S-1/A 1 d406707ds1a.htm AMENDMENT NO. 2 TO FORM S-1 Amendment No. 2 to Form S-1
Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on October 25, 2012

Registration No. 333-183808

 

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 2 to

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

   $ 290,091,904       $ 33,573.53 (3) 

 

 

 

(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.
(3) Includes $33,489.38 previously paid.

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.

 

 

 


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Index to Financial Statements

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 October 25, 2012

PROSPECTUS

15,765,864 Shares

 

LOGO

Energy & Exploration Partners, Inc.

Common Stock

 

 

We are offering 15,000,000 shares of our common stock and the selling stockholders are offering 765,864 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 $14.00 and $16.00 per share. Our common stock has been approved for listing on the New York Stock Exchange, subject to official notice of issuance, 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 17 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(1)

   $         $     

Proceeds to selling stockholders(2)

   $         $     

 

(1) For additional information about underwriting compensation, please see “Underwriting.”
(2) Expenses associated with the offering of shares by the selling stockholders, other than underwriting discounts, will be paid by us.

We have granted the underwriters a 30-day option to purchase up to an additional 2,364,880 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.

Global Hunter Securities

Stephens Inc.   Capital One Southcoast   Macquarie Capital   Wunderlich Securities

 

Knight   C. K. Cooper & Company   Guggenheim Securities

The date of this prospectus is                      2012.


Table of Contents
Index to Financial Statements

 

LOGO


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     17   

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     39   

USE OF PROCEEDS

     41   

DIVIDEND POLICY

     43   

CAPITALIZATION

     44   

DILUTION

     45   

SELECTED COMBINED FINANCIAL DATA

     46   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     48   

BUSINESS

     63   

MANAGEMENT

     83   

EXECUTIVE COMPENSATION

     90   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     96   

PRINCIPAL AND SELLING STOCKHOLDERS

     100   

DESCRIPTION OF CAPITAL STOCK

     102   

SHARES ELIGIBLE FOR FUTURE SALE

     107   

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

     109   

UNDERWRITING

     112   

LEGAL MATTERS

     119   

EXPERTS

     119   

WHERE YOU CAN FIND MORE INFORMATION

     119   

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.


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Index to Financial Statements

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. After giving effect to the acquisition of acreage from Chesapeake Energy Corporation and the related conveyance of acreage described below, we will own 84,989 net acres 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 13,935 net acres in our Eaglebine core area. 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 some 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 to acquire 57,275 net acres, eight producing wells and two non-producing wells in the Eaglebine (including 22,080 net acres in AMI #1 and AMI #2) from subsidiaries of Chesapeake Energy Corporation, or Chesapeake, for $126 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. Pursuant to our AMI #1 and AMI #2 agreements with Halcón and contingent upon closing of the Chesapeake acquisition, Halcón has elected to purchase its pro rata interest in the AMI #1 and AMI #2 acreage and AMI #2 wells we will acquire in the Chesapeake acquisition. Accordingly, we expect to convey to Halcón 16,529 net acres and an 80% working interest in two producing wells to be acquired in the Chesapeake acquisition for approximately $53.1 million. Pursuant to our agreement with Constellation, Constellation also has the right to acquire its pro rata interest in the AMI #1 and AMI #2 acreage and AMI #2 wells we will acquire in the Chesapeake acquisition. If Constellation exercises this right, we expect to convey 1,482 net acres and a 5% working interest in two producing wells to Constellation for approximately $4.7 million.

 

 

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Index to Financial Statements

In addition to our acreage in the Eaglebine, we have 13,377 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 (net of the acreage to be conveyed to Halcón), could contain a total of 1,030 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 October 11, 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 $15 million for leasehold acquisitions (excluding the Chesapeake acquisition and the potential Halcón acquisition described under “—Recent Developments—Letters of Intent with Halcón”) and $10 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)  

Current Eaglebine (2)

              

Horizontal Woodbine/Eagle Ford

     13,935         120         116         16       $ 111   

Vertical Lower Cretaceous

     13,935         160         87               $   
  

 

 

       

 

 

    

 

 

    

 

 

 

Total

     13,935            203         16       $ 111   

Chesapeake Eaglebine Acquisition (3)

              

Horizontal Woodbine/Eagle Ford

     40,746         120         340         21       $ 147   

Vertical Lower Cretaceous

     40,746         160         255         4       $ 12   
  

 

 

       

 

 

    

 

 

    

 

 

 

Total

     40,746            594         25       $ 159   
  

 

 

       

 

 

    

 

 

    

 

 

 

Total Eaglebine

     54,681            797         41       $ 270   

Wolfcamp (4)

              

Horizontal Wolfcamp

     13,377         160         84         5       $ 40   

Horizontal Cline

     13,377         160         84               $   
  

 

 

       

 

 

    

 

 

    

 

 

 

Total Wolfcamp

     13,377            167         5       $ 40   

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)

     84,989            1,030         61       $ 320   
  

 

 

       

 

 

    

 

 

    

 

 

 

 

(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) 

25% non-operated working interest in AMI #1, 15% non-operated working interest in AMI #2, and generally 100% operated working interest outside the AMIs. Gives effect to the conveyance of 16,529 net acres to Halcón pursuant to its election to purchase its pro rata interest in AMI #1 and AMI #2. Includes 1,482 net acres that may be conveyed to Constellation if it elects to purchase its pro rata working interest in AMI #1 and AMI #2. 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

 

 

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of net acreage to 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

Giving effect to the Chesapeake acquisition (net of the acreage to be conveyed to Halcón), we will own 54,681 net acres in the Eaglebine located in Leon, Grimes, Madison, Houston, Walker, and Robertson 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 (net of the acreage to be conveyed to Halcón), we estimate that we have 797 potential net drilling locations in the Eaglebine. Through the end of 2013, we plan to drill 37 net horizontal wells and 4 net vertical wells and have budgeted $270 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 September 17, 2012. Pursuant to the agreement, we conveyed a 65% working interest in 45,050 net acres (29,283 net to Halcón) for $43.9 million in proceeds, and received $0.7 million for Halcón’s share of acreage acquisition and surface costs, through September 30, 2012.

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 $29.3 million, upon the drilling and completion of two commercial wells on the acreage in which Halcón acquired an interest pursuant to the purchase and sale agreement. If Halcón does not drill two commercial wells on the acreage by April 19, 2013, 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 receipt of the contingent payment, we will have conveyed to Halcón 29,283 net acres for total proceeds of $73.2 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. Under the terms of AMI #1, we conveyed a 65% working interest in 949 net acres (617 net to Halcón) for $0.5 million in proceeds through October 11, 2012.

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, which is primarily located north and east of AMI #1. Pursuant

 

 

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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 October 11, 2012, we had acquired 3,738 net acres in AMI #2, of which we conveyed or will convey 2,990 net acres to Halcón in return for payment of 100% of the associated leasehold acquisition costs. In addition, we acquired 780 net acres from Halcón in September 2012 for $2.3 million of which Constellation has the right to acquire 195 acres for $0.6 million. Halcón will be the operator on all AMI #2 acreage in which we and Halcón jointly acquire an interest pursuant to this agreement.

In August 2012, we entered into a purchase and sale agreement with Constellation and, during the third quarter of 2012, we 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 this agreement, we conveyed 4,747 net acres in AMI #1 and AMI #2 for $30.9 million and received $2.5 million as reimbursement for costs associated with the first three Halcón-operated Eaglebine wells. In addition to the cash proceeds, 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. Following the final closings with both Halcón and Constellation in September 2012, we retained at a minimum a 25% working interest in AMI #1 and a 15% working interest in AMI #2. For future acquisitions, Constellation has the right to 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 acre in AMI #2.

In September 2012, we entered into a purchase and sale agreement with Chesapeake, which we amended in October 2012, to acquire a 100% working interest in 57,275 net acres (including 22,080 net acres in AMI #1 and AMI #2), eight producing wells, one well awaiting a pipeline connection and one non-producing well in the Eaglebine for $126 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. This acreage, which is located in Madison, Grimes, Leon, Robertson, and Houston Counties, would increase our total Eaglebine position to 54,681 net acres, giving effect to the conveyance to Halcón described below. We were required to offer our partners, Halcón and Constellation, their pro rata working interest in acreage and wells that we acquire in AMI #1 and AMI #2. Subject to closing of the Chesapeake acquisition, Halcón has elected to purchase its pro rata working interest in the acreage and the two wells located in AMI #2. Accordingly, we expect to convey to Halcón 16,529 net acres and an 80% working interest in two producing wells to be acquired in the Chesapeake acquisition for approximately $53.1 million. If Constellation elects to purchase its pro rata working interest in AMI #1 and AMI #2, we would expect to convey approximately 1,482 net acres and a 5% working interest in two producing wells to Constellation for approximately $4.7 million, thereby leaving us with 39,264 net acres from this transaction and a total of 53,199 net acres in the Eaglebine. Halcón will 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 Constellation. For additional information regarding the Chesapeake acquisition, including certain terms of the purchase and sale agreement, see “Business—Chesapeake Acquisition.”

Drilling on our AMI #1 acreage commenced in the second quarter of 2012. As of October 11, 2012, we had three Halcón-operated wells in AMI #1, in which we have a 25% non-operated working interest, in the process of drilling or completion. Halcón has received drilling permits for four additional AMI #1 wells, in which we will have a 25% non-operated working interest.

Drilling on our AMI #2 acreage commenced in the third quarter of 2012. As of October 11, 2012, we had one Halcón-operated well in AMI #2, in which we have a 20% non-operated working interest, in the process of drilling. Pursuant to our agreement with Constellation, we have sent to Constellation an election notice that will

 

 

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allow Constellation at its option to acquire from us a 5% working interest in this well for its pro rata share of well costs. Halcón has received a drilling permit for one additional AMI #2 well, in which we will have a 20% non-operated working interest, subject to Constellation’s right to elect to acquire from us a 5% working interest in the well for its pro rata share of well costs.

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, Chesapeake Energy Corporation, Samson Investment Company, Woodbine Acquisition Corporation, XTO Energy Inc., Trivium Operating, LLC, PetroMax Operating Company, Inc., Gastar Exploration Ltd., Encana Corporation, Terrace Energy Corp., Fidelity Exploration & Production, Navidad Resources, LLC, Burk Royalty Company, Silver Oak Energy, LLC, ZaZa Energy Corporation, Crimson Exploration Inc., and Crimson Energy Partners III, L.L.C. According to Drillinginfo, Inc., there were 320 drilling permits filed in 2011 and 278 filed in 2012 through October 11 in the Eaglebine. According to estimates prepared by Baker Hughes Incorporated, there were 25 rigs operating in the Eaglebine as of October 5, 2012.

Wolfcamp

As of October 11, 2012, we owned 13,377 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 167 net potential drilling locations in the Wolfcamp. Through the end of 2013, we plan to drill 5 net horizontal wells and have budgeted $40 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 Shell Western E&P Inc., BHP Billiton Petroleum, Apache Corporation, Chevron Corporation, Callon Petroleum Company, SM Energy Company, XTO Energy Inc. and Concho Resources, Inc. According to Drillinginfo, Inc., there were 163 drilling permits filed in 2011 and 100 filed in 2012 through October 11 in Lynn, Lubbock, Hockley, and Terry Counties, Texas, which offset our acreage position. According to estimates prepared by Baker Hughes, there were 500 rigs operating in the Permian Basin as of October 5, 2012.

 

 

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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 western, northern and eastern extensions 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 a PDC Energy, Inc.-operated horizontal Niobrara well located in Weld County, Colorado in the northern extension of Wattenberg Field. This well 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, Inc., 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 1,625 filed in 2012 through October 11 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 43 rigs operating in the Denver-Julesburg Basin as of October 5, 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 41 net wells and spend $270 million through 2013 in the Eaglebine alone. In addition, we plan to drill 5 net wells and spend $40 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.

 

 

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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 30, 2012, the credit facility had a borrowing base of $25 million, and we had $19.4 million in outstanding borrowings. We expect that the net 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 September 30, 2012, we had approximately $30.1 million in cash and deposits associated with our credit facility and approximately $5.6 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 (net of the acreage to be conveyed to Halcón), we expect to have accumulated a total of 84,989 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.    Giving effect to the Chesapeake acquisition (net of the acreage to be conveyed to Halcón) we estimate that there could be 1,030 potential net drilling locations across our 84,989 net acres. Through the end of 2013 we anticipate drilling 37 net horizontal Eaglebine wells, 4 net vertical Eaglebine Lower Cretaceous wells, 5 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.

 

 

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Experienced technical and land acquisition teams.    Our senior technical team is comprised of geoscience, engineering and operational professionals who average 34 years of industry experience. Members of our technical team have previously held technical and management positions with major and independent oil and natural gas companies, including Mobil Corporation, Phillips Petroleum Corporation, and Pitts Energy Group. Our core management and land acquisition team has built our existing significant acreage positions in our core areas. 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 40% of our outstanding shares following the completion of this offering, which we believe will align the interests of management, employees and stockholders.

Recent Developments – Letters of Intent with Halcón

In October 2012, we entered into two non-binding letters of intent with Halcón related to Eaglebine acreage. The first letter of intent, which we refer to as the Halcón acquisition LOI, contemplates establishment of a new Eaglebine area of mutual interest, which we refer to as AMI #3, and our acquisition from Halcón of a 65% operated working interest in 14,030 undeveloped acres (9,120 acres net to our interest) in AMI #3 in Leon County, Texas for approximately $22.8 million, subject to customary purchase price adjustments, which we refer to as the potential Halcón acquisition. Halcón will retain a 25% working interest. The terms of AMI #3 are to be negotiated, but we would be the operator in AMI #3. The Halcón acquisition LOI is subject to negotiation of a definitive agreement but requires Halcón and us to negotiate in good faith to reach agreement on definitive documentation. The potential Halcón acquisition also is subject to closing of the Chesapeake acquisition and completion of due diligence and receipt of necessary corporate and other internal approvals of Halcón and us. The Halcón acquisition LOI may be terminated by Halcón or us if definitive documentation has not been executed by November 30, 2012 or by us if the results of our due diligence are not satisfactory to us in our sole discretion. Although we present certain information in this prospectus regarding the acreage that we may acquire pursuant to the potential Halcón acquisition, the Halcón acquisition LOI does not obligate Halcón or us to consummate the transaction, and we therefore cannot assure you that the potential Halcón acquisition will be completed on the terms set forth in the Halcón acquisition LOI or at all.

The following table presents summary data for the leasehold acreage we would acquire in the potential Halcón acquisition if that transaction is consummated.

 

     Net
Acres
     Acre
Spacing
     Potential
Net Drilling
Locations(1)
 
        

Potential Halcón Eaglebine Acquisition(2):

        

Horizontal Woodbine/Eagle Ford

     9,120         120         76   

Vertical Lower Cretaceous

     9,120         160         57   
  

 

 

    

 

 

    

 

 

 

Total

     9,120            133   
  

 

 

       

 

 

 

 

  (1) 

Potential net drilling locations are calculated using the acre spacings specified in the table. There are no proved, probable or possible reserves attributable to any of these potential net drilling locations.

  (2) 

65% operated working interest.

The second letter of intent, which we refer to as the Halcón disposition LOI, contemplates our sale to Halcón of 952 net acres that we will acquire in the Chesapeake acquisition for approximately $9.5 million, which we refer to as the potential Halcón disposition. The Halcón disposition LOI is subject to negotiation of a definitive agreement but requires Halcón and us to negotiate in good faith to reach agreement on definitive

 

 

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documentation. The potential Halcón disposition also is subject to closing of the Chesapeake acquisition and completion of due diligence and receipt of necessary corporate and other internal approvals of Halcón and us. The Halcón disposition LOI may be terminated by Halcón or us if definitive documentation has not been executed by November 30, 2012 or if the Chesapeake acquisition has not closed by December 15, 2012 or by Halcón if the results of its due diligence are not satisfactory to it in its sole discretion. The Halcón disposition LOI does not obligate Halcón or us to consummate the transaction, and we therefore cannot assure you that the potential Halcón disposition will be completed on the terms set forth in the Halcón disposition LOI or at all.

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 11,521,240 shares of our 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 3,999,960 shares of our common stock; and

 

   

certain of the Niobrara investors contributed their net profits interests in our Niobrara acreage to us in exchange for 338,800 shares of our 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

 

 

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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 for de minimis consideration. Energy & Exploration Partners, LP is a plaintiff in certain immaterial contract disputes related to certain oil and natural gas properties previously held by us and holds no other assets. Mr. Pettit owns all of the limited partnership interests in Energy & Exploration Partners, LP.

Restricted Stock Awards for Management.    In connection with the transactions described above, we made awards to members of our senior management, other than Mr. Pettit, of 4,100,000 restricted shares of our common stock under our 2012 Stock Incentive Plan. These shares of restricted stock vest in three equal increments, initially upon completion of this offering and on the first and second anniversaries of the completion of this offering, except in the case of shares of restricted stock awarded to our Chief Financial Officer, Brian C. Nelson, which vest in 50% increments upon the completion of this offering and on January 1, 2013. See “Executive Compensation—2012 Stock Incentive Plan.”

In September 2012, Hunt Pettit contributed 900,000 shares of our 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 vest in three equal increments, initially upon the completion of this offering and on the first and second anniversaries of the completion of this offering.

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.”

 

 

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

Ownership Structure After this Offering

 

LOGO

 

(1) 

Includes 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.”

Corporate History; Corporate Information

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

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

Risk Factors

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

 

   

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

 

 

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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.

 

   

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

 

   

We may not complete the potential Halcón acquisition or the potential Halcón disposition on the terms described in this prospectus or at all.

 

   

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 17.

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

 

 

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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

15,000,000 shares

 

Common stock offered by the selling stockholders

765,864 shares

 

Common stock to be outstanding after this offering

35,000,000 shares

 

Option to purchase additional shares

The underwriters have an option to purchase a maximum of 2,364,880 additional shares of common stock from us to cover sales by the underwriters of more than 15,765,864 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 $207.2 million of net proceeds from the sale of the common stock offered by us, based upon an assumed initial public offering price of $15.00 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 $14.1 million.

 

  We intend to use the net proceeds we receive from this offering to fund the Chesapeake acquisition, to fund the potential Halcón acquisition if that transaction is consummated 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

Our common stock has been approved for listing on the New York Stock Exchange, subject to official notice of issuance, under the symbol “ENXP.”

 

Risk Factors

See “Risk Factors” beginning on page 17 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 5,250,000 shares of common stock reserved for issuance under our 2012 Stock Incentive Plan; and

 

   

gives effect to a 40-for-1 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 September 30, 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.

 

     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      $ (2,736   $ 1,733   

 

 

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     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       $ 38,322   

Property, plant and equipment

   $ 3,649       $ 21,641       $ 19,637       $ 19,637   

Total assets

   $ 6,728       $ 27,904       $ 45,799       $ 76,367   

Note payable, net of discount

   $       $ 9,928       $ 21,471       $ 14,957   

Total equity

   $ 5,669       $ 4,471       $ 4,705       $ 55,949   

 

     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 September 30, 2012, the NYMEX—WTI oil price ranged from a high of $113.93 per bbl to a low of $33.87 per bbl, while the NYMEX—Henry Hub natural gas price ranged from a high of $7.64 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 pursue 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.

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 (including contingent payments expected to be received from Halcón) and net proceeds from this offering. In addition to the net proceeds from this offering, cash on hand, proceeds from divestitures to Halcón, and borrowings under our existing credit facility, we will require approximately $99 million to fund our $497 million capital expenditures budget through December 31, 2013. We do not expect to generate significant revenues from production until 2013, and our cash flows from operating activities are therefore uncertain. Additionally, 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, our cash flows from operating activities are less than we expect or Halcón does not make its contingent payments to us, we will be required to seek other financing, which may not be available on favorable terms, or at all. If such financing is not available, we would be forced to curtail or delay our planned capital expenditures. Additionally, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or additional equity securities. The issuance of additional debt may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. If we succeed in selling additional equity securities to raise funds, at such time the ownership percentage of our existing stockholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we raise additional capital through debt financing, the financing may involve covenants that restrict our business activities. If we choose to farm-out interests in our prospects, we may lose operating control over such prospects.

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

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

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.

As of September 30, 2012, we had outstanding indebtedness of approximately $19.4 million and a borrowing capacity of $5.6 million under our credit facility. 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 October 11, 2012, all of our acreage, including the acreage we will acquire in the Chesapeake acquisition and may acquire in the potential Halcón 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 (net of the conveyance of acreage to Halcón), as of October 11, 2012, we had leases representing 2,506 net acres expiring in 2012, 16,811 net acres expiring in 2013, 35,200 net acres expiring in 2014 and 27,285 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.

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

 

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materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations including the acquisition of permits before conducting drilling or underground injection activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of our operations.

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

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

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

Additionally, the U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane, that are understood to contribute to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near

 

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future, although energy legislation and other initiatives continue to be proposed that may be relevant to greenhouse gas emissions issues. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that smaller sources could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil and natural gas we produce.

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

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

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

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

There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic-fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic-fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic-fracturing practices. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of

 

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hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic-fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.

Additionally, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the SEC to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural-gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural-gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate hydraulic fracturing activities.

Further, on April 17, 2012, the EPA approved final rules that would subject all oil and natural gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs. These rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion (REC) techniques developed in EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (MACT) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. At this point, the effect these proposed rules could have on our business has not been determined. While these rules have been finalized, many of the rules’ provisions will be phased-in over time, with the more stringent requirements like REC not becoming effective until 2015.

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

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

Our ability to acquire additional drilling locations and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, obtaining gathering, processing and pipeline transportation services, marketing oil and natural gas and securing equipment and trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil and natural gas properties and exploratory drilling locations or to identify, evaluate, bid for and purchase a greater number of properties and locations than our financial or personnel resources permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful drilling attempts, sustained periods of volatility in financial and commodity markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which would adversely affect our competitive position. In addition, companies may be able to offer better compensation packages to attract and

 

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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 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.

 

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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 were promulgated by the CFTC imposing federally-mandated position limits covering a wide range of derivatives positions, including non-exchange traded bilateral swaps related to commodities including oil and natural gas. These position limit rules were vacated by a Federal court in September 2012, and the CFTC could appeal that decision and/or re-promulgate the rules in a manner that addresses the defects identified by the court. If these position limits rules go into effect in the future, they 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 potential Halcón 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, and the definitive agreement for the potential Halcón acquisition is expected to include, 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 or the potential Halcón 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 not complete the potential Halcón acquisition or the potential Halcón disposition on the terms described in this prospectus or at all.

The potential Halcón acquisition and the potential Halcón disposition are subject to negotiation of definitive documentation, closing of the Chesapeake acquisition, completion of due diligence, and the receipt of necessary corporate and other internal approvals of Halcón and us or at all. The Halcón acquisition LOI and the Halcón disposition LOI may be terminated by Halcón or us if definitive documentation has not been executed by November 30, 2012, or by us or Halcón, respectively, if the results of due diligence are not satisfactory to us or Halcón. Additionally, the Halcón disposition LOI may be terminated by Halcón or us if the Chesapeake acquisition has not closed by December 15, 2012. Although we present certain information in this prospectus regarding the acreage that we may acquire pursuant to the potential Halcón acquisition and regarding the potential Halcón disposition, neither the Halcón acquisition LOI nor the Halcón disposition LOI obligates us or Halcón to consummate the transactions and we therefore cannot assure you that either transaction will be completed on the terms described in this prospectus or at all. In evaluating an investment in our company, you should not assume that the potential Halcón acquisition or the potential Halcón disposition will be completed.

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 and the potential Halcón 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 and the potential Halcón 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.

 

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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.

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.

 

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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 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 the potential Halcón acquisition and other 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 28% 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 $7.58 per share.

Based on an assumed initial public offering price of $15.00 per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $7.58 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 $7.42 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;

 

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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 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

 

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growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

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

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

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

We may sell additional shares of common stock in subsequent public offerings or otherwise issue additional shares of common stock or convertible securities. Assuming no exercise of the underwriters’ option to purchase additional shares, after the completion of this offering, we will have 35,000,000 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 19,093,856 shares, or 54.55% of our total outstanding shares, all of which will be restricted from immediate resale under the federal securities laws and 18,328,696 shares of which 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 are 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 5,250,000 shares of our common stock reserved for issuance under our stock incentive plan. Subject to the satisfaction of vesting conditions, restrictions applicable to our affiliates under Rule 144 under the Securities Act 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 and Delaware law 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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Furthermore, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the General Corporation Law of the State of Delaware, which prohibits, with some exceptions, stockholders owning in excess of 15% of our outstanding voting stock from engaging in business combination transactions with us. See “Description of Capital Stock—Anti-Takeover Effects of Provisions of Our Certificate of Incorporation, Our Bylaws and Delaware Law.”

We have renounced our interest and expectancy in certain corporate opportunities, which could adversely affect our business or prospects.

Our board of directors has approved a resolution providing that, for so long as Rosser Newton continues to be a member of our board of directors, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in, or in being offered an opportunity to participate in, any business opportunity (including without limitation principal investment opportunities and advisory services) that may be from time to time presented to Petro Capital Securities, LLC, Petro Capital Holdings, LLC, Petro Capital Holdings II, LLC or any of their respective officers, directors, agents, shareholders, members, partners, affiliates and subsidiaries (including Mr. Newton but other than us and our subsidiaries) (collectively, “Petro Capital”) or business opportunities that such parties participate in or desire to participate in, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so, neither Mr. Newton nor Petro Capital shall have any duty or obligation to communicate or offer such business opportunity to us, and no such person shall be liable to us for breach of any fiduciary or other duty, as a director or otherwise, by reason of the fact that such person pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us unless, in the case of Mr. Newton, any such business opportunity is expressly offered to Mr. Newton solely in his capacity as our director.

Petro Capital is an energy focused merchant and investment bank. As a result, Mr. Newton may become aware, from time to time, of certain business opportunities, such as acquisition opportunities, and may direct such opportunities to other businesses in which Petro Capital has invested or to which it provides merchant or investment banking services, in which case we may not become aware of or otherwise have the ability to pursue such opportunities. Further, such businesses may choose to compete with us for these opportunities. As a result, our renouncing our interest and expectancy in any business opportunity that may be from time to time presented to Petro Capital could adversely impact our business or prospects if attractive business opportunities are procured by such parties for their own benefit rather than for ours. See “Description of Capital Stock—Corporate Opportunity.”

 

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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 and the potential Halcón 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 $207.2 million from the sale of our common stock, assuming an initial public offering price of $15.00 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 $14.1 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 $126 million, and we paid a deposit to Chesapeake of $3.5 million, which will be applied to the purchase price at closing. The purchase price is subject to customary pre- and post-closing adjustments. We also expect to pay $3 million to Chesapeake to extend the closing date beyond October 31, 2012. See “Business—Chesapeake Acquisition.” We also intend to use approximately $22.8 million of the net proceeds of this offering to pay the purchase price for the potential Halcón acquisition if that transaction is consummated. We intend to use the remainder of the net proceeds from this offering to fund a portion of our $345 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 $320 million for drilling and developing our leasehold acreage, approximately $15 million for acquiring additional oil and natural gas leases (excluding the Chesapeake acquisition and the potential Halcón acquisition), and approximately $10 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 including the potential Halcón disposition and borrowings under our credit facility. If Constellation elects to purchase its pro rata working interest in the acreage and wells to be acquired from Chesapeake in AMI #1 and AMI #2, we will use the proceeds of the conveyance to Constellation for our capital expenditure budget.

The following table sets forth the expected sources and uses of funds for our capital expenditure budget for the second half of 2012 and 2013.

 

Sources of Funds ($ millions)

        

Uses of Funds ($ millions)

     

Net proceeds from this offering

  $ 207      

Chesapeake acquisition (6)

  $ 126   
    

Potential Halcón acquisition

    23   

Current cash, cash equivalents and deposits (1)

    30      

Drilling & completion capital (7)

    311   

Halcón payment for Chesapeake acquisition acreage and wells (2)

    53      

Leasehold acquisitions (8)

    5   

Halcón contingent payment (3)

    29      

Other (including seismic)

    10   

Potential Halcón disposition

    10        

Expected borrowings under existing credit facility (4)

    47        

Other sources (5)

    99        
 

 

 

      

 

 

 

Total sources of funds

  $ 475      

Total uses of funds

  $ 475   
 

 

 

      

 

 

 

 

(1) 

As of September 30, 2012.

(2) 

Expected payment for the conveyance to Halcón of 16,529 net acres and an 80% working interest in two wells that we will acquire in the Chesapeake acquisition.

(3) 

Expected payment due upon the earlier of drilling two commercial wells in AMI #1 or April 19, 2013.

(4) 

As of September 30, 2012, we had outstanding borrowings of approximately $19.4 million and approximately $5.6 million of available borrowing capacity under our $100 million credit facility. Additional borrowings are subject to approval of our lenders.

(5) 

Other sources include cash flow from operations, proceeds from potential asset divestitures (including the potential conveyance to Constellation described above) and/or additional debt.

(6) 

Purchase price of $126.0 million less $3.5 million deposit previously paid plus $3.0 million payment to extend the closing date.

 

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(7) 

$320 million capital budget for July 2012 through December 2013, less $8.7 million spent in the third quarter of 2012.

(8) 

$15 million capital budget for July 2012 through December 2013, less $9.9 million spent in the third quarter of 2012.

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,” “Business—Our Operations—Capital Expenditures” and “Risk Factors—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 pursue our exploration and production plans.”

 

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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       $ 38,322       $ 120,061   

Deposits(1)

     9,545         9,545         9,545   
  

 

 

    

 

 

    

 

 

 

Long-term debt, including current maturities

     21,471         14,957         14,957   

Members’/stockholders’ equity:

        

Equity

     4,705                   

Common stock, $0.01 par value; 175,000,000 shares authorized, 20,000,000 shares and 35,000,000 shares issued and outstanding (Pro Forma and Pro Forma As Adjusted, respectively)

             200         350   

Paid-in capital

             55,749         262,838   
  

 

 

    

 

 

    

 

 

 

Total members’/stockholders’ equity

     4,705         55,949         263,188   
  

 

 

    

 

 

    

 

 

 

Total capitalization

   $ 26,176       $ 70,906       $ 278,145   
  

 

 

    

 

 

    

 

 

 

 

(1) 

Deposits consist of cash held on our behalf by Guggenheim to fund the portion of our drilling, completion and seismic activities in the Eaglebine not covered by advances under our credit facility.

 

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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 $52.4 million, or $2.62 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 $259.7 million, or $7.42 per share. This represents an immediate increase in the net tangible book value of $4.80 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 $7.58 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

      $ 15.00   

Pro forma net tangible book value per share as of June 30, 2012 (after giving effect to the Pro Forma Transactions)

   $ 2.62      

Increase per share attributable to new investors in this offering

   $ 4.80      
  

 

 

    

As adjusted pro forma net tangible book value per share after giving effect to the Pro Forma Transactions and this offering

        7.42   
     

 

 

 

Dilution in pro forma net tangible book value per share to new investors in this offering

      $ 7.58   
     

 

 

 

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 $15.00, 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

     20,000,000         57.1   $ 52,437,000         18.9   $ 2.62   

New investors

     15,000,000         42.9     225,000,000         81.1     15.00   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Total

     35,000,000         100.0   $ 277,437,000         100.0   $ 7.93   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

 

(1)

The number of shares disclosed for the existing stockholders includes 765,864 shares being sold by the selling stockholders. The number of shares disclosed for the new investors does not include the 765,864 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.

 

 

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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)

        

Interest and other income

     3        25        52        9   

Interest expense

            (270            (1,097

Gains on sale of assets

     6,039        573        573        5,805   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income, net

     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. After giving effect to the Chesapeake acquisition and the related conveyance of acreage to Halcón, we will own 84,989 net acres 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 13,935 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 some 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 to acquire 57,275 net acres, eight producing wells and two non-producing wells in the Eaglebine (including 22,080 net acres in AMI #1 and AMI #2) from subsidiaries of Chesapeake Energy Corporation, or Chesapeake, for $126 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. Pursuant to our AMI #1 and AMI #2 agreements with Halcón and contingent upon closing of the Chesapeake acquisition, Halcón has elected to purchase its pro rata interest in the AMI #1 and AMI #2 acreage and AMI #2 wells we will acquire in the Chesapeake acquisition. Accordingly, we expect to convey to Halcón 16,529 net acres and an 80% working interest in two producing wells to be acquired in the Chesapeake acquisition for approximately $53.1 million. Pursuant to our agreement with Constellation, Constellation also has the right to acquire its pro rata interest in the AMI #1 and AMI #2 acreage and AMI #2 wells we will acquire in the Chesapeake acquisition. If Constellation exercises this right, we expect to convey 1,482 net acres and a 5% working interest in two producing wells to Constellation for approximately $4.7 million.

In October 2012, we entered into two non-binding letters of intent with Halcón related to Eaglebine acreage. The first letter of intent, which we refer to as the Halcón acquisition LOI, contemplates establishment of a new Eaglebine area of mutual interest, which we refer to as AMI #3, and our acquisition from Halcón of a 65% operated working interest in 14,030 undeveloped acres (9,120 acres net to our interest) in AMI #3 in Leon County, Texas for approximately $22.8 million, subject to customary purchase price adjustments, which we refer to as the potential Halcón acquisition. Halcón will retain a 25% working interest. The terms of AMI #3 are to be negotiated, but we would be the operator in AMI #3. The Halcón acquisition LOI is subject to negotiation of a definitive agreement but requires Halcón and us to negotiate in good faith to reach agreement on definitive documentation. The potential Halcón acquisition also is subject to closing of the Chesapeake acquisition and completion of due diligence and receipt of necessary corporate and other internal approvals of Halcón and us.

 

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The Halcón acquisition LOI may be terminated by Halcón or us if definitive documentation has not been executed by November 30, 2012 or by us if the results of our due diligence are not satisfactory to us in our sole discretion. Although we present certain information in this prospectus regarding the acreage that we may acquire pursuant to the potential Halcón acquisition, the Halcón acquisition LOI does not obligate Halcón or us to consummate the transaction, and we therefore cannot assure you that the potential Halcón acquisition will be completed on the terms set forth in the Halcón acquisition LOI or at all.

The second letter of intent, which we refer to as the Halcón disposition LOI, contemplates our sale to Halcón of 952 net acres that we will acquire in the Chesapeake acquisition for approximately $9.5 million, which we refer to as the potential Halcón disposition. The Halcón disposition LOI is subject to negotiation of a definitive agreement but requires Halcón and us to negotiate in good faith to reach agreement on definitive documentation. The potential Halcón disposition also is subject to closing of the Chesapeake acquisition and completion of due diligence and receipt of necessary corporate and other internal approvals of Halcón and us. The Halcón disposition LOI may be terminated by Halcón or us if definitive documentation has not been executed by November 30, 2012 or if the Chesapeake acquisition has not closed by December 15, 2012 or by Halcón if the results of its due diligence are not satisfactory to it in its sole discretion. The Halcón disposition LOI does not obligate Halcón or us to consummate the transaction, and we therefore cannot assure you that the potential Halcón disposition will be completed on the terms set forth in the Halcón disposition LOI or at all.

In addition to our acreage in the Eaglebine, we have 13,377 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 (net of the acreage to be conveyed to Halcón), could contain a total of 1,030 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 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.

Drilling on our AMI #1 acreage commenced in the second quarter of 2012. As of October 11, 2012, we had three Halcón-operated wells in AMI #1, in which we have a 25% non-operated working interest, in the process of drilling or completion. Halcón has received drilling permits for four additional AMI #1 wells, in which we will have a 25% non-operated working interest.

Drilling on our AMI #2 acreage commenced in the third quarter of 2012. As of October 11, 2012, we had one Halcón-operated well in AMI #2, in which we have a 20% non-operated working interest, in the process of drilling. Pursuant to our agreement with Constellation, we have sent to Constellation an election notice that will allow Constellation at its option to acquire from us a 5% working interest in this well for its pro rata share of well costs. Halcón has received a drilling permit for one additional AMI #2 well, in which we will have a 20% non-operated working interest, subject to Constellation’s right to elect to acquire from us a 5% working interest in the well for its pro rata share of well costs.

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.

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

 

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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 a PDC Energy, Inc.-operated Niobrara 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).

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 $113.93 per bbl to a low of $75.40 per bbl during the year ended December 31, 2011 and from a high of $109.77 per bbl to a low of $77.69 per bbl in the first nine months of 2012.

 

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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 $3.20 per MMBtu to a low of $1.82 per MMBtu in the first nine 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.

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

 

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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.

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 a PDC Energy, Inc.-operated Niobrara 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.

 

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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.

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 September 17, 2012. Pursuant to the agreement, we conveyed a 65% operated working interest in 45,050 net acres (29,283 net to Halcón) for $43.9 million in proceeds, and received $0.7 million for Halcón’s share of acreage acquisition and surface costs, through September 30, 2012.

 

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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 $29.3 million, upon the drilling and completion of two commercial wells on the acreage in which Halcón acquired an interest pursuant to the purchase and sale agreement. If Halcón does not drill two commercial wells on the acreage by April 19, 2013, 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 receipt of the contingent payment, we will have conveyed to Halcón 29,283 net acres for total proceeds of $73.2 million.

In August 2012, we entered into a purchase and sale agreement with Constellation and, during the third quarter of 2012, we 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 this agreement, we conveyed 4,747 net acres in AMI#1 and AMI #2 to Constellation for $30.9 million through September 30, 2012 and received $2.5 million as reimbursement for costs associated with the first three Halcón-operated Eaglebine wells. In addition to the cash proceeds, 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. Following the final closings with both Halcón and Constellation, we retained at a minimum a 25% working interest in AMI #1 and a 15% working interest in AMI #2. For future acquisitions, Constellation has the right to 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 acre in AMI #2.

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 the third and fourth quarters of 2012, we borrowed $2.9 million under our credit facility to fund 50% of our portion of two AMI #1 wells and repaid $6.5 million in connection with the conveyance of 4,747 net acres to Constellation, which reduced the borrowing base of our credit facility to $23.5 million. As of October 11, 2012, we had $17.9 million in outstanding borrowings under our credit facility and remaining undrawn capacity of $5.6 million. We anticipate using the remaining capacity of our credit facility to fund 50% of our portion of the drilling and completion costs for our next Eaglebine well, which has been pre-approved by Guggenheim, provided that drilling and completion costs do not exceed $10 million proportionately reduced 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 and AMI #2, 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 $8.0 million per well proportionately reduced 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 $8.0 million per well proportionately reduced 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.

 

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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, 2014

   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 1/12th increments as advances are made on each of the first twelve wells, may 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;

 

   

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.

 

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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, a PDC Energy, Inc.-operated Niobrara well, in which we have a 9.3% non-operated working interest, commenced production.

Drilling on our AMI #1 acreage commenced in the second quarter of 2012. As of October 11, 2012, we had three Halcón-operated wells in AMI #1, in which we have a 25% non-operated working interest, in the process of drilling or completion. Halcón has received drilling permits for four additional AMI #1 wells, in which we will have a 25% non-operated working interest.

Drilling on our AMI #2 acreage commenced in the third quarter of 2012. As of October 11, 2012, we had one Halcón-operated well in AMI #2, in which we have a 20% non-operated working interest, in the process of drilling. Pursuant to our agreement with Constellation, we have sent to Constellation an election notice that will allow Constellation at its option to acquire from us a 5% working interest in this well for its pro rata share of well costs. Halcón has received a drilling permit for one additional AMI #2 well, in which we will have a 20% non-operated working interest, subject to Constellation’s right to elect to acquire from us a 5% working interest in the well for its pro rata share of well costs.

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.

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.

 

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We estimate that we will make capital expenditures, excluding capitalized interest and general and administrative expense, of approximately $434 million, net of planned divestitures, 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 September 30, 2012, the balance owed under our credit facility was $19.4 million. As of September 30, 2012, we had cash and cash equivalents of $15.1 million, and deposits associated with our credit facility of $15.0 million, for a total of $30.1 million of cash and cash equivalents and deposits.

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.

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

 

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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 and September 2012, we borrowed $2.9 million under our credit facility to fund 50% of our portion of two AMI #1 wells. In August and October we repaid $6.5 million in connection with the conveyance of 4,747 net acres to Constellation for $30.9 million.

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

 

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

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

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

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

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

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

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The reserve estimates and the projected cash flows derived from these reserve estimates are prepared in accordance with SEC guidelines. The accuracy of our reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates, all of which could deviate significantly from actual results. As such, reserve estimates may vary materially from the ultimate quantities of oil, natural gas, and natural gas liquids eventually recovered.

Asset Retirement Obligations.    We comply with Accounting Standards Codification (ASC) 410-20, Asset Retirement and Environmental Obligations, to recognize estimated amounts for asset retirement obligations and asset retirement costs. This standard requires us to record a liability for the fair value of the asset retirement

 

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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.

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

 

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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 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

 

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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 September 30, 2012, we had $19.4 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. After giving effect to the Chesapeake acquisition and the related conveyance of acreage to Halcón, we will own 84,989 net acres 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 13,935 net acres in our Eaglebine core area. 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 to acquire 57,275 net acres, eight producing wells and two non-producing wells in the Eaglebine (including 22,080 net acres in AMI #1 AMI #2) from subsidiaries of Chesapeake Energy Corporation, or Chesapeake, for $126 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. Pursuant to our AMI #1 and AMI #2 agreements with Halcón and contingent upon closing of the Chesapeake acquisition, Halcón has elected to purchase its pro rata interest in the AMI #1 and AMI #2 acreage and AMI #2 wells we will acquire in the Chesapeake acquisition. Accordingly, we expect to convey to Halcón 16,529 net acres and an 80% working interest in two producing wells to be acquired in the Chesapeake acquisition for approximately $53.1 million. Pursuant to our agreement with Constellation, Constellation also has the right to acquire its pro rata interest in the AMI #1 and AMI #2 acreage and AMI #2 wells we will acquire in the Chesapeake acquisition. If Constellation exercises this right, we expect to convey 1,482 net acres and a 5% working interest in two producing wells to Constellation for approximately $4.7 million.

In addition to our acreage in the Eaglebine, we have 13,377 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 (net of the acreage to be conveyed to Halcón), could contain a total of 1,030 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 October 11, 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 $15 million for leasehold acquisitions (excluding the Chesapeake acquisition and the potential Halćon acquisition) and $10 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 “—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)  

Current Eaglebine (2)

              

Horizontal Woodbine/Eagle Ford

     13,935         120         116         16       $ 111   

Vertical Lower Cretaceous

     13,935         160         87               $   
  

 

 

       

 

 

    

 

 

    

 

 

 

Total

     13,935            203         16       $ 111   

Chesapeake Eaglebine Acquisition (3)

              

Horizontal Woodbine/Eagle Ford

     40,746         120         340         21       $ 147   

Vertical Lower Cretaceous

     40,746         160         255         4       $ 12   
  

 

 

       

 

 

    

 

 

    

 

 

 

Total

     40,746            594         25       $ 159   
  

 

 

       

 

 

    

 

 

    

 

 

 

Total Eaglebine

     54,681            797         41       $ 270   

Wolfcamp (4)

              

Horizontal Wolfcamp

     13,377         160         84         5       $ 40   

Horizontal Cline

     13,377         160         84               $   
  

 

 

       

 

 

    

 

 

    

 

 

 

Total Wolfcamp

     13,377            167         5       $ 40   

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)

     84,989            1,030         61       $ 320   
  

 

 

       

 

 

    

 

 

    

 

 

 

 

(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 generally 100% operated working interest outside AMIs.

(3) 

25% non-operated working interest in AMI #1, 15% non-operated working interest in AMI #2, and 100% operated working interest outside the AMIs. Gives effect to the conveyance of 16,529 net acres to Halcón pursuant to its election to purchase its pro rata interest in AMI #1 and AMI #2. Includes 1,482 net acres that may be conveyed to Constellation if it elects to purchase its pro rata working interest in AMI #1 and AMI #2. 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 Constellation. For additional information regarding the Chesapeake acquisition, including certain terms of the purchase and sale agreement, see “—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

Giving effect to the Chesapeake acquisition (net of the acreage to be conveyed to Halcón), we will own 54,681 net acres in the Eaglebine located in Leon, Grimes, Madison, Houston, Walker, and Robertson 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

 

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first two years of their three-year primary term and generally provide for two year extension options. Giving effect to the Chesapeake acquisition (net of the acreage to be conveyed to Halcón), we estimate that we have 797 potential net drilling locations in the Eaglebine. Through the end of 2013, we plan to drill 37 net horizontal wells and 4 net vertical wells and have budgeted $270 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 September 17, 2012. Pursuant to the agreement, we conveyed a 65% working interest in 45,050 net acres (29,283 net to Halcón) for $43.9 million in proceeds, and received $0.7 million for Halcón’s share of acreage acquisition and surface costs, through September 30, 2012.

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 $29.3 million, upon the drilling and completion of two commercial wells on the acreage in which Halcón acquired an interest pursuant to the purchase and sale agreement. If Halcón does not drill two commercial wells on the acreage by April 19, 2013, 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 receipt of the contingent payment, we will have conveyed to Halcón 29,283 net acres for total proceeds of $73.2 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. Under the terms of AMI #1, we conveyed a 65% working interest in 949 net acres (617 net to Halcón) for $0.5 million in proceeds through October 11, 2012.

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, which 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 October 11, 2012, we had acquired 3,738 net acres in AMI #2, of which we conveyed or will convey 2,990 net acres to Halcón in return for payment of 100% of the associated leasehold acquisition costs. In addition, we acquired 780 net acres from Halcón in September 2012 for $2.3 million of which Constellation has the right to acquire 195 acres for $0.6 million. Halcón will be the operator on all AMI #2 acreage in which we and Halcón jointly acquire an interest pursuant to this agreement.

In August 2012, we entered into a purchase and sale agreement with Constellation and, during the third quarter of 2012, we 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 this agreement, we conveyed 4,747 net acres in AMI #1 and AMI #2 for $30.9 million and received $2.5 million as reimbursement for costs associated with the first three Halcón-operated Eaglebine wells. In addition to the cash proceeds, 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. Following the final closings with both Halcón and Constellation in September 2012, we retained at a minimum a 25% working interest in AMI #1 and a 15% working interest in AMI #2. For future acquisitions, Constellation has the right to 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 acre in AMI #2.

 

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In September 2012, we entered into a purchase and sale agreement with Chesapeake, which we amended in October 2012, to acquire a 100% working interest in 57,275 net acres (including 22,080 net acres in AMI #1 and AMI #2), eight producing wells, one well awaiting a pipeline connection and one non-producing well in the Eaglebine for $126 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. This acreage, which is located in Madison, Grimes, Leon, Robertson, and Houston Counties, would increase our total Eaglebine position to 54,681 net acres, giving effect to the conveyance to Halcón described below. We were required to offer our partners, Halcón and Constellation, their pro rata working interest in acreage and wells that we acquire in AMI #1 and AMI #2. Subject to closing of the Chesapeake acquisition, Halcón has elected to purchase its pro rata working interest in the acreage and the two wells located in AMI #2. Accordingly, we expect to convey to Halcón 16,529 net acres and an 80% working interest in two producing wells to be acquired in the Chesapeake acquisition for approximately $53.1 million. If Constellation elects to purchase its pro rata working interest in AMI #1 and AMI #2, we would expect to convey approximately 1,482 net acres and a 5% working interest in two producing wells to Constellation for approximately $4.7 million, thereby leaving us with 39,264 net acres from this transaction and a total of 53,199 net acres in the Eaglebine. Halcón will 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 Constellation. For additional information regarding the Chesapeake acquisition, including certain terms of the purchase and sale agreement, see “Business—Chesapeake Acquisition.”

Drilling on our AMI #1 acreage commenced in the second quarter of 2012. As of October 11, 2012, we had three Halcón-operated wells in AMI #1, in which we have a 25% non-operated working interest, in the process of drilling or completion. Halcón has received drilling permits for four additional AMI #1 wells, in which we will have a 25% non-operated working interest.

Drilling on our AMI #2 acreage commenced in the third quarter of 2012. As of October 11, 2012, we had one Halcón-operated well in AMI #2, in which we have a 20% non-operated working interest, in the process of drilling. Pursuant to our agreement with Constellation, we have sent to Constellation an election notice that will allow Constellation at its option to acquire from us a 5% working interest in this well for its pro rata share of well costs. Halcón has received a drilling permit for one additional AMI #2 well, in which we will have a 20% non-operated working interest, subject to Constellation’s right to elect to acquire from us a 5% working interest in the well for its pro rata share of well costs.

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, Chesapeake Energy Corporation, Samson Investment Company, Woodbine Acquisition Corporation, XTO Energy Inc., Trivium Operating, LLC, PetroMax Operating Company, Inc., Gastar Exploration Ltd., Encana Corporation, Terrace Energy Corp., Fidelity Exploration & Production, Navidad Resources, LLC, Burk Royalty Company, Silver Oak Energy, LLC, ZaZa Energy Corporation, Crimson Exploration Inc., and Crimson Energy Partners III, L.L.C. According to Drillinginfo, Inc., there were 320 drilling permits filed in 2011 and 278 filed in 2012 through October 11 in the Eaglebine. According to estimates prepared by Baker Hughes Incorporated, there were 25 rigs operating in the Eaglebine as of October 5, 2012.

 

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Wolfcamp

As of October 11, 2012, we owned 13,377 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 167 net potential drilling locations in the Wolfcamp. Through the end of 2013, we plan to drill 5 net horizontal wells and have budgeted $40 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 Shell Western E&P Inc., BHP Billiton Petroleum, Apache Corporation, Chevron Corporation, Callon Petroleum Company, SM Energy Company, XTD Energy Inc. and Concho Resources, Inc. According to Drillinginfo, Inc., there were 163 drilling permits filed in 2011 and 100 filed in 2012 through October 11 in Lynn, Lubbock, Hockley, and Terry Counties, Texas, which offset our acreage position. According to estimates prepared by Baker Hughes, there were 500 rigs operating in the Permian Basin as of October 5, 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 western, northern and eastern extensions 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 a PDC Energy, Inc.-operated horizontal Niobrara well located in Weld County, Colorado on the northern extension of Wattenberg Field. This well 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

 

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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, Inc., 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 1,623 filed in 2012 through October 11 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 43 rigs operating in the Denver-Julesburg Basin as of October 5, 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 41 net wells and spend $270 million through 2013 in the Eaglebine alone. In addition, we plan to drill 5 net wells and spend $40 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 30, 2012, the credit facility had a borrowing base of $25 million, and we had $19.4 million in outstanding borrowings. We expect that the net 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 September 30, 2012, we had approximately $30.1 million in cash and deposits associated with our credit facility and approximately $5.6 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 (net of the acreage to be conveyed to Halcón), we expect to have accumulated a total of 84,989 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.    Giving effect to the Chesapeake acquisition (net of the acreage to be conveyed to Halcón) we estimate that there could be 1,030 potential net drilling locations across our 84,989 net acres. Through the end of 2013 we anticipate drilling 37 net horizontal Eaglebine wells, 4 net vertical Eaglebine Lower Cretaceous wells, 5 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 has built our existing significant acreage positions in our care areas. 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 40% 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, which we amended in October 2012, to acquire a 100% working interest in 57,275 net acres (including 22,080 net acres in AMI #1 and AMI #2), eight producing wells, one well awaiting a pipeline connection and one non-producing well in the Eaglebine for $126 million, subject to customary purchase price adjustments. In connection with signing the agreement, we deposited $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.

 

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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, 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 title defect claims exceed $10,000, individual environmental defect 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.

Subject to closing of the Chesapeake acquisition, Halcón has elected to purchase its pro rata working interest in the AMI #1 and AMI #2 acreage and AMI #2 wells that we will acquire in the Chesapeake acquisition. Halcón agreed to acquire 16,529 net acres and an 80% working interest in two producing wells to be acquired in the Chesapeake acquisition for approximately $53.1 million. We are required to offer Constellation its pro rata working interest in acreage and wells that we acquire in AMI #1 and AMI #2 in the Chesapeake acquisition. If Constellation elects to purchase its full pro rata working interest of the acreage and wells to be acquired from Chesapeake in AMI #1 and AMI #2, we would expect to convey approximately 1,482 net acres and a 5% working interest in two producing wells, thereby leaving us with 39,264 net acres from this transaction. Halcón will be the operator on the AMI #1 and AMI #2 acreage. The information in this prospectus regarding the net acreage, net drilling locations, net wells to be drilled, net proved reserves and related present value and net production with respect to the Chesapeake acquisition does not give effect to potential election by Constellation to purchase its pro rata working interests.

As of October 1, 2012, estimated proved developed producing reserves attributable to the wells we will acquire in the Chesapeake acquisition (net of the 80% working interest in two wells that we expect to convey to Halcón) were approximately 129,000 boe, with an estimated present value, discounted at an annual rate of 10%, of estimated future net revenues before income taxes of approximately $2.5 million. During the second quarter of 2012, the wells produced a total of approximately 9,629 boe, or approximately 106 boe/d (net of the 80% working interest in two wells that we expect to convey to Halcón).

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 October 11, 2012 for each of our core operating areas and the developed and undeveloped acreage we will acquire in the Chesapeake acquisition and the potential Halcón 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

     55,735         13,935                         55,735         13,935         0.0

Wolfcamp

     13,377         13,377                         13,377         13,377         0.0

Niobrara

     16,916         16,915         39         16         16,955         16,931         0.1
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total(1)

     86,028         44,227         39         16         86,067         44,243         0.0
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Chesapeake Eaglebine(2)

     53,051         37,575         4,224         3,171         57,275         40,746         7.8
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total with Chesapeake acquisition(1)

     139,079         81,803         4,262         3,186         143,342         84,989         3.7
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Potential Halcón acquisition

     14,030         9,120                         14,030         9,120         0.0

 

(1) 

Certain totals may not add due to rounding.

(2) 

Net of conveyance of acreage to Halcón. Information in this table does not give effect to the potential conveyance of net acreage to Constellation.

 

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Undeveloped acreage expirations

The following table sets forth the number of gross and net undeveloped acres as of October 11, 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         15,772         4,435         32,914         7,737   

Wolfcamp

                                     11,178         11,178         2,199         2,199   

Niobrara

                                     655         655         16,261         16,260   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total(1)

     249         62         6,799         1,700         27,605         16,268         51,374         26,196   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Chesapeake Eaglebine(2)

     2,444         2,444         23,414         15,111         25,057         18,931         2,136         1,089   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total with Chesapeake acquisition(1)

     2,693         2,506         30,213         16,811         40,289         23,367         35,050         8,826   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Potential Halcón acquisition

     1,735         1,128         5,606         3,644         3,029         1,969         3,659         2,378   

 

(1) 

Certain totals may not add due to rounding.

(2) 

Net of conveyance of acreage to Halcón. Information in this table does not give effect to the potential conveyance of net acreage to 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 October 11, 2012, we had one gross (0.093 net) productive well: a PDC Energy Inc. operated well in the Niobrara, 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 October 11, 2012, we had four gross (0.95 net) Halcón-operated wells in the process of drilling and completion in the Eaglebine AMI #1 and AMI #2.

 

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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

     16       $ 111   

Chesapeake Eaglebine

     25         159   

Wolfcamp

     5         40   

Niobrara

     15         10   
  

 

 

    

 

 

 

Drilling & Completion Total

     61       $ 320   

Leasehold Acquisition:

     

Eaglebine

      $ 10   

Wolfcamp

        3   

Niobrara

        2   
     

 

 

 

Leasehold Acquisition Total

      $ 15   

Other:

     

Eaglebine Seismic

      $ 10   
     

 

 

 

Other Total

      $ 10   
  

 

 

    

 

 

 

Total

     61       $ 345   
  

 

 

    

 

 

 

Chesapeake Eaglebine Acquisition(1)

      $  129   

Conveyance to Halcón of pro rata working interest

        (53

Potential Halcón Acquisition

        23   

Potential Halcón Divestiture

        (10
     

 

 

 

Total Including Potential Acquisitions (net of planned divestitures)

      $  434   
     

 

 

 

 

(1) Includes $3.0 million payment to extend the closing date.

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

 

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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.”

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.

 

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

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

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

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

 

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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 + 2.65%, 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 + 1.3%). This most recent index adjustment is currently being challenged by oil pipeline shippers in Federal court, and if successful this challenge could result in a decrease in the currently applicable index for annual adjustment of oil pipeline rates, although this is by no means certain or likely. FERC recently has adopted one change, and proposed others, to its rules governing the reporting of pipeline revenues and costs, with the stated aim of improving the transparency of the inputs to pipeline rates. It is not clear at this time whether the recent and potential changes to FERC’s rules will result in increased challenges to pipeline rates or stricter FERC scrutiny of such rates.

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

 

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policies. As a result, the interstate pipelines’ historical role as wholesalers of natural gas was eliminated and replaced by a structure under which pipelines provide transportation and storage service on an open access basis to others who buy and sell natural gas. Although FERC does not directly regulate natural gas producers (except with respect to a producer’s role as a marketer of natural gas, where FERC does exercise certain limited jurisdiction as discussed below), the current FERC regulatory structure is intended to foster increased competition within all phases of the natural gas industry.

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

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

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

 

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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.

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.

 

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

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

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

 

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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.

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.

 

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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 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

 

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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.

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

 

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government authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

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 October 11, 2012, we employed 49 people, including 10 employees in geology and geographic information systems, 2 employee in operations and engineering, 9 employees in accounting and finance, 20 employees in land and 8 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 October 11, 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)

Rocky L. Duckworth

     61       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 October 11, 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

     45       Executive 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 financial 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 financial reporting, technical accounting and the overall management of the E&P advisory services practice. 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 Public 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 our 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.

Rocky L. Duckworth, Director Nominee

Mr. Duckworth will become a director of our company upon the closing of this offering. Mr. Duckworth retired from KPMG LLP in September 2010 after more than 38 years, including more than 29 years as a Partner. From 2000 to September 2010, Mr. Duckworth served global energy clients, and he was the energy industry leader of the audit practice in KPMG’s Houston office until 2006. Prior to relocating to Houston, Mr. Duckworth was the Managing Partner of KPMG’s Oklahoma City office from 1987 to 2000. Mr. Duckworth was the partner in charge of the audit practice in Oklahoma City from 1984 until 1987. Mr. Duckworth earned a Bachelor of Science in Accounting with honors from Oklahoma State University. Mr. Duckworth was commissioned a 2nd lieutenant in the U.S. Army upon graduation from Oklahoma State University. In May 2011, Mr. Duckworth was appointed by Governor Rick Perry as a member of the board of directors of the Texas State Board of Public Accountancy and is a licensed CPA in the state of Texas.

Mr. Duckworth’s extensive audit and SEC reporting experience serving public oil and natural gas production companies will give him valuable insight into our financial reporting and internal control and risk control procedures. For these reasons, we believe Mr. Duckworth is qualified to serve as a director of our company.

David M. Fender, Director Nominee

Mr. Fender will become a director of our 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 our 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.

 

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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 our 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 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 our 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.

 

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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 was Chief Geophysicist 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 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, Executive Vice President—Land and Operations

Mr. Galloway has served as our Executive 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.

 

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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 the completion of this offering, who are named in this prospectus and have consented to serve. We anticipate that Messrs. Duckworth, Fender, Stanley and Steinsberger will be independent as determined by our board of directors under 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. Class I directors will be Messrs. Fender and Newton, Class II directors will be Messrs. Diffee and Stanley, and Class III directors will be Messrs. Pettit, Duckworth and Steinsberger. At each annual meeting of stockholders held after the initial classification, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

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 Messrs. Duckworth, Fender and Stanley, each of whom will be independent and financially literate. Mr. Duckworth is an “audit committee financial expert” as described in Item 407(d)(5) of Regulation S-K and will be the chairman of the audit committee.

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. We anticipate that our compensation committee will initially consist of Messrs. Duckworth, Fender and Steinsberger, each of whom will be independent, and Mr. Fender will be the chairman. 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

 

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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. We anticipate that our nominating and corporate governance committee will initially consist of Messrs. Fender, Stanley and Steinsberger, each of whom will be independent, and Mr. Steinsberger will be the chairman. 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. We anticipate that our reserve committee will initially consist of Messrs. Duckworth, Stanley and Steinsberger, each of whom will be independent, and Mr. Stanley will be the chairman. This committee will oversee the preparation by independent petroleum engineers of 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

We will enter into employment agreements contemporaneous with the consummation of this offering with each of our named executive officers, the material terms of which are described below.

Each employment agreement will have an initial three-year term and automatically renew and extend for a period of 12 months, unless written notice of non-renewal is delivered from either party to the other not less than 30 days prior to the then-existing term. Except as described below, each employment agreement will be executed with substantially similar terms and conditions. Each named executive officer will be entitled to, among other things, four weeks of paid vacation, customary employee benefits as offered by us, reimbursement of travel and business expenses. Each named executive officer will be eligible to participate in the 2012 Stock Incentive Plan. Each named executive officer will agree to maintain and protect the confidentiality of our information during or after his employment with us and will agree not to compete with us, solicit business from any of our customers or associated entities, or to solicit away any of our employees, during his employment and for twelve months after termination of his employment. The named executive officer will also agree to notify and present the terms and conditions of any new opportunity related to our business to us during his employment and for twelve months after termination of his employment.

Mr. Pettit

Mr. Pettit’s employment agreement will provide for an annual base salary of $450,000, subject to increase at our discretion, and an annual cash bonus of up to two times Mr. Pettit’s annual base salary, the amount of which shall be in the sole and absolute discretion of the compensation committee. If Mr. Pettit’s employment is terminated by us for cause (as defined in the employment agreement) or by Mr. Pettit’s death or disability, or Mr. Pettit voluntarily terminates his employment, he shall receive an amount consisting of his accrued and unpaid base salary, his earned but unpaid bonus with respect to any completed calendar year immediately preceding the year of termination (not payable upon termination by us for cause), reimbursement for unreimbursed business expenses, and benefits payable under our benefit plan terms including equity plans (collectively referred to herein as “accrued amounts”). Mr. Pettit will also be entitled to receive the following severance payments upon termination under the circumstances described below:

 

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Termination by us without cause (excluding death or disability) or by our failure to renew the employment agreement (provided no change in control occurred (as defined in the employment agreement) within the 24 month period immediately prior to the termination):

 

   

all accrued amounts; and

 

   

provided there exists compliance with the confidentiality and non-compete provisions contained in the agreement, and provided Mr. Pettit executes a release, he will receive:

 

  ¡    

an amount equal to the sum of:

 

  n  

the greater of:

 

   

two times Mr. Pettit’s base salary as of the termination date; or

 

   

the amount of base salary that would have been paid to Mr. Pettit for the period beginning on the termination date and ending on the last day of the term of the agreement had Mr. Pettit remained employed for such period; and

 

  n  

two times the greater of:

 

   

the amount of any cash bonus payable to Mr. Pettit for the year in which the termination date occurs (provided that if the bonus has not yet been determined as of the termination date, then the amount of the bonus shall be determined as if Mr. Pettit earned 100% of the targeted performance bonus for such year, to the extent such target bonus exists); or

 

   

the amount of the cash bonus paid to Mr. Pettit for services rendered during the year immediately prior to the calendar year in which the termination date occurs.

Termination by us without cause (excluding death or disability), by our failure to renew the employment agreement, or by Mr. Pettit for good reason (as defined in the employment agreement) (provided a change in control has occurred within the 24 month period immediately prior to the termination):

 

   

an amount, payable in a lump sum, equal to the sum of:

 

  ¡    

four times Mr. Pettit’s base salary as of the termination date; and

 

  ¡    

four times the greater of:

 

  n  

the amount of any cash bonus payable to Mr. Pettit for the year in which the termination date occurs (provided that if the bonus has not yet been determined as of the termination date, then the amount of the bonus shall be determined as if Mr. Pettit earned 100% of the targeted performance bonus for such year, to the extent such target bonus exists); or

 

  n  

the amount of the cash bonus paid to Mr. Pettit for services rendered during the year immediately prior to the calendar year in which the change in control occurred.

Mr. Van Ingen and Mr. Nelson

The employment agreements with Mr. Van Ingen and Mr. Nelson will provide for annual base salaries of $250,000 and $350,000, respectively, subject to increase at our discretion, and an annual cash bonus of up to such executive’s annual base salary, the amount of which shall be in the sole and absolute discretion of the compensation committee. If the executive’s employment is terminated by us for cause (as defined in the employment agreement) or by the executive’s death or disability, or the executive voluntarily terminates his employment, he shall receive a payment for accrued amounts. Each executive will also be entitled to receive the following severance payments upon termination under the circumstances described below:

Termination by us without cause (excluding death or disability) or by our failure to renew the employment agreement (provided no change in control (as defined in the employment agreement) occurred within the 24 month period immediately prior to the termination).

 

   

all accrued amounts;

 

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provided there exists compliance with the confidentiality and non-compete provisions contained in the agreement, and provided the executive executes a release, the executive will receive:

 

  ¡    

in the case of termination by us without cause:

 

  n  

an amount equal to the sum of:

 

   

one and a half times the executive’s base salary as of termination date; and

 

   

one and a half times the greater of:

 

  ¡    

the amount of any cash bonus payable to the executive for the year in which the termination date occurs (provided that if the bonus has not yet been determined as of the termination date, then the amount of the bonus shall be determined as if the executive earned 100% of the targeted performance bonus for such year, to the extent such target bonus exists); or

 

  ¡    

the amount of the cash bonus paid to the executive for services rendered during the year immediately prior to the calendar year in which the termination date occurs; or

 

  ¡    

in the case of termination by our failure to renew the employment agreement:

 

  n  

an amount equal to the sum of:

 

   

three-fourths times the executive’s base salary as of the termination date; and

 

   

three-fourths times the greater of:

 

  ¡    

the amount of any cash bonus payable to the executive for the year in which the termination date occurs (provided that if the bonus has not yet been determined as of the termination date, then the amount of the bonus shall be determined as if the executive earned 100% of the targeted performance bonus for such year, to the extent such target bonus exists); or

 

  ¡    

the amount of the cash bonus paid to the executive for services rendered during the year immediately prior to the calendar year in which the termination date occurs.

Termination by us without cause (excluding death or disability), by our failure to renew the employment agreement, or by the executive for good reason (as defined in the employment agreement) (provided a change in control has occurred within the 24 month period immediately prior to the termination).

 

   

an amount, payable in a lump sum, equal to the sum of:

 

  ¡    

three times the executive’s base salary as of the termination date; and

 

  ¡    

three times the greater of:

 

  n  

the amount of any cash bonus payable to the executive for the year in which the termination date occurs (provided that if the bonus has not yet been determined as of the termination date, then the amount of the bonus shall be determined as if the executive earned 100% of the targeted performance bonus for such year, to the extent such target bonus exists); or

 

  n  

the amount of the cash bonus paid to the executive for services rendered during the year immediately prior to the calendar year in which the change in control occurred.

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

 

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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 and may acquire in the potential Halcón 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. We intend to amend and restate our 2012 Stock Incentive Plan in connection with the completion of this offering. The following is a summary of the amended and restated 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.

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 10,250,000, subject to adjustment in accordance with the terms of the plan, 5,000,000 of which have been issued. 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 500,000 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 1,500,000 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.

 

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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 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 1,500,000 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 $3 million.

On August 22, 2012, Brian C. Nelson was awarded 2,000,000 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 100,000 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.

 

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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.

The following sets forth the compensation policy for our non-employee directors to be effective upon completion of this offering. Our non-employee director compensation policy is subject to annual review by our compensation committee.

Our board of directors has implemented a compensation policy applicable to all of our non-employee directors, which provides all non-employee directors the following compensation for board and committee services on an annual basis:

 

   

Each non-employee director shall receive $50,000 in cash, shares of our restricted common stock valued at $80,000 that vest annually, $1,500 in cash per meeting attended in person (capped at $18,000 per year) and $750 in cash per meeting held by telephone;

 

 

   

The chairman of each of the audit committee, the reserve committee and the compensation committee shall receive $12,000 in cash and shares of our restricted common stock valued at $20,000 that vest annually;

 

   

The chairman of the nominating and corporate governance committee shall receive $7,500 in cash and shares of our restricted common stock valued at $20,000 that vest annually;

 

   

Each member of the audit committee, the reserve committee and the compensation committee (other than the chairman) shall receive $6,000 in cash, $1,000 per meeting attended in person and $500 in cash per meeting held by telephone; and

 

   

Each member of the nominating and corporate governance committee (other than the chairman) shall receive $3,750 in cash, $1,000 per meeting attended in person and $500 in cash per meeting held by telephone

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.

The purpose of the corporate reorganization was twofold: (1) as it related to the entities owned by Mr. Pettit through which our business was previously conducted, to reorganize those entities as a corporation for the purpose of effecting this offering, and (2) to acquire the net profits interests in our acreage held by NASIF and the Niobrara investors.

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 11,521,240 shares of our 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 3,999,960 shares of our common stock; and

 

   

certain of the Niobrara investors contributed their net profits interests in our Niobrara acreage to us in exchange for 338,800 shares of our common stock.

The consideration for the contributions described above was determined through negotiations among us and the other parties to the contribution agreement. These negotiations were conducted primarily between our management, including our Chief Financial Officer and our General Counsel in consultation with Mr. Pettit, on one hand, and representatives of the largest limited partners of NASIF (i.e., the two “Oso + Toro” funds identified under “Principal and Selling Stockholders”), on the other hand. These parties used common industry valuation methodologies, including analysis of available information regarding other transactions in our core areas, to assess the relative value of the net profits interests in our acreage held by NASIF compared to the value of our business as a whole. On the basis of these assessments, our management and the NASIF limited partners negotiated the percentage of our company’s equity to be received by the NASIF limited partners in

 

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exchange for their interests in NASIF. We then used the same principles to determine the amount of equity in our company to be offered to the Niobrara investors in exchange for their net profits interests in our acreage. Mr. Pettit, as the sole direct or indirect equity owner of the companies that comprised our business prior to the reorganization, received the remainder of the equity in our company, other than the restricted stock awarded to our management as described below.

No value was attributed to Mr. Pettit’s interests in the general partner of NASIF and NASIF Advisors in the negotiation of the terms of the contribution agreement. Mr. Pettit acquired his interests in each of these entities upon their formation for de minimis capital contributions to the entities.

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 for de minimis consideration. Energy & Exploration Partners, LP is a plaintiff in certain immaterial contract disputes related to certain oil and natural gas properties previously held by us and holds no other assets. Mr. Pettit owns all of the limited partnership interests in Energy & Exploration Partners, LP.

Restricted Stock Awards for Management.    In connection with the transactions described above, we made awards to members of our senior management, other than Mr. Pettit, of 4,100,000 restricted shares of our common stock under our 2012 Stock Incentive Plan. These shares of restricted stock vest in three equal increments, initially upon completion of this offering and on the first and second anniversaries of the completion of this offering, except in the case of shares of restricted stock awarded to our Chief Financial Officer, Brian C. Nelson, which vest in 50% increments upon the completion of this offering and on January 1, 2013. See “Executive Compensation—2012 Stock Incentive Plan.”

In September 2012, Hunt Pettit contributed 900,000 shares of our 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 vest in three equal increments, initially upon completion of this offering and on the first and second anniversaries of the completion of this offering.

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.

 

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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. 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 XXV, LLC received a warrant to purchase 2.5% of Energy & Exploration Partners, LLC. In July 2012, we repurchased the warrant for $125,000. Petro Capital XXV, LLC and certain of its related entities also received a 0.625% overriding royalty interest in approximately 20,000 acres in the Eaglebine and a 0.44% overriding royalty interest in approximately 7,000 acres in the Eaglebine, which survived the repayment of the note. In addition, Petro Capital XXV, LLC, at its discretion, has the right to exchange its overriding royalty interests to other leases in AMI #1, on an acre for acre basis, until June 1, 2013. 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;

 

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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 transactio