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As filed with the Securities and Exchange Commission on October 18, 2007
Registration No. 333-144512
 
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
 
 
 
 
Approach Resources Inc.
(Exact name of registrant as specified in its charter)
 
         
Delaware   1311   51-0424817
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial
Classification Code Number)
  (I.R.S. Employer
Identification Number)
 
 
 
 
One Ridgmar Centre
6500 W. Freeway, Suite 800
Fort Worth, Texas 76116
(817) 989-9000
(Address, including zip code, and telephone number, including
area code, of registrant’s principal executive offices)
 
J. Ross Craft
President and Chief Executive Officer
One Ridgmar Centre
6500 W. Freeway, Suite 800
Fort Worth, Texas 76116
(817) 989-9000
(Name, address, including zip code, and telephone number, including area code, of agent for service)
 
 
 
 
Copies to:
 
     
Joe Dannenmaier
Wesley P. Williams
Jessica W. Hammons
Thompson & Knight LLP
1700 Pacific Avenue, Suite 3300
Dallas, Texas 75201
(214) 969-1700
  Gerald S. Tanenbaum, Esq.
Cahill Gordon & Reindel LLP
80 Pine Street
New York, New York 10005
(212) 701-3000
 
 
 
 
As soon as practicable after this Registration Statement is declared effective.
(Approximate date of commencement of proposed sale to the public)
 
If any 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, as amended (the “Securities Act”), check the following box.  o
 
If this form is filed to register additional securities for an offering pursuant to Rule 462(b) 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.  o
 
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.  o
 
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.  o
 
 
 
 
CALCULATION OF REGISTRATION FEE
 
                                         
            Proposed maximum
    Proposed maximum
     
Title of each class of
    Amount to be
    aggregate offering
    aggregate offering
    Amount of
Securities to be registered     registered(1)     price per shares(2)     price(2)     registration fee(3)
Common stock, par value $0.01 per share
      8,816,667       $ 16.00       $ 141,066,672       $ 4,331  
                                         
 
(1) Includes common stock issuable upon exercise of the underwriters’ option to purchase additional shares of common stock.
 
(2) Estimated solely for the purpose of calculating the registration fee under Rule 457(o) under the Securities Act.
 
(3) $4,061 was 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 or until this registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.
 


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The information in this preliminary prospectus is not complete and may be changed. We and the selling stockholder may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.
 
Subject to completion, dated October 18, 2007
 
Prospectus
 
7,666,667 shares
 
APPROACH LOGO
 
Common stock
 
 
Approach Resources Inc. is selling 5,605,377 shares of common stock, and the selling stockholder identified in this prospectus is selling an additional 2,061,290 shares. We will not receive any of the proceeds from the sale of the shares by the selling stockholder. This is the initial public offering of our common stock. The estimated initial public offering price is between $14.00 and $16.00 per share.
 
Prior to this offering, there has been no public market for our common stock. We have applied to have our common stock listed on the NASDAQ Global Market under the symbol “AREX.”
 
         
    Per share   Total
 
         
Initial public offering price
  $                  $               
         
Underwriting discount
  $   $
         
Proceeds to Approach Resources Inc., before expenses
  $   $
         
Proceeds to selling stockholder, before expenses(1)
  $   $
 
 
 
(1) Expenses associated with the offering, other than underwriting discounts, will be paid by us.
 
We and the selling stockholder have granted the underwriters an option for a period of 30 days to purchase up to 1,150,000 additional shares of our common stock on the same terms and conditions set forth above to cover over-allotments, if any.
 
 
Investing in our common stock involves a high degree of risk. See “Risk factors” beginning on page 14.
 
 
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
 
The underwriters expect to deliver the shares of common stock to investors on          , 2007.
 
JPMorgan
 
Wachovia Securities
 
KeyBanc Capital Markets TudorPickering
 
          , 2007


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  F-1
 Form of Underwriting Agreement
 Specimen Common Stock Certificate
 Opinion of Thompson & Knight LLP
 Form of Business Opportunities Agreement
 Form of Summary of Stock Option Grant Under 2007 Stock Incentive Plan
 Form of Stock Award Agreement Under 2007 Stock Incentive Plan
 Gas Purchase Contract
 Lease Crude Oil Purchase Agreement
 Consent of Hein & Associates LLP
 Consent of DeGolyer and MacNaughton
 Consent of Cawley, Gillespie & Associates, Inc.
 
You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with information different from that contained in this prospectus. We are offering to sell, and seeking offers to buy, shares of our common stock only in jurisdictions where offers and sales are permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our common stock.
 
No action is being taken in any jurisdiction outside the United States to permit a public offering of the common stock or possession or distribution of this prospectus in that jurisdiction. Persons who come into possession of this prospectus in jurisdictions outside the United States are required to inform themselves about and to observe any restrictions as to this offering and the distribution of this prospectus applicable to those jurisdictions.


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The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, governmental publications, reports by market research firms or other independent sources. Some data are also based on our good faith estimates. Although we believe these third-party sources are reliable, we have not independently verified the information.
 
The numbers contained in this prospectus relating to our gross and net leasehold acreage have been rounded to the nearest hundred acres.
 
We have filed an application for registration of a service mark for “Approach Resources Inc.” Other products, services and company names mentioned in this prospectus are the service marks/trademarks of their respective owners.


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Prospectus summary
 
This summary highlights information contained elsewhere in this prospectus. You should read this entire prospectus carefully, including the information contained under the heading “Risk factors,” our pro forma financial information and combined financial information and the notes thereto included elsewhere in this prospectus. In this prospectus, unless the context otherwise requires, the terms “Approach Resources,” “Approach,” “we,” “us” and “our” refer to the combined operations of Approach Resources Inc. and Approach Oil & Gas Inc. and their respective subsidiaries on a pro forma basis after giving effect to the acquisition by Approach Resources Inc. from Neo Canyon Exploration, L.P. of the 30% working interest in the Ozona Northeast field that Approach does not already own, which we refer to as the Neo Canyon interest.
 
Approach Resources Inc.
 
Overview
 
We are an independent energy company engaged in the exploration, development, exploitation, production and acquisition of unconventional natural gas and oil properties. Our principal operations are located in the Ozona Northeast field in West Texas, where we originally acquired approximately 28,000 gross (27,000 net) acres of leasehold interests in 2004. Since that time, through a series of strategic leasehold acquisitions, we have increased our West Texas acreage to 66,500 gross (51,700 net) acres located in the Ozona Northeast field and our nearby Cinco Terry project. Our management team has extensive experience finding and exploiting unconventional reservoirs, particularly tight gas sands like Ozona Northeast, by applying advanced completion, fracturing and drilling techniques. Substantially all of our growth has been through our own drilling efforts. Since 2004, we have added approximately 149 Bcfe of proved gas and oil reserves from unconventional reservoir formations.
 
At December 31, 2006, all of our proved reserves and production were located in West Texas and substantially all of those reserves and production were located in the Ozona Northeast field. As of such date, we owned working interests in 241 gross (226 net) producing wells with an average net production of approximately 22.7 MMcfe/d for the month of December 2006. At December 31, 2006, our total proved gas and oil reserves were approximately 149 Bcfe with a reserve life index of approximately 19 years. Our proved reserves are 94% gas and 51% proved developed. As the operator of substantially all of our proved reserves, we have a high degree of control over capital expenditures and other operating matters. As of July 31, 2007, we had identified a total of 833 drilling locations, of which 644 were located in the Ozona Northeast field, 126 in our Cinco Terry project and 63 in our North Bald Prairie prospect in East Texas.
 
Our growth efforts are focused primarily on finding and developing natural gas reserves in known tight gas sands and shale areas onshore in the United States and Western Canada. Since May 2006, we have acquired leasehold interests covering 13,600 gross (4,900 net) acres in East Texas, 90,300 gross (81,000 net) acres in Northern New Mexico, 74,000 gross (44,400 net) acres in Western Kentucky and 32,700 gross (7,400 net) acres in Western Canada. In total we have assembled leasehold interests of 277,100 gross (189,400 net) acres in our five operating areas—West Texas (Wolfcamp, Canyon Sands and Ellenburger), East Texas (Cotton Valley Sands, Bossier and Cotton Valley Lime), Northern New Mexico (Mancos Shale), Western Kentucky (New Albany Shale) and Western Canada (Triassic Shale and tight gas sands).


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At December 31, 2006, our standardized measure of discounted future net cash flows was $128.6 million, and our PV-10 was $179.9 million. The following table sets forth a summary of our estimated proved reserves and net average production attributable to our principal areas of operation as of December 31, 2006.
 
                         
    Estimated proved reserves    
        Proved
      Net average
    Total
  developed
  PV-10(1)
  production
    (Bcfe)   (Bcfe)   (millions)   (MMcfe/d)
 
Ozona Northeast
    147.0     74.9   $ 175.7     22.5
Cinco Terry
    1.8     0.9     4.2     0.2
     
     
Total
    148.8     75.8   $ 179.9     22.7
 
 
 
(1) PV-10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. See “Selected historical combined financial data—Reconciliation of non-GAAP financial measures” for our definition of PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows. Our calculation of PV-10 set forth in this table is based on gas and oil and condensate prices actually received by us on December 31, 2006, held flat for the life of the reserves. The weighted average price over the life of the Ozona Northeast reserves was $6.55 per Mcf of gas and $58.05 per Bbl of oil. The weighted average price over the life of the Cinco Terry reserves was $5.65 per Mcf of gas and $58.05 per Bbl of oil.
 
The following table sets forth a summary of our net acreage leasehold and estimated capital budget attributable to our principal areas of operation as of August 31, 2007, as well as identified drilling locations as of July 31, 2007. We currently anticipate drilling 67 gross (47.4 net) wells in 2007, at an estimated cost of $58.6 million (gross) and $40.3 million (net).
 
                                     
                Identified
  Capital budget(2)
    Net acreage leasehold   drilling
  2007
  2008
    Developed   Undeveloped   Total   locations(1)   (millions)   (millions)
 
Ozona Northeast
    26,900     17,100     44,000     644   $ 23.4   $ 29.5
Cinco Terry
    1,000     6,700     7,700     126     6.6     10.1
East Texas
        4,900     4,900     63     7.3     14.0
Northern New Mexico
        81,000     81,000             3.6
Western Kentucky
        44,400     44,400         1.8     2.6
Western Canada
        7,400     7,400         1.2     2.9
     
     
Total
    27,900     161,500     189,400     833   $ 40.3   $ 62.7
 
 
 
(1) Identified drilling locations represent total gross locations specifically identified by management as an estimate of our future multi-year drilling inventory on existing acreage. Of the total locations shown in the table, 178 are classified as proved. Our actual drilling activities may change depending on gas and oil prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. See “Risk factors—Risks related to our business.”
 
(2) An additional $8.0 million and $800,000 for 2007 and 2008, respectively, budgeted for lease acquisition, geophysical and geologic costs is not reflected here. Estimated capital expenditures for 2007 and 2008 give effect to the acquisition of the Neo Canyon interest in combination with the interest of Approach Resources Inc. and Approach Oil & Gas Inc. as if the Neo Canyon interest were acquired on October 1, 2007.


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Areas of operation
 
West Texas
 
Ozona Northeast field (Canyon Sands)
 
The Ozona Northeast field, in Crockett and Schleicher counties, Texas, is our largest operating area on the basis of proved reserves and production. The Canyon Sands of the Val Verde Basin in West Texas are located in a prolific tight gas reservoir with more than 11,800 total productive wells and cumulative historical production of more than 3.8 Tcfe over more than 50 years. In 2004, we began operations in the field through a farmout arrangement and have increased our total acreage position to 44,600 gross (44,000 net) acres. Beginning with our first well in February 2004, through June 30, 2007, we have drilled 257 successful wells out of 271 total wells drilled, which is a 95% success rate. As of December 31, 2006, we had proved reserves of 147 Bcfe. From 2004 through 2006, as a result of our own drilling efforts, we achieved a compound annual production growth rate of over 100%. We have identified 644 additional drilling locations in the field, and we estimate that completed costs for a vertical well currently are approximately $770,000, based on current markets for drilling services and equipment. Additionally, we own and operate 65 miles of gas gathering lines in the area that transport our gas to several regional pipeline systems.
 
Cinco Terry project (Wolfcamp, Canyon Sands and Ellenburger)
 
Since late 2005, we have leased and acquired options to lease 21,900 gross (7,700 net) acres five miles west of the Ozona Northeast field to evaluate the Wolfcamp, Canyon and Ellenburger formations. As of June 30, 2007, we had drilled and completed three Canyon wells and one Ellenburger well at a total cost of $5.9 million gross and $3.0 million net. As of December 31, 2006, we had proved reserves in the Cinco Terry project of 1.8 Bcfe. Wolfcamp wells in this area have demonstrated significant commercial production, and we are evaluating the formation for possible horizontal completions. Based upon data collected in the process of drilling the Canyon and Ellenburger wells, we believe we could achieve additional success in the shallower Wolfcamp formation. We own and operate seven miles of gas gathering lines in the area that transport our gas to several regional pipeline systems.
 
East Texas
 
North Bald Prairie prospect (Cotton Valley Sands, Bossier and Cotton Valley Lime)
 
In July 2007, we entered into a joint drilling venture with EnCana Oil & Gas (USA) Inc. in the East Texas Cotton Valley/Bossier trend. As part of the joint venture, we agreed to drill up to five wells at our cost to earn a 50% working interest in approximately 13,600 gross (4,900 net) acres. We believe significant potential exists for producing from multiple zones in the prospect area. Our primary targets are the Cotton Valley Sands, Bossier and Cotton Valley Lime, all unconventional tight gas formations where we believe we can apply our technical and operational expertise to successfully recover natural gas. Secondary targets include the shallower Rodessa, Pettit and Travis Peak formations. We have identified 63 potential drilling locations in the joint venture. We began drilling operations on the initial Cotton Valley well in August 2007.


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Northern New Mexico
 
El Vado East prospect (Mancos Shale)
 
Our El Vado East prospect is a 90,300 gross (81,000 net) acre Mancos Shale play located in the Chama Basin in Northern New Mexico in close proximity to several highly productive fields, including the Puerto Chiquito West and Puerto Chiquito East fields and the Boulder field, which collectively have produced in excess of 29 MMBoe of oil and gas. Although our primary objective in the El Vado East prospect is the Mancos Shale, finding commercial production in the Dakota, Morrison, Todilto and Entrada formations is a secondary objective. We expect that in the second quarter of 2008 we will spud the first of four vertical test wells to be identified and drilled in the El Vado East prospect. Depending on the initial results of these wells, we may elect to shoot 3-D seismic over a portion of this prospect at locations which have yet to be identified.
 
Western Kentucky
 
Boomerang prospect (New Albany Shale)
 
Our Boomerang prospect is a 74,000 gross (44,400 net) acre New Albany Shale play located in Western Kentucky in an area of the Illinois Basin that has not been widely explored. We believe the attributes of the New Albany Shale in the Boomerang prospect make it a promising unconventional resource play for natural gas, particularly with the introduction of horizontal drilling technology. In the first quarter of 2007, we drilled three vertical test wells. We have contracted to have core samples from these three wells analyzed. We expect to begin the completion of these three test wells in the fourth quarter of 2007 or first quarter of 2008. After evaluating the results of our initial drilling and completion activities, we will determine our development program in this prospect.
 
Western Canada
 
British Columbia prospect (Triassic Shale and tight gas sands)
 
In August 2007, we acquired a 25% non-operating, working interest in a lease acquisition and drilling project targeting unconventional gas reserves in the emerging Triassic shale and tight gas sands play in Northeast British Columbia. The project covers 32,700 gross (7,400 net) acres. Our primary targets are the Triassic-aged shale and tight gas sands. The operator began drilling operations in the project in August 2007.
 
Recent Developments
 
Our net average production at September 30, 2007 was 20.6 MMcfe/d, composed of 19.3 MMcfe/d from Ozona Northeast and 1.3 MMcfe/d from Cinco Terry. We drilled 12 Canyon wells in Ozona Northeast in the third quarter of 2007, three of which were awaiting completion at September 30, 2007. We drilled six wells in Cinco Terry in the third quarter of 2007 (three Canyon, two Ellenburger and one Wolfcamp well), three of which were awaiting completion at September 30, 2007. We drilled one Cotton Valley well, which is awaiting completion, and spudded a second Cotton Valley well, in our East Texas North Bald Prairie prospect in September 2007. We expect to complete and turn both of these Cotton Valley wells to sales in the fourth quarter of 2007. Finally, our Canadian operating partner drilled one Triassic tight gas well in Western Canada in September 2007, which is awaiting completion and a final pipeline connection and which we expect will be turned to sales in the fourth quarter of 2007.


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Strategy
 
Our strategy is to increase stockholder value by profitably growing our reserves, production, cash flow and earnings using a balanced program of (1) developing existing properties, (2) exploring and exploiting undeveloped properties, (3) completing strategic acquisitions and (4) maintaining financial flexibility. The following are key elements of our strategy:
 
•  Continue to develop our existing West Texas properties. We intend to develop further the significant remaining potential of our West Texas properties, where we have identified 770 drilling locations. From 2004 through 2006, we drilled 257 wells in our West Texas fields, making us one of the top ten most active drillers in West Texas and the second most active driller in the Canyon Sands during that time period.
 
•  Pursue unconventional gas and oil opportunities. With our East Texas, Northern New Mexico, Western Kentucky and Western Canada prospects, we have over 210,000 gross acres of unexplored tight gas and shale gas and oil inventory to explore and produce. We seek to add proved reserves and production from these properties through the application of advanced technologies, including horizontal drilling and advanced completion techniques.
 
•  Acquire strategic assets. We continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects. We focus particularly on opportunities where we believe our reservoir management and operational expertise in unconventional gas and oil properties will enhance value and performance. We remain focused on unconventional resource opportunities, but also look at conventional opportunities based on individual project economics.
 
•  Operate our properties as a low cost producer. We strive to minimize our operating costs by concentrating our assets within geographic areas where we can consolidate operating control and thus create operating efficiencies. We are the operator of substantially all of our producing properties and plan to continue to operate substantially all of our producing properties in the future. Operating control allows us to better manage timing and risk as well as the cost of exploration and development, drilling and ongoing operations.
 
Competitive strengths
 
We believe our historical success is, and future performance will be, directly related to the following combination of strengths that enable us to implement our strategy:
 
•  Experienced executive and technical team with significant employee ownership. The members of our executive and technical team (including our Chief Executive Officer) have an average of more than 26 years of experience in the oil and gas industry and significant experience in building and managing independent oil and gas companies. The majority of our executive and technical team have spent their entire careers developing unconventional gas and oil properties. Our team has a proven record of analyzing complex structural and stratigraphic formations using 3-D seismic and geological techniques, producing and optimizing gas reservoirs and drilling and completing unconventional gas reservoirs. Our management team and employees will own approximately 6.0% of our common stock after this offering, aligning their objectives with those of our stockholders.
 
•  Low risk, multi-year drilling inventory. We have identified 833 drillable, low to moderate risk locations on our West Texas and East Texas properties, providing us with approximately


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10 years of drilling inventory at our current drilling rate. Our technical team’s ability to locate and execute on repeatable low-risk drilling opportunities in our large and productive West Texas acreage holdings has helped us to achieve a drilling success rate of 95% since our inception.
 
•  Stable producing asset base. We own an operated asset base comprising of long-lived reserves. Approximately 94% of our reserves are gas, and all of our proved reserves are located in West Texas. These properties should produce stable cash flows to fund our development, exploitation and exploration opportunities.
 
•  Large acreage positions. We are a significant acreage holder in three of our primary operating areas and have an aggregate leasehold position of 277,100 gross (189,400 net) acres. We believe we have assembled a portfolio of properties, both in prolific producing gas and oil fields and in under-explored reservoirs, that would be difficult to replicate.
 
•  Operated asset base. We operate substantially all of our estimated reserves. By maintaining operating control, we are able to more effectively control our expenses, capital allocation and the timing and method of exploitation and development of our properties.
 
•  Financial flexibility. Upon the completion of this offering, we expect to have approximately $19.2 million in cash, no long-term debt and at least $75.0 million available for borrowings under our revolving credit facility, providing us with significant financial flexibility to pursue our business strategy.
 
•  Control of gathering infrastructure and gas marketing. We own and operate approximately 72 miles of gas gathering lines in West Texas. Owning and operating this infrastructure allows us to maintain greater control of our gathering pressures and to minimize down time associated with the system.
 
Our challenges and risks
 
The implementation of our business strategy, maintenance of our strengths and our future operating results and financial condition are subject to a number of challenges, risks and uncertainties. These include the following:
 
•  Gas and oil prices are volatile, and a decline in gas or oil prices could significantly affect our business, financial condition or results of operations and our ability to meet our capital expenditure requirements and financial commitments. In addition, as of December 31, 2006, more than 94% of our estimated proved reserves were natural gas. We are particularly exposed to volatility in natural gas prices.
 
•  Drilling and exploring for, and producing, gas and oil involve significant risks, including the potential unavailability of capital at attractive or acceptable costs, the possibility that we will not encounter commercially productive oil or natural gas reservoirs, the potential need to incur significant costs to drill and complete wells and the possibility that drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages, delays in the delivery of equipment or other factors that could adversely affect our business, financial condition or results of operations.
 
•  Competition in the oil and gas industry is intense, and many of our competitors have resources greater than ours.


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•  We face significant risks associated with our acquisition activities, including potential difficulties integrating operations, potential disruptions of operations, the potential failure to identify all risks associated with an acquisition, the potential failure to correctly evaluate reserve data or the exploitation potential of properties and the need to incur significant expenditures to identify and acquire properties.
 
•  We depend on our management team and other key personnel. Accordingly, the loss of any of these individuals could adversely affect our business, financial condition, results of operations and future growth.
 
•  Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and value of our reserves.
 
You should carefully consider these challenges and risks as well as all of the information contained in this prospectus prior to investing in the common stock. In particular, we urge you to carefully review the information under “Risk factors” so that you understand the risks associated with an investment in our company and our common stock.
 
Our structure
 
Approach Resources Inc. was formed as a Delaware corporation in September 2002. Our operations are currently conducted by two separate entities under common control, Approach Resources Inc. and Approach Oil & Gas Inc. Pursuant to a contribution agreement, the operations of Approach Oil & Gas Inc. will be combined under Approach Resources Inc., and we also will acquire the Neo Canyon interest immediately prior to the closing of this offering. For more information about our restructuring and our acquisition of the Neo Canyon interest, please read “Certain relationships and related party transactions—The contribution agreement.”
 
Our executive offices
 
Our principal executive offices are located at One Ridgmar Centre, 6500 W. Freeway, Suite 800, Fort Worth, Texas 76116. Our telephone number is (817) 989-9000.


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The offering
 
Common stock offered by us
5,605,377 shares
 
Common stock offered by the selling stockholder
2,061,290 shares
 
Common stock to be outstanding after this offering
19,255,789 shares
 
Use of proceeds
We expect to receive net proceeds from the sale of shares offered by us, after deducting estimated offering expenses and underwriting discounts, of approximately $76.9 million, based on an assumed offering price of $15.00 per share (the mid-point of the price range set forth on the front cover of this prospectus). We intend to use the net proceeds of this offering to repay approximately $48.0 million outstanding under our revolving credit facility, to repurchase 2,021,148 shares of our common stock held by Neo Canyon Exploration, L.P. at a purchase price of approximately $28.2 million and the remainder for general corporate purposes, including exploration and development activities, gas and oil reserve and leasehold acquisitions in the ordinary course of business and for working capital. We will not receive any proceeds from the sale of shares of our common stock by the selling stockholder. See “Use of proceeds.”
 
Dividend policy
We do not anticipate paying any cash dividends on our common stock. See “Dividend policy.”
 
Risk factors
For a discussion of factors you should consider in making an investment, see “Risk factors.”
 
Proposed NASDAQ Global Market symbol
“AREX”
 
Other information about this prospectus
Unless specifically stated otherwise, the information in this prospectus:
 
• is adjusted to reflect a three for one stock split of our shares of common stock to be effected in the form of a stock dividend concurrent with the consummation of this offering;
 
• assumes no exercise of the underwriters’ option to purchase additional shares of our common stock to cover over-allotments, if any; and
 
• assumes an initial public offering price of $15.00, which is the mid-point of the range set forth on the front cover of this prospectus.


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Summary combined historical and combined
pro forma financial data
 
The following table sets forth our summary historical combined and combined pro forma financial and operating data as of the dates and for the periods shown. Our operations are currently conducted by two separate operating entities under common control, Approach Resources Inc. and Approach Oil & Gas Inc. Pursuant to a contribution agreement, the operations of Approach Oil & Gas Inc. will be combined under Approach Resources Inc., and we also will acquire the Neo Canyon interest immediately prior to the closing of this offering. The amounts for each historical annual period presented below were derived from the audited combined financial statements of Approach Resources Inc. and Approach Oil & Gas Inc. included in this prospectus. The combined pro forma financial information gives effect to our acquisition of the Neo Canyon interest. The combined pro forma balance sheet assumes that the acquisition of the Neo Canyon interest occurred as of June 30, 2007, and the combined pro forma statements of operations for the year ended December 31, 2006 and for the six months ended June 30, 2007 assume that the acquisition of the Neo Canyon interest occurred on January 1, 2006. The combined pro forma balance sheet and the combined pro forma statement of operations were derived by adjusting the historical combined financial statements of Approach Resources Inc. and Approach Oil & Gas Inc. These adjustments are based on currently available information and certain estimates and assumptions, and, therefore, the actual effects of the acquisition of the Neo Canyon interest may differ from the effects reflected in the combined pro forma financial statements. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of this transaction as contemplated and that the pro forma adjustments give appropriate effect to those assumptions. The pro forma financial information is not necessarily indicative of the financial condition or results of operations of Approach Resources Inc. had the contribution and the acquisitions taken place on the assumed dates and should not be viewed as indicative of operations in the future. The following information should be read in conjunction with “Capitalization,” “Management’s discussion and analysis of financial condition and results of operations” and the historical combined and combined pro forma financial statements included in this prospectus.


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                                  Pro forma  
                      Six months
          Six months
 
                      ended
    Year ended
    ended
 
(in thousands, except shares and per
  Year ended December 31,     June 30,     December 31,
    June 30,
 
share data)   2004     2005     2006     2006     2007     2006     2007  
 
                      (unaudited)     (unaudited)     (unaudited)     (unaudited)  
 
Statement of operations data
                                                       
Revenues:
                                                       
Oil and gas sales
  $ 5,682     $ 43,263     $ 46,672     $ 26,390     $ 19,082     $ 66,230     $ 26,905  
Expenses:
                                                       
Lease operating expense
    179       2,910       3,889       1,992       2,023       5,418       2,744  
Severance and production taxes
    407       1,975       1,736       841       748       2,452       1,088  
Exploration
    2,396       733       1,640       993       633       1,640       633  
Impairment of non-producing properties
                558                   558        
General and administrative
    1,943       2,659       2,416       1,234       2,730       2,755       2,942  
Accretion of discount on asset retirement obligations
    1       5       10                   14        
Depletion, depreciation and amortization
    1,223       8,006       14,541       6,973       6,108       21,447       8,717  
     
     
Total expenses
    6,149       16,288       24,790       12,033       12,242       34,284       16,124  
     
     
Operating income (loss)
    (467 )     26,975       21,882       14,357       6,840       31,946       10,781  
Other:
                                                       
Interest income (expense), net
    201       (802 )     (3,814 )     (1,709 )     (1,954 )     (3,814 )     (1,954 )
Realized gain (loss) on commodity derivatives
          (2,924 )     6,222       3,085       2,244       6,222       2,244  
Change in fair value of commodity derivatives
          (4,163 )     8,668       5,447       (2,902 )     8,668       (2,902 )
     
     
Income (loss) before provision (benefit) for income taxes
    (266 )     19,086       32,958       21,180       4,228       43,022       8,169  
Provision (benefit) for income taxes
          7,028       11,756       7,435       1,818       15,480       3,184  
     
     
Net income (loss)
  $ (266 )   $ 12,058     $ 21,202     $ 13,745     $ 2,410     $ 27,542     $ 4,985  
     
     
Earnings (loss) per share(1):
                                                       
Basic
  $ (0.14 )   $ 4.03     $ 7.04     $ 4.62     $ 0.81     $ 5.91     $ 1.09  
Diluted
  $ (0.14 )   $ 4.03     $ 6.84     $ 4.49     $ 0.74     $ 5.80     $ 1.02  
Weighted average shares outstanding(1):
                                                       
Basic
    1,928,225       2,988,986       3,012,414       2,975,138       2,984,105       4,663,022       4,576,905  
Diluted
    1,928,225       2,988,986       3,101,180       3,060,083       3,297,655       4,751,788       4,890,455  
Statement of cash flow data
                                                       
Net cash provided (used) by:
                                                       
Operating activities
  $ 4,527     $ 40,589     $ 34,305     $ 17,345     $ 12,859                  
Investing activities
    (26,859 )     (72,224 )     (59,384 )     (37,598 )     (18,285 )                
Financing activities
    22,474       32,199       26,771       17,254       19,007                  
Other financial data
                                                       
EBITDA(2)
    756       27,894       51,313       29,862       12,290       68,283       18,840  
Capital expenditures
    25,313       73,770       59,384       37,603       17,358                  
 
 
 
(1) Does not give effect to our three for one common stock split.
 
(2) See “Selected historical combined financial data—Reconciliation of non-GAAP financial measures” for a reconciliation of our EBITDA to cash provided by operating activities.
 


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                Pro forma
                        Pro forma   as adjusted(1)
                        As of
  As of
    As of December 31,   As of June 30,   June 30,
  June 30,
(in thousands)   2004   2005   2006   2006   2007   2007   2007
                (unaudited)   (unaudited)   (unaudited)   (unaudited)
 
                                           
Balance sheet data
                                         
Cash and cash equivalents
  $ 2,656   $ 3,219   $ 4,911   $ 220   $ 18,492   $ 18,492   $ 19,196
Other current assets
    6,458     16,305     13,200     15,688     9,882     9,882     9,882
Property and equipment, net, successful efforts method
    24,223     88,803     132,112     118,436     142,754     206,410     206,410
Other assets
    1,565     89     86     126     1,179     1,179     840
     
     
Total assets
  $ 34,902   $ 108,416   $ 150,309   $ 134,470   $ 172,307   $ 235,963   $ 236,328
     
     
Current liabilities
  $ 9,827   $ 32,746   $ 15,421     23,531     14,697     14,697     14,674
Long-term debt
    100     29,425     47,619     44,567     46,769     46,769    
Other long-term liabilities
    99     6,555     17,697     14,215     18,772     18,839     18,839
Convertible debt
                    20,000     20,000    
Stockholders’ equity
    24,876     39,690     69,572     52,157     72,069     135,658     202,815
     
     
Total liabilities and stockholders’ equity
  $ 34,902   $ 108,416   $ 150,309   $ 134,470   $ 172,307   $ 235,963   $ 236,328
 
 
 
(1) As adjusted for (i) the consummation of the transactions described under “Certain relationships and related party transactions—The contribution agreement,” (ii) our three for one common stock split, (iii) the sale of 5,605,377 shares of common stock in this offering at an assumed initial public offering price of $15.00 per share, after deducting underwriting discounts and estimated offering expenses payable by us and the application of the estimated net proceeds from this offering as set forth under “Use of proceeds,” (iv) our receipt of $240,380 pursuant to an exercise of stock options covering 72,114 shares of our common stock by a former executive officer, (v) the conversion of $20.0 million of principal and $540,822 of accrued interest under convertible notes into 1,472,460 shares of our common stock along with the recognition of the related beneficial conversion feature amounting to $1,546,083, (vi) the grant of 322,500 restricted shares to our named executive officers and the related bonus for taxes as set forth under “Management—Grants of plan-based awards” and (vii) the election by each of Messrs. Brandi, Lubar and Whyte to receive 5,666 shares of our common stock and Mr. Crain to receive 2,833 shares of our common stock in lieu of cash for all or a portion of their 2007 director fees.

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Summary oil and gas data
 
Operating data
 
The following table presents certain information with respect to the combined historical operating data for the years ended December 31, 2004, 2005 and 2006 and for the six months ended June 30, 2007 and combined pro forma operating data for the year ended December 31, 2006 and the six months ended June 30, 2007, after giving effect to our acquisition of the Neo Canyon interest:
 
                                         
 
                      Pro forma  
                Six
        Six
 
                months
        months
 
                ended
    Year ended
  ended
 
    Year ended December 31,   June 30,
    December 31,
  June 30,
 
    2004   2005   2006   2007     2006   2007  
 
 
Gross wells
                                       
Drilled
    54     120     83     25       83     25  
Completed
    46     115     81     20 (1)     81     20 (1)
Net wells
                                       
Drilled
    34.9     77.2     55.1     17.0       79.6     23.1  
Completed
    29.6     74.8     53.5     13.6       77.3     19.4  
Net production data
                                       
Net volume (MMcfe)
    908     5,012     6,744     2,608       9,580     3,680  
Average daily volume (MMcfe/d)
    4     14     18     14       26     20  
Average sales price (per Mcfe)
                                       
Average sales price
(without the effects of commodity derivatives)
  $ 6.26   $ 8.63   $ 6.92   $ 7.32     $ 6.91   $ 7.31  
Average sales price
(with the effects of commodity derivatives)
    6.26     8.05     7.84     8.18       7.56     7.92  
Expenses (per Mcfe)
                                       
Lease operating
  $ 0.20   $ 0.58   $ 0.58   $ 0.78     $ 0.57   $ 0.75  
Production taxes
    0.45     0.39     0.26     0.29       0.26     0.30  
General and administrative
    2.14     0.53     0.36     1.05       0.29     0.80  
Exploration
    2.64     0.15     0.24     0.24       0.17     0.17  
Impairment
            0.08           0.06      
Depreciation, depletion and amortization
    1.35     1.60     2.16     2.34       2.24     2.37  
 
 
 
(1) At June 30, 2007, five wells were awaiting completion.


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Estimated reserve data
 
The estimates in the table below of proved reserves as of December 31, 2004 and 2005 are based on reserve reports prepared by our engineering staff and Cawley, Gillespie & Associates, Inc. The estimates as of December 31, 2006 are based on reserve reports prepared by our engineering staff and DeGolyer and MacNaughton.
 
                         
                Pro forma(1)
    December 31,   December 31,
    2004   2005   2006   2006
 
Estimated proved reserves
                       
Gas (Bcf)
    57.7     102.4     98.7     139.8
Oil (MMBbls)
    0.4     1.1     1.1     1.5
     
     
Total proved reserves (Bcfe)
    59.8     108.9     105.4     148.8
Total proved developed reserves (Bcfe)
    17.6     49.8     53.1     75.8
PV-10 value (millions)(2)
                       
Proved developed reserves
  $ 44.1   $ 151.9   $ 112.8   $ 158.3
Proved undeveloped reserves
    56.6     97.4     15.6     21.6
     
     
Total PV-10
  $ 100.7   $ 249.3   $ 128.4   $ 179.9
Standardized measure of oil and
gas quantities (millions)
  $ 60.3   $ 146.4   $ 77.9   $ 128.6
 
 
 
(1) Gives effect to our acquisition of the Neo Canyon interest.
 
(2) PV-10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. See “Selected historical combined financial data—Reconciliation of non-GAAP financial measures” for our definition of PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows. Our calculation of PV-10 set forth in this table is based on gas and oil and condensate prices actually received by us on December 31, 2006, held flat for the life of the reserves. The weighted average price over the life of the Ozona Northeast reserves was $6.55 per Mcf of gas and $58.05 per Bbl of oil. The weighted average price over the life of the Cinco Terry reserves was $5.65 per Mcf of gas and $58.05 per Bbl of oil.


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Risk factors
 
You should carefully consider the risk factors set forth below as well as the other information contained in this prospectus before investing in our common stock. Any of the following risks could materially and adversely affect our business, financial condition or results of operations. In such a case, you may lose all or part of your investment. The risks described below are not the only risks facing us. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial may also materially adversely affect our business, financial condition or results of operations.
 
Risks related to the oil and natural gas industry and our business
 
Gas and oil prices are volatile, and a decline in gas or oil prices could significantly affect our business, financial condition or results of operations and our ability to meet our capital expenditure requirements and financial commitments.
 
Our revenues, profitability and cash flow depend substantially upon the prices and demand for gas and oil. The markets for these commodities are volatile, and even relatively modest drops in prices can affect significantly our financial results and impede our growth. Prices for gas and oil fluctuate widely in response to relatively minor changes in the supply and demand for gas and oil, market uncertainty and a variety of additional factors beyond our control, such as:
 
•  domestic and foreign supply of gas and oil;
 
•  price and quantity of foreign imports;
 
•  commodity processing, gathering and transportation availability and the availability of refining capacity;
 
•  domestic and foreign governmental regulations;
 
•  political conditions in or affecting other gas producing and oil producing countries, including the current conflicts in the Middle East and conditions in South America and Russia;
 
•  the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
 
•  weather conditions, including unseasonably warm winter weather;
 
•  technological advances affecting gas and oil consumption;
 
•  overall United States and global economic conditions; and
 
•  price and availability of alternative fuels.
 
Further, gas prices and oil prices do not necessarily fluctuate in direct relationship to each other. Because more than 94% of our estimated proved reserves as of December 31, 2006 were gas reserves, our financial results are more sensitive to movements in gas prices. In the past, the price of gas has been extremely volatile, and we expect this volatility to continue. For example, during the year ended December 31, 2006, the NYMEX gas spot price ranged from a high of $9.90 per MMBtu to a low of $3.66 per MMBtu. The NYMEX gas spot price at December 31, 2006 was $5.50 per MMBtu. At May 1, 2007, the NYMEX gas spot price was $7.64 per MMBtu.


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The results of higher investment in the exploration for and production of gas and other factors may cause the price of gas to drop. Lower gas and oil prices may not only cause our revenues to decrease but also may reduce the amount of gas and oil that we can produce economically. Substantial decreases in gas and oil prices would render uneconomic some or all of our drilling locations. This may result in our having to make substantial downward adjustments to our estimated proved reserves and could have a material adverse effect on our financial condition, results of operations and cash flow.
 
Drilling and exploring for, and producing, gas and oil are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
 
Drilling and exploration are the main methods we use to replace our reserves. However, drilling and exploration operations may not result in any increases in reserves for various reasons. Exploration activities involve numerous risks, including the risk that no commercially productive gas or oil reservoirs will be discovered. In addition, the future cost and timing of drilling, completing and producing wells is often uncertain. Furthermore, drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
 
•  lack of acceptable prospective acreage;
 
•  inadequate capital resources;
 
•  unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents;
 
•  adverse weather conditions, including tornados;
 
•  unavailability or high cost of drilling rigs, equipment or labor;
 
•  reductions in gas and oil prices;
 
•  limitations in the market for gas and oil;
 
•  surface access restrictions;
 
•  title problems;
 
•  compliance with governmental regulations; and
 
•  mechanical difficulties.
 
Our decisions to purchase, explore, develop and exploit prospects or properties depend in part on data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often uncertain. Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists and geologists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or producible economically. In addition, the use of 3-D seismic and other advanced technologies require greater predrilling expenditures than traditional drilling strategies.
 
In addition, higher gas and oil prices generally increase the demand for drilling rigs, equipment and crews and can lead to shortages of, and increasing costs for, such drilling equipment, services and personnel. Such shortages could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the drilling of new wells or


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significant increase in drilling costs could adversely affect our ability to increase our reserves and production and reduce our revenues.
 
Currently, the vast majority of our producing properties are located in two counties in Texas, and our proved reserves are primarily attributable to one field in that area, making us vulnerable to risks associated with having our production concentrated in a small area.
 
The vast majority of our producing properties are geographically concentrated in two counties in Texas, and our proved reserves are primarily attributable to one field in that area. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailments of production, natural disasters, interruption of transportation of gas produced from the wells in these basins or other events that impact these areas.
 
Certain of our undeveloped leasehold acreage is subject to leases and options that may expire in the near future.
 
As of December 31, 2006, we held mineral leases in each of our areas of operations that are still within their original lease term and are not currently held by production. Unless we establish commercial production on the properties subject to these leases, most of these leases will expire between 2008 and 2015. Options covering approximately 12,000 gross acres in our Cinco Terry project are scheduled to expire before June 1, 2008. If these leases or options expire, we will lose our right to develop the related properties.
 
Identified drilling locations that we decide to drill may not yield gas or oil in commercially viable quantities and are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
 
Our drilling locations are in various stages of evaluation, ranging from locations that are ready to be drilled to locations that will require substantial additional evaluation and interpretation. There is no way to predict in advance of drilling and testing whether any particular drilling location will yield gas or oil in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively before drilling whether gas or oil will be present or, if present, whether gas or oil will be present in commercial quantities. The analysis that we perform may not be useful in predicting the characteristics and potential reserves associated with our drilling locations. As a result, we may not find commercially viable quantities of gas and oil.
 
Our drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including gas and oil prices, costs, the availability of capital, seasonal conditions, regulatory approvals and drilling results. Because of these uncertainties, we do not know when the unproved drilling locations we have identified will be drilled or if they will ever be drilled or if we will be able to produce gas or oil from these or any proved drilling locations. As such, our actual drilling activities may be materially different from those presently identified, which could adversely affect our business, results of operations or financial condition.


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Unless we replace our gas and oil reserves, our reserves and production will decline.
 
Our future gas and oil production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our level of production and cash flows will be affected adversely. In general, production from gas and oil properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of gas and oil reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves.
 
Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of our proved reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our reserve reports. These differences may be material.
 
The proved gas and oil reserve information included in this prospectus represents estimates. Petroleum engineering is a subjective process of estimating underground accumulations of gas and oil that cannot be measured in an exact manner. Estimates of economically recoverable gas and oil reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:
 
•  historical production from the area compared with production from other similar producing areas;
 
•  the assumed effects of regulations by governmental agencies;
 
•  assumptions concerning future gas and oil prices; and
 
•  assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.
 
Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:
 
•  the quantities of gas and oil that are ultimately recovered;
 
•  the production and operating costs incurred;
 
•  the amount and timing of future development expenditures; and
 
•  future gas and oil prices.
 
As of December 31, 2006, approximately 49% of our proved reserves were proved undeveloped. Estimates of proved undeveloped reserves are even less reliable than estimates of proved developed reserves.
 
Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material. The discounted future net cash flows included in this prospectus should not be considered as the current market value of the estimated gas and oil reserves attributable to our properties. As


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required by the Securities and Exchange Commission, or the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the measurement (December 31, 2006), while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:
 
•  the amount and timing of actual production;
 
•  supply and demand for gas and oil;
 
•  increases or decreases in consumption; and
 
•  changes in governmental regulations or taxation.
 
In addition, the 10% discount factor, which is required by the SEC to be used to calculate discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
 
You should not assume that the present value of future net revenues from our proved reserves referred to in this prospectus is the current market value of our estimated gas and oil reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If gas prices decline by $1.00 per Mcf from $6.55 per Mcf to $5.55 per Mcf, then our PV-10 as of December 31, 2006 would decrease from $179.9 million to $110.1 million. The average market price received for our natural gas production on December 31, 2006, after basis and Btu adjustments, was $6.55 per Mcf. The average market price received for our natural gas production on August 31, 2007, after basis and Btu adjustments, was $6.05 per Mcf.
 
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
 
Our industry is cyclical, and from time to time there is a shortage of drilling rigs, equipment, supplies and qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. As a result of historically strong prices of gas, the demand for oilfield and drilling services has risen, and the costs of these services are increasing. For example, average day rates for land based rigs have increased substantially during the last two years. We are particularly sensitive to higher rig costs and drilling rig availability, as we presently have two rigs under contract, one of which is on a well-to-well basis. If the unavailability or high cost of drilling rigs, equipment, supplies or qualified personnel were particularly severe in the areas where we operate, we could be materially and adversely affected.
 
Competition in the oil and gas industry is intense, and many of our competitors have resources that are greater than ours.
 
We operate in a highly competitive environment for acquiring prospects and productive properties, marketing gas and oil and securing equipment and trained personnel. Many of our competitors are major and large independent oil and gas companies that possess and employ financial, technical and personnel resources substantially greater than ours. Those companies


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may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional prospects and discover reserves in the future will depend on our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and gas industry. Larger competitors may be better able to withstand sustained periods of unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. 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.
 
Our customer base is concentrated, and the loss of our key customer could, therefore, adversely affect our financial results.
 
In 2006, Ozona Pipeline Energy Company, which we refer to as Ozona Pipeline, accounted for approximately 89.6% of our total gas and oil sales excluding realized commodity derivative settlements. To the extent that Ozona Pipeline reduces its purchases in gas or oil or defaults on its obligations to us, we would be adversely affected unless we were able to make comparably favorable arrangements with other customers. Ozona Pipeline’s default or non-performance could be caused by factors beyond our control. A default could occur as a result of circumstances relating directly to the customer, or due to circumstances related to other market participants with which the customer has a direct or indirect relationship.
 
We depend on our management team and other key personnel. Accordingly, the loss of any of these individuals could adversely affect our business, financial condition and the results of operations and future growth.
 
Our success largely depends on the skills, experience and efforts of our management team and other key personnel. The loss of the services of one or more members of our senior management team or of our other employees with critical skills needed to operate our business could have a negative effect on our business, financial condition, results of operations and future growth. We have entered into employment agreements with J. Ross Craft, our President and Chief Executive Officer, Steven P. Smart, our Executive Vice President and Chief Financial Officer and Glenn W. Reed, our Senior Vice President—Operations. See “Executive compensation—Other benefits—Employment agreements and other arrangements.” If any of these officers or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. Our ability to manage our growth, if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified personnel. Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.
 
We have three affiliated stockholders with a controlling interest in our company, whose interests may differ from your interests and who will be able to determine the outcome of matters voted upon by our stockholders.
 
After this offering, Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P. and Yorktown Energy Partners VII, L.P., or collectively, Yorktown, which are under common management, will beneficially own approximately 47.2% of our outstanding common stock in the


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aggregate (44.6% if the underwriters’ over-allotment option is exercised in full). In addition, one Yorktown representative serves on our board of directors, and our management team and employees will beneficially own or control approximately 7.4% of our common stock outstanding (7.0% if the underwriters’ over-allotment option is exercised in full). See “Security ownership of certain beneficial owners and management.” As a result of this ownership, Yorktown will have the ability to control the vote in any election of directors. Yorktown also will have control over our decisions to enter into significant corporate transactions and, in its capacity as our majority stockholder, will have the ability to prevent any transactions that it does not believe are in Yorktown’s best interest. As a result, Yorktown will be able to control, directly or indirectly and subject to applicable law, all matters affecting us, including the following:
 
•  any determination with respect to our business direction and policies, including the appointment and removal of officers;
 
•  any determinations with respect to mergers, business combinations or dispositions of assets;
 
•  our capital structure;
 
•  compensation, option programs and other human resources policy decisions;
 
•  changes to other agreements that may adversely affect us; and
 
•  the payment, or nonpayment, of dividends on our common stock.
 
Yorktown also may have an interest in pursuing transactions that, in their judgment, enhance the value of their respective equity investments in our company, even though those transactions may involve risks to you as a minority stockholder. In addition, circumstances could arise under which their interests could be in conflict with the interests of our other stockholders or you, a minority stockholder. Also, Yorktown and their affiliates have and may in the future make significant investments in other companies, some of which may be competitors. Yorktown and its affiliates are not obligated to advise us of any investment or business opportunities of which they are aware, and they are not restricted or prohibited from competing with us.
 
We have renounced any interest in specified business opportunities, and certain members of our board of directors and certain of our stockholders generally have no obligation to offer us those opportunities.
 
In accordance with Delaware law, we have renounced any interest or expectancy in any business opportunity, transaction or other matter in which our non-employee directors and certain of our stockholders, each referred to as a Designated Party, participates or desires to participate in that involves any aspect of the exploration and production business in the oil and industry. If any such business opportunity is presented to a Designated Person who also serves as a member of our board of directors, the Designated Party has no obligation to communicate or offer that opportunity to us, and the Designated Party may pursue the opportunity as he sees fit, unless:
 
•  it was presented to the Designated Party solely in that person’s capacity as a director of our company and with respect to which, at the time of such presentment, no other Designated Party has independently received notice of or otherwise identified the business opportunity; or
 
•  the opportunity was identified by the Designated Party solely through the disclosure of information by or on behalf of us.


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For a more complete discussion of this agreement, please read “Certain relationships and related party transactions—Business opportunities renunciation.” As a result of this renunciation, our non-employee directors should not be deemed to be breaching any fiduciary duty to us if they or their affiliates or associates pursue opportunities as described above and our future competitive position and growth potential could be adversely affected.
 
We are subject to complex governmental laws and regulations that may adversely affect the cost, manner or feasibility of doing business.
 
Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, gas and oil, and operating safety, and protection of the environment, including those relating to air emissions, wastewater discharges, land use, storage and disposal of wastes and remediation of contaminated soil and groundwater. Future laws or regulations, any adverse changes in the interpretation of existing laws and regulations or our failure to comply with existing legal requirements may harm our business, results of operations and financial condition. We may encounter reductions in reserves or be required to make large and unanticipated capital expenditures to comply with governmental laws and regulations, such as:
 
•  price control;
 
•  taxation;
 
•  lease permit restrictions;
 
•  drilling bonds and other financial responsibility requirements, such as plug and abandonment bonds;
 
•  spacing of wells;
 
•  unitization and pooling of properties;
 
•  safety precautions; and
 
•  permitting requirements.
 
Under these laws and regulations, we could be liable for:
 
•  personal injuries;
 
•  property and natural resource damages;
 
•  well reclamation costs, soil and groundwater remediation costs; and
 
•  governmental sanctions, such as fines and penalties.
 
Our operations could be significantly delayed or curtailed, and our cost of operations could significantly increase as a result of environmental safety and other regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects. Intricate and changing environmental and other regulatory requirements may require substantial expenditures to obtain and maintain permits. If a project is unable to function as planned, for example, due to costly or changing


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requirements or local opposition, it may create expensive delays, extended periods of non-operation or significant loss of value in a project. See “Business—Regulation.”
 
Operating hazards, natural disasters or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.
 
The oil and gas business involves certain operating hazards such as:
 
•  well blowouts;
 
•  cratering;
 
•  explosions;
 
•  uncontrollable flows of gas, oil or well fluids;
 
•  fires;
 
•  pollution; and
 
•  releases of toxic gas.
 
The occurrence of one of the above may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties.
 
In addition, our operations in Texas are especially susceptible to damage from natural disasters such as tornados and involve increased risks of personal injury, property damage and marketing interruptions. Any of these operating hazards could cause serious injuries, fatalities or property damage, which could expose us to liabilities. The payment of any of these liabilities could reduce, or even eliminate, the funds available for exploration, development, exploitation and acquisition, or could result in a loss of our properties. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. Our insurance might be inadequate to cover our liabilities. The insurance market in general and the energy insurance market in particular have been difficult markets over the past several years. Insurance costs are expected to continue to increase over the next few years and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incur liability at a time when we are not able to obtain liability insurance, then our business, results of operations and financial condition could be materially adversely affected.
 
Our results are subject to quarterly and seasonal fluctuations.
 
Our quarterly operating results have fluctuated in the past and could be negatively impacted in the future as a result of a number of factors, including:
 
•  seasonal variations in gas and oil prices;
 
•  variations in levels of production; and
 
•  the completion of exploration and production projects.


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Market conditions or transportation impediments may hinder our access to gas and oil markets or delay our production.
 
Market conditions, the unavailability of satisfactory gas and oil processing and transportation may hinder our access to gas and oil markets or delay our production. Although currently we control the pipeline operations for a majority of our production in the Ozona Northeast field, we do not have such control in other areas in which we expect to conduct operations. The availability of a ready market for our gas and oil production depends on a number of factors, including the demand for and supply of gas and oil and the proximity of reserves to pipelines or trucking and terminal facilities. In addition, the amount of gas and oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering or transportation system or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases we are provided with limited, if any, notice as to when these circumstances will arise and their duration. As a result, we may not be able to sell, or may have to transport by more expensive means, the gas and oil production from wells or we may be required to shut in gas wells or delay initial production until the necessary gathering and transportation systems are available. Any significant curtailment in gathering system or pipeline capacity, or significant delay in construction of necessary gathering and transportation facilities, could adversely affect our business, financial condition or results of operations.
 
Environmental liabilities may expose us to significant costs and liabilities.
 
There is inherent risk of incurring significant environmental costs and liabilities in our gas and oil operations due to the handling of petroleum hydrocarbons and generated wastes, the occurrence of air emissions and water discharges from work-related activities and the legacy of pollution from historical industry operations and waste disposal practices. We may incur joint and several or strict liability under these environmental laws and regulations in connection with spills, leaks or releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities, many of which have been used for exploration, production or development activities for many years, oftentimes by third parties not under our control. Private parties, including the owners of properties upon which we conduct drilling and production activities as well as 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, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our production or our operations or financial position. We may not be able to recover some or any of these costs from insurance. See “Business—Regulation—Environmental regulations.”
 
Our growth strategy could fail or present unanticipated problems for our business in the future, which could adversely affect our ability to make acquisitions or realize anticipated benefits of those acquisitions.
 
Our growth strategy may include acquiring oil and gas businesses and properties. We may not be able to identify suitable acquisition opportunities or finance and complete any particular acquisition successfully.


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Furthermore, acquisitions involve a number of risks and challenges, including:
 
•  diversion of management’s attention;
 
•  the need to integrate acquired operations;
 
•  potential loss of key employees of the acquired companies;
 
•  potential lack of operating experience in a geographic market of the acquired business; and
 
•  an increase in our expenses and working capital requirements.
 
Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows from the acquired businesses or realize other anticipated benefits of those acquisitions.
 
Severe weather could have a material adverse impact on our business.
 
Our business could be materially and adversely affected by severe weather. Repercussions of severe weather conditions may include:
 
•  curtailment of services;
 
•  weather-related damage to drilling rigs, resulting in suspension of operations;
 
•  weather-related damage to our facilities;
 
•  inability to deliver materials to jobsites in accordance with contract schedules; and
 
•  loss of productivity.
 
A terrorist attack or armed conflict could harm our business.
 
Terrorist activities, anti-terrorist efforts and other armed conflict involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for gas and oil, potentially putting downward pressure on demand for our services and causing a reduction in our revenue. Gas and oil related facilities could be direct targets for terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities we use for the production, transportation or marketing of our gas and oil production are destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become difficult to obtain, if available at all.
 
Risks related to our financial condition
 
We will require additional capital to fund our future activities. If we fail to obtain additional capital, we may not be able to implement fully our business plan, which could lead to a decline in reserves.
 
We depend on our ability to obtain financing beyond our cash flow from operations. Historically, we have financed our business plan and operations primarily with internally generated cash flows, borrowings under our revolving credit facility and issuances of common stock. We also require capital to fund our capital budget, which is expected to be approximately $53.6 million for 2007. As of December 31, 2006, approximately 49% of our total estimated proved


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reserves were undeveloped. Recovery of such reserves will require significant capital expenditures and successful drilling operations. We will be required to meet our needs from our internally generated cash flows, debt financings and equity financings.
 
If our revenues decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may, from time to time, need to seek additional financing. Our revolving credit facility contains covenants restricting our ability to incur additional indebtedness without lender consent. There can be no assurance that our bank lenders will provide this consent or as to the availability or terms of any additional financing. If we incur additional debt, the related risks that we now face could intensify.
 
Even if additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations and available under our revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our projects, which in turn could lead to a possible loss of properties and a decline in our gas reserves.
 
Our bank lenders can limit our borrowing capabilities, which may materially impact our operations.
 
At June 30, 2007, outstanding borrowings under our revolving credit facility totaled approximately $46.8 million. We intend to use a portion of the proceeds from this offering to repay the outstanding balance under our revolving credit facility. The borrowing base limitation under our revolving credit facility is redetermined semi-annually. Redeterminations are based upon information contained in an engineering report prepared by an independent petroleum engineering firm, including, without limitation, commodity prices and reserve levels. In addition, as is typical in the oil and gas industry, our bank lenders have substantial flexibility to reduce our borrowing base on the basis of subjective factors. Upon a redetermination, we could be required to repay a portion of our outstanding borrowings, including the total face amounts of all outstanding letters of credit and the amount of all unpaid reimbursement obligations, to the extent such amounts exceed the redetermined borrowing base. We may not have sufficient funds to make such required repayment, which could result in a default under the terms of the revolving credit facility and an acceleration of the loan. We intend to finance our development, acquisition and exploration activities with cash flow from operations, borrowings under our revolving credit facility and other financing activities. In addition, we may significantly alter our capitalization to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of debt. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance which will be affected by general economic conditions and financial, business and other factors. Many of these factors are beyond our control. Our level of debt affects our operations in several important ways, including the following:
 
•  a portion of our cash flow from operations is used to pay interest on borrowings;
 
•  the covenants contained in the agreements governing our debt limit our ability to borrow additional funds, pay dividends, dispose of assets or issue shares of preferred stock and


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otherwise may affect our flexibility in planning for, and reacting to, changes in business conditions;
 
•  a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or general corporate purposes;
 
•  a leveraged financial position would make us more vulnerable to economic downturns and could limit our ability to withstand competitive pressures; and
 
•  any debt that we incur under our revolving credit facility will be at variable rates which makes us vulnerable to increases in interest rates.
 
We engage in commodity derivative transactions which involve risks that can harm our business.
 
To manage our exposure to price risks in the marketing of our gas and oil production, we enter into gas and oil price commodity derivative agreements. While intended to reduce the effects of volatile oil and gas prices, such transactions may limit our potential gains and increase our potential losses if gas and oil prices were to rise substantially over the price established by the commodity derivative. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which our production is less than expected, there is a widening of price differentials between delivery points for our production and the delivery point assumed in the commodity derivative arrangement or the counterparties to the commodity derivative agreements fail to perform under the contracts.
 
Risks related to this offering
 
There has been no public market for our common stock, and our stock price may fluctuate significantly.
 
There is currently no public market for our common stock, and an active trading market may not develop or be sustained after the sale of all of the shares covered by this prospectus. The market price of our common stock could fluctuate significantly as a result of:
 
•  our operating and financial performance and prospects;
 
•  quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;
 
•  changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry;
 
•  liquidity and registering our common stock for public resale;
 
•  actual or unanticipated variations in our reserve estimates and quarterly operating results;
 
•  changes in gas and oil prices;
 
•  speculation in the press or investment community;
 
•  sales of our common stock by our stockholders;
 
•  increases in our cost of capital;


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•  changes in applicable laws or regulations, court rulings and enforcement and legal actions;
 
•  changes in market valuations of similar companies;
 
•  adverse market reaction to any increased indebtedness we incur in the future;
 
•  additions or departures of key management personnel;
 
•  actions by our stockholders;
 
•  general market and economic conditions, including the occurrence of events or trends affecting the price of gas; and
 
•  domestic and international economic, legal and regulatory factors unrelated to our performance.
 
If a trading market develops for our common stock, stock markets in general experience volatility that often is unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.
 
We do not anticipate paying any dividends on our common stock in the foreseeable future.
 
We do not expect to declare or pay any cash or other dividends in the foreseeable future on our common stock, as we intend to use cash flow generated by operations to expand our business. Our revolving credit facility will restrict our ability to pay cash dividends on our common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that restrict or limit our ability to pay cash dividends on our common stock.
 
Certain stockholders’ shares are restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of our common stock to drop significantly.
 
After this offering, we will have outstanding 19,255,789 shares of common stock. Of these shares, the 7,666,667 shares we and the selling stockholder are selling in this offering will be freely tradeable without restriction under the Securities Act except for any shares purchased by one of our “affiliates” as defined in Rule 144 under the Securities Act. A total of 11,589,122 shares will be “restricted securities” (within the meaning of Rule 144 under the Securities Act) or subject to lock-up arrangements. In connection with this offering, we, our executive officers and directors and the other holders of our common stock (including the selling stockholder) have agreed that, during the period beginning from the date of this prospectus and continuing to and including the day 180 days after the date of this prospectus, neither we nor any of them will, directly or indirectly, offer, sell, offer to sell, contract to sell or otherwise dispose of any shares of our common stock without the prior written consent of J.P. Morgan Securities Inc., on behalf of the underwriters, except in limited circumstances. See “Underwriting” for a description of these lock-up arrangements.
 
Sales of a substantial number of shares of our common stock in the public markets following this offering by any of our existing stockholders (or persons to whom our existing stockholders may distribute shares of our common stock), or the perception that such sales might occur, could have a material adverse effect on the price of our common stock or could impair our ability to obtain capital through an offering of equity securities.


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As soon as practicable after this offering, we intend to file one or more registration statements with the SEC on Form S-8 providing for the registration of 2,027,440 shares of our common stock issued or reserved for issuance under our stock incentive plan, which number is subject to adjustment pursuant to the terms of the plan. Subject to the exercise of unexercised options or the expiration or waiver of vesting conditions for restricted stock and the expiration of lock-ups we and certain of our stockholders have entered into, shares registered under these registration statements on Form S-8 will be available for resale immediately in the public market without restriction.
 
You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock.
 
We may in the future issue our previously authorized and unissued securities, resulting in the dilution of the ownership interests of our present stockholders and purchasers of common stock offered hereby. We are currently authorized to issue 90 million shares of common stock and 10 million shares of preferred stock with preferences and rights as determined by our board of directors. The potential issuance of such additional shares of common stock may create downward pressure on the trading price of our common stock. We may also issue additional shares of our common stock or other securities that are convertible into or exercisable for common stock in connection with the hiring of personnel, future acquisitions, future public offerings or private placements of our securities for capital raising purposes, or for other business purposes. Any of these events may dilute your ownership interest in us and have an adverse impact on the price of our common stock.
 
In addition, sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. This could also impair our ability to raise additional capital through the sale of our securities.
 
If equity research analysts do not publish research or reports about our business or if they issue unfavorable commentary or downgrade our common stock, the price of our common stock could decline.
 
The trading market for our common stock may rely in part on the research and reports that equity research analysts publish about us and our business. We do not control the opinions of these analysts. The price of our stock could decline if one or more equity analysts downgrade our stock or if those analysts issue other unfavorable commentary or cease publishing reports about us or our business.
 
Certain provisions of Delaware law, our restated certificate of incorporation and our restated bylaws could hinder, delay or prevent a change in control of our company, which could adversely affect the price of our common stock.
 
Certain provisions of Delaware law, our restated certificate of incorporation and our restated bylaws have the effect of discouraging, delaying or preventing transactions that involve an actual or threatened change in control of our company. Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our


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outstanding common stock. In addition, our restated certificate of incorporation and restated bylaws include the following provisions:
 
•  Written consent of stockholders. Our restated certificate of incorporation and restated bylaws provide that any action required or permitted to be taken by our stockholders must be taken at a duly called meeting of stockholders and not by written consent.
 
•  Call of special meetings of stockholders. Our restated bylaws provide that special meetings of stockholders may be called at any time only by our board of directors, chairman or Chief Executive Officer and not the stockholders.
 
•  Classified board of directors. Our board of directors will be divided into three classes with staggered terms of office of three years each. The classification and staggered terms of office of our directors make it more difficult for a third party to gain control of our board of directors. At least two annual meetings of stockholders, instead of one, generally would be required to effect a change in a majority of the board of directors.
 
•  Removal of directors. Under our restated certificate of incorporation, a director may be removed only for cause and only by the affirmative vote of at least 67% of the voting power of the outstanding shares of our capital stock.
 
•  Number of directors, board vacancies, term of office. Our restated certificate of incorporation and our restated bylaws provide that only the board of directors may set the number of directors. We have elected to be subject to certain provisions of Delaware law which vest in the board of directors the exclusive right, by the affirmative vote of a majority of the remaining directors, to fill vacancies on the board even if the remaining directors do not constitute a quorum. When effective, these provisions of Delaware law, which are applicable even if other provisions of Delaware law or the charter or bylaws provide to the contrary, also provide that any director elected to fill a vacancy shall hold office for the remainder of the full term of the class of directors in which the vacancy occurred, rather than the next annual meeting of stockholders as would otherwise be the case, and until his or her successor is elected and qualifies.
 
•  Advance notice provisions for stockholder nominations and proposals. Our restated bylaws require advance written notice for stockholders to nominate persons for election as directors at, or to bring other business before, any meeting of stockholders. This bylaw provision limits the ability of stockholders to make nominations of persons for election as directors or to introduce other proposals unless we are notified in a timely manner prior to the meeting.
 
•  Amending the bylaws. Our restated certificate of incorporation permits our board of directors to adopt, alter or repeal any provision of the restated bylaws or to make new bylaws. Our restated certificate of incorporation also provides that our restated bylaws may be amended by the affirmative vote of the holders of at least 67% of the voting power of the outstanding shares of our capital stock.
 
•  Authorized but unissued shares. Under our restated certificate of incorporation, our board of directors has authority to cause the issuance of preferred stock from time to time in one or more series and to establish the terms, preferences and rights of any such series of preferred stock, all without approval of our stockholders. Nothing in our restated certificate of incorporation precludes future issuances without stockholder approval of the authorized but unissued shares of our common stock.


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See “Description of capital stock—Anti-takeover effects of provisions of Delaware law, our restated certificate of incorporation and restated bylaws.” Any one or more of these factors could have the effect of delaying or preventing a change in control or the removal of management, and deterring potential acquirers from making an offer to our stockholders, even if that event potentially would be favorable to the interests of our stockholders.
 
Purchasers of common stock in this offering will experience immediate and substantial dilution of $4.47 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 $4.47 per share in the as adjusted pro forma net tangible book value per share of common stock from the initial public offering price, and our pro forma as adjusted net tangible book value as of June 30, 2007 after giving effect to this offering would be $10.53 per share. See “Dilution.”


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Cautionary statement regarding
forward-looking statements
 
Various statements in this prospectus, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future reserves, production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project” or their negatives, other similar expressions or the statements that include those words, it usually is a forward-looking statement.
 
The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:
 
•  our business strategy;
 
•  estimated quantities of gas and oil reserves;
 
•  technology;
 
•  uncertainty of commodity prices in oil and gas;
 
•  our financial position;
 
•  our cash flow and liquidity;
 
•  declines in the prices we receive for our gas and oil affecting our operating results and cash flow;
 
•  economic slowdowns that can adversely affect consumption of gas and oil by businesses and consumers;
 
•  uncertainties in estimating our gas and oil reserves;
 
•  replacing our gas and oil reserves;
 
•  uncertainty regarding our future operating results;


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•  uncertainties in exploring for and producing gas and oil;
 
•  our inability to obtain additional financing necessary to fund our operations and capital expenditures and to meet our other obligations;
 
•  availability of drilling and production equipment and field service providers;
 
•  disruptions to, capacity constraints in or other limitations on the pipeline systems which deliver our gas and other processing and transportation considerations;
 
•  competition in the oil and gas industry;
 
•  marketing of gas and oil;
 
•  exploitation or property acquisitions;
 
•  our inability to retain and attract key personnel;
 
•  the effects of government regulation and permitting and other legal requirements;
 
•  costs associated with perfecting title for mineral rights in some of our properties;
 
•  plans, objectives, expectations and intentions contained in this prospectus that are not historical; and
 
•  other factors discussed under “Risk factors.”


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Use of proceeds
 
We estimate that the net proceeds to us from the sale of common stock in this offering will be approximately $76.9 million (or $90.8 million if the underwriters exercise their over-allotment option in full), in each case based on an offering price of $15.00 per share, the mid-point of the estimated price range shown on the front cover of this prospectus, and after deducting the underwriting discounts and the estimated offering expenses payable by us. Each dollar increase (decrease) in the per share offering price will increase (decrease) the amount of net proceeds we receive from this offering by $5.2 million.
 
We intend to use the net proceeds of this offering to repay approximately $48.0 million outstanding under our revolving credit facility, to repurchase 2,021,148 shares of our common stock held by Neo Canyon Exploration, L.P. at a purchase price of approximately $28.2 million and the remainder of approximately $700,000 for general corporate purposes, including exploration and development activities, gas and oil reserves and leasehold acquisitions in the ordinary course of business and for working capital.
 
Our revolving credit facility bore interest at 6.87% per annum as of June 30, 2007 and matures on July 31, 2010. At June 30, 2007, outstanding borrowings under our revolving credit facility totaled approximately $46.8 million. We incurred the debt under our revolving credit facility principally to meet our capital expenditure requirements and other working capital needs. We will have no outstanding borrowings under our revolving credit facility after the closing of this offering, leaving us with approximately $75.0 million available for future borrowings under such revolving credit facility. See “Management’s discussion and analysis of financial condition and results of operations—Credit facility” for a description of our revolving credit facility.
 
We will not receive any proceeds from the sale of shares of common stock by the selling stockholder.
 
Dividend policy
 
We do not expect to pay any cash or other dividends in the foreseeable future on our common stock, as we intend to reinvest cash flow generated by operations in our business. Our revolving credit facility currently restricts our ability to pay cash dividends on our common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that restrict or limit our ability to pay cash dividends on our common stock.


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Capitalization
 
The following table sets forth our cash and cash equivalents and capitalization as of June 30, 2007:
 
•  on an actual historical basis;
 
•  on a pro forma basis, reflecting the consummation of the transactions described under “Certain relationships and related party transactions—The contribution agreement.”; and
 
•  on pro forma as adjusted basis, reflecting (i) the consummation of the transactions described under “Certain relationships and related party transactions—The contribution agreement,” (ii) our three for one common stock split, (iii) our sale of 5,605,377 shares of common stock in this offering at an assumed initial public offering price of $15.00 per share, after deducting underwriting discounts and estimated offering expenses payable by us and the application of the estimated net proceeds from this offering as set forth under “Use of proceeds” and (iv) certain other transactions.
 
                   
    As of June 30, 2007
            Pro forma
(in thousands)   Actual   Pro forma   as adjusted(1)
 
Cash and cash equivalents
  $ 18,492   $ 18,492   $ 19,196
     
     
Long-term debt
  $ 46,769   $ 46,769   $
Convertible debt
    20,000     20,000    
Stockholders’ equity:
                 
Preferred stock, $0.01 par value, 10,000,000 shares authorized, no shares issued and outstanding actual, no shares issued and outstanding pro forma, no shares issued and outstanding pro forma as adjusted
           
Common stock, $0.01 par value, 90,000,000 shares authorized, 3,002,085 shares issued and outstanding actual, 4,594,885 shares issued and outstanding pro forma, 19,255,789 shares issued and outstanding pro forma as adjusted
    30     46     192
Additional paid-in capital
    38,971     102,544     178,559
Retained earnings
    33,068     33,068     24,064
     
     
Total stockholders’ equity
    72,069     135,658     202,815
     
     
Total capitalization
  $ 138,838   $ 202,427   $ 202,815
 
 
(1) Includes the effects of (i) our receipt of $240,380 pursuant to an exercise of stock options covering 72,114 shares of our common stock by a former executive officer, (ii) the conversion of $20.0 million of principal and $540,822 of accrued interest under convertible notes into 1,472,460 shares of our common stock along with the recognition of the related beneficial conversion feature amounting to $1,546,083, (iii) the grant of 322,500 restricted shares to our named executive officers and the related bonus for taxes as set forth under “Management—Grants of plan based awards” and (iv) the election by each of Messrs. Brandi, Lubar and Whyte to receive 5,666 shares of our common stock and Mr. Crain to receive 2,833 shares of our common stock in lieu of cash for all or a portion of their 2007 director fees.


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Dilution
 
Purchasers of 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. Net tangible book value per share is determined by dividing our tangible net worth (tangible assets less total liabilities) by the total number of outstanding shares of common stock. At June 30, 2007, after giving effect to the issuance of 5,228,400 shares as described under “Certain relationships and related party transactions—The contribution agreement,” certain other transactions, principally the conversion of certain convertible promissory notes as described under “Certain relationships and related party transactions—Convertible notes” and our three for one common stock split, the pro forma net tangible book value per share of our common stock was $154.1 million, or $9.83 per share of common stock. After giving effect to the sale of 5,605,377 shares of common stock in this offering and assuming the receipt of the estimated net proceeds, after deducting the underwriters’ discounts and estimated offering expenses, our pro forma as adjusted net tangible book value at June 30, 2007 would have been approximately $202.8 million, or $10.53 per share. This represents an immediate and substantial increase in the pro forma as adjusted net tangible book value of $0.70 per share to existing stockholders and an immediate dilution of $4.47 per share to new investors purchasing common stock in this offering, resulting from the difference between the initial public offering price and the pro forma as adjusted net tangible book value after this offering. All per share amounts in this section have been adjusted for our three for one common stock split. The following table illustrates the per share dilution to new investors purchasing common stock in this offering:
 
             
Assumed initial public offering price per share(1)
        $ 15.00
Adjusted net tangible book value per share at June 30, 2007(2)
  $ 9.83      
Increase per share attributable to new public investors(3)
  $ 0.70      
             
As adjusted net tangible book value per share after this offering(3)
        $ 10.53
             
Dilution in as adjusted net tangible book value per share to new investors
        $ 4.47
 
 
 
(1) Before deduction of underwriting discounts and estimated offering expenses.
 
(2) Net tangible book value is defined as stockholders’ equity less intangible assets.
 
(3) Takes into account underwriting discounts and estimated offering expenses.
 
A $1.00 increase (decrease) in the assumed public offering price of $15.00 would increase (decrease) our as adjusted net tangible book value per share after this offering by $0.27 per share and the dilution in net tangible book value to new investors by $0.73 per share, assuming the number of shares offered by us, as set forth on the cover of this preliminary prospectus, remains the same and after deducting estimated underwriting discounts and estimated offering expenses payable by us.


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The following table sets forth, on the pro forma as adjusted basis set forth above as of June 30, 2007, 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 calculated before deduction of estimated underwriting discounts:
 
                               
    Shares purchased(1)   Total consideration   Average price
    Number   Percent   Amount   Percent   per share
 
Existing stockholders(1)
    15,671,560     74%     130,052,220     61%     8.30
New investors
    5,605,377     26%     84,080,655     39%     15.00
           
           
Total
    21,276,937     100%     214,132,875     100%     10.06
 
 
 
(1) The number of shares disclosed for the existing stockholders includes shares being sold by the selling stockholder in this offering. The number of shares disclosed for the new investors does not include the shares being purchased by the new investors from the selling stockholder in this offering.
 
A $1.00 increase (decrease) in the assumed initial public offering price per share would increase (decrease) total consideration paid by new investors by $5.6 million, or increase (decrease) the percent of total consideration paid by new investors to 1.5%, assuming the number of shares offered by us, as set forth on the cover of this prospectus, remains the same.


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Unaudited combined pro forma financial data
 
The following combined pro forma financial information gives effect to the following transactions:
 
•  The issuance of 1,413,081 shares of Approach Resources Inc. common stock to Neo Canyon Exploration, L.P. for its 30% working interest in the Ozona Northeast field that Approach does not already own; and
 
•  The issuance of 329,719 shares of Approach Resources Inc. common stock in exchange for 150,000 shares of Approach Oil & Gas Inc. common stock, representing all of the issued and outstanding shares of Approach Oil & Gas Inc. common stock.
 
The unaudited combined pro forma financial statements and the accompanying notes presented herein do not give effect to our three for one common stock split.
 
Our operations are currently conducted by two separate operating entities under common control: Approach Resources Inc. and Approach Oil & Gas Inc. Pursuant to a contribution agreement, the operations of Approach Oil & Gas Inc. will be combined under Approach Resources Inc., and we will also acquire the Neo Canyon interest immediately prior to the closing of this offering.
 
The combined pro forma balance sheet as of June 30, 2007 is based on our unaudited combined balance sheet as of June 30, 2007, appearing elsewhere in this prospectus, and gives effect to the transactions described above as if they occurred on June 30, 2007.
 
The combined pro forma statement of operations for the six months ended June 30, 2007 is based on our unaudited combined statement of operations for the six months ended June 30, 2007 and the unaudited Historical Summary of Revenues and Direct Operating Expenses of Properties to be Acquired by Approach Resources Inc. for the six months ended June 30, 2007, both of which appear elsewhere in this prospectus, and gives effect to the transactions described above as if they occurred on January 1, 2006.
 
The combined pro forma statement of operations for the year ended December 31, 2006 is based on our audited combined statement of operations for the year ended December 31, 2006, and the audited historical summary of revenues and direct operating expenses of properties to be acquired by Approach Resources Inc. for the year ended December 31, 2006, both of which appear elsewhere in this prospectus, and gives effect to the transactions described above as if they occurred on January 1, 2006.
 
The unaudited combined pro forma financial statements presented herein have been included as required by the rules of the SEC and are provided for comparative purposes only. These unaudited combined pro forma financial statements should be read in conjunction with our historical combined financial statements and related notes for the periods presented.
 
The unaudited combined pro forma financial statements presented herein are based upon assumptions and include adjustments as explained in the notes to the unaudited combined pro forma financial statements, and the actual recording of the transactions could differ. The unaudited combined pro forma financial statements presented herein are not necessarily indicative of the financial results that would have occurred had the transactions described above occurred on the dates indicated and should not be viewed as indicative of operations in the future. However, management believes that the assumptions used provide a reasonable basis for presenting the significant effects of the transactions discussed above and that the pro forma adjustments give appropriate effect to those assumptions.


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Approach Resources Inc.
Unaudited combined pro forma balance sheet
June 30, 2007
 
                         
 
    Approach
             
    Resources Inc.
             
    combined
          Combined
 
    historical
    Pro forma
    pro forma
 
(in thousands)   amounts     adjustments     amounts  
 
Assets
                       
Current assets:
                       
Cash and cash equivalents
  $ 18,492     $     $ 18,492  
Accounts receivable:
                       
Joint interest owners
    3,338             3,338  
Oil and gas sales
    3,941             3,941  
Prepaid expenses and other current assets
    2,603             2,603  
     
     
Total current assets
    28,374             28,374  
Property and equipment:
                       
Oil and gas properties, using the successful efforts method of accounting
    172,363       63,656 (a)     236,019  
Furniture, fixtures and equipment
    264             264  
Less accumulated depreciation, depletion and amortization
    (29,873 )           (29,873 )
     
     
Net property and equipment
    142,754       63,656       206,410  
Other assets
    1,179             1,179  
     
     
Total assets
  $ 172,307     $ 63,656     $ 235,963  
     
     
Liabilities and stockholders’ equity
                       
Current liabilities:
                       
Accounts payable
  $ 6,807     $     $ 6,807  
Oil and gas payables
    5,431             5,431  
Accrued liabilities
    2,459             2,459  
     
     
Total current liabilities
    14,697             14,697  
Non-current liabilities:
                       
Long-term debt
    46,769             46,769  
Convertible debt
    20,000             20,000  
Asset retirement obligation
    163       67 (a)     230  
Deferred tax liability
    18,609               18,609  
     
     
Total liabilities
    100,238       67       100,305  
Stockholders’ equity:
                       
Common stock
    30       14 (a)     46  
              2 (b)        
Additional paid-in capital
    38,971       63,575 (a)        
              (2 )(b)     102,544  
Retained earnings
    33,068             33,068  
     
     
Total stockholders’ equity
    72,069       63,589       135,658  
     
     
Total liabilities and stockholders’ equity
  $ 172,307     $ 63,656     $ 235,963  
 
See accompanying notes.


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Approach Resources Inc.
Unaudited combined pro forma statement of operations
Six months ended June 30, 2007
 
                               
 
    Approach
                 
    Resources Inc.
                 
    combined
    Neo Canyon
        Combined
 
(in thousands, except shares and per share
  historical
    historical
  Pro forma
    pro forma
 
data)   amounts     amounts   adjustments     amounts  
 
Revenues:
                             
Oil and gas sales
  $ 19,082     $ 7,823   $     $ 26,905  
Expenses:
                             
Lease operating
    2,023       933     (212 )(c)     2,744  
Severance and production taxes
    748       340           1,088  
Exploration
    633                 633  
General and administrative
    2,730           212 (c)     2,942  
Accretion of discount on asset retirement obligations
                     
Depreciation, depletion and amortization
    6,108           2,609 (d)     8,717  
     
     
Total expenses
    12,242       1,273     2,609       16,124  
     
     
Operating income
    6,840       6,550     (2,609 )     10,781  
Other income (expense):
                             
Interest expense, net
    (1,954 )               (1,954 )
Realized gain (loss) on commodity derivatives
    2,244                 2,244  
Change in fair value of commodity derivatives
    (2,902 )               (2,902 )
     
     
Income (loss) before provision (benefit) for income taxes
    4,228       6,550     (2,609 )     8,169  
Provision (benefit) for income taxes
    1,818             1,366 (e)     3,184  
     
     
Net income (loss)
  $ 2,410     $ 6,550   $ (3,975 )   $ 4,985  
     
     
Earnings (loss) per share:
                             
Basic
  $ 0.81                   $ 1.09  
                               
Diluted
  $ 0.74                   $ 1.02  
                               
Weighted average shares outstanding:
                             
Basic
    2,984,105             1,592,800 (g)     4,576,905  
                               
Diluted
    3,297,655             1,592,800 (g)     4,890,455  
 
See accompanying notes.


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Approach Resources Inc.
Unaudited combined pro forma statement of operations
Year ended December 31, 2006
 
                               
 
    Approach
                 
    Resources Inc.
                 
    combined
    Neo Canyon
        Combined
 
    historical
    historical
  Pro forma
    pro forma
 
(in thousands, except shares and per share data)   amounts     amounts   adjustments     amounts  
 
Revenues:
                             
Oil and gas sales
  $ 46,672     $ 19,558   $     $ 66,230  
Expenses:
                             
Lease operating
    3,889       1,868     (339 )(c)     5,418  
Severance and production taxes
    1,736       716           2,452  
Exploration
    1,640                 1,640  
Impairment of non-producing properties
    558                 558  
General and administrative
    2,416           339 (c)     2,755  
Accretion of discount on asset retirement obligations
    10           4 (f)     14  
Depreciation, depletion and amortization
    14,541           6,906 (d)     21,447  
     
     
Total expenses
    24,790       2,584     6,910       34,284  
     
     
Operating income
    21,882       16,974     (6,910 )     31,946  
Other income (expense):
                             
Interest expense, net
    (3,814 )               (3,814 )
Realized gain (loss) on commodity derivatives
    6,222                 6,222  
Change in fair value of commodity derivatives
    8,668                 8,668  
     
     
Income before provision for income taxes
    32,958       16,974     (6,910 )     43,022  
Provision for income taxes
    11,756           3,724 (e)     15,480  
     
     
Net income (loss)
  $ 21,202     $ 16,974   $ (10,634 )   $ 27,542  
     
     
Earnings per share:
                             
Basic
  $ 7.04                   $ 5.91  
                               
Diluted
  $ 6.84                   $ 5.80  
                               
Weighted average shares outstanding:
                             
Basic
    3,012,414             1,650,608 (h)     4,663,022  
                               
Diluted
    3,101,180             1,650,608 (h)     4,751,788  
 
See accompanying notes.


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Approach Resources Inc.
Notes to unaudited combined pro forma
financial statements
 
The accompanying unaudited combined pro forma balance sheet at June 30, 2007 assumes that the acquisition of the Neo Canyon interest occurred as of June 30, 2007. The unaudited combined pro forma statement of operations for the year ended December 31, 2006 and the six months ended June 30, 2007 assume the acquisition occurred as of January 1, 2006 and January 1, 2007, respectively. The following adjustments have been made to the accompanying pro forma statements:
 
(a)  To record the acquisition of the Neo Canyon interest for $63.7 million by the issuance of 1,413,081 shares of Approach Resources Inc. common stock at June 30, 2007, and the assumption of related asset retirement obligations at that date. The issuance of 1,413,081 shares of common stock is subject to adjustment based on (i) changes in the relative value of the future net cash flows associated with the Neo Canyon interest to the combined future net cash flows after giving effect to any financing transactions and acquisitions consummated by Approach Resources Inc. and Approach Oil & Gas Inc. after the execution of the contribution agreement but before the closing of the offering, and (ii) a proposed three for one stock split of Approach Resources Inc. common stock.
 
We determined the purchase price for the Neo Canyon interests based on a formula that compares the discounted future net cash flows attributable to the Neo Canyon interest with the discounted future net cash flows of the combined oil and gas reserves of Approach Resources Inc., Approach Oil & Gas Inc. and the Neo Canyon interest. We made such comparison using January 1, 2007 reserve data priced using forward strip gas prices at March 31, 2007. Based on this comparison, we determined that the discounted future net cash flows related to the Neo Canyon interest would represent approximately 30% of the combined discounted future net cash flows after all of the transactions contemplated in this pro forma information had occurred. We determined the number of shares to be issued in connection with the acquisition of the Neo Canyon interest as the number of shares that would represent 30% of our common shares outstanding after the all of the transactions contemplated in this pro forma financial information had occurred. The price per share is $45.00, which represents the midpoint of the range of our estimated initial public offering price set forth on the cover of this prospectus on a pre-split basis.


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The following is a summary of the purchase price and its allocation (in thousands) based on our estimates described above:
       
 
Purchase price:
     
Issuance of 1,413,081 shares of Approach Resources Inc. common stock valued at $45.00 per share
  $ 63,589
Plus: assumption of asset retirement obligations
    67
       
Total purchase price
  $ 63,656
       
Allocation:
     
Mineral interests in oil and gas properties
  $ 4,709
Wells and equipment and related facilities
    58,947
       
Total
  $ 63,656
 
 
 
(b)  To record the issuance of 329,719 shares of Approach Resources Inc. common stock in exchange for 150,000 shares of Approach Oil & Gas Inc. common stock.
 
(c)  To eliminate operating overhead recoveries by Approach from Neo Canyon.
 
(d)  To adjust annual depletion and depreciation expense for the Neo Canyon interest based on the acquisition price valued at $69.5 million. The pro forma adjustment is based on the production and reserve information summarized under Pro Forma Supplementary Financial Information for Oil and Gas Producing Activities (Unaudited) below.
 
(e)  To record additional provision for income tax related to the acquisition of the Neo Canyon interest based on an effective income tax rate of 34.66%.
 
(f)  To record additional accretion of discount on asset retirement obligations related to the obligations assumed in the acquisition of the Neo Canyon interest. The pro forma amount for the six months ended June 30, 2007 is inconsequential.
 
(g)  To adjust the weighted average shares outstanding for the issuance of shares to Neo Canyon in exchange for the interest acquired as well as shares issued to stockholders of Approach Oil & Gas Inc. The pro forma adjustment comprises the following:
 
         
Issuance of shares for the acquisition of Neo Canyon interest
    1,413,081  
Issuance of shares for the Approach Oil & Gas Inc. combination
    329,719  
Purchase of Approach Oil & Gas Inc. common shares
    (150,000 )
         
Total
    1,592,800  
 
 


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(h)  To adjust the weighted average shares outstanding for the issuance of shares to Neo Canyon in exchange for the interest acquired as well as shares issued to stockholders of Approach Oil & Gas Inc. The pro forma adjustment comprises the following:
 
         
Issuance of shares for the acquisition of Neo Canyon interest
    1,413,081  
Issuance of shares for the Approach Oil & Gas Inc. combination
    329,719  
Purchase of Approach Oil & Gas Inc. common shares (represents the weighted average shares outstanding of Approach Oil & Gas Inc. for the year ended December 31, 2006)
    (92,192 )
         
Total
    1,650,608  
 
 
 
Pro forma supplementary financial information for oil and gas producing activities (unaudited)
 
The following tables present certain unaudited pro forma information concerning Approach’s proved oil and gas reserves giving effect to the acquisition of the Neo Canyon interest as if it had occurred on January 1, 2006. There are numerous uncertainties inherent in estimating the quantities of proved reserves and projecting future rates of production and timing of development expenditures. The following reserve data represent estimates only and should not be construed as being exact. The proved oil and gas reserve information for Approach and Neo Canyon is as of December 31, 2006 and reflects prices and costs as of those dates.
 
                         
 
    Approach Resources Inc.
    Neo Canyon
    Combined
 
    combined historical
    historical
    pro forma
 
Reserves—Crude oil & natural gas liquids (MBbls)   amounts     amounts     amounts  
 
 
Reserves at beginning of period
    1,086       467       1,553  
Extensions and discoveries
    339       61       400  
Revisions of previous estimates
    (226 )     (105 )     (331 )
Production
    (77 )     (32 )     (109 )
     
     
Reserves at end of period
    1,122       391       1,513  
     
     
Proved developed reserves at end of period
    496       170       666  
 
 
 
                         
 
    Approach Resources Inc.
    Neo Canyon
    Combined
 
    combined historical
    historical
    pro forma
 
Reserves—Natural gas (MMcf):   amounts     amounts     amounts  
 
 
Reserves at beginning of period
    102,405       42,899       145,304  
Extensions and discoveries
    15,655       6,421       22,076  
Revisions of previous estimates
    (13,121 )     (5,526 )     (18,647 )
Production
    (6,282 )     (2,645 )     (8,927 )
     
     
Reserves at end of period
    98,657       41,149       139,806  
     
     
Proved developed reserves at end of period
    51,004       21,400       72,404  
 
 


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Standardized measure of discounted future cash flows (in thousands):
 
                         
 
    Approach Resources Inc.
    Neo Canyon
    Combined
 
    combined historical
    historical
    pro forma
 
    amounts     amounts     amounts  
 
Future cash inflows
  $ 709,184     $ 292,399     $ 1,001,583  
Future production costs
    (198,023 )     (81,784 )     (279,807 )
Future development costs
    (108,451 )     (45,957 )     (154,408 )
Future income taxes
    (109,784 )     (1,647 )     (111,431 )
     
     
Future net cash flows
    292,926       163,011       455,937  
10% annual discount
    (215,049 )     (112,306 )     (327,355 )
     
     
Standardized measure of discounted future net cash flows
  $ 77,877     $ 50,705     $ 128,582  
 
 
 
Changes in standardized measure of discounted future cash flows (in thousands):
 
                         
 
    Approach Resources Inc.
    Neo Canyon
    Combined
 
    combined historical
    historical
    pro forma
 
    amounts     amounts     amounts  
 
Balance at beginning of period
  $ 146,439     $ 109,078     $ 255,517  
Net changes in prices and production costs
    (106,246 )     (56,734 )     (162,980 )
Net changes in future development costs
    (43,229 )     (9,707 )     (52,936 )
Sales of oil and gas produced, net
    (41,047 )     (16,974 )     (58,021 )
Net change due to extensions, discoveries and improved recovery techniques
    28,418       10,265       38,683  
Revisions of previous quantity estimates
    (22,112 )     (9,314 )     (31,426 )
Previously estimated development costs incurred
    52,108       22,332       74,440  
Net change in income taxes
    52,303       (726 )     51,577  
Accretion of discount
    15,546       6,136       21,682  
Other
    (4,303 )     (3,651 )     (7,954 )
     
     
Balance at end of period
  $ 77,877     $ 50,705     $ 128,582  
 
 


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Selected historical combined financial data
 
The following table sets forth our selected historical combined financial data as of the dates and for the periods shown. Our operations are currently conducted in two separate entities under common control, Approach Resources Inc. and Approach Oil & Gas Inc. Pursuant to a contribution agreement, the operations of Approach Oil & Gas Inc. will be combined under Approach Resources Inc., and we will also acquire the Neo Canyon interest immediately prior to the closing of this offering. The historical financial data for the year ended December 31, 2002 has been derived from our unaudited financial statements, which are not included in this prospectus. The historical financial data for the year ended December 31, 2003 have been derived from our audited financial statements, which are not included in this prospectus. The historical combined financial data for the years ended December 31, 2004, 2005 and 2006 and for the six months ended June 30, 2006 and 2007 have been derived from the combined financial statements of Approach Resources Inc. and Approach Oil & Gas Inc. included in this prospectus. The following information should be read in conjunction with “Capitalization,” “Management’s discussion and analysis of financial condition and results of operations” and the historical combined and combined pro forma financial statements included in this prospectus.


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    September 13,
                            Six months
 
    2002 to
    Year ended December 31,     ended June 30,  
    December 31,
          2004
    2005
    2006
    2006
    2007
 
    2002
    2003
    combined
    combined
    combined
    combined
    combined
 
(in thousands, except per share data)   historical     historical     historical     historical     historical     historical     historical  
 
    (unaudited)                             (unaudited)     (unaudited)  
 
Operating results data
                                                       
Revenues:
                                                       
Oil and gas sales
  $     $     $ 5,682     $ 43,263     $ 46,672     $ 26,390     $ 19,082  
Expenses:
                                                       
Lease operating expense
                179       2,910       3,889       1,992       2,023  
Severance and production taxes
                407       1,975       1,736       841       748  
Exploration
          442       2,396       733       1,640       993       633  
Impairment of non-producing properties
                            558              
General and administrative
    406       1,535       1,943       2,659       2,416       1,234       2,730  
Accretion of discount on asset retirement obligations
                1       5       10              
Depletion, depreciation and amortization
    2       9       1,223       8,006       14,541       6,973       6,108  
     
     
Total expenses
    408       1,986       6,149       16,288       24,790       12,033       12,242  
     
     
Operating income (loss)
    (408 )     (1,986 )     (467 )     26,975       21,882       14,357       6,840  
Other:
                                                       
Interest income (expense), net
    (1 )     59       201       (802 )     (3,814 )     (1,709 )     (1,954 )
Realized gain (loss) on commodity derivatives
                      (2,924 )     6,222       3,085       2,244  
Change in fair value of commodity derivatives
                      (4,163 )     8,668       5,447       (2,902 )
     
     
Income (loss) before provision for income taxes
    (409 )     (1,927 )     (266 )     19,086       32,958       21,180       4,228  
Provision (benefit) for income taxes
                      7,028       11,756       7,435       1,818  
     
     
Net income (loss)
  $ (409 )   $ (1,927 )   $ (266 )   $ 12,058     $ 21,202     $ 13,745     $ 2,410  
     
     
Earnings (loss) per share(1):
                                                       
Basic
  $     $ (3.44 )   $ (0.14 )   $ 4.03     $ 7.04     $ 4.62     $ 0.81  
     
     
Diluted
  $     $ (3.44 )   $ (0.14 )   $ 4.03     $ 6.84     $ 4.49     $ 0.74  
     
     
Statement of cash flows data
                                                       
Net cash provided (used) by:
                                                       
Operating activities
  $ (258 )   $ (2,391 )   $ 4,527     $ 40,589     $ 34,305     $ 17,345     $ 12,859  
Investing activities
    (3 )     (15 )     (26,859 )     (72,224 )     (59,384 )     (37,598 )     (18,285 )
Financing activities
    282       4,898       22,474       32,199       26,771       17,254       19,007  
Other financial data
                                                       
EBITDA(2)
    (406 )     (1,977 )     756       27,894       51,313       29,862       12,290  
Capital expenditures
    3       15       25,313       73,770       59,384       37,603       17,358  
 
 
 
(1) Does not give effect to our three for one common stock split.
 
 
(2) See “—Reconciliation of non-GAAP financial measures” below for additional information.
 


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    As of December 31,   As of June 30,
              2004
  2005
  2006
  2006
  2007
    2002
    2003
  combined
  combined
  combined
  combined
  combined
(in thousands)   historical     historical   historical   historical   historical   historical   historical
    (unaudited)                     (unaudited)   (unaudited)
 
Balance sheet data
                                           
Cash
  $ 21     $ 2,513   $ 2,656   $ 3,219   $ 4,911   $ 220   $ 18,492
Other current assets
    92       410     6,458     16,305     13,200     15,688     9,882
Property and equipment, net, successful efforts method
          35     24,223     88,803     132,112     118,436     142,754
Other assets
    29           1,565     89     86     126     1,179
     
     
Total assets
  $ 142     $ 2,958   $ 34,902   $ 108,416   $ 150,309   $ 134,470   $ 172,307
     
     
Current liabilities
  $ 499     $ 86   $ 9,827   $ 32,746   $ 15,421   $ 23,531   $ 14,697
Long-term debt
              100     29,425     47,619     44,567     46,769
Other long-term liabilities
              99     6,555     17,697     14,215     18,772
Convertible debt
                              20,000
Stockholders’ equity (deficit)
    (357 )     2,872     24,876     39,690     69,572     52,157     72,069
     
     
Total liabilities and stockholders’ equity
  $ 142     $ 2,958   $ 34,902   $ 108,416   $ 150,309   $ 134,470   $ 172,307
 
 
 
Reconciliation of non-GAAP financial measures
 
The following table shows our reconciliation of our PV-10 to our standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented in accordance with generally accepted accounting principles, or GAAP). PV-10 is our estimate of the present value of future net revenues from estimated proved gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” We believe PV-10 to be an important measure for evaluating the relative significance of our gas and oil properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating gas and oil companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis.

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PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as computed under GAAP.
 
         
 
    As of
 
    December 31,
 
(in thousands)   2006  
 
 
PV-10
  $ 179,865  
Less: Undiscounted income taxes
    (111,431 )
Plus: 10% discount factor
    60,148  
         
Discounted income taxes
    (51,283 )
         
Standardized measure of discounted future net cash flows
  $ 128,582  
 
 
 
The following table reconciles our net income to EBITDA. EBITDA is defined as net income or loss excluding income tax, depreciation, depletion and amortization and interest expense. Although EBITDA is not calculated in accordance with GAAP, management believes that it is a measure commonly reported and used by investors as a financial indicator providing additional information about our profitability, ability to meet our future requirements for debt service, capital expenditures and working capital. EBITDA should not be considered in isolation or as a substitute for net income, operating income, net cash provided by operating activities or any other measure of financial performance presented in accordance with GAAP.
 
While we have disclosed our EBITDA to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, investors should be cautioned that EBITDA as reported by us may not be comparable in all instances to EBITDA as reported by other companies. In addition, EBITDA amounts may not be fully available for management’s discretionary use, due to the requirements to conserve funds for capital expenditures, debt service or other commitments.
 
                                                             
    September 13,
                        Six months
  Pro forma
    2002 to
    Year ended December 31,   ended June 30,       Six months
    December 31,
          2004
    2005
  2006
  2006
  2007
  Year ended
  ended
    2002
    2003
    combined
    combined
  combined
  combined
  combined
  December 31,
  June 30,
(in thousands)   historical     historical     historical     historical   historical   historical   historical   2006   2007
    (unaudited)                         (unaudited)   (unaudited)   (unaudited)   (unaudited)
 
Net income (loss)
  $ (409 )   $ (1,927 )   $ (266 )   $ 12,058   $ 21,202   $ 13,745   $ 2,410   $ 27,542   $ 4,985
Income taxes
                      7,028     11,756     7,435     1,818     15,480     3,184
Depreciation, depletion and amortization
    2       9       1,223       8,006     14,541     6,973     6,108     21,447     8,717
Interest expense (income)
    1       (59 )     (201 )     802     3,814     1,709     1,954     3,814     1,954
     
     
EBITDA
  $ (406 )   $ (1,977 )   $ 756     $ 27,894   $ 51,313   $ 29,862   $ 12,290   $ 68,283   $ 18,840
 
 


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We believe the most closely related GAAP measure of liquidity is cash provided by operating activities. Below is a reconciliation of EBITDA to our cash provided by operating activities included in our Combined Statements of Cash Flows in our financial statements.
 
                                                         
 
    September 13,
                            Six months ended
 
    2002 to
    Year ended December 31,     June 30,  
    December 31,
          2004
    2005
    2006
    2006
    2007
 
    2002
    2003
    combined
    combined
    combined
    combined
    combined
 
(in thousands)   historical     historical     historical     historical     historical     historical     historical  
 
    (unaudited)                             (unaudited)     (unaudited)  
 
EBITDA
  $ (406 )   $ (1,977 )   $ 756     $ 27,894     $ 51,313     $ 29,862     $ 12,290  
Items excluded from EBITDA but included in cash provided by operating activities
                                                       
Interest (expense) income
    (1 )     59       201       (802 )     (3,814 )     (1,709 )     (1,954 )
Income taxes
                      (7,028 )     (11,756 )     (7,435 )     (1,818 )
Change in fair value of commodity derivatives
                      4,163       (8,668 )     (5,447 )     2,902  
Dry hole costs
                      1,187       2,173       993       633  
Deferred income taxes
                      6,448       11,102       7,061       1,060  
Interest earned on loans to stockholders
          (24 )     (124 )     (235 )                  
Amortization of loan origination fees
                1       47       72       40       52  
Accretion of discount on asset retirement obligations
                      5       10              
Non-cash compensation
                            33       33       87  
Changes in operating assets and liabilities:
    149       (449 )     3,693       8,910       (6,160 )     (6,053 )     (393 )
     
     
Net cash provided by operating activities
  $ (258 )   $ (2,391 )   $ 4,527     $ 40,589     $ 34,305     $ 17,345     $ 12,859  
 
 


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Management’s discussion and analysis of financial
condition and results of operations
 
The following discussion is intended to assist in understanding our results of operations and our financial condition. Our combined financial statements and the accompanying notes included elsewhere in this prospectus contain additional information that should be referred to when reviewing this material. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed.
 
Overview
 
We are an independent energy company engaged in the exploration, development, exploitation, production and acquisition of unconventional oil and gas properties onshore in the United States and Western Canada. We are focusing our growth efforts primarily on finding and developing natural gas reserves in known tight gas sands and shale areas and have assembled leasehold interests aggregating approximately 277,100 gross (189,400 net) acres. We expect to leverage our management team’s proven track record of finding and exploiting unconventional reservoirs through application of advanced completion, fracturing and drilling techniques. As the operator of substantially all of our proved reserves, we have a high degree of control over capital expenditures and other operating matters.
 
We currently operate in five areas: West Texas (Wolfcamp, Canyon Sands and Ellenburger), East Texas (Cotton Valley Sands, Bossier and Cotton Valley Lime), Northern New Mexico (Mancos Shale), Western Kentucky (New Albany Shale) and Western Canada (Triassic Shale and tight gas sands). As of December 31, 2006, all of our proved reserves and production were located in our West Texas operating area and substantially all of those reserves and production were located in the Ozona Northeast field.
 
Our financial results depend upon many factors, particularly the price of oil and gas. Commodity prices are affected by changes in market demand, which is impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, gas price differentials and other factors. As a result, we cannot accurately predict future oil and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success. Future finding and development costs are subject to changes in the industry, including the costs of acquiring, drilling and completing our projects.
 
Higher oil and gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services and have caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher drilling and operating costs. Given the inherent volatility of gas prices, which are influenced by many factors beyond our control, we plan our activities and budget based on conservative sales price assumptions, which generally are lower than the average sales prices received. We focus our efforts on increasing gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flow from operations will depend on our ability to manage our overall cost structure.


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Like all oil and gas production companies, we face the challenge of natural production declines. Oil and gas production from a given well naturally decreases over time. Additionally, our reserves have a rapid initial decline. We attempt to overcome this natural decline by drilling to develop and identify additional reserves and by acquisitions. Our future growth will depend upon our ability to continue to add oil and gas reserves in excess of production at a reasonable cost. We will maintain our focus on the costs of adding reserves through drilling and acquisitions as well as the costs necessary to produce such reserves.
 
We also face the challenge of financing future acquisitions. We plan to use the proceeds of this offering to repay approximately $48.0 million of outstanding borrowings under our revolving credit facility plus accrued interest. At that point, we believe we will have adequate unused borrowing capacity under our revolving credit facility for possible acquisitions, temporary working capital needs and any expansion of our drilling program. Funding for future acquisitions also may require additional sources of financing, which may not be available.
 
Our operations are currently conducted in two separate entities under common control, Approach Resources Inc. and Approach Oil & Gas Inc. Pursuant to a contribution agreement, the operations of these two entities will be combined under Approach Resources Inc., and we will also acquire the Neo Canyon interest immediately before the closing of this offering.
 
Critical accounting policies and estimates
 
The discussion and analysis of our financial condition and results of operations are based upon our combined financial statements, which have been prepared in accordance with accounting policies generally accepted in the United States. The preparation of our combined financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some 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. Actual results may differ from the estimates and assumptions used in the preparation of our combined financial statements. Described below are the most significant policies we apply in preparing our combined financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See notes to the financial statements under the heading “Summary of significant accounting policies” for additional accounting policies and estimates by management.
 
Oil and gas activities
 
Accounting for oil and gas activities is subject to special, unique rules. We use the successful efforts method for accounting for our oil and gas activities. The significant principles for this method are:
 
•  geological and geophysical evaluation costs are expensed as incurred;
 
•  dry holes for exploratory wells are expensed, and dry holes for developmental wells are capitalized; and
 
•  impairments of properties, if any, are based on the evaluation of the carrying value of properties against their fair value based upon pools of properties grouped by geographical and geological conformity.


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Our engineering estimates of proved oil and gas reserves directly impact financial accounting estimates including depletion, depreciation and amortization expense, evaluation of impairment of properties and the calculation of plugging and abandonment liabilities. Proved oil and gas reserves are the estimated quantities of oil and gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under period-end economic and operating conditions. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for any reservoir may change substantially over time as a result of changing results from operational activity and results. Changes in commodity prices, operation costs and techniques may also affect the overall evaluation of reservoirs. A hypothetical 10% decline in our December 31, 2006 proved reserves volumes would have resulted in approximately $1.4 million of additional depletion expense for the year ended December 31, 2006. The average market price received for our natural gas production on December 31, 2006, after basis and Btu adjustments, was $6.55 per Mcf. The average market price received for our natural gas production on August 31, 2007, after basis and Btu adjustments, was $6.05 per Mcf.
 
Our estimated proved reserves as of December 31, 2006 were prepared by DeGolyer and MacNaughton.
 
Derivative instruments and commodity derivative activities
 
All derivative instruments are recorded on the balance sheet at fair value. We determine the fair value of our derivatives by estimating the present value of future net cash flows expected from those contracts. We compute the estimate by multiplying the notional quantities specified in our contracts by the difference between exchange-quoted forward prices and the strike price specified in our contracts. We then compute the present value of those cash flows using our credit-adjusted risk-free rate. Changes in the derivative’s fair value are currently recognized in the statement of operations unless specific commodity derivative accounting criteria are met. For qualifying cash-flow commodity derivatives, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the commodity derivative is effective. The ineffective portion of the commodity derivative is recognized immediately in the statement of operations. Gains and losses on commodity derivative instruments included in cumulative other comprehensive income (loss) are reclassified to oil and gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for commodity derivative accounting treatment are recorded as derivative assets and liabilities at fair value in the balance sheet, and the associated unrealized gains and losses are recorded as current income or expense in the statement of operations.
 
Historically, we have not designated our derivative instruments as cash-flow hedges. We record our open derivative instruments at fair value on our combined balance sheets as either unrealized gains or losses on commodity derivatives. We record changes in such fair value in earnings on our combined statements of operations under the caption entitled “change in fair value of commodity derivatives.”
 
Although we have not designated our derivative instruments as cash-flow hedges, we use those instruments to reduce our exposure to fluctuations in commodity prices related to our oil and gas production. Accordingly, we record realized gains and losses under those instruments in other revenues on our combined statements of operations. For the years ended December 31, 2005 and 2006, we recognized an unrealized loss of $4,163,098 and an unrealized gain of


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$8,668,094 from changes in the fair values of commodity derivatives, respectively. A 10% increase in the NYMEX floating prices would have resulted in a $2.0 million decrease in the December 31, 2006 fair value recorded on our balance sheet, and a corresponding increase to loss on commodity derivatives in our statement of operations.
 
Recent accounting pronouncements
 
On December 16, 2004, the Financial Accounting Standards Board, or FASB, published Statement of Financial Accounting Standards No. 123 (Revised 2004), Share Based Payment, or SFAS 123(R). SFAS 123(R) requires compensation cost related to share based payment transactions to be recognized in the financial statements. Share based payment transactions within the scope of SFAS 123(R) include stock options, restricted stock plans, performance based awards, stock appreciation rights and employee share purchase plans. The provisions of SFAS 123(R) were effective for us as of the first annual reporting period beginning after December 15, 2005. Accordingly, we implemented the revised standard on January 1, 2006.
 
In March 2005, FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, or FIN 47. FIN 47 clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement No. 143, Accounting for Asset Retirement Obligations. A conditional asset retirement obligation is defined as an asset retirement activity in which the timing and/or method of settlement are dependent on future events that may be outside our control. FIN 47 states that we must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This interpretation is intended to provide more information about long-lived assets, future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. We do not believe that our financial position, results of operations or cash flows will be impacted by FIN 47.
 
In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109, or FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. We adopted FIN 48 on January 1, 2007 and it did not have a material impact on our financial statements.
 
In September 2006, the FASB issued FAS No. 157, Fair Value Measurements, or FAS 157. FAS 157 defines fair value to measure assets and liabilities, establishes a framework for measuring fair value and requires additional disclosures about the use of fair value. FAS 157 is applicable whenever another accounting pronouncement requires or permits assets and liabilities to be measured at fair value. FAS 157 does not expand or require any new fair value measures. FAS 157 is effective for our fiscal year beginning January 1, 2008. We are currently evaluating the impact that the adoption of FAS 157 will have on our financial position or results of operations.
 
Effects of 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, 2004, 2005 or 2006. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the cost of labor or supplies. To the extent permitted by


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competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher prices.
 
Stock based and other compensation
 
Our 2007 Stock Incentive Plan, referred to as our 2007 Plan, allows grants of stock and options to management and key employees. Granting of awards may increase our general and administrative expenses subject to the size and timing of the grants. See “Management—Executive compensation—Discussion of summary compensation and plan-based awards tables—Description of the 2007 Plan.”
 
Public company expenses
 
We believe that our general and administrative expenses will increase in connection with the completion of this offering as a result of us operating as a public company. This increase will consist of legal and accounting fees and additional expenses associated with compliance with the Sarbanes Oxley Act of 2002 and other regulations. We anticipate that our ongoing general and administrative expenses also will increase as a result of being a publicly traded company. This increase will be due primarily to the cost of accounting support services, filing annual and quarterly reports with the SEC, investor relations, directors’ fees, directors’ and officers’ insurance and registrar and transfer agent fees. As a result, we believe that our general and administrative expenses for future periods will increase significantly. Our consolidated financial statements following the completion of this offering will reflect the impact of these increased expenses and affect the comparability of our financial statements with periods before the completion of this offering.


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Results of operations
 
Six months ended June 30, 2006 and 2007
 
             
    Six months ended
    June 30,
    2006   2007
 
Revenues (in thousands):
           
Gas
  $ 23,677   $ 16,916
Oil
    2,713     2,166
     
     
Total oil and gas sales
    26,390     19,082
Realized gain on commodity derivatives
    3,085     2,244
     
     
Total oil and gas sales including derivative impact
    29,475     21,326
Production:
           
Gas (MMcf)
    3,366     2,376
Oil (MBbl)
    42     39
     
     
Total (MMcfe)
    3,619     2,608
Average prices:
           
Gas, per Mcf
  $ 7.03   $ 7.12
Oil, per Bbl
    64.15     55.93
     
     
Total, per Mcfe
    7.29     7.32
Realized gain on commodity derivatives, per Mcfe
    0.85     0.86
     
     
Total per Mcfe including derivative impact
    8.14     8.18
Costs and expenses (per Mcfe):
           
Lease operating expenses
  $ 0.55   $ 0.78
Severance and production taxes
    0.23     0.29
Depreciation, depletion and amortization
    1.93     2.34
Exploration
    0.27     0.24
General and administrative
    0.34     1.05
 
 
 
Oil and gas sales. Oil and gas sales decreased $7.3 million, or 27.7%, for the six months ended June 30, 2007 to $19.1 million from $26.4 million for the six months ended June 30, 2006. The decrease in gas sales principally resulted from the natural decline in production of our tight gas sands in the Ozona Northeast field. Further, we had four rigs drilling in the second half of 2005 and the first half of 2006, which dramatically increased production in the first six months of 2006 from new wells placed in production compared to the use of only one rig in the latter part of 2006 and early 2007. The average price per Mcfe we received for our production remained relatively unchanged as reflected in the table above. Gas sales represented 88.7% of the total oil and gas sales for the six months ended June 30, 2007 compared to 89.8% for the six months ended June 30, 2006.
 
Commodity derivative activities. Realized gains from our commodity derivative activity increased our earnings $2.2 million for the six months ended June 30, 2007. In comparison, our commodity


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derivative activity increased our earnings $3.1 million for the six months ended June 30, 2006. The increase resulted from the relative movement of the NYMEX gas prices in relation to the fixed notional pricing for the respective time periods.
 
Lease operating expense. Our lease operating expenses increased $31,000, or 1.5%, for the six months ended June 30, 2007 to $2.0 million ($0.78 per Mcfe) from 2.0 million ($0.58 per Mcfe) for the six months ended June 30, 2006. The primary factor in the slight increase in lease operating expense was an increase of approximately $200,000 in our estimated ad valorem taxes in the 2007 period, which partially was offset by the release later in 2006 of one of our seven rented compressors and an amine unit.
 
Severance and production taxes. Our production taxes decreased $93,000, or 11.0%, for the six months ended June 30, 2007 to $748,000 from $841,000 for the six months ended June 30, 2006. The decrease in production taxes was a function of the reduced oil and gas sales in 2007, offset partly by the timing of severance tax refunds in the 2006 period.
 
Exploration. Our dry hole costs associated with exploratory drilling decreased $360,000 to $633,000 for the six months ended June 30, 2007 from $993,000 for the six months ended June 30, 2006. The 2007 dry hole costs resulted from a mechanical failure in the drilling of a test well in our Boomerang prospect. Exploration expense in 2006 resulted primarily from two dry holes drilled on our Pecos County project, which was abandoned in the fourth quarter of 2006.
 
General and administrative. Our general and administrative expenses increased $1.5 million or 121.2%, to $2.7 million for the six months ended June 30, 2007 from $1.2 million for the six months ended June 30, 2006. The increase in general and administrative expense was principally due to bonus payments made in the first six months of 2007 to cover tax liabilities incurred by management in connection with the repayment of management notes in January 2007. See “Certain relationships and related party transactions—Other related party transactions.” Additionally, the 2007 period includes a severance obligation of $350,000 related to a former employee.
 
Depreciation, depletion and amortization (DD&A). Our DD&A expense decreased $865,000, or 12.4%, to $6.1 million for the six months ended June 30, 2007 from $7.0 million for the six months ended June 30, 2006. Our DD&A expense per Mcfe produced increased by $0.41, or 21.2%, to $2.34 per Mcfe for the six months ended June 30, 2007, as compared to $1.93 per Mcfe for the six months ended June 30, 2006. This increase was primarily attributable to our drilling of mostly proved undeveloped locations in the 2007 period, which were previously recorded in our prior year’s reserves, which had the effect of increasing production but did not increase reserves to the same degree.
 
Interest income (expense), net. Our interest expense increased $246,000, or 14.4%, to $2.0 million for the six months ended June 30, 2007 from $1.7 million for the six months ended June 30, 2006. This increase was a function of increased borrowings in 2006 to fund our development of the Ozona Northeast field and higher interest rates.
 
Income taxes. Our provision for income taxes decreased $5.6 million, or 75.6%, to $1.8 million for the six months ended June 30, 2007, from a provision of $7.4 million for the six months ended June 30, 2006. The decrease in income tax expense is consistent with the decrease in our income before income taxes. Our effective income tax rate for the six months ended June 30, 2006 amounted to 35.1% compared with 43.0% for the six months ended June 30, 2007. The increase in the effective rate results primarily from changes in the valuation allowance provided


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against net operating loss carryovers for Approach Oil & Gas Inc. We do not recognize a tax benefit for the net operating loss carryovers of Approach Oil & Gas Inc. based on our assessment of the likelihood of Approach Oil & Gas Inc. being able to utilize those carryovers to reduce future taxable income. Subsequent to the combination of Approach Oil & Gas Inc. and Approach Resources Inc., we believe that the net operating loss carryovers of Approach Oil & Gas Inc. will be available to offset our future taxable income, subject to certain limits.
 
Years ended December 31, 2005 and 2006
 
               
    Year ended
    December 31,
    2005     2006
 
Revenues (in thousands):
             
Gas
  $ 40,085     $ 41,851
Oil
    3,179       4,821
     
     
Total oil and gas sales
    43,264       46,672
Realized gain (loss) on commodity derivatives
    (2,924 )     6,222
     
     
Total oil and gas sales including derivative impact
    40,340       52,894
Production:
             
Gas (MMcf)
    4,668       6,282
Oil (MBbl)
    57       77
     
     
Total (MMcfe)
    5,012       6,744
Average prices:
             
Gas, per Mcf
  $ 8.59     $ 6.66
Oil, per Bbl
    55.54       62.65
     
     
Total, per Mcfe
    8.63       6.92
Realized gain (loss) on commodity derivatives, per Mcfe
    (0.58 )     0.92
     
     
Total per Mcfe including derivative impact
    8.05       7.84
Costs and expenses (per Mcfe):
             
Lease operating expenses
  $ 0.58     $ 0.58
Severance and production taxes
    0.39       0.26
Depreciation, depletion and amortization
    1.60       2.16
Exploration
    0.15       0.24
Impairment of non-producing properties
          0.08
General and administrative
    0.53       0.36
 
 
 
Oil and gas sales. Oil and gas sales increased $3.4 million, or 7.9%, for the year ended December 31, 2006 to $46.7 million from $43.3 million for the year ended December 31, 2005. The increase in sales principally resulted from a 34.6% increase in production, as we drilled and completed 81 gross (53.5 net) wells in 2006. The effects of increased production were offset by a decrease in price. The average price before the effect of commodity derivatives decreased $1.71 per Mcfe, or 19.8%, from $8.63 per Mcfe in 2005 to $6.92 per Mcfe in 2006 as the 2005 period


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included the effects of the spike in gas prices after Hurricane Katrina and Hurricane Rita. Gas sales represented 89.7% of the total oil and gas sales in 2006 compared to 92.7% in 2005.
 
Commodity derivative activities. Realized gains from our commodity derivative activity increased our earnings $6.2 million for the year ended December 31, 2006. In comparison, realized losses from our commodity derivative activity decreased our earnings $2.9 million for the year ended December 31, 2005. During the years ended December 31, 2005 and 2006, we used gas swaps to mitigate commodity price risk. During 2005, commodity prices tended to be higher than the notional prices specified in our swap agreements, which resulted in a loss to us. In contrast, during 2006, commodity prices tended to be lower than the prices specified in our swap agreements, which resulted in a gain to us.
 
Lease operating expense. Our lease operating expenses increased $1.0 million, or 33.7%, for the year ended December 31, 2006 to $3.9 million from $2.9 million for the year ended December 31, 2005. This increase primarily was the result of a $765,000 increase in ad valorem taxes and from increased pumper costs of $200,000 from the continued development of the Ozona Northeast properties.
 
Severance and production taxes. Our production taxes decreased $239,000, or 12.1%, for the year ended December 31, 2006 to $1.7 million from $2.0 million for the year ended December 31, 2005. The decrease in production taxes is a function of increased oil and gas revenues that were more than offset by refunds received applicable to prior years. Our natural gas production from the Ozona Northeast field is afforded a severance tax rate lower than the normal rate (7.5%). However, we are required to file abatement requests with the State of Texas to receive the lower rate. Until the abatement requests are approved, we are required to pay the normal rate. During 2005, we were still awaiting approvals for abatements on several of our Ozona Northeast wells. We received such approvals during 2006, which resulted in the refunds mentioned above.
 
Exploration and impairment of non-producing properties. Our exploration costs increased $907,000 to $1.6 million for the year ended December 31, 2006 from $734,000 for the year ended December 31, 2005. The 2006 period included dry hole costs of $1.3 million related to two wells drilled on a prospect in Pecos County, Texas, $195,000 from one well in Ozona Northeast and $165,000 from a well in our Boomerang prospect. The 2005 period included dry hole costs of $902,000 from Pecos County and $285,000 from the same well mentioned above in Ozona Northeast. Additionally, the 2005 period included the recoupment of $564,000 of geological evaluation costs from a participant in the Pecos County project. The balance of the 2005 expense is geological and geophysical costs mostly attributable to Ozona Northeast.
 
Our impairment of non-producing properties of $558,000 in 2006 arose from the abandonment of our leasehold position in Pecos County. As a result of the abandonment, we no longer anticipate incurring any costs related to this area.
 
General and administrative. Our general and administrative expenses decreased $243,000, or 9.1%, to $2.4 million for the year ended December 31, 2006 from $2.7 million for the year ended December 31, 2005. The decrease in general and administrative expense was principally due to the accrual in 2005 of bonuses totaling approximately $800,000 that did not recur in 2006, offset by increases in 2006 for professional fees, the number of employees and increases in their compensation and benefits. Additionally, operating overhead recoveries in 2006 were $514,000 as compared to $408,000 in 2005.


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Depreciation, depletion and amortization (DD&A). Our DD&A expense increased $6.5 million, or 81.6%, to $14.5 million for the year ended December 31, 2006 from $8.0 million for the year ended December 31, 2005. Our DD&A expense per Mcfe produced increased by $0.56, or 35.0%, to $2.16 per Mcfe for the year ended December 31, 2006, as compared to $1.60 per Mcfe for the year ended December 31, 2005. This increase was primarily attributable to increased production and increased oil and gas property costs in 2006.
 
Interest income (expense), net. Our interest expense increased $3.0 million, or 375%, to $3.8 million for the year ended December 31, 2006 from $802,000 for the year ended December 31, 2005. This significant increase was a function of increased borrowings under our revolving credit facility and an increase in interest rates during 2006. Interest rates attributable to amounts outstanding under our revolving credit facility amounted to 6.75% at December 31, 2005, compared with 7.75% at December 31, 2006.
 
Income taxes. Income taxes increased $4.8 million, or 67.3%, to $11.8 million for the year ended December 31, 2006 from $7.0 million for the year ended December 31, 2005. Income taxes increased consistent with our income before tax, offset by a decrease in our effective tax rates, which amounted to 36.8% and 35.7% for the years ended December 31, 2005 and 2006, respectively. Our effective tax rate decreased due primarily to a change in the tax law in the State of Texas which changed the tax from 4.5% of net income to 1% of our “margin,” as defined in the new law. Based on this change in the Texas tax law, we reduced our deferred tax liability by approximately $1.1 million for the year ended December 31, 2006.


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Years ended December 31, 2004 and 2005
 
               
 
    Year ended
 
    December 31,  
    2004   2005  
 
 
Revenues (in thousands):
             
Gas
  $ 5,302   $ 40,085  
Oil
    380     3,179  
     
     
Total oil and gas sales
    5,682     43,264  
Realized loss on commodity derivatives
        (2,924 )
     
     
Total oil and gas sales including derivative impact
    5,682     40,340  
Production:
             
Gas (MMcf)
    858     4,668  
Oil (MBbl)
    8     57  
     
     
Total (MMcfe)
    908     5,012  
Average prices:
             
Gas, per Mcf
  $ 6.18   $ 8.59  
Oil, per Bbl
    45.56     55.54  
     
     
Total, per Mcfe
    6.26     8.63  
Realized loss on commodity derivatives, per Mcfe
        (0.58 )
     
     
Total per Mcfe including derivative impact
    6.26     8.05  
Costs and expenses (per Mcfe):
             
Lease operating expenses
  $ 0.20   $ 0.58  
Severance and production taxes
    0.45     0.39  
Depreciation, depletion and amortization
    1.35     1.60  
Exploration
    2.64     0.15  
General and administrative
    2.14     0.53  
 
 
 
Oil and gas sales. Oil and gas sales increased $37.6 million to $43.3 million for the year ended December 31, 2005 from $5.7 million for the year ended December 31, 2004. This increase in oil and gas sales principally resulted from the substantial increase in gas prices in the aftermath of Hurricane Katrina and Hurricane Rita in the third quarter of 2005 and our increased drilling activities in 2005. We drilled 120 and completed 115 successful wells during the year ended December 31, 2005 in the Ozona Northeast field in West Texas. In addition, our first few wells in the Ozona Northeast field were not completed and producing until May 2004 and, therefore, the full year of production from these wells in 2005 further contributed to the increase in gas and oil production from 2004 to 2005.
 
Commodity derivative activities. We had no commodity derivatives in place prior to 2005. Realized losses from our commodity derivative activity decreased our earnings $2.9 million for the year ended December 31, 2005. During the year ended December 31, 2005, we used gas


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swaps to mitigate commodity price risk. During 2005, commodity prices tended to be higher than the notional prices specified in our swap agreements, which resulted in a loss to us.
 
Lease operating expense. Lease operating expense increased $2.7 million to $2.9 million for the year ended December 31, 2005 from $179,000 for the year ended December 31, 2004. This increase was primarily attributable to our increased compression facility costs to handle the increase in gas produced.
 
Severance and production taxes. Our production taxes increased $1.6 million to $2.0 million for the year ended December 31, 2005 from $406,000 for the year ended December 31, 2004. This increase was a function of increased production and increased pricing.
 
Exploration. Our exploration costs decreased $1.7 million to $734,000 for the year ended December 31, 2005 from $2.4 million for the year ended December 31, 2004. The 2005 period included dry hole costs of $902,000 related to two wells drilled on a prospect in Pecos County, Texas and $285,000 from a well in Ozona Northeast. Additionally, the 2005 period included the recoupment of $564,000 of geological evaluation costs from a participant in the Pecos County project. The balance of the 2005 expense is geological and geophysical costs mostly attributable to Ozona Northeast. The 2004 period included geological and geophysical costs of $1.5 million from the Pecos County, Texas area and $873,000 from Ozona Northeast. The Pecos County project was abandoned at the end of 2006.
 
General and administrative. Our general and administrative expenses increased $715,000, or 36.8%, to $2.7 million for the year ended December 31, 2005 from $1.9 million for the year ended December 31, 2004. This increase was largely due to the accrual of $800,000 for bonuses in 2005. Additionally, operating overhead recoveries in 2005 were $408,000, as compared to $278,000 in 2004.
 
Depreciation, depletion and amortization (DD&A). Our DD&A expense increased $6.8 million to $8.0 million for the year ended December 31, 2005 from $1.2 million for the year ended December 31, 2004. Our DD&A expense per Mcfe produced increased by $0.25, or 18.5%, to $1.60 per Mcfe for the year ended December 31, 2005, as compared to $1.35 per Mcfe for the year ended December 31, 2004. This increase was primarily attributable to increased production and oil and gas property costs in 2005.
 
Interest expense. Our interest expense, net of interest income, increased $1.0 million to $802,000 for the year ended December 31, 2005 from interest income of $201,000 for the year ended December 31, 2004. This increase was primarily attributable to the increase in the average amount borrowed under our revolving credit facility as a result of increased costs from our drilling program.
 
Income taxes. Our income tax expense increased for the year ended December 31, 2005 compared to 2004 as net income increased from 2004 to 2005. We recorded an accrual of $580,000 as an estimate of the current taxes due for 2005. Additionally, we recorded a deferred tax provision of $6.4 million in 2005 largely due to the difference in depletion, depreciation and capitalization methods for oil and gas properties. No taxes were accrued for 2004 as we utilized net operating loss carryforwards to offset any potential liability.
 
Liquidity and capital resources
 
For the six months ended June 30, 2007, the majority of our cash was generated from operating and financing activities. We used $19.2 million of net proceeds from bank and convertible debt


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borrowings and cash flow from operations of $12.9 million to fund $17.4 million of capital expenditures related to our drilling program activities and our $917,000 investment in a Canadian-based private exploration company. During the same six months in 2006, we used $17.3 million of cash flow from operations and $18.6 million of proceeds from borrowings under a note with one of our stockholders and our revolving credit facility and available cash to fund $37.6 million for our drilling program and $1.3 million to repurchase shares and options.
 
Our primary sources of cash in 2006 were from financing and operating activities. Approximately $18.2 million from borrowings under our revolving credit facility, $6.5 million from the issuance of common stock, $3.5 million from a loan from one of our stockholders and cash from operations were used to fund our drilling program and the acquisition of another working interest in the Ozona Northeast field.
 
For the year ended December 31, 2005, cash flow from operations of $40.6 million, borrowings under our revolving credit facility of $29.3 million and $3.0 million from the issuance of common stock provided the funds to drill additional wells in the Ozona Northeast field.
 
For the year ended December 31, 2004, operating cash flow of $4.5 million combined with $22.4 million from the issuance of common stock funded our initial drilling activities in the Ozona Northeast field.
 
Our cash flow from operations is driven by commodity prices and production volumes. Prices for oil and gas are driven by seasonal influences of weather, national and international economic and political environments and, increasingly, from heightened demand for hydrocarbons from emerging nations, particularly China and India. Our working capital is significantly influenced by changes in commodity prices and significant declines in prices could decrease our exploration and development expenditures. Cash flows from operations were primarily used to fund exploration and development of our mineral interests. Our cash flows from operations increased dramatically between 2004 and 2005 as we developed the Ozona Northeast field. In comparing 2005 and 2006, our cash flows from operations declined slightly due to a $6.2 million decrease in working capital components partially offset by the increase in oil and gas sales in 2006.
 
The following table summarizes our sources and uses of funds for the periods noted:
 
                                         
 
          Six months ended
 
    Year ended December 31,     June 30,  
(in thousands)   2004     2005     2006     2006     2007  
 
 
Cash flows provided by operating activities
  $ 4,527     $ 40,589     $ 34,305     $ 17,345     $ 12,859  
Cash flows used in investing activities
    (26,859 )     (72,224 )     (59,384 )     (37,598 )     (18,285 )
Cash flows provided by financing activities
    22,474       32,199       26,771       17,254       19,007  
     
     
Net increase (decrease) in cash and cash equivalents
  $ 142     $ 564     $ 1,692     $ (2,999 )   $ 13,581  
 
 


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Operating activities
 
For the six months ended June 30, 2007, our cash flow from operations was used for drilling activities. The $12.9 million in cash flow generated in the first six months of 2007 decreased $4.5 million from the first six months of 2006 due mostly to lower oil and gas sales and higher general and administrative expenses in the 2007 period.
 
Net cash provided by operating activities increased from $4.5 million in 2004 to $40.6 million in 2005 and to $34.3 million in 2006. The increase in 2005 resulted from increased sales volumes from our successful drilling activities and increased commodity prices. In comparing 2005 and 2006, our cash flows from operations declined $6.3 million in part due to a decrease in working capital components partially offset by the increase in oil and gas sales and net income in 2006 from our continued development of the Ozona Northeast field in West Texas.
 
Investing activities
 
Of the cash flows used in investing activities in the first six months of 2007, $12.7 million was for the continued development of the Ozona Northeast field, $1.0 million for the drilling of the test wells in our Boomerang prospect, $2.7 million for the acquisition of the El Vado East leasehold, $873,000 for wells in our Cinco Terry project and $917,000 for our investment in a Canadian-based private exploration company. For the comparable period of 2006, $32.1 million was for the drilling of Ozona Northeast wells, $3.4 million was for the acquisition of the Boomerang leasehold and $2.1 million was used for acreage cost and the drilling of Cinco Terry wells.
 
The majority of our cash flows used in investing activities for 2004 through 2006 have been used for the continued development of the Ozona Northeast field. In 2006, an additional $4.1 million was used for undeveloped leaseholds in our Cinco Terry and Boomerang fields, and $3.6 million was invested in the initial wells in our Cinco Terry project.
 
We have established an exploratory and development budget of $48.3 million and $63.5 million for 2007 and 2008, respectively, after the completion of the acquisition of the Neo Canyon interest. Our budgets are established based on expected volumes to be produced and commodity prices.
 
Financing activities
 
We borrowed $19.2 million net under convertible notes and our revolving credit facility in the first six months of 2007 as compared to $18.6 million net in the first six months of 2006. In addition, $1.3 million was spent in the first six months of 2006 to purchase common stock and related options from a former employee.
 
During 2006, we sold approximately $6.5 million of common stock. These proceeds were primarily used to fund the acquisition of our Boomerang prospect and drilling costs for our Cinco Terry project.
 
In February 2007, we entered into an amended and restated $100 million revolving credit facility with The Frost National Bank. In June 2007, we amended our credit facility agreement to extend the due date of any balance outstanding at maturity to July 2010. As of June 30, 2007, we had an outstanding balance under the credit facility of approximately $46.8 million, with a borrowing base of $75 million. The borrowing base is subject to adjustment twice each year. The assessment by the bank petroleum engineers is based on their evaluation of the future cash flows from proved oil and gas reserves using the bank’s pricing parameters.


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Our goal is to actively manage our borrowings to help us maintain the flexibility to expand and invest, and to avoid the problems associated with highly leveraged companies of large interest costs and possible debt reductions restricting ongoing operations.
 
We believe that cash flow from operations and borrowings under our revolving credit facility will finance substantially all of our anticipated drilling, exploration and capital needs. We will also use our revolving credit facility for possible acquisitions, temporary working capital needs through 2008 and any expansion of our drilling program.
 
Future capital expenditures for 2007 and 2008
 
The following table summarizes information regarding our historical 2006 and estimated 2007 and 2008 capital expenditures. The 2007 and 2008 estimates include the interest of Neo Canyon after completion of the acquisition of the 30% working interest in the Ozona Northeast field that we do not already own. We will be required to meet our needs from our internally generated cash flow, debt financings and equity financings. The estimated capital expenditures are subject to change depending upon a number of factors, including the results of our development and exploration efforts, the availability of sufficient capital resources to us and other participants for drilling prospects, economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and gas and the availability of drilling rigs and crews, our financial results and the availability of leases on reasonable terms and our ability to obtain permits for the drilling locations.
 
                   
    Historical
  Estimated(2)
    year ended
  Year ending
    December 31,
  December 31,
(in thousands)   2006(1)   2007   2008
 
Capital expenditures:
                 
Ozona Northeast
  $ 52,303   $ 23,400   $ 29,500
Cinco Terry
    3,176     6,600     10,100
East Texas
        7,300     14,000
Northern New Mexico
            3,600
Western Kentucky
        1,800     2,600
Western Canada
        1,200     2,900
Lease acquisition, geological, geophysical and other
    3,873     8,000     800
     
     
Total capital expenditures
  $ 59,352   $ 48,300   $ 63,500
 
 
 
(1)  Historical amounts here include actual amounts incurred to the interest of Approach Resources Inc. and Approach Oil & Gas Inc.
 
(2)  Estimated capital expenditures for 2007 and 2008 give effect to the acquisition of the Neo Canyon interest in combination with the interest of Approach Resources Inc. and Approach Oil & Gas Inc. as if the Neo Canyon interest were acquired on October 1, 2007.


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Credit facility
 
In February 2007, we entered into an amended and restated $100 million revolving credit facility with The Frost National Bank. In June 2007, we amended our credit facility agreement to extend the due date of any balance outstanding at maturity to July 2010. In July 2007, we amended the credit facility agreement to allow the bank to issue letters of credit for the account of Approach Oil & Gas Inc.
In September 2007, we amended our credit facility agreement to clarify the annual date for delivery of our year-end reserve report from our independent engineering firm. The availability of funds under our revolving credit facility is subject to a borrowing base which was initially set at, and currently is, $75 million. The borrowing base will be redetermined every six months or, upon the election by us or the bank, one additional time each calendar year.
 
Our revolving credit facility provides for interest on outstanding amounts to accrue at a rate calculated, at our option, at either (i) the base rate, which is the bank’s prime rate, or (ii) the sum of the LIBOR plus a margin which ranges from 1.25% to 2.0% per annum, as applicable, as amounts outstanding under our revolving credit facility increase as a percentage of the borrowing base. In addition, we pay an annual commitment fee of 0.375% of non-utilized borrowings available under our revolving credit facility.
 
We are subject to a financial covenant requiring maintenance of a minimum modified ratio of current assets to current liabilities. In addition, we are subject to covenants restricting cash dividends and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, assets sales, investments in other entities and liens on properties.
 
Loans under our revolving credit facility are secured by first priority liens on substantially all of our West Texas assets including equity interests in our subsidiaries. All outstanding amounts under our revolving credit facility are due and payable in July 2010.
 
We anticipate that the proceeds to us from this offering will be used to pay off outstanding borrowings under our revolving credit facility. As of December 31, 2006 and June 30, 2007, the outstanding balance under our revolving credit facility was $47.6 million and $46.8 million, respectively.
 
Contractual commitments
 
We have a lease for our current office space in Fort Worth, Texas, that expires in May 2009. Our obligation under this lease is approximately $119,000 per year. In April 2007, we signed a five-year lease for approximately 13,000 square feet of space in Fort Worth, Texas. In January 2008, we will begin rent payments of approximately $20,000 per month, including common area expenses. We have signed subleases for approximately two-thirds of our current office space beginning in October 2007.


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The following table summarizes these commitments as of December 31, 2006 (in thousands):
 
                               
        Less than
          More than
Contractual obligations   Total   1 year   1-3 years   3-5 years   5 years
 
Long-term debt obligations—revolving credit facility(1)
  $ 47,619   $   $ 47,619   $   $
Operating lease obligations(2)
    285     117     168        
Asset retirement obligations
    148                 148
Employment agreements with executive officers and other key personnel(3)
    1,463     1,463            
     
     
Total
  $ 49,515   $ 1,580   $ 47,787   $   $ 148
 
 
 
(1) Excludes accrued interest amounts. In June 2007, we extended the due date of any balance outstanding at maturity to July 2010; therefore, our contractual obligation related to our revolving credit facility is now due in 3-5 years.
 
(2) Operating lease obligation is for office space.
 
(3) These agreements contain automatic renewal provisions providing that such agreements may be automatically renewed for successive terms of one year unless employment is terminated at the end of the term by written notice given to the employee not less than 60 days prior to the end of such term. Our maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were all terminated without cause, was approximately $1,463,000 at December 31, 2006. See “Executive compensation—Other benefits—Employment agreements and other arrangements.”
 
Off-balance sheet arrangements
 
From time to time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2006, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit, operating lease agreements and gas transportation commitments. We do not believe that these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.
 
Quantitative and qualitative disclosure about market risk
 
Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices, and other related factors. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for commodity derivative and investment purposes, not for trading purposes.
 
Commodity price risk
 
We enter into financial swaps and collars to hedge future oil and gas production to mitigate portions of the risk of market price fluctuations.
 
To designate a derivative as a cash flow hedge, we document at the commodity derivative’s inception our assessment as to whether the derivative will be highly effective in offsetting expected changes in cash flows from the item hedged. This assessment, which is updated at least


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quarterly, is generally based on the most recent relevant historical correlation between the derivative and the item hedged. The ineffective portion of the commodity derivative, if any, is calculated as the difference between the change in fair value of the derivative and the estimated change in cash flows from the item hedged.
 
If, during a commodity derivative’s term, we determine the commodity derivative is no longer highly effective, commodity derivative accounting is prospectively discontinued and any remaining unrealized gains or losses on the effective portion of the derivative are reclassified to earnings when the underlying transaction occurs. If it is determined that the designated commodity derivative transaction is not likely to occur, any unrealized gains or losses are recognized immediately in the consolidated statements of income as a derivative fair value gain or loss.
 
As of June 30, 2007, we had two gas swaps in place for the remainder of 2007 for an average volume of 230,000 MMBtu per month. One of the swaps provides for us to be paid a notional price averaging $8.72 as compared to the floating NYMEX price for that period. In addition, we have in place a WAHA basis swap of $1.02 per MMBtu for the remainder of 2007. At December 31, 2006 and June 30, 2007, the fair value of our open derivative contracts was an asset of approximately $4.5 million and $1.6 million, respectively.
 
In May 2007, we entered into a gas collar for 2008 based on the NYMEX floating MMBtu price with a $7.50 floor and a $11.45 ceiling. In addition, we entered into a WAHA basis swap for 2008 for $0.69 per MMBtu. Both of these commodity derivatives were for an average volume of approximately 186,000 MMBtu per month.
 
We have reviewed the financial strength of our commodity derivative counterparty and believe our credit risk to be minimal. Our commodity derivative counterparty is a participant in our credit facility and the collateral for the outstanding borrowings under our revolving credit facility is used as collateral for our commodity derivatives.


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Business
 
Overview
 
We are an independent energy company engaged in the exploration, development, exploitation, production and acquisition of unconventional natural gas and oil properties. We were formed as a Delaware corporation in September 2002. We received our initial round of equity financing from Yorktown Energy Partners V, L.P. and members of our management team in January 2003 and began our evaluation of potential lease acquisition, drilling and seismic projects later that year.
 
Our principal operations are located in the Ozona Northeast field in West Texas, where we originally acquired approximately 28,000 gross (27,000 net) acres of leasehold interests in 2004 through a Farmout Agreement with the predecessors of Neo Canyon Exploration, L.P. Since that time, through a series of strategic leasehold acquisitions, we have increased our West Texas acreage to 66,500 gross (51,700 net) acres located in the Ozona Northeast field and our nearby Cinco Terry project. Our management team has extensive experience finding and exploiting unconventional reservoirs, particularly tight gas sands like Ozona Northeast, by applying advanced completion, fracturing and drilling techniques. Substantially all of our growth has been through our own drilling efforts. Since 2004, we have added approximately 149 Bcfe of proved gas and oil reserves from unconventional reservoir formations.
 
Presently, Approach Resources Inc. and Approach Oil & Gas Inc. are operated as two separate yet affiliated entities with the operations of each conducted primarily though their respective operating subsidiaries. Each of Approach Resources Inc. and Approach Oil & Gas Inc. is controlled by funds affiliated with Yorktown Partners LLC. Upon consummation of the transactions described under “Certain relationships and related party transactions—The contribution agreement,” Approach Oil & Gas Inc. and its operating subsidiaries will become operating subsidiaries of Approach Resources Inc.
 
At December 31, 2006, all of our proved reserves and production were located in our West Texas operating area and substantially all of those reserves and production were located in the Ozona Northeast field. As of such date, we owned working interests in 241 gross (226 net) producing wells with an average net production of approximately 22.7 MMcfe/d for the month of December 2006. At December 31, 2006, our estimated total proved gas and oil reserves were approximately 149 Bcfe with a reserve life index of approximately 19 years. Our proved reserves are 94% gas and 51% proved developed. As the operator of substantially all of our proved reserves, we have a high degree of control over capital expenditures and other operating matters.
 
As of July 31, 2007, we had identified a total of 833 drilling locations, of which 644 were located in the Ozona Northeast field, 126 in our Cinco Terry project and 63 in our North Bald Prairie prospect in East Texas. Of the total, 178 locations were classified as proved. The final determination of whether or not to drill any particular well, including those wells currently budgeted, will depend on a number of factors, including the results of our development and exploration efforts, the availability of sufficient capital resources to us and other participants for drilling prospects, economic and industry conditions at the time of drilling, including prevailing and anticipated prices for gas and oil and the availability of drilling rigs and crews, our financial results, the availability of leases on reasonable terms and our success in obtaining permits for potential drilling locations.


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Our growth efforts are focused primarily on finding and developing natural gas reserves in known tight gas sands and shale areas onshore in the United States and Western Canada. Since May 2006, we have acquired leasehold interests covering 13,600 gross (4,900 net) acres in East Texas, 90,300 gross (81,000 net) acres in Northern New Mexico, 74,000 gross (44,000 net) acres in Western Kentucky and 32,700 gross (7,400 net) acres in Western Canada. In total we have assembled leasehold interests of 277,100 gross (189,400 net) acres in our five operating areas—West Texas (Wolfcamp, Canyon Sands and Ellenburger), East Texas (Cotton Valley Sands, Bossier and Cotton Valley Lime), Northern New Mexico (Mancos Shale), Western Kentucky (New Albany Shale) and Western Canada (Triassic Shale and tight gas sands).
 
Status as a controlled company
 
We expect to qualify as a “controlled company” under the NASDAQ Marketplace Rules because more than 50% of our voting power will be held collectively by Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P. and Yorktown Energy Partners VII, L.P., which are under common management by Yorktown Partners, LLC. Under the NASDAQ Marketplace Rules, a “controlled company” may elect not to comply with certain NASDAQ corporate governance requirements, including (1) the requirement that a majority of the board of directors consist of independent directors, (2) the requirement that the nominating and corporate governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities and (3) the requirement that the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities. However, we do not currently intend to rely on the controlled company exception to the NASDAQ corporate governance requirements following this offering. See “Management—Board of directors; committees of the board” for a discussion of our compliance with the corporate governance requirements of the NASDAQ Marketplace Rules.
 
As a result of Yorktown’s ownership of our outstanding securities, Yorktown will have the ability to control the vote in any election of directors. Yorktown also will have control over our decisions to enter into significant corporate transactions and, in its capacity as our majority stockholder, will have the ability to prevent any transactions that it does not believe are in Yorktown’s best interest. As a result, Yorktown will be able to control, directly or indirectly and subject to applicable law, all matters affecting us, including the following:
 
•  any determination with respect to our business direction and policies, including the appointment and removal of officers;
 
•  any determinations with respect to mergers, business combinations or dispositions of assets;
 
•  our capital structure;
 
•  compensation, option programs and other human resources policy decisions;
 
•  changes to other agreements that may adversely affect us; and
 
•  the payment, or nonpayment, of dividends on our common stock.
 
Yorktown and its affiliates are not obligated to advise us of any investment or business opportunities of which they are aware, and they are not restricted or prohibited from competing with us.


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Strategy
 
Our strategy is to increase stockholder value by profitably growing our reserves, production, cash flow and earnings using a balanced program of (1) developing existing properties, (2) exploring and exploiting undeveloped properties, (3) completing strategic acquisitions and (4) maintaining financial flexibility. The following are key elements of our strategy:
 
•  Continue to develop our existing West Texas properties. We intend to develop further the significant remaining potential of our West Texas properties, where we have identified 770 drilling locations.
 
  •  We acquired our initial position in the Ozona Northeast field through a Farmout Agreement with the predecessors of Neo Canyon Exploration, L.P. In January 2004. The agreement covered 28,000 gross (27,400 net) acres. During 2005, we leased an additional 16,600 gross (16,600 net) acres. We began our drilling program late in the first quarter of 2004 and by year-end we had drilled 54 wells with an 85% success rate. In early 2005, in response to increased gas prices, we increased our drilling rig inventory from two rigs to four rigs and sought regulatory approval for 20-acre down spacing. By the end of 2005, we had drilled another 120 wells with a 96% success rate. In December 2005, we obtained regulatory approval for the 20-acre down spacing, which substantially increased our proved undeveloped inventory. During the first half of 2006, we elected not to renew two of our four drilling rig contracts due to increased rig pricing. By year-end 2006, we had drilled 79 additional wells with a 97% success rate. We currently plan to continue to develop the Ozona Northeast field by drilling an additional 45 wells in 2007 and 40 wells in 2008. We estimate that as of July 31, 2007, we had 644 identified drilling locations in the Ozona Northeast field, 175 of which were proved.
 
  •  In January 2007 we implemented several changes to our drilling and completion techniques for our developmental Canyon wells in Ozona Northeast, where we have 644 remaining drilling locations. Primarily, we streamlined our casing design and modified our stimulation process. We estimate that these changes have resulted in current drilling and completion cost savings of approximately $50,000 per well, based on current markets for drilling services and equipment.
 
  •  We believe our Cinco Terry project has significant potential reserves in both the (i) established Canyon and Ellenburger formations and (ii) shallower and less-explored Wolfcamp trend. During the second quarter of 2007, we recompleted one of our existing wells into the Wolfcamp formation. We drilled six wells in Cinco Terry in the third quarter of 2007 (three Canyon, two Ellenburger and one Wolfcamp). We plan to drill six Canyon/Ellenburger/Wolfcamp/wells in the fourth quarter of 2007 and 24 Canyon/Ellenburger/Wolfcamp wells in 2008.
 
•  Pursue unconventional gas and oil opportunities. With our East Texas, Northern New Mexico, Western Kentucky and Western Canada prospects, we have over 210,000 gross acres of unexplored tight gas and shale inventory to explore and produce. We spudded our first wells in East Texas and Western Canada in August 2007. We expect to drill three gross (1.5 net) wells in 2007 and 11 gross (5.5 net) wells in 2008 on our North Bald Prairie prospect. We plan to begin the completion of our three Western Kentucky test wells in the New Albany Shale in the fourth quarter of 2007 or first quarter of 2008. We also plan to identify and begin drilling up to four Mancos Shale wells in El Vado East in the second quarter of 2008. We intend to


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support our unconventional tight gas and shale exploration with cash flow from our long-lived, producing properties in West Texas and borrowings under our revolving credit facility.
 
•  Acquire strategic assets. We continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects. We focus particularly on opportunities where we believe our reservoir management and operational expertise in unconventional gas and oil properties will enhance value and performance. We remain focused on unconventional resource opportunities, but also look at conventional opportunities based on individual project economics. We may enter into commodity derivative agreements in connection with future acquisitions to protect our return on investment. Our management team members have gained significant acquisition experience during their careers with Approach and previous employers.
 
•  Operate our producing properties as a low-cost producer. We strive to minimize our operating costs by concentrating our assets within geographic areas where we can consolidate operating control and thus capture operating efficiencies. We are the operator of substantially all of our producing properties and plan to continue to operate substantially all of our producing properties in the future. Operating control allows us to better manage timing and risk as well as the cost of exploration and development, drilling and ongoing operations. We believe that in the competitive market for drilling rigs it is advantageous to have the flexibility to control the length of rig commitments in order to secure service at the lowest cost.
 
Competitive strengths
 
We believe our historical success is, and future performance will be, directly related to the following combination of strengths which enable us to implement our strategy:
 
•  Experienced executive and technical team with significant employee ownership. The members of our executive and technical team (including our Chief Executive Officer) have an average of over 26 years of experience in the oil and gas industry and significant experience in building and managing independent oil and gas companies. The majority of our executive and technical team have spent their entire careers developing unconventional gas and oil properties. Our technical team includes two geologists and three petroleum engineers with industry expertise in working with shallow to intermediate depth tight gas sand wells. Our team has a proven record of analyzing complex structural and stratigraphic formations using 3-D seismic and geological expertise, producing and optimizing gas reservoirs and drilling and completing unconventional gas reservoirs. Further, our professionals have developed completion techniques that enhance initial production rates and ultimate reserve recoveries in mature tight gas fields. Our team was responsible for the initial implementation of CO2 foam fracs in West Texas Canyon Sands tight gas fields and certain areas of the Piceance Basin in Colorado in the late 1980s. This same team has presented technical papers and delivered numerous industry presentations covering CO2 foam fracing on low pressure, water-sensitive tight gas reservoirs. Several of our directors also have significant experience in managing both public and private oil and gas companies. Our management team and employees will own approximately 7.4% of our common stock after this offering, aligning their objectives with those of our stockholders.
 
•  Low risk, multi-year drilling inventory. We have identified 833 drillable, low to moderate risk locations on our West Texas and East Texas properties, providing us with approximately 10 years of drilling inventory at our current drilling rate. Our technical team’s ability to locate


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and execute on repeatable low-risk drilling opportunities in our large and productive West Texas acreage holdings has helped us to achieve a drilling success rate of 95% since our inception. In addition, our technical expertise also has allowed us to improve our production rates and ultimate hydrocarbon recoveries on our wells.
 
•  Stable producing asset base. We own an operated asset base comprising long-lived reserves. Approximately 94% of our reserves are gas, and all of our proved reserves are located in West Texas. These properties should produce stable cash flows to fund our development, exploitation and exploration opportunities.
 
•  Large acreage positions. We are a significant acreage holder in three of our primary operating areas and have an aggregate leasehold position of 277,100 gross (189,400 net) acres. We believe we have assembled a portfolio of properties, both in producing natural gas and oil fields and in under-explored reservoirs, that would be difficult to replicate.
 
•  Operated asset base. We operate substantially all of our estimated reserves. By maintaining operating control, we are able to more effectively control our expenses, capital allocation and the timing and method of exploitation and development of our properties.
 
•  Financial flexibility. Upon the completion of this offering, we expect to have approximately $19.2 million in cash, no long-term debt and at least $75.0 million available for borrowings under our revolving credit facility, providing us with significant financial flexibility to pursue our business strategy.
 
•  Control of gathering infrastructure and gas marketing. We own and operate approximately 72 miles of gas gathering lines in West Texas that collect and transport our production to multiple delivery points for several regional and interstate pipelines. Owning and operating this infrastructure allows us to maintain greater control of our gathering pressures and to minimize down time associated with the system. We intend to purchase or construct additional gas gathering assets as necessary to fully develop our tight gas and shale opportunities in West Texas, Western Kentucky and Northern New Mexico.
 
Areas of operation
 
West Texas
 
The Wolfcamp Canyon Sands play is the predominant producer in Edwards, Sutton, Schleicher and Crockett Counties in West Texas. There have been over 11,800 Canyon Sands wells drilled to date. Major canyon fields located in this area are Sawyer Canyon, Ozona Canyon, Ozona Northeast Proper Canyon, Davidson Ranch Canyon, Henderson Canyon and Ozona Northeast Canyon. To date, the combined production from these fields is over 3.8 Tcfe. The Canyon Sands are a tight sand and siltstone reservoir that requires large fracture stimulation. The large independent companies currently active in the Canyon Sands play include Anadarko Petroleum Corp., Dominion Resources Inc. and Encore Acquisition Company along with several smaller companies, including Approach.
 
Ozona Northeast field (Canyon Sands)
 
The Ozona Northeast field, in Crockett and Schleicher counties, Texas, is our largest operating area on the basis of proved reserves and production. The Ozona Northeast field is one of the top 100 gas fields in the United States in both reserves and production. In 2004, we entered the


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field through a farmout arrangement and have since increased our total acreage position to 44,600 gross (44,000 net) acres. In February 2004, we drilled our first well, and, as of December 31, 2006, we had 237 producing wells with proved reserves of 147 Bcfe. During that period we have achieved an average compound annual production growth rate of over 100% as a result of our own drilling efforts. We have identified 644 additional drilling locations in the field, and we estimate that completed costs per location currently are approximately $770,000, based on current markets for drilling services and equipment. We currently have no plans to drill horizontal wells in our Ozona Northeast drilling program.
 
Cinco Terry project (Wolfcamp, Canyon Sands and Ellenburger)
 
Since late 2005, we have leased and acquired options to lease 21,900 gross (7,700 net) acres five miles west of our Ozona Northeast field in order to evaluate the Wolfcamp, Canyon and Ellenburger formations. As of June 30, 2007, we had drilled and completed three Canyon wells and one Ellenburger well at a total cost of $5.9 million gross and $3.0 million net. Proved reserves in the Cinco Terry project are estimated to be 1.8 Bcfe at December 31, 2006. Wolfcamp wells in this area have demonstrated significant commercial production, and we are evaluating the formation for possible horizontal completions. Based upon data collected in the process of drilling the Canyon and Ellenburger wells, we believe additional success could be achieved in the shallower Wolfcamp formation.
 
Ozona pipeline system
 
We own and operate 72 miles of gas gathering lines for the Ozona Northeast and Cinco Terry production that transport our gas to a custody transfer point. We rent all compression equipment, which minimizes our overall cost to add or remove compression depending on field requirements. Owning and operating the gathering systems allows us to maintain control of our gathering pressures as well as minimizing down time associated with the system. Our system delivers into Ozona Pipeline Energy Company and Duke Energy Corp.’s pipeline system.
 
East Texas
 
North Bald Prairie prospect (Cotton Valley Sands, Bossier, Cotton Valley Lime)
 
Our North Bald Prairie prospect is a joint venture with EnCana Oil & Gas (USA) Inc., covering 13,600 gross (4,900 net) acres in Limestone and Robertson Counties, Texas. As part of the joint venture, we have agreed to drill up to five wells at our cost to earn a 50% working interest in the project. We plan to exploit tight gas reservoirs in North Bald Prairie where we can use our expertise in fracturing and stimulating low permeability formations. Our primary targets are the Cotton Valley Sands, Bossier and Cotton Valley Lime formations. Other potential zones include the Rodessa, Pettit and Travis Peak formations. We have identified 63 potential drilling locations in the North Bald Prairie prospect. Initially, we expect to offset several productive Cotton Valley and Rodessa wells in the prospect area. We expect the average gross drilling and completion costs per location for a vertical well in this prospect to be approximately $2.4 million.


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Northern New Mexico
 
El Vado East prospect (Mancos Shale)
 
Our El Vado East prospect is a 90,300 gross (81,000 net) acre Mancos Shale play located in the Chama Basin in Northern New Mexico in proximity to several highly productive fields, including the Puerto Chiquito West and Puerto Chiquito East fields and the Boulder field. The Puerto Chiquito West field has produced over 22 MMBoe of oil and natural gas, the Puerto Chiquito East field has produced over 5 MMBoe of oil and natural gas and the Boulder Field has produced over 2 MMBoe of oil and natural gas. Other producing Mancos Shale fields in the San Juan Basin include the Gavilan and Verde Fields. The Mancos Shale is a thick, organic-rich Upper Cretaceous marine shale. We believe considerable exploration and development potential exists for this play.
 
Although our primary objective in the El Vado East prospect is the Mancos Shale, the possibility of finding commercial production in the Dakota, Morrison, Todilto and Entrada formations is a secondary objective. We anticipate spudding our initial test well in the El Vado East, which we expect to be the first of four vertical test wells, in the second quarter of 2008. Depending on the initial results of these wells, we may elect to shoot 3-D seismic over a portion of this prospect at locations which have yet to be identified.
 
Western Kentucky
 
Boomerang prospect (New Albany Shale)
 
Our Boomerang prospect is a 74,000 gross (44,400 net) acre New Albany Shale play located in Western Kentucky in an area of the Illinois Basin that we believe has not been widely explored. The New Albany Shale produces both biogenic and thermogenic gas from fractured reservoirs across a wide area in Illinois and Indiana. Thermogenic gas fields have been successfully developed in Kentucky, most notably in the Appalachian Basin part of Eastern Kentucky. Renewed interest in the Illinois Basin shale gas play has resulted in recent activity by several independent operators.
 
We believe the attributes of the New Albany Shale in our Boomerang prospect make it a promising unconventional resource play for natural gas, particularly with the introduction of horizontal drilling technology. In the first quarter of 2007, we drilled the last of three vertical test wells. We have contracted to have core samples from these three wells analyzed for their geological, petrophysical, geomechanical, geochemical and production properties. We expect to begin the completion of these three test wells in the fourth quarter of 2007 or first quarter of 2008. After evaluating the results of our initial drilling and completion activities, we will determine our development program in the Boomerang prospect.
 
Western Canada
 
British Columbia Prospect (Triassic Shale and tight gas sands)
 
We own a 25% non-operating, working interest in a Canadian joint venture focused on unconventional shale and tight gas sands in Northeast British Columbia. The project covers 32,700 gross acres and our working interest represents 7,400 net acres. Our primary targets are Triassic-aged thick shales and interbedded silts and sandstones capped by shallow carbonates and evaporates. Historically, the Triassic section has been a focus of drilling for conventional


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reservoirs in northeastern British Columbia. Recently, the Triassic has seen renewed industry activity, focused primarily on the potential of unconventional shale and tight gas sand reservoirs. Current operators in the trend include EnCana Corporation, Murphy Oil Corporation and Duvernay Oil Corp.
 
Estimated proved reserves
 
As of December 31, 2006, all of our proved reserves and production were located in our West Texas operating area and substantially all of those reserves and production were located in the Ozona Northeast field. The following table sets forth a summary of our estimated proved reserves and estimated average daily net production for the month ended December 31, 2006.
 
                                                 
            Production for the month ended
    Estimated proved reserves at December 31, 2006       December 31, 2006
                Percent
      Identified
  Net
   
    Developed
  Undeveloped
  Total
  of total
  PV-10(1)
  drilling
  average
  Percent
    (Bcfe)   (Bcfe)   (Bcfe)   reserves   (millions)   locations(2)   MMcfe/d   of total
 
Ozona Northeast
    74.9     72.1     147.0     99%   $ 175.7     644     22.5     99%
Cinco Terry
    0.9     0.9     1.8     1%     4.2     126     0.2     1%
     
     
Total
    75.8     73.0     148.8     100%   $ 179.9     770     22.7     100%
 
 
 
(1) PV-10 is a non-GAAP financial measure and generally differs from standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. See “Selected historical combined financial data—Reconciliation of non-GAAP financial measures” for our definition of PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows. Our calculation of PV-10 set forth in this table is based on gas and oil and condensate prices actually received by us on December 31, 2006, held flat for the life of the reserves. The weighted average price over the life of the Ozona Northeast reserves was $6.55 per Mcf of gas and $58.05 per Bbl of oil. The weighted average price over the life of the Cinco Terry reserves was $5.65 per Mcf of gas and $58.05 per Bbl of oil.
 
(2) Represents total gross drilling locations identified by management as of July 31, 2007. Of the total, 178 locations are classified as proved. The table excludes 63 identified locations in our North Bald Prairie prospect in East Texas, none of which are proved. The final determination with respect to the drilling of any well, including those currently budgeted, will depend on a number of factors, including the results of our development and exploration efforts, the availability of sufficient capital resources to us and other participants for drilling prospects, economic and industry conditions at the time of drilling, including prevailing and anticipated prices for gas and oil and the availability of drilling rigs and crews, our financial results and the availability of leases on reasonable terms and permitting for the potential drilling locations.
 
The average market price received for our natural gas production on December 31, 2006, after basis and Btu adjustments, was $6.55 per Mcf. The average market price received for our natural gas production on August 31, 2007, after basis and Btu adjustments, was $6.05 per Mcf.


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Operating data
 
The following table presents certain information with respect to our historical operating data for the years ended December 31, 2004, 2005 and 2006 and for the six months ended June 30, 2007 and combined pro forma operating data for the year ended December 31, 2006 and the six months ended June 30, 2007, after giving effect to our acquisition of the Neo Canyon interest:
 
                                         
 
                      Pro forma  
                Six
        Six
 
                months
    Year
  months
 
                ended
    ended
  ended
 
    Year ended December 31,   June 30,
    December 31,
  June 30,
 
    2004   2005   2006   2007     2006   2007  
 
 
Gross wells
                                       
Drilled
    54     120     83     25       83     25  
Completed
    46     115     81     20 (1)     81     20 (1)
Net wells
                                       
Drilled
    34.9     77.2     55.1     17.0       79.6     23.1  
Completed
    29.6     74.8     53.5     13.6       77.3     19.4  
Net production data
                                       
Net volume (MMcfe)
    908     5,012     6,744     2,608       9,580     3,680  
Average daily volume (MMcfe/d)
    4     14     18     14       26     20  
Average sales price (per Mcfe)
                                       
Average sales price (without the effects of commodity derivatives)
  $ 6.26   $ 8.63   $ 6.92   $ 7.32     $ 6.91   $ 7.31  
Average sales price (with the effects of commodity derivatives)
    6.26     8.05     7.84     8.18       7.56     7.92  
Expenses (per Mcfe)
                                       
Lease operating
  $ 0.20   $ 0.58   $ 0.58   $ 0.78     $ 0.57   $ 0.75  
Production taxes
    0.45     0.39     0.26     0.29       0.26     0.30  
General and administrative
    2.14     0.53     0.36     1.05       0.29     0.80  
Exploration
    2.64     0.15     0.24     0.24       0.17     0.17  
Impairment
            0.08           0.06      
Depreciation, depletion and amortization
    1.35     1.60     2.16     2.34       2.24     2.37  
 
 
 
(1) At June 30, 2007, five wells were awaiting completion.
 
At December 31, 2006, our standardized measure of discounted future net cash flows was $128.6 million, and our PV-10 was $179.9 million. The estimates in the table below of proved


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reserves as of December 31, 2006 are based on a reserve report prepared by us and audited by DeGolyer and MacNaughton.
 
             
    As of
  Pro forma
    December 31,
  December 31,
    2006   2006(1)
 
Estimated proved reserves
           
Gas (Bcf)
    98.7     139.8
Oil (MMBbls)
    1.1     1.5
     
     
Total proved reserves (Bcfe)
    105.4     148.8
Total proved developed reserves (Bcfe)
    53.1     75.8
PV-10 (millions)(2)
           
Proved developed reserves
  $ 112.8   $ 158.3
Proved undeveloped reserves
    15.6     21.6
     
     
Total PV-10 value
  $ 128.4   $ 179.9
Standardized measure of oil and gas quantities (millions)
  $ 77.9   $ 128.6
 
 
 
(1) Gives effect to our acquisition of the Neo Canyon interest.
 
(2) PV-10 is a non-GAAP financial measure and generally differs from standardized measure of discounted future net cash flows, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. See “Selected historical combined financial data—Reconciliation of non-GAAP financial measures” for our definition of PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows. Our calculation of PV-10 set forth in this table is based on gas and oil and condensate prices actually received by us on December 31, 2006, held flat for the life of the reserves. The weighted average price over the life of the Ozona Northeast reserves was $6.55 per Mcf of gas and $58.05 per Bbl of oil. The weighted average price over the life of the Cinco Terry reserves was $5.65 per Mcf of gas and $58.05 per Bbl of oil.
 
Development and exploration projects
 
The following table summarizes our historical 2006 and our estimated 2007 and 2008 capital expenditures. The estimated 2007 and 2008 capital expenditures shown are preliminary full year estimates. The estimated capital expenditures are subject to change depending upon a number


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of factors, including availability of capital, drilling results, oil and gas prices, costs of drilling and completion and availability of drilling rigs, equipment and labor.
 
                         
    Historical(1)        
        Six months
  Estimated(2)
    Year ended
  ended
  Year ending
    December 31,
  June 30,
  December 31,
(in thousands)   2006   2007   2007   2008
 
Capital expenditures:
                       
Ozona Northeast
  $ 52,303   $ 12,742   $ 23,400   $ 29,500
Cinco Terry
    3,176     873     6,600     10,100
East Texas
            7,300     14,000
Northern New Mexico
                3,600
Western Kentucky
        1,040     1,800     2,600
Western Canada
            1,200     2,900
Lease acquisition, geological, geophysical and other
    3,873     2,704     8,000     800
     
     
Total capital expenditures
  $ 59,352   $ 17,359   $ 48,300   $ 63,500
 
 
 
(1) Historical amounts here include actual amounts incurred to the interest of Approach Resources Inc. and Approach Oil & Gas Inc.
 
(2) Estimated capital expenditures for 2007 and 2008 give effect to the acquisition of the Neo Canyon interest in combination with the interest of Approach Resources Inc. and Approach Oil & Gas Inc. as if the Neo Canyon interest were acquired on October 1, 2007.
 
Markets and customers
 
The revenues generated by our operations are highly dependent upon the prices of, and demand for, gas and oil. The price we receive for our gas and oil production depends on numerous factors beyond our control, including seasonality, the conditions of the United States economy, particularly in the manufacturing sector, political conditions in other oil and gas producing countries, the extent of domestic production and imports of gas and oil, the proximity and capacity of gas pipelines and other transportation facilities, demand for oil and gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
 
During the year end