drilling plan.

Substantial drilling inventory.    Based on our current acreage position of 43,012 net acres and giving effect to the Chesapeake acquisition of 57,275 net acres, we estimate there could be up to 1,254 net potential drilling locations on our acreage. Through the end of 2013 we anticipate drilling 37 net horizontal Eaglebine wells, 5 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.

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.

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 have built large acreage positions in several developing unconventional plays. 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 stockholders. Our management has been and will continue to be compensated with equity incentives and 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.

Corporate Reorganization

We were incorporated on July 31, 2012 pursuant to the laws of the State of Delaware as Energy & Exploration Partners, Inc. to become a holding company for our business. We recently completed a

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series of reorganization transactions described below, which we refer to collectively as our corporate reorganization.

Prior to the completion of our corporate reorganization, our business was 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 owned all of the equity interests in the general partner of NASIF, and the other investors owned all of the limited partner interests in NASIF. Mr. Pettit also owned all of the outstanding equity interests in North American Shale Investment Advisors, LLC, or NASIF Advisors, which was 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, owned additional net profits interests in our Niobrara acreage.

Our corporate reorganization consisted of the following transactions:

Contributions to Energy & Exploration Partners, Inc.    Pursuant to a contribution agreement, on August 22, 2012, the following contributions were made to us:

• Hunt Pettit, our founder, President and Chief Executive Officer, and an affiliated entity contributed the following interests to us in exchange for shares representing approximately 58% 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 contributed all of the outstanding limited partner interests in NASIF to us in exchange for shares representing approximately 20% of our outstanding common stock; and

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

The consideration for the contributions described above was determined through negotiations among us and the other parties to the contribution agreement.

Immediately prior to the contributions described above, the limited partners of NASIF and the Niobrara investors received overriding royalty interests in our acreage. For additional information regarding these overriding royalty interests and overriding royalty interests held by our executive officers, certain other members of our management and an entity affiliated with one of our non-employee directors, see “Certain Relationships and Related Party Transactions—Overriding Royalty Interests” and “Executive Compensation—Overriding Royalty Interests.” Additionally, we repurchased the net profits interests held by the Niobrara investors that were not parties to the contribution agreement for total cash payments of $1.7 million.

Following the contributions described above, we assigned our interests in Energy & Exploration Partners Operating, LP and in its general partner to Energy & Exploration Partners, LLC. Additionally, NASIF, its general partner and NASIF Advisors were merged into Energy & Exploration Partners, LLC, the investment management agreement between NASIF and NASIF Advisors was terminated, and the net profits interests in our acreage previously held by NASIF and the Niobrara investors were canceled.

Energy & Exploration Partners, LLC also recently assigned its general partnership interest in Energy & Exploration Partners, LP to an affiliated entity of Hunt Pettit forde minimis consideration. Energy &

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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 made awards to members of our senior management, other than Mr. Pettit, of restricted shares of our common stock representing approximately 21% of our outstanding shares of common stock under our 2012 Stock Incentive Plan. These shares of restricted stock generally vest over a three-year period. See “Executive Compensation—2012 Stock Incentive Plan.”

In September 2012, Hunt Pettit contributed shares representing approximately 5% of our outstanding shares of common stock back to us for no consideration, and we used those shares to grant restricted stock awards to certain members of our management under our 2012 Stock Incentive Plan. These shares of restricted stock generally vest over a three-year period.

For more information on our corporate reorganization and the ownership of our common stock by our principal stockholders, see “Certain Relationships and Related Party Transactions—Corporate Reorganization” and “Principal and Selling Stockholders.”

The following diagram indicates our ownership structure after giving effect to the transactions described above and this offering.

Ownership Structure After this Offering

⁽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.”

⁽²⁾  Includes Oso + Toro Multi Strategy Fund Series Interests of the SALI Multi-Series Fund II 3(c)(1), L.P., Oso + Toro Multi Strategy Fund (Tax Exempt) Segregated Portfolio of SALI Multi-Series Fund SPC, Ltd. and certain other persons beneficially owning less than 5% of our outstanding common stock. See “Principal and Selling Stockholders.”

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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 ishttp://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.

• Certain of our directors, executive officers and other members of management, and our largest stockholders have direct economic interests in some of 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 15.

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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.

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The Offering

Issuer Energy & Exploration Partners, Inc.

Common stock offered by us              shares

Common stock offered by the selling stockholders              shares

Common stock to be outstanding after this offering              shares

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 the Chesapeake acquisition and to fund a portion of our 2012 and 2013 capital expenditure budget for drilling and developing our leasehold acreage, acquiring additional oil and natural gas leases and acquiring 3D seismic data. We will not receive any proceeds from the sale of shares by the selling stockholders. 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 16 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;

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

• gives effect to a              for              stock split that we will effect immediately prior to the completion of this offering.

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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 six months ended June 30, 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 six months ended June 30, 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 six months ended June 30, 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 six months ended June 30, 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 was 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 was 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 conveyances of working interests to Halcón through June 30, 2012 in the pro forma statement of operations data, and our conveyances of working interests to Halcón and Constellation through August 31, 2012 in the pro forma balance sheet data, each as described under “—Our Core Areas—Eaglebine”; and

• our acquisition of certain undeveloped leasehold interests.

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 June 30, 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

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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,						Six Months Ended June 30,						Year Ended December 31,			Six Months Ended June 30,
	2010			2011			2011			2012			2011			2012
							(unaudited)						(unaudited)
	(in thousands)
Statement of operations data:
Revenues	$	—		$	—		$	—		$	111		$	—		$	111
Operating expenses	$	1,901		$	1,777		$	359		$	1,794		$	1,912		$	1,836
Loss from operations	$	(1,901	)	$	(1,777	)	$	(359	)	$	(1,683	)	$	(1,912	)	$	(1,725	)
Net income (loss)	$	4,129		$	(1,478	)	$	256		$	384		$	(2,887	)	$	1,658

	As of December 31,				As of June 30,
	2010		2011		2012		Pro Forma 2012
					(unaudited)		(unaudited)
	(in thousands)
Balance sheet data:
Cash and cash equivalents	$	2,565	$	5,333	$	10,358	$	31,959
Property, plant and equipment	$	3,649	$	21,641	$	19,637	$	19,637
Total assets	$	6,728	$	27,904	$	45,799	$	70,004
Note payable, net of discount	$	—	$	9,928	$	21,471	$	16,498
Total equity	$	5,669	$	4,471	$	4,705	$	42,829

	Year Ended December 31,						Six Months Ended June 30,
	2010			2011			2011			2012
							(unaudited)
	(in thousands)
Other financial data:
Net cash used in operating activities	$	(2,594	)	$	(1,078	)	$	(375	)	$	(3,138	)
Net cash provided by (used in) investing activities	$	2,406		$	(17,843	)	$	(8,721	)	$	7,729
Net cash provided by financing activities	$	797		$	21,689		$	9,499		$	434
Opening cash	$	1,956		$	2,565		$	2,565		$	5,333
Closing cash	$	2,565		$	5,333		$	2,968		$	10,358

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RISK FACTORS

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.

Risks Related to the Oil and Natural Gas Industry and Our Business

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 have no operating history and our future performance is uncertain.

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

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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. For example, for the four years ended August 31, 2012, the NYMEX—WTI oil price ranged from a high of $120.92 per bbl to a low of $33.87 per bbl, while the NYMEX—Henry Hub natural gas price ranged from a high of $8.26 per MMBtu to a low of $1.82 per MMBtu. 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:

• worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;

• the actions of the Organization of Petroleum Exporting Countries, or OPEC;

• the price and quantity of imports of foreign oil and natural gas;

• political conditions in or hostilities in oil-producing and natural gas-producing regions, including current conflicts in the Middle East and conditions in Africa, South America and Russia;

• the level of global oil and domestic natural gas exploration and production;

• the level of global oil and domestic natural gas inventories;

• prevailing prices on local oil and natural gas price indexes in the areas in which we operate;

• localized supply and demand fundamentals and transportation availability;

• weather conditions and natural disasters;

• domestic and foreign governmental regulations;

• authorization of exports from the United States of liquefied natural gas;

• speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;

• price and availability of competitors’ supplies of oil and natural gas;

• technological advances affecting energy consumption; and

• the price and availability of alternative fuels.

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.

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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:

• increases in the costs of, shortages of or delays in obtaining rigs, equipment, qualified personnel or other services;

• facility or equipment malfunctions;

• unexpected drilling conditions;

• pressure or irregularities in geological formations;

• adverse weather conditions;

• reductions in oil and natural gas prices;

• delays imposed by or resulting from compliance with permitting and other regulatory requirements;

• proximity to and capacity of transportation facilities;

• compliance with changing environmental and other regulatory requirements;

• environmental hazards, such as natural gas leaks, oil spills, salt water spills, pipeline ruptures and discharges of toxic gases;

• lost or damaged oilfield development and service tools;

• pipe or cement failures, casing collapses or other downhole failures;

• loss of drilling fluid circulation;

• fires, blowouts, surface craterings and explosions;

• uncontrollable flows of oil, natural gas or well fluids;

• loss of leases due to incorrect payment of royalties;

• title problems; and

• limitations in the market for oil and natural gas.

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.

Our future capital requirements will depend on many factors, including:

• the scope, rate of progress and cost of our exploration and production activities;

• oil and natural gas prices;

• our ability to locate and acquire hydrocarbon reserves;

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• our ability to produce oil or natural gas from those reserves;

• the terms and timing of any drilling and other production-related arrangements that we may enter into;

• fluctuations in our working capital needs;

• interest payments and debt service requirements;

• prevailing economic conditions;

• the ability and willingness of banks and other lenders to lend to us;

• our ability to access the equity and debt capital markets;

• the cost and timing of governmental permits or approvals; and

• the effects of competition by larger companies operating in the oil and natural gas industry.

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. If the lenders decline to advance such funds, we will be required to seek other financing, which may not be available on favorable terms, or at all. 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 the lenders under our credit facility decline to advance funds for the drilling and completion of our wells or 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.

Our credit facility includes covenants that, among other things, restrict:

• our investments, loans and advances and the payment of dividends and other restricted payments;

• our incurrence of additional indebtedness;

• the granting of liens other than certain permitted liens;

• mergers, consolidations and sales of all or a substantial part of our business or properties;

• the sale of assets (other than production sold in the ordinary course of business);

• our general and administrative expenses; and

• our capital expenditures.

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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 significant portion of our cash flows could be used to service our indebtedness;

• a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

• the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;

• a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

• our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

• a high level of debt may make it more likely that a reduction in our borrowing base following a semi-annual redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

• a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate expenses or other purposes.

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.

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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:

• the timing and amount of capital expenditures;

• the operator’s expertise and financial resources;

• the approval of other participants in drilling wells;

• the selection of technology; and

• the rate of production of reserves, if any.

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.

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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 August 31, 2012, all of our acreage, including the acreage we will acquire in the Chesapeake acquisition, 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

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condition or results of operations. We have recently experienced delays in contracting for drilling rigs in the Eaglebine. 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, transportation and processing 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:

• environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

• abnormally pressured formations;

• mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

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• fires, explosions and ruptures of pipelines;

• personal injuries and death; and

• natural disasters.

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

• injury or loss of life;

• damage to and destruction of property, natural resources or equipment;

• pollution or other environmental damage;

• regulatory investigations or penalties;

• suspension of our operations; or

• repair or remediation costs.

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. Giving pro forma effect to the Chesapeake acquisition, as of August 31, 2012, we had leases representing 2,506 net acres expiring in 2012, 25,112 net acres expiring in 2013, 41,303 net acres expiring in 2014 and 27,142 net acres expiring thereafter. Of the 2,506 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.

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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, and inflows remained below average through July 2012. 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.

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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.

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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

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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

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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:

• production is less than the volume covered by the derivative instruments;

• the counter-party to the derivative instrument defaults on its contract obligations; or

• there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.

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

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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.

Our credit facility requires that we enter into commodity derivative contracts for specified minimum percentages of our anticipated future production. Additionally, the credit facility provides that the lenders must approve the terms of our commodity derivative contracts. These restrictions could limit our flexibility in managing our exposure to commodity price risk. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facilities.”

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.

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Increased costs of capital could adversely affect our business.

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, including the Chesapeake acquisition, 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:

• recoverable reserves;

• future oil and natural gas prices and their appropriate differentials;

• development and operating costs; and

• potential environmental and other liabilities.

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. Although the purchase and sale agreement for the Chesapeake acquisition includes certain representations and warranties of the sellers and requires the sellers to indemnify us for certain losses, these representations, warranties and indemnities are subject to significant limitations and may not protect us against all liabilities or other problems associated with the acquired properties.

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

• diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

• challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of ours while carrying on our ongoing business;

• difficulty associated with coordinating geographically separate organizations; and

• challenge of attracting and retaining personnel associated with acquired operations.

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.

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If we fail to realize the anticipated benefits of a significant acquisition, including the Chesapeake 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. This is the approach we expect to take for the Chesapeake acquisition.

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, including the acreage to be acquired in the Chesapeake acquisition, is undeveloped. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest or that we acquire, 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.

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Risks Relating to the Offering and our Common Stock

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 following factors could affect our stock price:

• our operating and financial performance and drilling results, including reserve estimates;

• quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

• strategic actions by our competitors;

• changes in revenue or earnings estimates, publication of reports or changes or withdrawals of research coverage by equity research analysts;

• speculation in the press or investment community;

• sales of our common stock by us or our stockholders or the perception that such sales may occur;

• changes in accounting principles;

• additions or departures of key management personnel;

• actions by our stockholders;

• general market conditions, including fluctuations in commodity prices; and

• domestic and international economic, legal and regulatory factors unrelated to our performance.

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.

Certain of our directors, executive officers and other members of management, and our largest stockholders have direct economic interests in some of our properties, and their interests may not be aligned with our interests.

Each of our executive officers, certain other members of our management, an entity affiliated with one of our non-employee directors, 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 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. These percentages range from 0% to 2.5% in the Eaglebine, 0% to 2.2% in the Wolfcamp and 0% to 4.2% in the Niobrara. Because the

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amounts of the overriding royalty interest percentages vary among our properties and will not apply to all of our properties, including properties acquired in the Chesapeake acquisition and 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 June 30, 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:

• institute a more comprehensive compliance function;

• design, establish, evaluate and maintain a system of internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

• comply with rules promulgated by the NYSE;

• prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

• establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

• involve and retain to a greater degree outside counsel and accountants in the above activities; and

• establish an investor relations function.

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

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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

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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 management and our stockholders who acquired 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:

• a classified board of directors, so that only approximately one-third of our directors are elected each year;

• limitations on the removal of directors; and

• limitations on the ability of our stockholders to call special meetings; and

• advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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.

Forward-looking statements may include statements about our:

• discovery and development of oil and natural gas reserves;

• cash flows and liquidity;

• business and financial strategy, budget, projections and operating results;

• oil and natural gas realized prices;

• timing and amount of future production of oil and natural gas;

• availability of drilling and production equipment;

• availability of oil field labor;

• amount, nature and timing of capital expenditures, including future development costs;

• borrowing capacity under our credit facility;

• availability and terms of capital;

• drilling and completion of wells;

• competition;

• marketing of oil and natural gas;

• timing, location and size of property acquisitions;

• expected benefits and closing of the Chesapeake acquisition;

• costs of exploiting and developing our properties and conducting other operations;

• general economic and business conditions;

• effectiveness of our risk management activities;

• environmental and other liabilities;

• counterparty credit risk;

• governmental regulation and taxation of the oil and natural gas industry; and

• plans, objectives, expectations and intentions contained in this prospectus that are not historical.

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:

• variations in the market demand for, and prices of, oil and natural gas;

• lack of proved reserves;

• estimates of oil and natural gas data;

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• the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our credit facility;

• general economic and business conditions;

• failure to realize expected value creation from property acquisitions;

• uncertainties about our ability to replace reserves and economically develop our reserves;

• risks related to the concentration of our operations;

• drilling results;

• potential financial losses or earnings reductions from our commodity price risk management programs;

• potential adoption of new governmental regulations; and

• our ability to satisfy future cash obligations and environmental costs.

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

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USE OF PROCEEDS

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 will not receive any of the proceeds from the sale of shares of our common stock by the selling stockholders. We will pay all expenses related to this offering, other than the underwriting discount related to the shares sold by the selling stockholders.

We intend to use a portion of the net proceeds we receive from this offering to pay the remaining balance of the purchase price for the Chesapeake acquisition. The total purchase price is $125 million, and we will pay a deposit to Chesapeake of $3.5 million, which will be applied to the purchase price at closing. The purchase price is subject to customery pre- and post-closing adjustments. See “Business—Chesapeake Acquisition.” We intend to use the remainder of the net proceeds from this offering to fund a portion of our $400 million capital expenditure budget for the second half of 2012 and 2013 for drilling and developing our leasehold acreage, acquiring additional oil and natural gas leases and acquiring 3D seismic data. The capital expenditure budget includes approximately $370 million for drilling and developing our leasehold acreage, approximately $26 million for acquiring additional oil and natural gas leases (excluding the Chesapeake acquisition), and approximately $4 million for acquiring 3D seismic data. 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. If Halcón and Constellation elect to purchase their pro rata working interest of the acreage to be acquired from Chesapeake in AMI #1 and AMI #2, we will use the proceeds of the conveyance to Halcón and Constellation for our capital expenditure budget.

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.”

DIVIDEND POLICY

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.

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CAPITALIZATION

The following table sets forth our capitalization as of June 30, 2012:

• on a historical basis;

• on a pro forma basis giving effect to the Pro Forma Transactions described under “Prospectus Summary—Summary Historical and Pro Forma Combined Financial Data;” and

• on a pro forma as adjusted basis giving further effect to this offering, the receipt of the net proceeds therefrom and the use of the net proceeds to pay the purchase price for the Chesapeake acquisition.

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.

	As of June 30, 2012
	Historical		Pro Forma		Pro Forma As Adjusted
	(in thousands)
Cash and cash equivalents	$	10,358	$	31,959
Long-term debt, including current maturities		21,471		16,498
Members’/stockholders’ equity:
Equity		4,705		—
Common stock, $0.01 par value;              shares authorized,              shares and              shares issued and outstanding (Pro Forma and Pro Forma As Adjusted, respectively)		—		5
Paid-in capital		—		42,824
Total members’/stockholders’ equity		4,705		42,829
Total capitalization	$	26,176	$	59,327	$

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DILUTION

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 June 30, 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 June 30, 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:

Assumed initial public offering price per share		$
Pro forma net tangible book value per share as of June 30, 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		$

The following table summarizes, on an as adjusted pro forma basis as of June 30, 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:

	Shares  Acquired(1)				Total Consideration					Average Price Per Share
	Number	Percent			Amount		Percent
Existing stockholders			%			$		%			$
New investors			%					%
Total				%	$				%	$

⁽¹⁾ The number of shares disclosed for the existing stockholders includes              shares being sold by the selling stockholders. The number of shares disclosed for the new investors does not include the              shares being purchased by the new investors from the selling stockholders in this offering.

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SELECTED COMBINED FINANCIAL DATA

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 six months ended June 30, 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 six months ended June 30, 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 was 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 was 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.

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	Year Ended December 31,						Six Months Ended June 30,
	2010			2011			2011			2012
							(unaudited)
	(in thousands)
Statement of operations data:
Revenues
Oil and natural gas revenues	$	—		$	—		$	—		$	111
Expenses
Lease operating expense		—			—			—			9
Abandoned leasehold interests		—			679			—			—
General and administrative		1,858			1,069			348			1,721
Depreciation, depletion, and amortization		43			29			11			64
Total expenses		1,901			1,777			359			1,794
Loss from operations		(1,901	)		(1,777	)		(359	)		(1,683	)
Other income (expense)
Other income		—			21			—			—
Interest income		3			4			52			9
Interest expense		—			(270	)		—			(1,097	)
Gains on sale of assets		6,039			573			573			5,805
Total other income (expense)		6,042			328			625			4,717
Income (loss) before taxes		4,141			(1,449	)		266			3,034
Income tax expense		(12	)		(29	)		(10	)		(2,650	)
Net income (loss)	$	4,129		$	(1,478	)	$	256		$	384

	As of December 31,				As of June 30,
	2010		2011		2012
					(unaudited)
	(in thousands)
Balance sheet data:
Cash and cash equivalents	$	2,565	$	5,333	$	10,358
Property, plant and equipment	$	3,649	$	21,641	$	19,637
Total assets	$	6,728	$	27,904	$	45,799
Note payable, net of discount	$	—	$	9,928	$	21,471
Total equity	$	5,669	$	4,471	$	4,705

	Year Ended December  31,						Six Months Ended June 30,
	2010			2011			2011			2012
							(unaudited)
	(in thousands)
Other financial data:
Net cash used in operating activities	$	(2,594	)	$	(1,078	)	$	(375	)	$	(3,138	)
Net cash provided by (used in) investing activities	$	2,406		$	(17,843	)	$	(8,721	)	$	7,729
Net cash provided by financing activities	$	797		$	21,689		$	9,499		$	434
Opening cash	$	1,956		$	2,565		$	2,565		$	5,333
Closing cash	$	2,565		$	5,333		$	2,968		$	10,358

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.”

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 43,012 net acres as of August 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 12,826 net acres in our Eaglebine core area. Recently we have entered into two agreements with a subsidiary of Halcón Resources Corporation, or Halcón, and one agreement with a subsidiary of Constellation Energy Commodities Group, Inc., or Constellation, related to the Eaglebine. These agreements, which are described further under “Business—Our Core Areas—Eaglebine” below, provided for our conveyance of operated working interests in substantially all of our Eaglebine acreage and established two areas of mutual interest, which we refer to as AMI #1 and AMI #2. We also signed a purchase and sale agreement on September 10, 2012 to acquire 57,275 net acres in the Eaglebine with an operated 100% working interest from subsidiaries of Chesapeake Energy Corporation, or Chesapeake, for $125 million, subject to customary purchase price adjustments. We refer to this transaction as the Chesapeake acquisition and expect to close in the fourth quarter of 2012. This agreement is described further under “Business—Our Core Areas—Eaglebine” below. In addition to our acreage in the Eaglebine, we have 13,254 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, including the acreage we expect to acquire in the Chesapeake acquisition, could contain a total of 1,254 net drilling locations, of which a majority 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 25% working interest. We anticipate this well will commence production before the end of September 2012. We added a second drilling rig to our Eaglebine acreage in August 2012 and commenced drilling our second Halcón-operated well in AMI #1, the Charles M. Baker #1H, in which we have a 25% non-operated working interest. We anticipate this well will commence production before the end of the fourth quarter of 2012. We commenced drilling our third Halcón-operated well in AMI #1, the WD Smith #1H, in which we have a 25% non-operated working interest, in September 2012. We anticipate this well will commence production before the end of the fourth quarter of 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.

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How We Conduct Our Business and Evaluate Our Operations

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;

• realized prices on the sale of oil and natural gas, including the effect of our commodity derivative contracts;

• oil and natural gas production and operating expenses;

• capital expenditures;

• general and administrative expenses;

• net cash provided by operating activities; and

• net income.

Production Volumes

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.

Realized Prices on the Sale of Oil and Natural Gas

Factors Affecting the Sales Price of Oil and Natural Gas

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).

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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 eight 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 eight months of 2012.

Commodity Derivative Contracts

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.

Oil and Natural Gas Production Expenses

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.

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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.

Production and Ad Valorem Taxes

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 of crude petroleum 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% based on gross income and a conservation tax of 0.07% based on the market value of oil and natural gas production. Wyoming imposes production taxes at a base rate of 6% and conservation tax of 0.04% based on the market 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

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.

Income Tax Expense

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 period from January 1, 2012 to April 13, 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.

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. In connection with our becoming a C corporation, an estimated net deferred tax liability of approximately $1.1 million was established for differences between the book and tax basis of our assets and liabilities and a corresponding expense was recorded to net income from operations.

Results of Operations

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

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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.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

For the six months ended June 30, 2012, we recognized approximately $111,000 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 six months ended June 30, 2011.

Total expenses increased by $1.4 million to $1.8 million for the six months ended June 30, 2012. The net increase was primarily due to increases in professional fees, salaries and wages, contract labor, and consulting fees.

Interest expense was $1.1 million for the six months ended June 30, 2012 compared to $0 for the six months ended June 30, 2011. The increase in the expense was due to interest and amortization of loan costs associated with outstanding debt ranging from $10.0 million to $21.5 million during the six months ended June 30, 2012, compared to no debt outstanding during the six months ended June 30, 2011.

Gain on sale of assets increased to $5.8 million for the six months ended June 30, 2012 compared to a $0.6 million, primarily due to our sales of a 65% working interest in certain of our Eaglebine acreage to Halcón during the six months ended June 30, 2012.

Income tax expense was $2.7 million for the six months ended June 30, 2012 compared to $10,000 for the six months ended June 30, 2011. During the six months ended June 30, 2011, we were not directly subject to federal income taxes. On April 13, 2012, when Energy & Exploration Partners, LLC became a C corporation, we recorded $1.1 million of deferred federal and state tax liabilities related to the difference between the book and tax basis of our assets. For the period from April 13, 2012 to June 30, 2012, we recorded a provision of $1.6 million for federal income taxes and for state income taxes, net of the federal benefit.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

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.

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Liquidity and Capital Resources

Asset Sales

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.

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. 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 August 31, 2012. In the final closing under the agreement scheduled for September 2012, we estimate that we will convey to Halcón a 65% operated working interest in an additional 7,911 net acres (5,142 net to Halcón) for approximately $7.7 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 net acre conveyed to Halcón, or an estimated total of $29.9 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, 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 29,851 net acres for total proceeds of $74.6 million.

In August 2012, we entered into a purchase and sale agreement with Constellation and sold a 10% non-operated working interest in our Eaglebine acreage in AMI #1 and a 5% non-operated working interest in AMI #2 for $6,500 per net acre. Pursuant to the first closing of this agreement, we conveyed 3,801 net acres in AMI#1 to Constellation for $24.7 million. The final closing under this agreement is scheduled for September 2012, and we estimate that we will convey 928 net acres in AMI #1 and 160 net acres in AMI #2 to Constellation for total consideration of $7.1 million plus $1.7 million as reimbursement for subsequent Eaglebine wells. Following the final closings with both Halcón and Constellation in September 2012, we will retain a 25% working interest in AMI #1 and a 15% working interest in AMI #2. For future acquisitions, Constellation can elect to participate in AMI #1 or AMI #2 by paying its pro-rata 10% share of all acreage costs in AMI #1 and its pro-rata 5% share of all acreage costs plus $100 per net mineral acre in AMI #2. In addition to the cash proceeds received from both closings, if Constellation achieves a 20% internal rate of return, it will reconvey 30% of the working interest it holds in wells and acreage in both AMI #1 and AMI #2 back to us.

Credit Facilities

During 2012, prior to repayment as described below, 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, which is secured by substantially all of our assets, had an initial borrowing base of $30 million. In August 2012, we borrowed $1.4 million under our credit facility to fund 50% of our portion of the Charles M. Baker #1H well and repaid $5 million in connection with the conveyance of 3,801 net acres to Constellation, which reduced the borrowing base of our credit facility to $25 million. As of September 2, 2012, we had $17.9 million in outstanding borrowings under our credit facility and remaining undrawn capacity of $7.1 million. We anticipate using the

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remaining capacity of our credit facility to fund 50% of our portion of the drilling and completion costs for our next two 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:

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

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.

The credit facility contains certain covenants that, among other things:

• limit our investments, loans and advances and the payment of dividends and other restricted payments;

• limit our incurrence of additional indebtedness;

• prohibit the granting of liens, other than liens created pursuant to the credit facility and certain permitted liens;

• prohibit mergers, consolidations and sales of all or a substantial part of our business or properties without lender consent;

49

• limit general and administrative costs, other than our landmen, to $2.25 million during any three consecutive months; and

• limit our capital expenditures to the extent such expenditures reduce our unrestricted cash balance below $7 million without lender consent.

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:

• after three wells have been online and producing for 60 days: 40%;

• after five wells have been online and producing for 60 days: 50%; and

• after ten wells have been online and producing for 60 days: 60%.

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:

• failure to pay any principal or interest due under our credit agreement;

• failure to perform or otherwise comply with the covenants in the credit agreement;

• bankruptcy or insolvency events involving us or our subsidiaries;

• the entry of a judgment, order, decree, or arbitration award of more than $100,000 individually or $200,000 in the aggregate;

• a change of control, as defined in the credit agreement;

• failure to operate our oil & gas properties in a prudent manner;

• 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; and

• a change in management such that either Hunt Pettit ceases to be our Chief Executive Officer or Brian Nelson ceases to be our Chief Financial Officer and a replacement approved by Guggenheim is not installed within 30 days.

Other Sources of Liquidity

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 25% non-operated working interest, commenced drilling. We expect to commence production in the third quarter of 2012. In August 2012, the Charles M. Baker #1H well, in which we have a 25% non-operated working interest, commenced drilling. We expect to commence production from this well before the end of the fourth quarter of 2012. In September 2012, the WD Smith #1H well, in which we have a 25% non-operated working interest, commenced drilling. We expect to commence production from this well before the end of the fourth 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.

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Liquidity Outlook

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 and excluding the purchase price for the Chesapeake acquisition, of approximately $400 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 June 30, 2012, we had a working capital deficit, as measured by current assets less current liabilities, of $2.1 million. However, we believe that actions subsequent to June 30, 2012, including our disposition of working interests to Halcón and Constellation, and entry into our credit facility in June 2012 have provided us with sufficient liquidity to support our requirements.

Cash Flows

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.

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Cash flows used in operating activities

Net cash used in operating activities was $3.1 million for the six months ended June 30, 2012 compared to net cash used in operating activities of $0.4 million for the six months ended June 30, 2011. The increase of $2.7 million was primarily due to an increase in general and administrative expenses of $1.4 million, and an increase in interest expense of $1.1 million in 2012, compared to 2011.

Net cash used in operating activities was $1.1 million for the year ended December 31, 2011 compared to $2.6 million for the year ended December 31, 2010. The decrease of $1.5 million was primarily due to a decrease in general and administrative expenses of $0.8 million in 2011 compared to 2010, as well as $0.6 million of additional cash used to fund changes in accounts receivable in 2010 compared to 2011.

Cash flows provided by (used in) investing activities

Net cash provided by investing activities was $7.7 million for the six months ended June 30, 2012 compared to net cash used in investing activities of $8.7 million for the six months ended June 30, 2011. This increase in cash from investing activities of $16.4 million was primarily due to an increase in proceeds from disposals of oil and gas working interests of $31.9 million, offset by an increase in acquisitions of unevaluated oil and natural gas properties of $13.6 million and of additions to evaluated oil and natural gas properties of $1.5 million for the six months ended June 30, 2012 compared to the six months ended June 30, 2011.

Net cash used in investing activities was $17.8 million for the year ended December 31, 2011 compared to cash provided by investing activities of $2.4 million for the year ended December 31, 2010. This decrease in cash flows from investing activities of $20.2 million was primarily due to a decrease in proceeds from sales of leasehold interests of $43.2 million, which was offset by a decrease in acquisitions of leasehold interests of $22.9 million for 2011 as compared to 2010.

Cash flows provided by financing activities

Net cash provided by financing activities was $0.4 million for the six months end June 30, 2012 compared to net cash provided by financing activities of $9.5 million for the six months ended June 30, 2011. The primary source of cash during the six months ended June 30, 2012 was $16.9 million of proceeds of borrowings under the credit facility, net of deposits, offset by payments of $14.3 million of the preexisting note payable, $1.3 million of loan origination costs, and $0.8 million of prepaid offering costs. For the six months ended June 30, 2011, the primary source of financing cash was proceeds from investment deposits of $9.4 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.

Obligations and Commitments

We had the following contractual obligations and commitments as of June 30, 2012:

	Obligations and Commitments Due By Period
	Total		2012		2013 to 2014		2015 to 2016		2017 & Beyond
	(in thousands)
Guggenheim credit facility(1)	$	21,471	$	—	$	21,471	$	—	$	—
Contractual lease payments		331		134		197		—		—
Total contractual obligations	$	21,802	$	134	$	21,668	$	—	$	—

(1) In August 2012, we borrowed $1.4 million under our credit facility to fund 50% of our portion of the Charles M. Baker #1H well and repaid $5 million in connection with the conveyance of 3,801 net acres to Constellation for $24.7 million.

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Critical Accounting Policies and Estimates

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 adopted 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.

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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.

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Recent Accounting Pronouncements

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.

Internal Controls and Procedures

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. We are in the process of implementing sufficient accounting and financial reporting systems, processes, and personnel in order to adequately support our development strategy and to comply with public reporting requirements.

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

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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

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.

Quantitative and Qualitative Disclosures About Market Risk

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 August 31, 2012, we had $17.9 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.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

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BUSINESS

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 43,012 net acres as of August 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 12,826 net acres in our Eaglebine core area. Recently we have entered into two agreements with a subsidiary of Halcón Resources Corporation, or Halcón, and one agreement with a subsidiary of Constellation Energy Commodities Group, Inc., or Constellation, related to the Eaglebine. These agreements, which are described further under “—Our Core Areas—Eaglebine” below, provided for our conveyance of operated working interests in substantially all of our Eaglebine acreage and established two areas of mutual interest, which we refer to as AMI #1 and AMI #2. We also signed a purchase and sale agreement on September 10, 2012 to acquire 57,275 net acres in the Eaglebine with an operated 100% working interest from subsidiaries of Chesapeake Energy Corporation, or Chesapeake, for $125 million, subject to customary purchase price adjustments. We refer to this transaction as the Chesapeake acquisition and expect to close the transaction in the fourth quarter of 2012. This agreement is described further under “—Our Core Areas—Eaglebine” below. In addition to our acreage in the Eaglebine, we have 13,254 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, including the acreage we expect to acquire in the Chesapeake acquisition, could contain a total of 1,254 net drilling locations, of which a majority 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 August 31, 2012 and the acreage we will acquire in the Chesapeake acquisition, and our drilling capital budget from July 1, 2012 to December 31, 2013. We have also budgeted estimated capital expenditures of $26 million for leasehold acquisitions (excluding the Chesapeake acquisition) 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.”

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	Net Acres		Acre Spacing		Potential Net Drilling Locations(1)		Drilling Capital  Budget July 1, 2012 - December 31, 2013
							Net Wells		(in millions)
Eaglebine:
Current Eaglebine(2):
Horizontal Woodbine/Eagle Ford		12,826		120		107		16	$	111
Vertical Lower Cretaceous		12,826		160		80		5	$	15
Total		12,826				187		21	$	126
Chesapeake Eaglebine Acquisition(3):
Horizontal Woodbine/Eagle Ford		57,275		120		477		21	$	147
Vertical Lower Cretaceous		57,275		160		358		—	$	—
Total		57,275				835		21	$	147
Total Eaglebine		70,101				1,022		42	$	273
Wolfcamp(4):
Horizontal Wolfcamp		13,254		160		83		11	$	87
Horizontal Cline		13,254		160		83		—	$	—
Total Wolfcamp		13,254				166		11	$	87
Niobrara(4):
Horizontal Niobrara		16,350		320		51		—	$	—
Vertical Codell/Niobrara		581		40		15		15	$	10
Total Niobrara		16,931				66		15	$	10
Total (including the Chesapeake acquisition(5)		100,287				1,254		68	$	370

⁽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⁾  25% non-operated working interest in AMI #1, 15% non-operated working interest in AMI #2, and 100% operated working interest outside AMIs.

⁽³⁾  100% operated working interest. 17,990 net acres are subject to AMI #1 and AMI #2 and may be conveyed to Halcón and Constellation if they elect to purchase their pro rata working interest. Information in this table and elsewhere in this prospectus regarding net acreage, potential net drilling locations, and net wells to be drilled with respect to the Chesapeake acquisition does not give effect to the potential conveyance of net acreage to Halcón or Constellation.

⁽⁴⁾  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.

⁽⁵⁾  Certain totals may not add due to rounding.

Our Core Areas

Eaglebine

As of August 31, 2012, we owned 12,826 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 current 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. The majority of the leases associated with the Chesapeake acquisition are within the first two years of their three-year primary term and generally provide for two year extension options. Giving effect to the Chesapeake acquisition, we estimate that we have 1,022 net drilling locations in the Eaglebine. Through the end of 2013, we plan to drill 37 net horizontal wells and 5 net vertical wells and have budgeted $273 million for estimated drilling capital expenditures in the Eaglebine.

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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. 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 August 31, 2012. In the final closing under the agreement scheduled for September 2012, we estimate that we will convey to Halcón a 65% operated working interest in an additional 7,911 net acres (5,142 net to Halcón) for approximately $7.7 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 net acre conveyed to Halcón, or an estimated total of $29.9 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, 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 29,851 net acres for total proceeds of $74.6 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 purchase and sale 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 August 31, 2012, we had acquired 3,105 net acres in AMI #2 of which we expect to convey 2,484 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.

In August 2012, we entered into a purchase and sale agreement with Constellation and sold a 10% non-operated working interest in our Eaglebine acreage in AMI #1 and a 5% non-operated working interest in AMI #2 for $6,500 per net acre. Pursuant to the first closing under this agreement, we conveyed 3,801 net acres in AMI#1 to Constellation for $24.7 million and received $0.8 million as reimbursement for Constellation’s 10% share of the Covington #1H well described below. The final closing under this agreement is scheduled for September 2012, and we estimate that we will convey 928 net acres in AMI #1 and 160 net acres in AMI #2 to Constellation for total consideration of $7.1 million plus $1.7 million as reimbursement for subsequent Eaglebine wells. Following the final closings with both Halcón and Constellation in September 2012, we will retain a 25% working interest in AMI #1 and a 15% working interest in AMI #2. For future acquisitions, Constellation can elect to participate in AMI #1 or AMI #2 by paying its pro-rata 10% share of all acreage costs in AMI #1 and its pro-rata 5% share of all acreage costs plus $100 per net mineral acre in AMI #2. In addition to the cash proceeds received from both closings, if Constellation achieves a 20% internal rate of return, it will reconvey 30% of the working interest it holds in wells and acreage in both AMI #1 and AMI #2 back to us.

In September 2012, we entered into a purchase and sale agreement with Chesapeake to acquire a 100% working interest in Chesapeake’s 57,275 net undeveloped acres in the Eaglebine for $125 million, subject to customary purchase price adjustments. The closing date for this transaction is scheduled for October 31, 2012, but we may extend the closing date to a date not later than December 14, 2012 for an additional $3 million

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payment. The 57,275 net acres, which are located in Madison, Grimes, Leon, Robertson, and Houston Counties, would increase our total Eaglebine position to 70,099 net acres. We are required to offer our partners, Halcón and Constellation, their pro rata working interest in acreage that we acquire in AMI #1 and AMI #2. If Halcón and Constellation elect to purchase their pro rata working interest in AMI #1 and AMI #2, we would expect to convey approximately 17,990 net acres (16,509 net to Halcón and 1,480 net to Constellation) out of the 57,275 net acres, thereby leaving us with 39,285 net acres from this transaction and a total of 52,111 net acres in the Eaglebine. If Halcón elects to purchase its pro rata working interest, Halcón would be the operator on the AMI #1 and AMI #2 acreage. Information in this prospectus regarding net acreage, potential net drilling locations, and net wells to be drilled with respect to the Chesapeake acquisition does not give effect to the potential conveyance of net acreage to Halcón or Constellation. For additional information regarding the Chesapeake acquisition, including certain terms of the purchase and sale agreement, see “Business—Chesapeake Acquisition.”

We commenced drilling our first Halcón-operated well in AMI #1, the Covington #1H in which we have a 25% 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 sidetracked and drilled the well laterally for 1,000 feet and plan to complete the well with a four stage hydraulic fracture stimulation in the Woodbine formation. We anticipate this well will commence production before the end of September 2012.

We added a second drilling rig to our Eaglebine acreage in August 2012 and commenced drilling our second Halcón-operated well in AMI #1, the Charles M. Baker #1H, in which we have a 25% non-operated working interest. We plan to drill the lateral to 6,000 feet and complete the well with a 30 plus stage hydraulic fracture stimulation in the Eagle Ford Shale. We anticipate this well will commence production before the end of the fourth quarter of 2012.

We commenced drilling our third Halcón-operated well in AMI #1, the WD Smith #1H, in which we have a 25% non-operated working interest, in September 2012. We plan to drill the lateral to 5,850 feet and complete the well with a 25 plus stage hydraulic fracture stimulation in the Eagle Ford Shale. We anticipate this well will commence production before the end of the fourth 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 with average estimated ultimate recoveries, or EURs, of 400,000 to 500,000 boe per well and initial 30-day average production of 400 to 1,200 boe/d per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur or the results we will achieve from our wells.

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 228 filed in 2012 through August 31 in the Eaglebine. According to estimates prepared by Baker Hughes Incorporated, there were 20 rigs operating in the Eaglebine as of August 31, 2012.

Wolfcamp

As of August 31, 2012, we owned 13,254 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

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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 166 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 with average EURs of 420,000 to 570,000 boe per well and initial 30-day average production of 525 to 600 boe/d per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur or the results we will achieve from our wells.

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 88 filed in 2012 through August 31 in Lynn, Lubbock, Hockley, and Terry Counties, Texas, which offset our acreage position. According to estimates prepared by Baker Hughes, there were 511 rigs operating in the Permian Basin as of August 31, 2012.

Niobrara

As of August 31, 2012, we owned 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 with average EURs of 250,000 to 500,000 boe per well and initial 30-day average production of 300 to 600 boe/d per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur or the results we will achieve from our wells.

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,

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Inc., there were 2,903 drilling permits filed in 2011 and 1,408 filed in 2012 through August 31 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 46 rigs operating in the Denver-Julesburg Basin as of August 31, 2012.

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. We plan to drill 42 net wells and spend $273 million through 2013 in the Eaglebine alone. In addition, we plan to drill 11 net wells and spend $87 million in the Wolfcamp, and we plan to drill 15 net wells and spend $10 million in the Niobrara, through the end of 2013. We believe our 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 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. On our operated acreage, 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 had an initial borrowing base of $30 million. In August 2012, we borrowed $1.4 million under our credit facility to fund 50% of our portion of the Charles M. Baker #1H well and repaid $5 million in connection with the conveyance of 3,801 net acres to Constellation, which reduced the borrowing base of our credit facility to $25 million. As of September 2, 2012, the credit facility had a borrowing base of $25 million, and we had $17.9 million in outstanding borrowings. 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 June 30, 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.

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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.    Giving effect to the Chesapeake acquisition, we expect to have accumulated a total of 100,287 net acres 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, although such activity may not be indicative of our future operations. We believe that lease terms in our three core areas allow us enough time to conduct our internal geologic analysis and drill wells needed for the majority of our acreage to be held by production based on our current drilling plan.

Substantial drilling inventory.    Based on our current acreage position of 43,012 net acres and giving effect to the Chesapeake acquisition of 57,275 net acres, we estimate there could be up to 1,254 net potential drilling locations on our acreage. Through the end of 2013 we anticipate drilling 37 net horizontal Eaglebine wells, 5 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.

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.

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 have built large acreage positions in several developing unconventional plays. 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 stockholders. Our management has been and will continue to be compensated with equity incentives and 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.

Chesapeake Acquisition

In September 2012, we entered into a purchase and sale agreement with Chesapeake to acquire a 100% working interest in Chesapeake’s 57,275 net undeveloped acres in the Eaglebine for $125 million, subject to adjustment as described below. In connection with signing the agreement, we will deposit $3.5 million with Chesapeake, which will be applied to the purchase price at closing. The purchase price will be subject to customary pre- and post-closing adjustments, including for uncured title and environmental defects (to the extent the defects exceed minimum thresholds individually and 2% of the purchase price in the aggregate), exercises by third parties of preferential purchase rights or failure to receive required third party consents, and certain lease expiration defects.

The closing date for this transaction is scheduled for October 31, 2012, but we can elect to delay the closing date to a date not later than December 14, 2012 for an additional $3 million payment. The $3 million payment would not be applied to the purchase price at the closing. Closing is subject to customary conditions. The purchase and sale agreement provides for an effective date of June 1, 2012 and includes customary representations and warranties of the parties. The sellers are required to indemnify us for certain losses,

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including losses resulting from breaches by the sellers of the purchase and sale agreement and the ownership and operation of the acquired leases prior to the effective date. We may not make claims under the sellers’ indemnity obligations unless individual claims exceed $50,000 and aggregate claims exceed 2% of the unadjusted purchase price. Additionally, the sellers’ liability for indemnification is capped at 10% of the unadjusted purchase price. We will be required to indemnify the sellers for certain losses, including losses resulting from breaches by us of the purchase and sale agreement and the ownership and operation of the acquired leases after the effective date.

We are required to offer our partners, Halcón and Constellation, their pro rata working interest in acreage that we acquire in AMI #1 and AMI #2 in the Chesapeake acquisition. If Halcón and Constellation elect to purchase their pro rata working interest of the acreage to be acquired from Chesapeake in AMI #1 and AMI #2, we would expect to convey approximately 17,990 net acres (16,509 net to Halcón and 1,480 net to Constellation) out of the 57,275 net acres, thereby leaving us with 39,285 net acres from this transaction and a total of 52,112 net acres in the Eaglebine. If Halcón elects to purchase its pro rata working interest, Halcón would be the operator on the AMI #1 and AMI #2 acreage. The information in this prospectus regarding the net acreage, net drilling locations and net wells to be drilled with respect to the Chesapeake acquisition does not give effect to potential elections by Halcón or Constellation to purchase their pro rata working interests.

Our Operations

Acreage

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

	Undeveloped Acres				Developed Acres				Total				% of Acreage Held-by- Production
	Gross		Net		Gross		Net		Gross		Net
Eaglebine		49,909		12,826		—		—		49,909		12,826		0.0	%
Wolfcamp		13,254		13,254		—		—		13,254		13,254		0.0	%
Niobrara		16,916		16,915		39		16		16,955		16,931		0.1	%
Total(1)		80,079		42,996		39		16		80,118		43,012		0.0	%
Chesapeake Eaglebine(2)		53,051		53,051		4,224		4,224		57,275		57,275		7.4	%
Total with Chesapeake(1)		133,131		96,048		4,262		4,239		137,393		100,287		4.2	%

⁽¹⁾  Certain totals may not add due to rounding.

⁽²⁾  Information in this table does not give effect to the potential conveyance of net acreage to Halcón or Constellation.

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Undeveloped acreage expirations

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

	2012					2013					2014					2015 and thereafter
	Gross		Net			Gross		Net			Gross		Net			Gross		Net
Eaglebine		249		62			6,799		1,700			15,680		4,412			27,180		6,652
Wolfcamp		—		—			—		—			11,178		11,178			2,076		2,076
Niobrara		—		—			—		—			655		655			16,299		16,276
Total(1)		249		62			6,799		1,700			27,513		16,245			45,555		25,004
Chesapeake Eaglebine(2)		2,444		2,444			23,412		23,412			25,057		25,057			2,138		2,138
Total with Chesapeake(1)		2,693		2,506			30,211		25,112			52,570		41,303			47,694		27,142
% of total				3	%				26	%				43	%				28	%

⁽¹⁾  Certain totals may not add due to rounding.

⁽²⁾  Information in this table does not give effect to the potential conveyance of net acreage to Halcón or Constellation.

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.

Productive wells and drilling activity

As of August 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 August 31, 2012, we had three gross (0.75 net) Halcón operated wells in the process of drilling: the Covington #1H, the Charles M. Baker #1H and the WD Smith #1H wells in the Eaglebine AMI #1.

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Capital Budget

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:

	Capital Expenditure Budget July 1, 2012 - December 31,  2013
	Net Wells		(in millions)
Drilling & Completion:
Current Eaglebine		21	$	126
Chesapeake Eaglebine Acquisition		21	$	147
Wolfcamp		11	$	87
Niobrara		15	$	10
Drilling & Completion Total		68	$	370
Leasehold Acquisition:
Eaglebine			$	11
Wolfcamp			$	10
Niobrara			$	5
Leasehold Acquisition Total			$	26
Other:
Eaglebine Seismic			$	4
Other Total			$	4
Total		68	$	400

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.”

Title to Properties

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.”

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Oil and Natural Gas Leases

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 to the 8/8ths generally range from 25% to 29.25%, resulting in a net revenue interest to us generally ranging from 70.75% to 75%, 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%.

Competition

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.”

Hydraulic Fracturing

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.

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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.”

Regulation of the Oil and Natural Gas Industry

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.

Regulation of Transportation of Oil

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

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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.

Regulation of Transportation and Sales of Natural Gas

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

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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 ade 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.

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Regulation of Production

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.

Other Federal Laws and Regulations Affecting Our Industry

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

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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.

Environmental, Health and Safety Regulation

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.

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Hazardous Substances and Waste

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.

Pipeline Safety and Maintenance

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.

On December 13, 2011, Congress passed the Pipeline Safety and Regulatory Certainty Act (PSRCA). The PSCRA imposes significant new records verification obligations on pipeline operators, requires the reconfirmation of the maximum allowable operating pressure of pipe for which records cannot be identified, and requires the Pipeline and Hazardous Materials Safety Administration (PHMSA) to study the status of cast iron pipe replacement. PSRCA also seeks to promote the use of one-call systems and requires PHMSA to

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conduct rulemakings on a variety of issues. Because PHMSA has not completed the rulemaking process, the financial and operational consequences of PSRCA are not yet known. 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.

Air Emissions

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. 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.

Climate Change

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.

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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.

Water Discharges

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.

Endangered Species Act, Migratory Birds, Natural Resources Damages

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.

Employee Health and Safety

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.

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Other Laws

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.

Legal Proceedings

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.

Employees

As of August 31, 2012, we employed 37 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 9 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.

Offices

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.

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MANAGEMENT

Directors, Executive Officers and Key Employees

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

Name	Age		Position
B. Hunt Pettit		42	Director, President and Chief Executive Officer
Brian C. Nelson		42	Executive Vice President and Chief Financial Officer
Joseph C. Daches		45	Executive Vice President and Chief Accounting 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
Enick E. Diffee		57	Director Nominee(1)
David M. Fender		65	Director Nominee(1)
Rosser Newton		47	Director Nominee(1)
Neal A. Stanley		65	Director Nominee(1)
Nicholas Steinsberger		48	Director Nominee(1)

⁽¹⁾  These individuals will become directors in connection with the completion of this offering.

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

Name	Age		Position
Steven C. Wilson		55	Senior Vice President—Geophysics and Geological Engineering
John C. Evans		61	Senior Vice President—Reservoir Engineering
Chad Galloway		44	Senior Vice President—Land and Operations
Robert G. Karpman		50	Executive Vice President—Business Operations and Development

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

B. Hunt Pettit, Director, President and Chief Executive Officer

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. 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.

Brian C. Nelson, Executive Vice President and Chief Financial Officer

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

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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.

Joseph C. Daches, Executive Vice President and Chief Accounting Officer

Mr. Daches has served as our Executive Vice President and Chief Accounting Officer since September 2012 and has more than 20 years of SEC reporting, technical accounting, management and oil and gas accounting experience, primarily within the energy industry. Prior to joining us, he served as Partner and Managing Director of the Willis Consulting Group, LLC from January 2012 to September 2012. From October 2003 to January 2012, Mr. Daches served as the Director of Financial Reporting at Sirius Solutions, LLLC, where he was primarily responsible for SEC reporting, technical accounting and the overall management of the E&P advisory services practice. Mr. Daches has also held positions as a Controller and a Chief Financial Officer within the energy industry. Mr. Daches earned a Bachelor of Science in Accounting from Wilkes University, and he is a CPA in good standing with the Texas State Board of Accountancy.

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.

Lawrence “Laurie” Van Ingen, Executive Vice President—Geology

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. 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 at Austin.

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Enick E. Diffee, Director Nominee

Mr. Diffee will become a director of the Company upon the closing of this offering. Mr. Diffee has over 30 years of experience in the oil and natural gas industry, working in multiple basins and serving in multiple capacities. Mr. Diffee was the founder and president of Trinity Resources in Roswell, New Mexico, initiating and managing land acquisitions and divestitures in the South and Southeast United States from 1997 to 2007. Prior to that, Mr. Diffee was the founder and president of Trinity L.P. in Roswell, New Mexico, focusing on acquisitions and divestitures of producing oil and gas properties from 1992 to 1997. Prior to that Mr. Diffee worked as a landman and served in related capacities for Hondo Oil & Gas Company, Gulf Oil Company, Continental Oil Company and other independent oil and natural gas companies. Mr. Diffee earned a Bachelor of Business Administration in Personnel Administration from Eastern New Mexico University.

Mr. Diffee brings years of hands-on experience with oil and natural gas companies in many capacities and across multiple basins. For these reasons, we believe Mr. Diffee is qualified to serve as a director of our company.

David M. Fender, Director Nominee

Mr. Fender will become a director of the Company upon the closing of this offering. Mr. Fender has over 37 years of experience in the oil and natural gas industry. He has served as the Principal and Managing Partner of Fender Exploration and Production Company, L.P. since January 2001 and was the President and Managing Partner of such company for the ten years prior to that. From 1985 to 1996, Mr. Fender served as President and Chief Executive Officer of Thor Energy Resources Inc., a publicly traded company listed on the American Stock Exchange, Mr. Fender has also served on the board of directors of Kilgore First Corporation, Tahoka Bank Corporation, Charter Bank Northwest and Cedar Creek State Bank, all banking organizations in Texas as well as multiple non-profit organizations. Mr. Fender earned a Graduate Banking Degree from the Cox School of Business at SMU and a Bachelor of Journalism degree from the University of Texas at Austin.

Mr. Fender has experience in leading a public oil and natural gas company and possesses significant business, leadership and management skills. Mr. Fender also brings noteworthy prior board service experience to our board. For these reasons, we believe Mr. Fender is qualified to serve as a director of our company.

Rosser Newton, Director Nominee

Mr. Newton will become a director of the Company upon the closing of this offering. Since its founding in 2002, Mr. Newton has been the Managing Member of the various legal entities that comprise Petro Capital, an energy focused merchant and investment bank (“Petro Capital”). Prior to founding Petro Capital in 2002, Mr. Newton was an investment banker for energy companies. Mr. Newton is currently serving as Chairman of the Board of Lynx Pressure Solutions, LLC, an oilfield services company, since January 2012; as a board member of EagleRidge Energy, LLC, an exploration and production company, since February 2009; and as a board member of Shack Energy Services, Inc., an oilfield services company, since December 2009. Mr. Newton previously served as Chairman of the Board of Directors of Cougar Pressure Control, Inc., an oilfield services company, from 2005 to 2008, and Chairman of the Board of Managers of EagleRidge Energy, LLC from 2009 to 2010. Mr. Newton earned Juris Doctor from the University of Texas School of Law and a Bachelor of Arts in Political Science from Vanderbilt University.

Mr. Newton’s financial and investment banking expertise has been invaluable to us in our efforts to grow through additional financing and capital. Additionally, he has prior experience as board member of several companies. For these reasons, we believe Mr. Newton is qualified to serve as a director of our company.

Neal A. Stanley, Director Nominee

Mr. Stanley will become a director of the Company upon the closing of this offering. Mr. Stanley has over 37 years of experience as a petroleum engineer. Mr. Stanley currently serves on the board of directors of Great

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Western Oil and Gas Company and National Fuel Corporation, both private production companies. Previously, Mr. Stanley served on the board and audit committee of Delta Petroleum Corporation (OTC Bulletin Board: DPTRQ) from August 2004 to February 2009. Mr. Stanley retired from his position of Corporate Director at Delta Petroleum in February 2009. Mr. Stanley served on the board and audit and compensation committees of Pure Energy Services Ltd, a Calgary, Canada based company on the Toronto Exchange, PVS.TO, from May 2005 to December 2009. Prior to that, Mr. Stanley served as Senior Vice president of the U.S. Western Region for Forest Oil Corporation where he was responsible for exploration and production and implementation of the operational planning system. Prior to that, in 1991 he founded Teton Oil and Gas Company focusing on Rocky Mountain prospects with a joint venture with Pacific Enterprises Oil Company and Hunt Oil Company. Prior to that, Mr. Stanley served at Terra Resources, a medium-sized independent oil company, as Rocky Mountain Regional Vice President focused on exploration and production and reserve and operation planning. He began his career as an engineer with Amoco Production Company in 1975. Mr. Stanley served in the U.S. Army as a medical corpsman from 1966 to 1969, and he flew 746 helicopter medevac missions in Vietnam. Mr. Stanley earned a BS in Mechanical Engineering from the University of Oklahoma in 1975.

Mr. Stanley has substantial prior board service, including service on the board of two public oil and gas companies, and is an accomplished petroleum engineer in our industry. For these reasons, we believe Mr. Stanley is qualified to serve as a director of our company.

Nicholas Steinsberger, Director Nominee

Mr. Steinsberger will become a director of the Company upon the closing of this offering. Mr. Steinsberger has 25 years of experience as a petroleum engineer. He is currently the principal of Steinsberger Tight Gas Consulting, drilling and completion engineering consulting firm he founded in 2005. Prior to this, Mr. Steinsberger served as Vice President of Engineering for Republic Energy, a private exploration and production company. Mr. Steinsberger served in various capacities at Mitchell Energy until its sale to Devon Energy in January 2002, most recently as the Completion Manager for the Barnett Shale of Devon Energy. Mr. Steinsberger earned a BS in Petroleum Engineering from the University of Texas at Austin.

Mr. Steinsberger has extensive technical experience in drilling and completion of shale and tight oil and natural gas in addition to significant business and managerial skills by founding his own petroleum engineering consulting firm. For these reasons, we believe Mr. Steinsberger is qualified to serve as a director of our company.

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. From March 2003 to December 2010, Mr. Wilson worked at Amana Partners, Inc., an oil and natural gas exploration and development company, 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. Mr. Wilson is a highly skilled geophysical 2D and 3D seismic interpreter and computer programmer. Mr. Wilson earned a Bachelor of Science in Geological Engineering from the Colorado School of Mines.

John C. Evans, Senior Vice President—Reservoir Engineering

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. From 1986 to October 2010, Mr. Evans served as President of CreditPro, Inc., a credit software company. From 1974 to 1979, Mr. Evans worked at Phillips

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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.

Chad A. Galloway, Senior Vice President—Land and Operations

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.

Board of Directors

Our board of directors currently consists of one member, Hunt Pettit, our President and Chief Executive Officer. We intend to appoint six additional directors, contemporaneously with and following the completion of this offering, five of whom are named in this prospectus and have consented to serve. We anticipate that Messrs. Diffee, Fender, Stanley and Steinsberger will be independent as determined by our board of directors under the applicable securities law requirements and the independence standards of the NYSE and therefore that a majority of the members of our board will be independent upon completion of this offering. We expect that Mr. Pettit will serve as Chairman of the Board and that one of our independent directors will act as lead independent director.

In evaluating director candidates, we have assessed 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,

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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.

Committees of the Board of Directors

Upon the conclusion of this offering, we intend to have an audit committee, 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.

Audit Committee

We will establish an audit committee in connection with 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.

Compensation Committee

We will establish a compensation committee in connection with the completion of this offering consisting 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.

Nominating and Governance Committee

We will establish a nominating and governance committee in connection with the completion of this offering consisting 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.

Reserve Committee

We will establish a reserve committee in connection with the completion of this offering consisting of three independent directors. This committee will oversee the preparation by independent petroleum engineers of

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annual and any special reserve reports and/or audits of the estimated amounts of our hydrocarbon reserves and related information. Upon formation of the reserve committee, we expect to adopt a reserve committee charter defining the committee’s primary duties.

Compensation Committee Interlocks and Insider Participation

The directors serving on the compensation committee are not and will not at any time be one of our employees. 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.

Code of Business Conduct and Ethics

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.

Corporate Governance Guidelines

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.

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EXECUTIVE COMPENSATION

Summary Compensation Table

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.

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

Employment Agreements

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.

Overriding Royalty Interests

In August 2012 we completed the granting of overriding royalty interests in our acreage to our executive officers, including the named executive officers, certain other members of management, the limited partners of NASIF and the Niobrara investors. These overriding royalty interests entitle the holders to receive percentages 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. These percentages range from 0% to 2.5% in the Eaglebine, 0% to 2.2% in the Wolfcamp and 0% to 4.2% in the Niobrara. With respect to our named executive officers, B. Hunt Pettit, Lawrence B. Van Ingen, and Brian C. Nelson received overriding royalty interests ranging from 0% to 4.2%, 0% to 0.29% and 0% to 0.25%, respectively. As described under “Certain Relationships and Related Party Transactions—Corporate Reorganization,” the limited partners of NASIF and the Niobrara investors received overriding royalty interests in connection with our corporate reorganization. Following the completion of this offering, we do not intend to grant additional overriding royalty interests with respect to our properties, including properties we expect to acquire in the Chesapeake acquisition, to our executive officers or other employees.

Outstanding Equity Awards at Fiscal Year-End

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

2012 Stock Incentive Plan

In connection with our corporate reorganization, we adopted our 2012 Stock Incentive Plan. The following is a summary of the plan, which is filed as an exhibit to the registration statement of which this prospectus forms a part. The purpose of the plan is to enable us to attract and retain the types of employees, consultants and directors who will contribute to our long range success, provide incentives that align the interests of employees, consultants and directors with those of our stockholders and promote the success of our business.

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Eligibility.    Employees, consultants and directors of us and our affiliates are eligible to participate in the plan.

Administration.    Upon completion of this offering, our compensation committee will administer the plan and will generally be responsible for selecting participants from among eligible persons. Unless otherwise limited, the compensation committee will have broad discretion to administer the plan, including the power to determine to whom and when awards will be granted, to determine the amount of such awards (measured in cash, shares of common stock or otherwise), to prescribe the terms and conditions of each award, to accelerate the exercise terms of any award, to delegate duties under the plan and to execute all other responsibilities permitted or required under the plan.

Shares Available.    The maximum aggregate number of shares of our common stock that may be reserved and available for delivery in connection with awards under the plan is                 , subject to adjustment in accordance with the terms of the plan. Shares covered by awards that terminate by expiration, forfeiture, cancellation, or otherwise without the issuance of shares or are settled in cash will not count against this limit and can be regranted under the plan. Shares surrendered or withheld in payment of the exercise price of an option and shares withheld by us to satisfy any tax withholding obligation will count against the limit. Subject to adjustment in accordance with the terms of the plan, no more than                  shares may be subject to options or stock appreciation rights granted under the plan to any one participant during any one year period, and no more than                  shares may be subject to any other awards granted under the plan to any one participant during any one year period.

Terms of Options.    The compensation committee may grant (a) incentive stock options that comply with Section 422 of the Code to our employees and (b) nonqualified options to any eligible person under the Plan. Except as described below, the exercise price for an option must not be less than the fair market value per share of common stock as of the date of grant and may be exercised on such terms as the compensation committee determines, but not later than ten years from the date of grant. For participants who own 10% or more of the voting power of our outstanding stock, the exercise price for an option must not be less than 110% of the fair market value per share of common stock as of the date of grant and is not exercisable after the expiration of five years from the date of grant.

Terms of Stock Appreciation Rights.    SARs may be awarded in connection with or separate from an option. A SAR is the right to receive an amount equal to the excess of the fair market value of one share of our common stock on the date of exercise over the grant price of the SAR. SARs will be exercisable on such terms as the compensation committee determines. The term of an SAR will be for a period determined by the compensation committee but will not exceed ten years. SARs may be paid in cash, common stock or a combination of cash and common stock, as determined by the compensation committee in the award agreement.

Restricted Stock Awards.    A restricted stock award is a grant of shares of common stock subject to a risk of forfeiture, restrictions on transferability and any other restrictions determined by the compensation committee. Except as otherwise provided under the terms of the plan or an award agreement, the holder of a restricted stock award may have rights as a stockholder, including the right to vote or to receive dividends (subject to any mandatory reinvestment or other requirements determined by the compensation committee). Unless otherwise determined by the compensation committee, a restricted stock award will be forfeited and reacquired by us upon termination of employment other than death or disability. Common stock distributed in connection with a stock split or stock dividend, and other property distributed as a dividend, may be subject to the same restrictions and risk of forfeiture as the restricted stock with respect to which the distribution was made.

Restricted Stock Units.    Restricted stock units are rights to receive cash, common stock or a combination of cash and common stock at the end of a specified period. Restricted stock units may be subject to restrictions, including a risk of forfeiture, as determined by the compensation committee. Restricted stock units may be satisfied by cash, common stock or any combination of cash and common stock, as determined by the

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compensation committee. Unless otherwise determined by the compensation committee, restricted stock units will be forfeited upon termination of a participant’s employment other than death or disability. The compensation committee may, in its sole discretion, grant dividend equivalents with respect to restricted stock units.

Performance Awards.    The plan will provide for the grant of performance awards that may be granted in the form of cash, common stock or a combination of cash and common stock. Each performance award will set forth (a) the amount, including a target and maximum amount if applicable, the recipient may earn in the form of cash or shares of common stock or a formula for determining that amount, (b) the performance criteria and level of achievement versus the criteria that will determine the amount of cash payable or number of shares of our common stock to be granted, issued, retained and/or vested, (c) the performance period over which performance is to be measured, (d) the timing of any payments to be made, (e) restrictions on the transferability of the award and (f) such other terms and conditions as our compensation committee may determine. The maximum performance award payable to any one participant under the plan is                  shares of common stock, or cash equivalent thereof as determined by the compensation committee, and the maximum cash bonus that may be paid to any participant in any calendar year is $1 million.

On August 22, 2012, Brian C. Nelson was awarded 50,000 restricted shares of our common stock, 50% of which vest on the earlier of January 1, 2013 or the completion of this offering, and the remaining 50% of which vest on January 1, 2013. In addition, the restricted shares vest upon a change in control or death or disability. If Mr. Nelson’s employment terminates during the restricted period for any reason other than death or disability, his unvested shares are automatically forfeited.

On September 6, 2012, Lawrence B. Van Ingen was awarded 2,500 restricted shares of our common stock which vest ratably in three equal installments. The first vesting date is the earlier of January 1, 2013 or the completion of this offering, and the second and third vesting dates are the first and second anniversaries of the first vesting date. In addition, the restricted shares vest upon a change in control or death or disability. If Mr. Van Ingen’s employment terminates during the restricted period for any reason other than death or disability, his unvested shares are automatically forfeited.

Director Compensation

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:

• an annual cash retainer fee and cash payments for each board and committee meeting attended;

• an initial equity award of restricted stock; and

• an annual equity award of restricted stock.

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.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Corporate Reorganization

We were incorporated on July 31, 2012 pursuant to the laws of the State of Delaware as Energy & Exploration Partners, Inc. to become a holding company for our business. We recently completed a series of reorganization transactions described below, which we refer to collectively as our corporate reorganization.

Prior to the completion of our corporate reorganization, our business was 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 owned all of the equity interests in the general partner of NASIF, and the other investors owned all of the limited partner interests in NASIF. Mr. Pettit also owned all of the outstanding equity interests in North American Shale Investment Advisors, LLC, or NASIF Advisors, which was 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, owned additional net profits interests in our Niobrara acreage.

Our corporate reorganization consisted of the following transactions:

Contributions to Energy & Exploration Partners, Inc.    Pursuant to a contribution agreement, on August 22, 2012, the following contributions were made to us:

• Hunt Pettit, our founder, President and Chief Executive Officer, and an affiliated entity contributed the following interests to us in exchange for shares representing approximately 58% 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 contributed all of the outstanding limited partner interests in NASIF to us in exchange for shares representing approximately 20% of our outstanding common stock; and

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

The consideration for the contributions described above was determined through negotiations among us and the other parties to the contribution agreement.

Immediately prior to the contributions described above, the limited partners of NASIF and the Niobrara investors received overriding royalty interests in our acreage. For additional information regarding these overriding royalty interests and overriding royalty interests held by our executive officers, certain other members of our management and an entity affiliated with one of our non-employee directors, see “Certain Relationships and Related Party Transactions—Overriding Royalty Interests” and “Executive Compensation— Overriding Royalty Interests.” Additionally, we repurchased the net profits interests held by the Niobrara investors that were not parties to the contribution agreement for total cash payments of $1.7 million.

Following the contributions described above, we assigned our interests in Energy & Exploration Partners Operating, LP and in its general partner to Energy & Exploration Partners, LLC. Additionally, NASIF, its general partner and NASIF Advisors were merged into Energy & Exploration Partners, LLC, the investment management agreement between NASIF and NASIF Advisors was terminated, and the net profits interests in our acreage previously held by NASIF and the Niobrara investors were canceled.

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Energy & Exploration Partners, LLC also recently assigned its general partnership interest in Energy & Exploration Partners, LP to an affiliated entity of Hunt Pettit forde 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 made awards to members of our senior management, other than Mr. Pettit, of restricted shares of our common stock representing approximately 21% of our outstanding shares of common stock under our 2012 Stock Incentive Plan. These shares of restricted stock generally vest over a three-year period. See “Executive Compensation—2012 Stock Incentive Plan.”

Registration Rights Agreement.    In connection with our corporate reorganization, we entered 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 have demand and piggyback registration rights under which we are required to use our reasonable best efforts to register the resale of shares of our common stock held by these stockholders or their permitted transferees under certain circumstances at our expense.

Overriding Royalty Interests

In August 2012 we completed the granting of overriding royalty interests in our acreage to our executive officers, including the named executive officers, certain other members of management, the limited partners of NASIF and the Niobrara investors. These overriding royalty interests entitle the holders to receive percentages 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. These percentages range from 0% to 2.5% in the Eaglebine, 0% to 2.2% in the Wolfcamp and 0% to 4.2% in the Niobrara. As described under “—Corporate Reorganization,” the limited partners of NASIF and the Niobrara investors received overriding royalty interests in connection with our corporate reorganization. Oso + Toro Multi Strategy Fund Series Interests of the SALI Multi-Series Fund II 3(c)(1), L.P. and Oso + Toro Multi Strategy Fund (Tax Exempt) Segregated Portfolio of SALI Multi-Series Fund SPC, Ltd., former NASIF limited partners who each beneficially own more than 5% of our outstanding common stock, received overriding royalty interests ranging from 0% to 0.85% and 0% to 0.57%, respectively. Following the completion of this offering, we do not intend to grant additional overriding royalty interests with respect to our properties, including properties we expect to acquire in the Chesapeake transaction, to our executive officers or other employees.

Other Related Party 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.

On April 10, 2012, EX Operating LLC, a Texas limited liability company wholly owned by Enick Diffee, a director nominee, executed a Lease Purchase Agreement to purchase certain oil and natural gas leases in Lynn County, Texas from a third party 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.

In 2009, Mr. Diffee loaned Energy & Exploration Partners, L.P., which is no longer a subsidiary of us, $500,000 to purchase certain oil and natural gas leases in Atascosa County, Texas from the Jupe family.

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Mr. Pettit repaid Mr. Diffee the entire balance of the loan when he sold such leases to Comstock Oil & Gas, L.P. in late 2009. As consideration for his loan, Mr. Diffee received a 0.5% overriding royalty interest in the Jupe “A” 1H well, which he retained after the sale to Comstock.

Rosser Newton, a director nominee, is the Managing Member of Petro Capital XXV LLC. In September 2011, we entered into a senior secured note with Petro Capital XXV, LLC, the balance of which was periodically increased to a final balance of $15 million in March 2012. The note was repaid in June 2012 with borrowings from our new credit facility. In connection with the note, Petro Capital received a warrant to purchase 2.5% of Energy & Exploration Partners, LLC. In July 2012, we repurchased the warrant for $125,000. Petro Capital and certain of its related entities also received a 0.625% overriding royalty interests in approximately 25,000 of our acres in the Eaglebine, which survived the note. Pursuant to a consulting agreement, we paid Petro Capitol Advisors LLC, of which Mr. Newton is the Managing Member, $100,000 in 2011 and $200,000 in the first six months of 2012. The consulting agreement expired in June 2012.

Procedures for Approval of Related Person Transactions

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:

• any person who is, or at any time during the applicable period was, one of our executive officers, directors or director nominees;

• any person who is known by us to be the beneficial owner of more than 5.0% of our outstanding common stock;

• any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law, or any person (other than a tenant or employee) sharing the household; and

• any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10.0% or greater beneficial ownership interest.

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.

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PRINCIPAL AND SELLING STOCKHOLDERS

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 and nominee for director of Energy & Exploration Partners, Inc., (3) each of our named executive officers, and (4) all executive officers, directors and nominees for director as a group. The table also sets forth information regarding the shares of common stock that will be sold by the selling stockholders in this offering. As of            , 2012, there were             shares of our common stock outstanding giving effect to the            for            stock split that will be effected prior to completion of this offering. 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, and the sale by the selling stockholders of             outstanding shares of common stock in this offering. 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.

	Shares of Common Stock Beneficially Owned Prior to this Offering		Shares Offered Pursuant to this Prospectus	Shares of Common Stock Beneficially Owned After this Offering
Name of Beneficial Owner	Number	Percentage		Number	Percentage
Selling Stockholders
Scott Burk
Joseph C. Daches
John C. Evans
Chad Galloway
Robert G. Karpman
Tom D. McNutt
Brian C. Nelson
David L. Patty
Lawrence B. Van Ingen
Steven C. Wilson
Other Directors, Nominees and Named Executive Officers
B. Hunt Pettit
Enick E. Diffee
David M. Fender
Rosser Newton
Neal A. Stanley
Nicholas Steinsberger
All directors and executive officers as a group (11 persons)
Other 5% Holders
Oso + Toro Multi Strategy Fund Series Interests of the SALI Multi-Series Fund II 3(c)(1), L.P.(1)
Oso + Toro Multi Strategy Fund (Tax Exempt) Segregated Portfolio of SALI Multi-Series Fund SPC, Ltd.(1)

⁽¹⁾  The business address is 6836 Austin Center Boulevard, Suite 320, Austin, Texas 78731.

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DESCRIPTION OF CAPITAL STOCK

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.

Common Stock

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.

Preferred Stock

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

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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.

Opt Out of Section 203 of the Delaware General Corporation Law

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:

• the transaction is approved by the board of directors before the date the interested stockholder attained that status;

• upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced; or

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:

• establish advance notice procedures with regard to stockholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our stockholders. These procedures provide that notice of stockholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. Generally, to be timely, notice must be received at our principal executive offices not less than 90 days nor more than 120 days prior to the first anniversary date of the annual meeting for the preceding year. Our amended and restated bylaws specify the requirements as to form and content of all stockholders’ notices. These requirements may preclude stockholders from bringing matters before the stockholders at an annual or special meeting;

• provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

• provide that the authorized number of directors may be changed only by resolution of the board of directors;

• provide that all vacancies, including newly created directorships, may, except as otherwise required by law, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;

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• provide that any action required or permitted to be taken by the stockholders must be effected at a duly called annual or special meeting of stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders, subject to the rights of the holders of any series of preferred stock;

• provide that our certificate of incorporation and bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our then outstanding common stock; and

• provide that special meetings of our stockholders may only be called by the board of directors, the chief executive officer or the chairman of the board;

• provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms, other than directors who may be elected by holders of preferred stock, if any. For more information on the classified board of directors, please see “Management.” This system of electing and removing directors may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for stockholders to replace a majority of the directors; and

• provide that our bylaws can be amended or repealed at any regular or special meeting of stockholders or by the board of directors.

Limitation of Liability and Indemnification Matters

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:

• for any breach of their duty of loyalty to us or our stockholders;

• for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

• for unlawful payment of dividend or unlawful stock repurchase or redemption, as provided under Section 174 of the DGCL; or

• for any transaction from which the director derived an improper personal benefit.

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.

Transfer Agent and Registrar

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

Listing

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

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SHARES ELIGIBLE FOR FUTURE SALE

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.

Sales of Restricted Shares

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.

Lock-up Agreements

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.

Rule 144

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.

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Rule 701

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.

Stock Issued Under Employee Plans

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.

Registration Rights

We entered into a registration rights agreement in connection with our corporate reorganization pursuant to which we are required to use our reasonable best efforts to register the resale of shares of our common stock held by certain of our stockholders or their permitted transferees under certain circumstances at our expense. See “Certain Relationships and Related Party Transactions—Corporate Reorganization.”

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MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS TO NON-U.S. HOLDERS

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:

• an individual citizen or resident of the U.S.;

• a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in the U.S. or under the laws of the U.S. or any state or the District of Columbia;

• a partnership (or other entity treated as a partnership or other pass-through entity for U.S. federal income tax purposes);

• an estate whose income is subject to U.S. federal income tax regardless of its source; or

• a trust (x) whose administration is subject to the primary supervision of a U.S. court and which has one or more U.S. persons who have the authority to control all substantial decisions of the trust or (y) which has made a valid election to be treated as a U.S. person.

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.

Distributions

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

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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.

Gain on Disposition of Common Stock

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:

• the gain is effectively connected with a U.S. trade or business of the non-U.S. holder and, if required by an applicable tax treaty, is attributable to a U.S. permanent establishment maintained by such non-U.S. holder;

• the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met; or

• our common stock constitutes a “U.S. real property interest” by reason of our status as a U.S. real property holding corporation, or USRPHC, for U.S. federal income tax purposes at any time within the shorter of the five-year period preceding the disposition or the non-U.S. holder’s holding period for our common stock.

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

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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.

Backup Withholding and Information Reporting

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.

Additional Withholding Requirements

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.

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UNDERWRITING

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 among us, the selling stockholders and the representatives, we and the selling stockholders have agreed to sell to the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us and the selling stockholders, the number of shares of common stock set forth opposite its name below.

Underwriter	Number of Shares
Canaccord Genuity Inc.
Johnson Rice & Company L.L.C.
Total

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 and the selling stockholders 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.

Commissions and Discounts

The underwriters have advised us and the selling stockholders 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 and the proceeds to the selling stockholders. The information assumes either no exercise or full exercise by the underwriters of their option to purchase additional shares.

		Total
	Per Share	Without Over-allotment Exercise	With Over-allotment Exercise
Public offering price	$	$	$
Underwriting discount paid by us
Proceeds, before expenses, to us
Proceeds to selling stockholders

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

Option to Purchase Additional Shares

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.

Lock-Up Agreements

We, each of our executive officers and directors and each of our existing stockholders (including the selling 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):

• offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of any shares of our common stock, preferred stock or other capital stock, or any options or warrants to purchase any shares of our common stock, preferred stock or other capital stock, or any securities convertible into, exchangeable for or that represent the right to receive shares of our common stock, preferred stock or other capital stock, whether now owned or later acquired or owned directly or beneficially by the stockholder (including holding as a custodian);

• engage in any hedging or other transaction that is designed to or reasonably expected to lead to, or result in, a sale or disposition of such securities (such prohibited hedging or other transactions includes any short sale (whether or not against the box) or any purchase, sale or grant of any right (including any put or call option or any swap or other arrangements that transfers to another, in whole or in part, directly or indirectly, any of the economic consequences of ownership of such securities) with respect to any of such securities or with respect to any security that includes, relates to, or derives any significant part of its value from such securities); and

• file or cause the filing of any registration statement with respect to any of our common stock, preferred stock or other capital stock or any securities convertible into or exercisable or exchangeable for any of our common stock, preferred stock or other capital stock, other than certain registration statements filed to register securities to be sold to the underwriters pursuant to the underwriting agreement and to register common stock to be issued pursuant to certain of our stock compensation plans.

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

100

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.

New York Stock Exchange Listing

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.

Price Stabilization, Short Positions and Penalty Bids

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

101

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.

Electronic Distribution

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

Conflicts of Interest

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.

Notice to Prospective Investors in the European Economic Area

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:

A. to any legal entity which is a qualified investor as defined in the Prospectus Directive;

B. to fewer than 100 or, if the Relevant Member State has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the representatives; or

C. in any other circumstances falling within Article 3(2) of the Prospectus Directive,

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

102

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.

Notice to Prospective Investors in the United Kingdom

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.

Notice to Prospective Investors in Switzerland

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.

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Notice to Prospective Investors in the Dubai International Financial Centre

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.

Notice to Prospective Investors in Hong Kong, Singapore, and Japan

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.

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LEGAL MATTERS

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.

EXPERTS

The following financial statements included in this prospectus and the related registration statement have been audited by Hein & Associates LLP, an independent registered public accounting firm, as stated in their reports appearing elsewhere herein, and are included in reliance upon such reports and upon the authority of such firm as experts in auditing and accounting:

• Financial statements of Energy & Exploration Partners, Inc. as of July 31, 2012;

• 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;

• 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.

WHERE YOU CAN FIND MORE INFORMATION

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 ishttp://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 athttp://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.

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INDEX TO FINANCIAL STATEMENTS

	Page
Energy & Exploration Partners, Inc.
Unaudited Pro Forma Combined and Condensed Financial Statements:
Introduction		F-2
Unaudited Pro Forma Combined and Condensed Statement of Operations for the Year Ended December  31, 2011		F-4
Unaudited Pro Forma Combined and Condensed Statement of Operations for the Six Months Ended June  30, 2012		F-5
Unaudited Pro Forma Combined and Condensed Statement of Financial Position as of June 30, 2012		F-6
Notes to Unaudited Pro Forma Combined and Condensed Financial Statements		F-7
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 June 30, 2012 and December 31, 2011 and for the Six Months Ended June 30, 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-39
Combined and Consolidated Statement of Assets and Liabilities		F-40
Combined and Consolidated Statement of Operations		F-41
Combined and Consolidated Statement of Changes in Net Assets		F-42
Combined and Consolidated Statement of Cash Flows		F-43
Combined and Consolidated Schedule of Investments		F-44
Notes to the Combined and Consolidated Financial Statements		F-45
Unaudited Combined and Consolidated Financial Statements as of June 30, 2012 and December 31, 2011 and for the Six Months ended June 30, 2012 and for the period of inception (February 1, 2011) through June 30, 2011:
Combined and Consolidated Statement of Assets and Liabilities		F-50
Combined and Consolidated Statement of Operations		F-51
Combined and Consolidated Statement of Changes in Net Assets		F-52
Combined and Consolidated Statement of Cash Flows		F-53
Combined and Consolidated Schedule of Investments		F-54
Combined and Consolidated Supplemental Schedule of Investments		F-55
Notes to the Combined and Consolidated Financial Statements		F-56

F-1

ENERGY & EXPLORATION PARTNERS, INC.

UNAUDITED PRO FORMA COMBINED AND CONDENSED FINANCIAL STATEMENTS

INTRODUCTION

The unaudited pro forma combined and condensed statements of financial position of Energy & Exploration Partners, Inc. (the “Company”) as of June 30, 2012 and the unaudited pro forma combined and condensed statements of operations for the year ended December 31, 2011 and the six month period ended June 30, 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 six month period ended June 30, 2012 have been prepared as if the transactions had occurred on June 30, 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 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 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 Company’s corporate reorganization, as follows:

• Hunt Pettit contributed his equity interests in ENXP, except for the interest in Energy & Exploration Partners, LP, to the Company;

• the owners of NASIF contributed all of their outstanding ownership interests in NASIF to the Company; and

F-2

ENERGY & EXPLORATION PARTNERS, INC.

UNAUDITED PRO FORMA COMBINED AND CONDENSED FINANCIAL STATEMENTS

• certain of the Niobrara investors contributed their net profits interests in our Niobrara acreage to the Company for common stock, and others accepted cash payments in return for a release of our obligation to provide returns.

• The Company sold a 65% working interest in its Eaglebine assets acquired after June 30, 2012 on July 31, 2012 for $3.2 million, and sold a 10% working interest in all of its Eaglebine assets for $25.5 million (comprised of the sales price of $24.7 million and the reimbursement of well costs of $0.8 million).

• The Company made a non-refundable deposit on September 10, 2012 as part of its purchase of acreage from Chesapeake.

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.

Energy & Exploration Partners, Inc. has issued 500,000 common shares, which were assumed to be issued and outstanding during each of the respective periods for purposes of computing earnings per share. Potentially dilutive warrants outstanding as of December 31, 2011 and June 30, 2012 were antidilutive for purposes of the amount of weighted average common shares outstanding, fully diluted.

F-3

ENERGY & EXPLORATION PARTNERS, INC.

UNAUDITED PRO FORMA COMBINED AND CONDENSED STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2011

(in thousands, except for per share amounts)

	Combined ENXP Historical			Combined and Consolidated NASIF Historical			Pro Forma Adjustments			Energy & Exploration Partners, Inc. As Adjusted
REVENUES	$	1,129		$	—		$	(1,129	)(g)	$	—
OPERATING EXPENSES		2,333			135			(556	)(g)		1,912
LOSS FROM OPERATIONS		(1,204	)		(135	)		(573	)		(1,912	)
OTHER INCOME (EXPENSE)
Other income		21			—			—			21
Interest income		4			—			—			4
Interest expense		(270	)		—			(2,834	)(b)		(3,104	)
Gain on sale of assets		—			—			573	(g)		573
Unrealized gain on investments		—			20,683			(20,683	)(d)		—
Total other income (expense)		(245	)		20,683			(22,944	)		(2,506	)
INCOME (LOSS) BEFORE INCOME TAX EXPENSE		(1,449	)		20,548			(23,517	)		(4,418	)
INCOME TAX EXPENSE		(29	)		—			1,560	(h)		1,531
Net Income (Loss)	$	(1,478	)	$	20,548		$	(21,957	)	$	(2,887	)
Loss per common share										$	(5.77	)
Loss per common share—diluted										$	(5.77	)
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
Basic											500,000
Diluted											500,000

See the accompanying notes to these unaudited pro forma combined and

condensed financial statements.

F-4

ENERGY & EXPLORATION PARTNERS, INC.

UNAUDITED PRO FORMA COMBINED AND CONDENSED STATEMENT OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2012

(in thousands, except for per share amounts)

	Combined ENXP Historical			Combined and Consolidated NASIF Historical			Pro Forma Adjustments			Energy & Exploration Partners, Inc. As Adjusted
REVENUES	$	111		$	—		$	—		$	111
OPERATING EXPENSES		1,794			42			—			1,836
LOSS FROM OPERATIONS		(1,683	)		(42	)		—			(1,725	)
OTHER INCOME (EXPENSE)
Interest income		9			—			—			9
Interest expense		(1,097	)		—			(454	)(b)		(1,551	)
Gain on sale of assets		5,805			—			—			5,805
Unrealized gain on investments		—			(4,326	)		4,326	(d)		—
Total other income (expense)		4,717			(4,326	)		3,872			4,263
INCOME (LOSS) BEFORE INCOME TAX EXPENSE		3,034			(4,368	)		3,872			2,538
INCOME TAX EXPENSE		(2,650	)		—			1,770	(h)		(880	)
Net Income (Loss)	$	384		$	(4,368	)	$	5,642		$	1,658
Income per common share										$	3.32
Income per common share—diluted										$	3.32
WEIGHTED-AVERAGE COMMON SHARES OUTSTANDING
Basic											500,000
Diluted											500,000

See the accompanying notes to these unaudited pro forma combined and

condensed financial statements.

F-5

ENERGY & EXPLORATION PARTNERS, INC.

UNAUDITED PRO FORMA COMBINED AND

CONDENSED STATEMENT OF FINANCIAL POSITION

AS OF JUNE 30, 2012

(in thousands)

	Combined ENXP Historical		Combined and Consolidated NASIF Historical		Pro Forma Adjustments			Energy & Exploration Partners, Inc. As Adjusted
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	10,358	$	26	$	21,575	(a,b)	$	31,959
Deposits		9,545		—		—			9,545
Accounts receivable		80		34		(34	)(c)		80
Investments		—		26,739		(26,739	)(d)		—
Other current assets		1,771		—		—			1,771
Total current assets		21,754		26,799		(5,198	)		43,355
PROPERTY, PLANT, AND EQUIPMENT		19,637		—		—			19,637
LONG-TERM ASSETS		4,408		—		2,604	(a)		7,012
Total Assets	$	45,799	$	26,799	$	(2,594	)	$	70,004
LIABILITIES, EQUITY AND NET ASSETS
LIABILITIES
Accounts payable, accrued and other liabilities	$	1,397	$	19	$	5,182	(a,c,d,e)	$	6,598
Current tax liability		4,975		—		(896	)(a)		4,079
Warrant liability		125		—		(125	)(b)		—
Deposit for investments		13,126		—		(13,126	)(d)		—
Total current liabilities		19,623		19		(8,965	)		10,677
Note payable		21,471		—		(4,973	)(a)		16,498
Total liabilities		41,094		19		(13,938	)		27,175
EQUITY AND NET ASSETS
Equity		4,705		—		(4,705	)(a,e,f)		—
Noncontrolling interest equity		—		26,780		(26,780	)(d)		—
Common stock, par value		—		—		5	(d,f)		5
Additional Paid in Capital		—		—		31,221	(f)		42,824
						11,603	(d)
Total equity		4,705		26,780		11,344			42,829
Total liabilities and equity	$	45,799	$	26,799	$	(2,594	)	$	70,004

See the accompanying notes to these unaudited pro forma combined and

condensed financial statements.

F-6

ENERGY & EXPLORATION PARTNERS, INC.

NOTES TO UNAUDITED PRO FORMA COMBINED AND

CONDENSED FINANCIAL STATEMENTS

1.  OFFERING ADJUSTMENTS

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 June 30, 2012, in the case of the unaudited pro forma combined and condensed statement of financial position as of June 30, 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 six month period ended June 30, 2012, respectively:

(a) Certain changes in equity totaling $26.7MM which reflect the following:

i) the Company’s sold a 65% working interest in its Eaglebine assets acquired after June 30, 2012 on July 31, 2012 for $3.2 million and sold a 10% working interest in all of its Eaglebine assets on August 23, 2012 for $25.5 million (comprised of the sales price of $24.7 million and the reimbursement of well costs of $0.8 million);

ii) certain costs related to the proceeds consisting of the acquisition of acreage in Walker County, Texas on July 24, 2012 for $2 million;

iii) payment on August 24, 2012 against the principal balance of our credit facility of 20% of the net proceeds from our sale of Eaglebine assets of August 23, 2012;

iv) the deposit of $3.5 million for Chesapeake acreage; and

v) certain changes in deferred tax assets and current tax liabilities related to the timing differences between when we were able to expense the basis in our Eaglebine assets related to these sales.

(b) Reflects the differences between interest expense and amortization of loan acquisition costs under the Company’s credit facility with Guggenheim Corporate Funding, LLC and that under the previous note payable to Petro Capital XXV, LLC;

(c) Reflects the Company will offset the accounts payable and receivable balances between ENXP and NASIF;

(d) Reflects the elimination of intercompany deposits for investments between ENXP and NASIF totaling $10.4 million and elimination of investment company fair value adjustments totaling $26.7 million for presentation under the full cost method of accounting, the contribution by NASIF ownership interests to the Company, the contribution of certain other investment depositors, for whom ENXP had a recorded liability of $1.2 million, of net profits interests in Niobrara, and the cash payment of $1.7 million to other investment depositors for whom we had recorded a liability of $1.5 million;

(e) Reflects the accrual of $152,000 of commissions to certain investment depositors as return on their deposits;

(f) Reflects ENXP’s corporate reorganization: the contribution of Hunt Pettit’s pro forma equity in ENXP to the Company, including his historical equity of $4.7 million and the effects of pro forma adjustments such as the proceeds from the transactions noted in (d) on July 31, 2012 for $3.2 million and on August 23, 2012 for $25.5 million, net of $2.0 million of lease purchases on July 24, 2012 related to the proceeds, and the costs related to depositors as noted in (c);

(g) Reflects the reclassification of amounts in the historical financial statements to be consistent with the current year presentation; and

(h) Reflects the tax expense attributable to the adjusted net income before taxes.

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 June 30, 2012 and the results of operations for the

F-7

year ended December 31, 2011 and the six months ended June 30, 2012, of Energy & Exploration Partners, LP included in the audited and unaudited historical combined financial statements of ENXP werede 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.

F-8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholder of:

Energy & Exploration Partners, Inc.

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.

/s/ Hein & Associates LLP

Dallas, Texas

August 1, 2012

F-9

ENERGY & EXPLORATION PARTNERS, INC.

STATEMENT OF FINANCIAL POSITION

ASOF JULY 31, 2012

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	$	—

See accompanying notes to this statement of financial position.

F-10

ENERGY & EXPLORATION PARTNERS, INC.

NOTES TO THE STATEMENT OF FINANCIAL POSITION

1.  Significant Accounting Policies

Organization

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.

Basis of Accounting

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”).

Fiscal Year

Our fiscal year reporting cycle begins January 1 and ends December 31.

2.  Formation Transaction

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.

* * * * * * *

F-11

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Energy & Exploration Partners, LLC

Energy & Exploration Partners, LP

Energy & Exploration Partners Operating, LP

Energy & Exploration Partners Operating GP, LLC

Fort Worth, Texas

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.

/s/ Hein & Associates LLP

Dallas, Texas

August 1, 2012

F-12

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

COMBINED STATEMENTS OF FINANCIAL POSITION

(in thousands)

	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
Unproved 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

See accompanying notes to these combined financial statements.

F-13

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

COMBINED STATEMENTS OF OPERATIONS

(in thousands)

	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

See accompanying notes to these combined financial statements.

F-14

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

COMBINED STATEMENTS OF CHANGES IN EQUITY

(in thousands)

	For the Year Ended December 31,
	2011			2010
EQUITY,beginning of year	$	5,669		$	1,706
CONTRIBUTIONS		326			378
DISTRIBUTIONS		(46	)		(544	)
NET INCOME (LOSS)		(1,478	)		4,129
EQUITY, end of year	$	4,471		$	5,669

See accompanying notes to these combined financial statements.

F-15

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

	For the Year Ended December 31,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(1,478	)	$	4,129
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation		29			43
Abandoned leasehold interests		679			—
Amortization of debt discount and debt origination costs		109			—
Cost of leasehold interests sold		556			—
Acquisitions of leasehold interests		(18,913	)		(3,558	)
Gain on the forgiveness of liabilities		(21	)		—
Changes in operating assets and liabilities:
Accounts receivable		36			(514	)
Prepaid expenses		(24	)		—
Long-term deposits		(25	)		—
Accounts payable		13			—
Accounts payable—related party		34			(20	)
Accrued liabilities		128			(193	)
Other liabilities		15			—
Net cash used in operating activities		(18,862	)		(113	)
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisition of furniture, fixtures, and equipment		(59	)		(75	)
Net cash used in investing activities		(59	)		(75	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from equity contributions		122			378
Payments of equity distributions		(46	)		(544	)
Proceeds from notes payable, net of debt service deposits		9,300			—
Payments of loan origination costs		(234	)		—
Proceeds from investment deposits		12,577			1,538
Repayments of investment deposits		(30	)		(575	)
Net cash provided by financing activities		21,689			797
NET INCREASE IN CASH AND CASH EQUIVALENTS		2,768			609
CASH AND CASH EQUIVALENTS, beginning of year		2,565			1,956
CASH AND CASH EQUIVALENTS, end of year	$	5,333		$	2,565
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
NON-CASH EQUITY CONTRIBUTIONS	$	205		$	—
CASH PAID FOR INTEREST	$	156		$	—

See accompanying notes to these combined financial statements.

F-16

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS

1.  ORGANIZATION

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 wasde 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”).

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Accounting

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

Combination

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.

F-17

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

Accounting Estimates

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 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.

Financial Instruments

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 and Cash Equivalents

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

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

Revenue and Accounts Receivable

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.

Unproved Oil and Natural Gas Leasehold Interests

The Companies acquire unproved 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

F-18

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

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 unproved leasehold acreage. At that time, the Companies elected the full cost method of accounting for oil and natural gas activities.

Furniture, Fixtures and Equipment

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.

Deposits for Investments

The Companies fund a portion of the unproved 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.

Concentrations of Credit Risk

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.

F-19

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

Income Taxes

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.

3.  UNPROVED OIL AND NATURAL GAS LEASEHOLD INTERESTS

Unproved 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:

	2011		2010
	(in thousands)
March Ranch	$	—	$	15
Niobrara		10,769		2,539
Eaglebine		7,815		127
Wolfcamp		2,950		—
Del Ray		—		409
Van Cleve		44		44
Wildcatter II		—		483
Total	$	21,578	$	3,617

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. In addition, the Companies recognized $475,000 in abandonment costs related to leases for which it was not able to obtain legal title and payments could not be recovered.

F-20

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

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

	2011		2010
	(in thousands)
Niobrara	$	6,200	$	505
Eaglebine		4,134		—
Del Ray		—		409
March Ranch		—		16
Wolfcamp		2,748		—
Van Cleve		44		44
Other		—		49
Total	$	13,126	$	1,023

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.

4.  NOTE PAYABLE

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.

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.

F-21

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

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:

	(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

5.  FAIR VALUE

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:

• Level 1 inputs:    Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date. At December 31, 2011 and 2010, the Companies had no Level 1 measurements.

• Level 2 inputs:    Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At December 31, 2011 and 2010, the Companies had no Level 2 measurements.

• Level 3 inputs:    Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At December 31, 2011, the fair value of detachable warrant issued in conjunction with the note payable was measured using Level 3 measurements.

F-22

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

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.

The change in the Companies’ Level 3 measurements during 2011 is as follows:

	(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

6.  COMMITMENTS AND CONTINGENCIES

Office and Equipment Leases

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

	(in thousands)
2012	$	15
2013		4
	$	19

This lease was terminated on January 31, 2012.

Litigation

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.

Environmental Liabilities

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.

F-23

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

7.  RELATED PARTY TRANSACTIONS

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.

Additional related party disclosures are included in Note 3.

8.  SUBSEQUENT EVENTS

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

	Office		Furniture		Total
	(in thousands)
2012	$	192	$	50	$	242
2013		197		—		197
	$	389	$	50	$	439

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

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 for $1.9 million.

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, as sellers, closed on a property conveyance with a third-party operator, a North American exploration and production company, to develop the Companies’ undeveloped leasehold acreage in the Eaglebine formation. The gross proceeds of this transaction were approximately $19.9 million

F-24

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

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, forde 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, a North American exploration and production company, 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 operator 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.

* * * * * * *

F-25

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

COMBINED STATEMENTS OF FINANCIAL POSITION

(unaudited, in thousands)

	As of June 30, 2012			As of December 31, 2011
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	10,358		$	5,333
Deposit		9,545			700
Accounts receivable		80			4
Prepaid expenses		1,771			24
Total current assets		21,754			6,061
PROPERTY, PLANT, AND EQUIPMENT
Unevaluated oil and natural gas properties		17,822			21,608
Evaluated oil and natural gas properties		1,547			—
Furniture, fixtures, and equipment		403			104
Accumulated depreciation and depletion		(135	)		(71	)
Net property, plant, and equipment		19,637			21,641
LONG-TERM ASSETS
Loan origination fees, net		1,269			177
Deferred tax assets		2,325			—
Long-term deposits		34			25
Other assets		780			—
Total long-term assets		4,408			202
Total assets	$	45,799		$	27,904
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable, accrued and other liabilities	$	1,322		$	220
Accounts payable—related parties		75			34
Warrant liability		125			125
Deposit for investments		2,192			2,192
Deposit for investments—related party		10,934			10,934
Current income tax liability		4,975			—
Total current liabilities		19,623			13,505
Notes payable, net of discount ($0 and $72 respectively)		21,471			9,928
Total liabilities		41,094			23,433
EQUITY		4,705			4,471
Total liabilities and equity	$	45,799		$	27,904

See accompanying notes to these combined financial statements.

F-26

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

COMBINED STATEMENTS OF OPERATIONS

(unaudited, in thousands)

	For the Six Months Ended June 30,
	2012			2011
REVENUES
Oil and gas sales	$	111		$	—
OPERATING EXPENSES
Lease operating expense		9			—
General and administrative		1,721			348
Depreciation and depletion		64			11
Total operating expenses		1,794			359
LOSS FROM OPERATIONS		(1,683	)		(359	)
OTHER INCOME (EXPENSE)
Interest income		9			52
Interest expense		(1,097	)		—
Gains on sales of assets		5,805			573
Total other income		4,717			625
INCOME (LOSS) BEFORE INCOME TAX EXPENSE		3,034			266
INCOME TAX EXPENSE		(2,650	)		(10	)
NET INCOME (LOSS)	$	384		$	256

See accompanying notes to these combined financial statements.

F-27

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

COMBINED STATEMENT OF CHANGES IN EQUITY

(unaudited, in thousands)

	For the Six Months Ended June 30,
	2012			2011
EQUITY, beginning of period	$	4,471		$	5,669
CONTRIBUTIONS		—			88
DISTRIBUTIONS		(150	)		—
NET INCOME		384			256
EQUITY, end of period	$	4,705		$	6,013

See accompanying notes to these combined financial statements.

F-28

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

COMBINED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)

	For the Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	384		$	256
Adjustments to reconcile net income to net cash used in operating activities:
Gains on sales of oil and gas interests		(5,805	)		(573	)
Depreciation and depletion		64			11
Amortization of debt discount and debt origination costs		249			—
Changes in operating assets and liabilities:
Accounts receivable		(133	)		8
Prepaid expenses		(1,747	)		(50	)
Deferred tax assets		(2,325	)		—
Accounts payable—related party		41			(23	)
Current income tax liability		4,975			—
Accounts payable, accrued and other liabilities		1,159			(4	)
Net cash used in operating activities		(3,138	)		(375	)
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of unevaluated oil and natural gas properties		(23,446	)		(9,803	)
Additions to evaluated oil and natural gas properties		(1,547	)		—
Proceeds from sale of oil and gas working interests, net of transaction costs		33,037			1,129
Acquisition of furniture, fixtures, and equipment		(299	)		(47	)
Purchase of security deposits		(16	)		—
Net cash provided by (used in) investing activities		7,729			(8,721	)
CASH FLOWS FROM FINANCING ACTIVITIES
(Distribution to) proceeds from equity owner		(150	)		88
Proceeds from notes payable, net of deposits funded		16,942			—
Payments on outstanding debt obligation, net of deposits returned		(14,316	)		—
Payments of prepaid offering costs		(780	)		—
Payments of loan origination costs		(1,262	)		—
Proceeds from investment deposits		—			9,441
Repayments of investment deposits		—			(30	)
Net cash provided by financing activities		434			9,499
NET CHANGE IN CASH AND CASH EQUIVALENTS		5,025			403
CASH AND CASH EQUIVALENTS, beginning of period		5,333			2,565
CASH AND CASH EQUIVALENTS, end of period	$	10,358		$	2,968
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
CASH PAID FOR INTEREST	$	946		$	—

See accompanying notes to these combined financial statements.

F-29

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS

(unaudited)

1.  BASIS OF PRESENTATION

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 following (a) condensed combined statement of financial position as of December 31, 2011, which has been derived from audited financial statements, and (b) the unaudited interim condensed combined 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 the first quarter of 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:

• As a company engaged in the purchase and sales of leases, we recorded revenues and costs of sales of leases, and included the cost of sales and acquisitions of leases as components of cash flows from operating activities in our audited Combined Statement of Cash Flows in our audited Combined Statement of Operations for the year ended December 31, 2011. As an oil and natural gas developer electing to account for oil and natural gas activities under the full cost method, we report the proceeds from the sales of leases against the applicable basis in the properties, report the gains or losses on lease sales as a component of cash flow from operating activities, and report the proceeds from or purchases and additions to oil and gas properties as cash flows from investing activities in the unaudited Combined and Consolidated interim financial statements;

• We condensed our Combined Statements of Financial Position by aggregating accounts payable, accrued liabilities, and other liabilities as accounts payable, accrued liabilities, and other; and

• We condensed our Combined Statements of Financial Position by aggregating undeveloped oil and natural gas leasehold interests and overriding royalty interests as unevaluated oil and natural gas properties.

F-30

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(unaudited)

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Unevaluated Oil and Natural Gas Properties

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.

Full Cost Accounting

The Companies elected the full cost method of accounting (“FCA”) for their oil and natural gas activities in the first quarter of 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 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. As of June 30, 2012, the Companies included $1.2 million of exploratory well costs pending determination in Evaluated oil and natural gas properties which were excluded from the amortization base.

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.

Revenue Recognition

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.

F-31

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(unaudited)

Income taxes

Effective April 13, 2012, the Companies terminated their election to report as an S corporation and became a C corporation for federal income tax reporting purposes. Subsequently, we account for income taxes using the asset and liability method. Deferred tax assets and liabilities arise from the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary difference and carry forwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are established when necessary to reduce the deferred tax asset to the amount more likely than not to be recovered.

Additionally, the Companies are required to determine whether it is more likely than not (a likelihood of more than 50%) that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position in order to record any financial statement benefit. If that step is satisfied, then the Companies must measure the tax position to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that has greater than a 50% likelihood of being realized upon ultimate settlement. Any interest or penalties would be recognized as a component of income tax expense.

The Companies apply significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from these estimates, which could impact the Companies’ financial position, results of operations and cash flows. The Companies do not have uncertain tax positions and, as such, did not record a liability as of June 30, 2012.

The tax years 2008 through 2011 for federal returns and 2007 through 2011 for state returns remain open to examination by the major taxing jurisdictions in which the Companies operate.

3.  UNEVALUATED OIL AND NATURAL GAS PROPERTIES

Unevaluated oil and natural gas properties 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 June 30, 2012 and December 31, 2011 the carrying costs by project were as follows:

	June 30, 2012 (Unaudited)		December 31, 2011
	(in thousands)
Niobrara	$	11,071	$	10,769
Eaglebine		—		7,815
Wolfcamp		6,677		2,950
Other		74		74
Total	$	17,822	$	21,608

F-32

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(unaudited)

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

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 million. 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 million, and Energy & Exploration Partners, LLC purchased the leases effective as of April 10, 2012 for $1.9 million.

The Companies, as sellers, closed on multiple property conveyances with a third-party operator, a North American oil and gas exploration and production company, to develop the Companies’ undeveloped leasehold acreage in the Eaglebine formation. The gross proceeds of these transactions were approximately $33.9 million during the three and six months ended June 30, 2012 and the operator purchased a 65% working interest in the undeveloped leasehold acreage. On July 31, 2012, additional working interest conveyances of newly acquired undeveloped leasehold acreage in the same formation were closed for gross proceeds of $3.2 million. The areas covered by these conveyances are collectively known as Area of Mutual Interest #1 (“AMI #1”).

On June 29, 2012, we entered into a second agreement with the third-party operator, a North American oil and gas exploration and production company, 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 operator 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 25 2012, the operator advanced funds under this agreement for $1.9 million, and the Companies purchased additional leases in AMI #2 for this amount.

4.  NOTE PAYABLE

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 was due in full at the maturity of the loan.

The loan matured on September 8, 2012 with two extension options. The Companies had 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 were required to repay at least $3.0 million of the principal balance outstanding prior to that date.

The credit agreement required 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.

F-33

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(unaudited)

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 was October 7, 2018. This repurchase amount was 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 was amortized over the life of the note payable to interest expense. On July 5, 2012, the Companies exercised their repurchase option for $125,000 and retired the detachable warrants.

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 previously described. 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. The credit facility requires the Companies to make a payment of 20% of the proceeds from a sale meeting certain predefined terms to be applied against its outstanding principal balance. As discussed further in Note 9, this payment was made August 24, 2012.

The $100.0 million credit facility requires, and the $15.0 million credit agreement required, cash to be maintained on deposit to fund future drilling costs in bank accounts controlled by our lenders. Amounts recorded in Deposits at June 30, 2012 and December 31, 2011 represent funds controlled by the lender under our $100.0 million credit facility and $15.0 million credit agreement, respectively.

The Companies incurred $1.3 million in loan origination costs during the six months ended June 30, 2012 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. The Companies incurred no such costs during the six months ended June 30, 2011.

5.  EQUITY

On April 13, 2012, one outstanding membership unit of the Companies was transferred to a holding corporation controlled by the Companies’ equity owner. On June 25, 2012, Energy & Exploration Partners, LLC assigned their interests in Energy & Exploration Partners, LP to Septa Holdings LLC, a Texas limited liability company owned by Energy & Exploration LLC’s equity owner, forde minimis consideration. These transactions had no impact on the combined equity of the Companies. On June 25, 2012, the Companies distributed $150,000 to their equity owner.

6.  FAIR VALUE

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.

F-34

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(unaudited)

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:

• Level 1 inputs:    Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date. At June 30, 2012 and 2011, the Companies had no Level 1 measurements.

• Level 2 inputs:    Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At June 30, 2012 and 2011, the Companies had no Level 2 measurements.

• Level 3 inputs:    Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

At June 30, 2012, the fair value of the detachable warrant issued in conjunction with the note payable was measured using a Level 3 measurement, the $125,000 cash buyout completed by the Companies on July 5, 2012. There has been no change in the fair value of the detachable warrant as of June 30, 2012.

Changes in the fair value of the detachable warrants for the six month period ended June 30, 2012 are as follows:

Beginning balance	$	(125	)
Change in the fair value of detachable warrant		—
Ending balance	$	(125	)

The following table presents the fair value of the detachable warrants as of June 30, 2012:

	As of June 30, 2012		Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	(in thousands)
Detachable warrants	$	125	$	—	$	—	$	125

F-35

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(unaudited)

7.  INCOME TAX

Income tax provision

We calculate our provision for federal and state income taxes based on current tax law. The reported tax provision differs from the amounts currently receivable or payable because some income and expense items are recognized in different time periods for financial reporting purposes than for income tax purposes. The following is a summary of our provision for income taxes (in thousands):

	For the Six Months Ended June 30,
	2012			2011
Current
Federal	$	4,809		$	—
State		166			10
		4,975			10
Deferred
Federal		(2,254	)		—
State		(71	)		—
		(2,325	)		—
Income tax provision	$	2,650		$	10

In addition to our provision for income taxes based on our results of operations, we have recorded deferred federal and state income tax assets and liabilities attributable to the differences in the basis in our assets for U.S. GAAP and for federal and state taxation purposes upon our conversion to a C Corporation. A reconciliation of the statutory federal tax provision to our income tax provision in the accompanying statements of income is as follows (in thousands):

	For the Six Months     Ended June 30,
	2012		2011
Statutory federal provision (34%)	$	1,031	$	—
Federal tax provision attributed to period we were not directly subject to federal taxation		453		—
Statutory state income tax provision, net of federal tax benefit in 2012		41		10
Tax effect of expenses not deductible for federal or state taxation		3		—
Recognition of temporary differences upon change in tax status		1,122		—
Income tax expense	$	2,650	$	10

F-36

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(unaudited)

Deferred Tax Assets/Liabilities

The tax effects of temporary differences between reported earnings and taxable earnings consisted of the following (in thousands):

	June 30, 2012
Deferred Tax Assets:
Difference in basis of unevaluated oil and natural gas properties	$	2,312
Other		13
Total deferred tax assets		2,325
Total deferred tax liabilities		—
Deferred tax assets, net	$	2,325

8.  RELATED PARTY TRANSACTIONS

As of June 30, 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 $41,000 in reimbursements for general and administrative expenses as of June 30, 2012.

9.  SUBSEQUENT EVENTS

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.

On August 22, 2012, investment depositors, for whom we have recorded a deposit liability of $10.4 million as of June 30, 2012, contributed their outstanding equity interests to Energy & Exploration Partners, Inc., a company that is majority owned by the Companies’ equity owner, for common stock. Effective July 27, 2012, these depositors amended their letter agreements with the Companies to clarify that, with respect to their participation in net returns from Companies’ projects, no taxable gain would be recognized, nor proceeds distributed, until the Companies sold substantially all of their assets in the assets subject to the letter agreements.

In July and August 2012, and by August 22, 2012, investment depositors, for whom we have recorded a deposit liability of $1.2 million as of June 30, 2012, contributed their outstanding equity interests to Energy & Exploration Partners, Inc., a company that is majority owned by the Companies’ equity owner, for shares of its common stock. We also returned $1.7 million to depositors, for whom we have recorded a deposit liability of $1.5 million as of June 30, 2012, in exchange for a release of our obligation to provide returns under our letter agreements with them.

On August 22, 2012, the Companies’ equity owner contributed all of his interest in the Companies, except for his interest in Energy & Exploration Partners, LP, to Energy & Exploration Partners, Inc., for the majority of the common stock of Energy & Exploration Partners, Inc.

F-37

ENERGY & EXPLORATION PARTNERS, LLC

ENERGY & EXPLORATION PARTNERS, LP

ENERGY & EXPLORATION PARTNERS OPERATING, LP

ENERGY & EXPLORATION PARTNERS OPERATING GP, LLC

NOTES TO COMBINED FINANCIAL STATEMENTS—(Continued)

(unaudited)

On August 22, 2012, Energy & Exploration Partners, Inc., a corporation majority owned by the Companies’ equity owner, assigned its ownership interest in Energy & Exploration Partners Operating, L.P., Energy & Exploration Partners Operating GP, LLC, North American Shale, GP, LLC, North American Shale Investment Advisors, LLC, North American Shale Investment Fund GP, LP, and North American Shale Investment Fund, LP to Energy & Exploration Partners, LLC.

Subsequent to the June 26, 2012 extinguishment of the 14% note payable discussed in Note 4, the managing member of the lender under the note was nominated to be a director of Energy & Exploration Partners, Inc. In addition, the Companies paid an entity affiliated with the lender $200,000 and $0 for the six months ended June 30, 2012 and 2011, respectively, in consulting fees.

On August 23, 2012, we entered into a purchase and sale agreement with the oil and gas exploration subsidiary of a subsidiary of a North American energy company, to sell a 10% non-operated working interest in our Eaglebine acreage in AMI #1 and a 5% non-operated working interest in AMI #2. Pursuant to the first closing of this agreement, we conveyed acreage in AMI #1 for $24.7 million and received $0.8 million as reimbursement for the buyer’s 10% share of a well. The agreement provides for future closings of additional acreage. Following the final closings with both our third party operator and the buyer, we will retain a 25% working interest in AMI #1 and a 15% working interest in AMI #2. For future acquisitions, the buyer can elect to participate in AMI #1 or AMI #2 by paying its pro-rata 10% share of all acreage costs in AMI #1 and its pro-rata 5% share of all acreage costs plus $100 per net mineral acre in AMI #2. In addition to the cash proceeds received from both closings, if the buyer achieves a specified rate of return, it will re-convey 30% of the working interest it holds in wells and acreage in both AMI #1 and AMI #2 back to the Companies. On August 24, 2012, the Companies made a payment of $5.0 million, or 20% of the proceeds, net of broker fee, from this sale, to its lender to be applied against its outstanding principal balance, pursuant to provisions of its credit facility.

On September 6, 2012, North American Shale, GP, LLC, North American Shale Investment Advisors, LLC, North American Shale Investment Fund GP, LP, and North American Shale Investment Fund, LP, Indy Exploration I, LLC, Indy Exploration II, LLC and Indy Exploration III, LLC were merged into Energy & Exploration Partners, LLC.

On September 10, 2012, we entered into a purchase and sale agreement with a North American exploration and production company pursuant to which we agreed to purchase 100% of its acreage in the Eaglebine. Pursuant to the agreement, the seller will convey to us a 100% operated working interest in acreage for $125 million in proceeds. We are required to offer our partners in previous Eaglebine sales their pro-rata working interest in the newly acquired acreage in AMI #1 and AMI #2. The Companies will provide a $3.5 million non-refundable deposit to be applied against the purchase price. The agreement provides for a closing date of October 31, 2012, after which date if the sale has not occurred, the deposit would be forfeited. Under the agreement, the Companies have the right to extend the closing date of the sale to December 14, 2012, for a payment of $3 million.

Management has evaluated subsequent events through September 10, 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.

*  *  *  *  *  *  *

F-38

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

North American Shale Investment Fund GP, LP

North American Shale GP, LLC

North American Shale Investment Advisors, LLC

Fort Worth, Texas

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.

/s/ Hein & Associates LLP

Dallas, Texas

August 1, 2012

F-39

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

COMBINED AND CONSOLIDATED STATEMENT OF ASSETS AND LIABILITIES

ASOF DECEMBER 31, 2011

(in thousands)

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

See accompanying notes to these combined and consolidated financial statements.

F-40

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

COMBINED AND CONSOLIDATED STATEMENT OF OPERATIONS

FORTHE PERIODOF INCEPTION (FEBRUARY 1, 2011)THROUGH DECEMBER 31, 2011

(in thousands)

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	$	—

See accompanying notes to these combined and consolidated financial statements.

F-41

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

COMBINED AND CONSOLIDATED STATEMENT OF CHANGES IN NET ASSETS

FORTHE PERIODOF INCEPTION (FEBRUARY 1, 2011)THROUGH DECEMBER 31, 2011

(in thousands)

	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

See accompanying notes to these combined and consolidated financial statements.

F-42

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

COMBINED AND CONSOLIDATED STATEMENT OF CASH FLOWS

FORTHE PERIODOF INCEPTION (FEBRUARY 1, 2011)THROUGH DECEMBER 31, 2011

(in thousands)

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

See accompanying notes to these combined and consolidated financial statements.

F-43

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

COMBINED AND CONSOLIDATED SCHEDULE OF INVESTMENTS

ASOF DECEMBER 31, 2011

(in thousands)

Investments	Estimated Fair  Value		% of Pro-rata Ownership of Project
Niobrara	$	4,025		32	%
Eaglebine		16,090		54	%
Wolfcamp		10,950		95	%
Total	$	31,065

See accompanying notes to these combined and consolidated financial statements.

F-44

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

NOTES TO THE COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS

1.  ORGANIZATION

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.”

Prior to March 2011, the activities of the Companies were immaterial.

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.

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Accounting

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.

F-45

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

NOTES TO THE COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Combination and Consolidation

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.

Accounting Estimates

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.

Investments

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. As of December 31, 2011, all of ENEXP’s projects were oil and gas interests in unproved properties.

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

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

Cash

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.

Income Taxes

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.

F-46

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

NOTES TO THE COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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.

3.  FINANCIAL HIGHLIGHTS

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:

	(Unaudited)
Expense		7	%
Net investment income		0	%

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%.

4.  NONCONTROLLING INTERESTS

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.

5.  FAIR VALUE

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.

F-47

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

NOTES TO THE COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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:

• Level 1 inputs:    Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date. At December 31, 2011, the Companies had no Level 1 measurements.

• Level 2 inputs:    Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At December 31, 2011, the Companies had no Level 2 measurements.

• Level 3 inputs:    Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At December 31, 2011, the fair value of investment assets was measured using Level 3 measurements.

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. As of December 31, 2011, all of ENEXP’s projects were oil and gas interests in unproved properties.

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:

	(in thousands)
Beginning balance	$	—
Purchase of investment assets		10,382
Unrealized gain on investments		20,683
Ending balance	$	31,065

	As of December 31, 2011		Quoted Prices in Active Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
	(in thousands)
Niobrara	$	4,025	$	—	$	—	$	4,025
Eaglebine	$	16,090	$	—	$	—	$	16,090
Wolfcamp	$	10,950	$	—	$	—	$	10,950

F-48

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

NOTES TO THE COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

6.  RELATED PARTY TRANSACTIONS

Management Fees

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.

Incentive Allocation

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.

7.  COMMITMENTS AND CONTINGENCIES

Litigation

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.

Service Contract Commitments

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:

	(in thousands)
2012	$	30
2013		3
	$	33

8.  SUBSEQUENT EVENTS

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.

* * * * * * *

F-49

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

COMBINED AND CONSOLIDATED STATEMENT OF ASSETS AND LIABILITIES

(unaudited, in thousands)

	June 30, 2012		December 31, 2011
ASSETS
ASSETS
Cash	$	26	$	64
Accounts receivable—related party		34		34
Investments		26,739		31,065
Total assets	$	26,799	$	31,163
LIABILITIES AND NET ASSETS
LIABILITIES
Accounts payable and accrued liabilities	$	19	$	15
Total liabilities		19		15
NET ASSETS
Net assets attributable to controlling interests		—		—
Net assets attributable to noncontrolling interests		26,780		31,148
Total net assets		26,780		31,148
Total liabilities and net assets	$	26,799	$	31,163

See accompanying notes to these combined and consolidated financial statements.

F-50

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

COMBINED AND CONSOLIDATED STATEMENT OF OPERATIONS

FORTHE PERIODOF INCEPTION (FEBRUARY 1, 2011)TO JUNE 30, 2011

ANDTHE SIX MONTHS ENDED JUNE 30, 2012

(unaudited, in thousands)

	Six Months Ended June 30, 2012			February 1, 2011 to June 30, 2011
EXPENSES
General and administrative	$	42		$	88
Total operating expenses		42			88
LOSS BEFORE UNREALIZED LOSS ON INVESTMENTS	$	(42	)	$	(88	)
Unrealized gain (loss) on investments		(4,326	)		12,598
NET INCOME (LOSS)	$	(4,368	)	$	12,510
NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTERESTS	$	(4,368	)	$	12,510
NET INCOME (LOSS) ATTRIBUTABLE TO CONTROLLING INTERESTS	$	—		$	—

See accompanying notes to these combined and consolidated financial statements.

F-51

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

COMBINED AND CONSOLIDATED STATEMENT OF CHANGES IN NET ASSETS

FORTHE PERIODOF INCEPTION (FEBRUARY 1, 2011)TO JUNE 30, 2011

AND FORTHE SIX MONTHS ENDED JUNE 30, 2012

(unaudited, in thousands)

	Controlling Interest		Noncontrolling Interest			Total Net Assets
NET ASSETS, February 1, 2011	$	—	$	—		$	—
CONTRIBUTIONS		—		10,600			10,600
NET INCOME		—		12,510			12,510
NET ASSETS, June 30, 2011	$	—	$	23,110		$	23,110
NET ASSETS, January 1, 2012	$	—	$	31,148		$	31,148
NET LOSS		—		(4,368	)		(4,368	)
NET ASSETS, June 30, 2012	$	—	$	26,780		$	26,780

See accompanying notes to these combined and consolidated financial statements.

F-52

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

COMBINED AND CONSOLIDATED STATEMENT OF CASH FLOWS

FORTHE PERIODOF INCEPTION (FEBRUARY 1, 2011)TO JUNE 30, 2011

AND FORTHE SIX MONTHS ENDED JUNE 30, 2012

(unaudited, in thousands)

	Six Months Ended June 30, 2012			Period from February 1, 2011 to June 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	(4,368	)	$	12,510
Adjustments to reconcile net loss to net cash used in operating activities:
Unrealized loss (gain) on investments		4,326			(12,598	)
Change in operating assets and liabilities:
Accounts payable and accrued liabilities		4			19
Net cash used in operating activities		(38	)		(69	)
CASH FLOWS FROM INVESTING ACTIVITIES
Purchase of investments		—			(7,280	)
Net cash used in operating activities		—			(7,280	)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from equity contributions		—			10,600
Net cash provided by financing activities		—			10,600
NET DECREASE IN CASH AND CASH EQUIVALENTS		(38	)		3,251
CASH AND CASH EQUIVALENTS, beginning of period		64			—
CASH AND CASH EQUIVALENTS, end of period	$	26		$	3,251

See accompanying notes to these combined and consolidated financial statements.

F-53

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

COMBINED AND CONSOLIDATED SCHEDULE OF INVESTMENTS

ASOF JUNE 30, 2012

(unaudited, in thousands)

Investments	Estimated Fair Value		% of Pro-rata Ownership of Project
Niobrara	$	3,906		31	%
Eaglebine		14,485		15	%
Wolfcamp		8,348		42	%
Total	$	26,739

See accompanying notes to these combined and consolidated financial statements.

F-54

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

COMBINED AND CONSOLIDATED SUPPLEMENTAL SCHEDULE OF INVESTMENTS

ASOF DECEMBER 31, 2011

(unaudited, in thousands)

Investments	Estimated Fair Value		% of Pro-rata Ownership of Project
Niobrara	$	4,025		32	%
Eaglebine		16,090		54	%
Wolfcamp		10,950		95	%
Total	$	31,065

See accompanying notes to these combined and consolidated financial statements.

F-55

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1.  ORGANIZATION

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.”

Prior to March 2011, the activities of the Companies were immaterial.

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.

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 year ended December 31, 2011 and notes thereto.

2.  FINANCIAL HIGHLIGHTS

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 January 1, 2012 through June 30, 2012.

For the period from February 1, 2011 to June 30, 2011 and the six months ended June 30, 2012, the net investment income, combined expense ratios, internal rate of return, and ratio of total contributed capital to total committed capital are:

	Six Months Ended June 30, 2012			Period from February 1, 2011 to June 30, 2011
Expense		2	%		6	%
Net investment income		0	%		0	%
Internal rate of return		-3	%		-5	%
Ratio of total contributed capital to total committed capital		100	%		100	%

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.

F-56

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

3.  NONCONTROLLING INTERESTS

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.

4.  FAIR VALUE

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:

• Level 1 inputs:    Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date. At June 30, 2012 and December 31, 2011, the Companies had no Level 1 measurements.

• Level 2 inputs:    Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At June 30, 2012 and December 31, 2011, the Companies had no Level 2 measurements.

• Level 3 inputs:    Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at measurement date. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At June 30, 2012 and December 31, 2011, the fair value of investment assets was measured using Level 3 measurements.

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 June 30, 2012.

F-57

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

The following tables present the fair value per acre for the investment leases held and the change in fair value for the period from January 1, 2012 through June 30, 2012:

	(in thousands)
Beginning balance	$	31,065
Unrealized loss on investments		(4,326	)
Ending balance	$	26,739

	As of June 30, 2012		Quoted Prices in Active  Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Niobrara	$	3,906	$	—	$	—	$	3,906
Eaglebine	$	14,485	$	—	$	—	$	14,485
Wolfcamp	$	8,348	$	—	$	—	$	8,348

The following tables present the fair value per acre for the investment leases held and the change in fair value for the period from Feburary 1, 2011 through June 30, 2011:

	(in thousands)
Beginning balance	$	—
Investments		7,280
Unrealized gain on investments		12,598
Ending balance	$	19,878

	As of June 30, 2011		Quoted Prices in Active  Markets for Identical Assets		Significant Other Observable Inputs		Significant Unobservable Inputs
Niobrara	$	4,539	$	—	$	—	$	4,539
Eaglebine	$	10,958	$	—	$	—	$	10,958
Wolfcamp	$	4,381	$	—	$	—	$	4,381

5.  RELATED PARTY TRANSACTIONS

Management Fees

During the period from February 1, 2011 (inception) through December 31, 2011, certain expenses were paid to Energy & Exploration Partners, LLC (“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 and June 30, 2012.

Incentive Allocation

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

F-58

NORTH AMERICAN SHALE INVESTMENT FUND GP, LP

NORTH AMERICAN SHALE GP, LLC

NORTH AMERICAN SHALE INVESTMENT ADVISORS, LLC

NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(unaudited)

cumulative unrealized net capital appreciation. For the six-month period ended June 30, 2012 and for the period from February 1, 2011 (inception) through December 31, 2011 there have been no realization events and, therefore, no incentive allocation to the general partner.

Credit Facility Guaranty

On June 26, 2012, subsidiaries of the Companies provided an unconditional guaranty of ENEXP’s $100 million credit facility, which matures December 17, 2014. The credit facility will be used to fund the exploitation of ENEXP’s oil and natural gas properties, in which the Companies’ subsidiaries invest. Under the guaranty, the Companies’ subsidiaries are obligated to make any payment obligation that ENEXP fails to pay, limited only to the extent of debtor’s relief laws. As of June 30, 2012, there were no current obligations owed by the Companies under the guaranty.

6.  SUBSEQUENT EVENTS

On July 27, 2012, Indy Exploration I, LLC, Indy Exploration II, LLC, and Indy Exploration III, LLC amended its letter agreements with ENEXP to clarify that, with respect to their participation in net returns from ENEXP’s projects, no taxable gain would be recognized, nor proceeds distributed, until ENEXP sold substantially all of its interest in the assets subject to the letter agreements.

On August 22, 2012, the Companies’ controlling and non-controlling members contributed their outstanding ownership interests in the Companies to Energy & Exploration Partners, Inc., a company that is majority owned by the Companies’ controlling member, and the non-controlling numbers received approximately 20% of its common stock.

Management has evaluated subsequent events through September 10, 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.

* * * * * * *

F-59

GLOSSARY OF SELECTED OIL AND NATURAL GAS TERMS

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.

3D seismic data.    Geophysical data that depicts the subsurface strata in three dimensions.

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.

A-1

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.

Mcf.    Thousand cubic feet of natural gas.

MMBtu.    Million British Thermal Units.

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

NYMEX.    New York Mercantile Exchange.

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.

A-2

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

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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.

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            Shares

Energy & Exploration Partners, Inc.

Common Stock

PROSPECTUS

Canaccord Genuity

Johnson Rice & Company L.L.C.

                    , 2012

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.

Part II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. Other Expenses of Issuance and Distribution

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.

SEC Registration Fee	$	31,515
FINRA Filing Fee		41,750
New York Stock Exchange listing fee		*
Accountants’ fees and expenses		*
Legal fees and expenses		*
Printing and engraving expenses		*
Transfer agent and registrar fees		*
Miscellaneous		*
Total	$	*

* To be provided by amendment.

ITEM 14. Indemnification of Directors and Officers

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

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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.

ITEM 15. Recent Sales of Unregistered Securities

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.

On August 22, 2012, in connection with our corporate reorganization, we issued an aggregate of 396,500 shares of our common stock to a group of accredited investors in exchange for certain interests owned by them.

During the period from August 22, 2012 to September 6, 2012, we issued an aggregate of 125,000 restricted shares of our common stock to certain members of our management under our 2012 Stock Incentive Plan pursuant to Restricted Stock Award Agreements. Hunt Pettit contributed 22,500 of his shares of common stock back to us for no consideration, and these shares were used by us to make some of the restricted share awards. These restricted shares generally vest over a three-year period.

The foregoing issuances of shares did not involve any underwriters, underwriting discounts or commissions, or any public offering, and we believe the issuances were exempt from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereunder, and in the case of the restricted shares awarded to certain members of management, pursuant to Rule 701 under the Securities Act.

ITEM 16. Exhibits and Financial Statement Schedules

(a) Exhibits

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.

ITEM 17. Undertakings

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.

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The undersigned registrant hereby undertakes that:

(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.

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SIGNATURES

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 September 10, 2012.

ENERGY & EXPLORATION PARTNERS, INC.
By:	/s/ B. Hunt Pettit
	Name: B. Hunt Pettit
	Title:   President and Chief Executive Officer

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.

Signature	Title	Date
/s/ B. Hunt Pettit B. Hunt Pettit	President, Chief Executive Officer and Director (principal executive officer)	September 10, 2012
/s/ Brian C. Nelson Brian C. Nelson	Executive Vice President and Chief Financial Officer (principal financial officer)	September 10, 2012
/s/ Joseph C. Daches Joseph C. Daches	Executive Vice President and Chief Accounting Officer (principal accounting officer)	September 10, 2012

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INDEX TO EXHIBITS

Exhibit Number		Description
	1.1*	Form of Underwriting Agreement
	2.1	Contribution Agreement dated as of August 22, 2012 among Energy & Exploration Partners, Inc., Hunt Pettit, H Pettit HC, Inc., the Fund Limited Partners identified therein, the Niobrara Investors identified therein and Energy & Exploration Partners, LLC
	2.2†	Purchase and Sale Agreement dated as of March 5, 2012 between Energy & Exploration Partners, LLC and Halcón Energy Properties, Inc. (formerly RWG Energy, Inc.)
	2.3†	First Amendment to Purchase and Sale Agreement dated as of April 19, 2012 between Energy & Exploration Partners, LLC and Halcón Energy Properties, Inc.
	2.4	Second Amendment to Purchase and Sale Agreement dated as of May 10, 2012 between Energy & Exploration Partners, LLC and Halcón Energy Properties, Inc.
	2.5†	Third Amendment to Purchase and Sale Agreement dated as of May 24, 2012 between Energy & Exploration Partners, LLC and Halcón Energy Properties, Inc.
	2.6†	Fourth Amendment to Purchase and Sale Agreement dated as of June 21, 2012 between Energy & Exploration Partners, LLC and Halcón Energy Properties, Inc.
	2.7	Fifth Amendment to Purchase and Sale Agreement dated as of July 16, 2012 between Energy & Exploration Partners, LLC and Halcón Energy Properties, Inc.
	2.8†	Sixth Amendment to Purchase and Sale Agreement dated as of July 31, 2012 between Energy & Exploration Partners, LLC and Halcón Energy Properties, Inc.
	2.9	Seventh Amendment to Purchase and Sale Agreement dated as of August 29, 2012 between Energy & Exploration Partners, LLC and Halcón Energy Properties, Inc.
	2.10†	Lease Purchase Agreement dated as of April 5, 2012 between Herd Producing Company, Inc. and Energy & Exploration Partners, LLC
	2.11†	Purchase and Sale Agreement dated as of August 23, 2012 between Energy & Exploration Partners, LLC and CEU Huntsville, LLC
	2.12†	Purchase and Sale Agreement dated as of September 4, 2012 among Energy & Exploration Partners, LLC, Chesapeake Exploration, L.L.C., Arcadia Resources, L.P. and Jamestown Resources L.L.C.
	3.1*	Form of Amended and Restated Certificate of Incorporation of Energy & Exploration Partners, Inc.
	3.2*	Form of Amended and Restated Bylaws of Energy & Exploration Partners, Inc.
	5.1*	Opinion of Bracewell & Giuliani LLP as to the legality of the securities being registered
	10.1	Credit Agreement dated as of June 26, 2012 among Energy & Exploration Partners, LLC, the Lenders party thereto, and Guggenheim Corporate Funding, LLC, as Administrative Agent
	10.2	First Amendment to Credit Agreement dated as of July 11, 2012 among Energy & Exploration Partners, LLC, the Lenders party thereto, and Guggenheim Corporate Funding, LLC, as Administrative Agent
	10.3	Consent Letter Agreement dated as of July 31, 2012 among Energy & Exploration Partners, LLC and the lenders party to the Credit Agreement dated as of June 26, 2012
	10.4	Consent Letter Agreement dated as of August 31, 2012 among Energy & Exploration Partners, LLC and the lenders party to the Credit Agreement dated as of June 26, 2012
	10.5*	Consent Letter Agreement dated as of September 4, 2012 among Energy & Exploration Partners, LLC and the lenders party to the Credit Agreement dated as of June 26, 2012

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Exhibit Number		Description
	10.6*	Equity Kicker Letter dated as of June 26, 2012 between Energy & Exploration Partners, LLC and Guggenheim Corporate Funding, LLC, as Administrative Agent
	10.7	First Amendment to Equity Kicker Letter dated as of July 11, 2012 between Energy & Exploration Partners, LLC and Guggenheim Corporate Funding, LLC, as Administrative Agent
	10.8	Registration Rights Agreement dated as of August 22, 2012 among Energy & Exploration Partners, Inc. and its stockholders named therein
	10.9	Energy & Exploration Partners, Inc. 2012 Stock Incentive Plan
	10.10	Form of Restricted Stock Award Agreement
	10.11	Restricted Stock Award Agreement dated as of August 22, 2012 between Energy & Exploration Partners, Inc. and Brian C. Nelson
	10.12*	Form of Employment Agreement between Energy & Exploration Partners, Inc. and each of its executive officers
	10.13*	Form of Indemnification Agreement between Energy & Exploration Partners, Inc. and each of its executive officers and directors
	10.14*	Assignment of Overriding Royalty dated as of August 20, 2012 among BHP Consulting LP and the assignees party thereto
	10.15*	Assignment of Overriding Royalty dated as of August 20, 2012 among TDM Holding, LLC and the assignees party thereto
	10.16*	Assignment of Overriding Royalty dated as of August 29, 2012 among TDM Holding, LLC and the assignees party thereto
	10.17*	Assignment of Overriding Royalty dated as of August 20, 2012 among INDY Exploration II, LLC and the assignees party thereto
	10.18*	Assignment of Overriding Royalty dated as of August 20, 2012 among Energy & Exploration Partners, LLC and the assignees party thereto
	10.19*	Assignment of Overriding Royalty dated as of August 20, 2012 among Energy & Exploration Partners, LLC and the assignees party thereto
	10.20*	Assignment of Overriding Royalty dated as of August 20, 2012 among Energy & Exploration Partners, LLC and the assignees party thereto
	10.21*	Assignment of Overriding Royalty dated as of August 20, 2012 among Energy & Exploration Partners, LLC and the assignees party thereto
	10.22*	Assignment of Overriding Royalty dated as of August 20, 2012 among Energy & Exploration Partners, LLC and the assignees party thereto
	10.23*	Assignment of Overriding Royalty dated as of August 20, 2012 among Energy & Exploration Partners, LLC and the assignees party thereto
	10.24*	Assignment of Overriding Royalty dated as of August 20, 2012 among Energy & Exploration Partners, LLC and the assignees party thereto
	10.25*	Assignment of Overriding Royalty dated as of August 20, 2012 among Energy & Exploration Partners, LLC and the assignees party thereto
	10.26*	Stipulation of Interest dated as of August 20, 2012 among Energy & Exploration Partners, LLC, Halcón Energy Properties, Inc., and the assignees party thereto

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Exhibit Number		Description
	10.27*	Stipulation of Interest dated as of August 20, 2012 among Energy & Exploration Partners, LLC, Halcón Energy Properties, Inc., and TDM Holding, LLC
	21.1	List of Subsidiaries of Energy & Exploration Partners, Inc.
	23.1	Consent of Hein & Associates LLP
	23.2*	Consent of Bracewell & Giuliani LLP (included as part of Exhibit 5.1 hereto)
	23.3	Consent of Enick E. Diffee to be named as Director
	23.4	Consent of David M. Fender to be named as Director
	23.5	Consent of Rosser Newton to be named as Director
	23.6	Consent of Neil A. Stanley to be named as Director
	23.7	Consent of Nicholas Steinsberger to be named as Director
	24.1*	Power of Attorney
	99.1	Consent of Drillinginfo, Inc.
	99.2	Confidential Draft Registration Statement submitted August 3, 2012

* To be filed by amendment.

† The schedules and exhibits to this agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant will furnish supplementally a copy of each such schedule and exhibit to the Securities and Exchange Commission upon request.

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