8-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 OR 15(d) of The Securities Exchange Act of 1934

Date of Report (Date of earliest event reported)
October 7, 2011

APPROACH RESOURCES INC.

(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of incorporation) 001-33801
(Commission File Number) 51-0424817
(IRS Employer Identification No.)

One Ridgmar Centre
6500 West Freeway, Suite 800
Fort Worth, Texas
(Address of principal executive offices) 76116
(Zip Code)

(817) 989-9000
(Registrant’s telephone number, including area code)

Not Applicable
(Former name or former address, if changed since last report.)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o  Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o  Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o  Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o  Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 1.01 Entry into a Material Definitive Agreement.

     Effective October 7, 2011, Approach Resources Inc. (the “Company”) entered into an eleventh amendment (the “Eleventh Amendment”) to its Credit Agreement dated as of January 18, 2008 (as amended, the “Credit Agreement”), by and among the Company and its subsidiary guarantors, the lenders and JPMorgan Chase Bank, N.A., as administrative agent and lender.

     The Eleventh Amendment, among other things, (a) increases the borrowing base to $260 million from $200 million, and (b) adds Wells Fargo Bank, N.A. as a sixth lender to the bank syndicate.

     The foregoing description of the terms of the Eleventh Amendment is qualified in its entirety by the Eleventh Amendment, which is filed as Exhibit 10.1 to this current report and is incorporated herein by reference.

Item 2.03 Creation of a Direct Financial Obligation or an Obligation Under an Off-Balance Sheet Arrangement of a Registrant.

     The information set forth under Item 1.01 above is incorporated herein by reference.

Item 7.01 Regulation FD Disclosure.

     On October 11, 2011, Approach Resources Inc. (the “Company”) posted a new presentation titled “Canaccord Genuity 5^th Annual Global Energy Conference, October 12-13, 2011” under the “Investor Relations — Presentations” section of the Company’s website, www.approachresources.com.

     For the benefit of all investors, the presentation is attached hereto as Exhibit 99.1.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits.

Exhibit No.	Description
10.1	Amendment No. 11 dated as of October 7, 2011, to Credit Agreement dated as of January 18, 2008, among Approach Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as administrative agent and lender, BNP Paribas, KeyBank National Association, The Frost National Bank, Royal Bank of Canada and Wells Fargo Bank, N.A., as lenders, and Approach Oil & Gas Inc. and Approach Resources I, LP, as guarantors.
99.1	Canaccord Genuity 5th Annual Global Energy Conference, October 12-13, 2011.

     In accordance with General Instruction B.2 of Form 8-K, the information in this current report on Form 8-K, including the attached exhibit, shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liabilities of that section, nor shall it be deemed incorporated by reference into any registration statement or other filing under the Securities Act of 1933, as amended, or the Exchange Act, except as otherwise expressly stated in such filing.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	APPROACH RESOURCES INC.
Date: October 11, 2011	By:	/s/ J. Curtis Henderson
		J. Curtis Henderson
		Executive Vice President and General Counsel

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EXHIBIT INDEX

Exhibit No.	Description
10.1	Amendment No. 11 dated as of October 7, 2011, to Credit Agreement dated as of January 18, 2008, among Approach Resources Inc., as Borrower, JPMorgan Chase Bank, N.A., as administrative agent and lender, BNP Paribas, KeyBank National Association, The Frost National Bank, Royal Bank of Canada and Wells Fargo Bank, N.A., as lenders, and Approach Oil & Gas Inc. and Approach Resources I, LP, as guarantors.
99.1	Canaccord Genuity 5th Annual Global Energy Conference, October 12-13, 2011.

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EX-10.1

Exhibit 10.1

[Execution Version]

October 7, 2011

JPMorgan Chase Bank, N.A.
2200 Ross Avenue, Third Floor
Dallas, Texas 75201
Attention: Kimberly A. Bourgeois

Re:   Eleventh Amendment to Credit Agreement dated as of January 18, 2008 among Approach Resources Inc. (“Borrower”), JPMorgan Chase Bank, N.A. and the institutions named therein (“Lenders”) and JPMorgan Chase Bank, N.A., as Agent (“Agent”)

Ladies and Gentlemen:

     Reference is hereby made to that certain Credit Agreement dated as of January 18, 2008 among Approach Resources Inc., a Delaware corporation (“Borrower”), JPMorgan Chase Bank, N.A., as Agent (“Agent”), and the Lenders that are signatory parties hereto (the “Lenders”), as amended by amendments dated February 19, 2008, May 6, 2008, August 26, 2008, April 8, 2009, July 8, 2009, October 30, 2009, February 1, 2010, May 3, 2010, October 21, 2010, May 4, 2011 and as of the date hereof (as amended, the “Loan Agreement”). All capitalized terms herein shall have the meanings ascribed to them in the Loan Agreement.

     Pursuant to this Eleventh Amendment (the “Amendment”), Agent, Lenders and Borrower agree, effective as of the date hereof, to amend the Loan Agreement according to the terms and provisions set forth below.

     1. Definition of Loan Documents. Section 1 of the Loan Agreement is hereby amended to redefine “Loan Documents” as follows:

     “Loan Documents means this Agreement, the Notes, the Collateral Documents and all other documents executed by Borrower with Agent or Lenders in connection with the transaction described in this Agreement, including any and all amendments to this Agreement made pursuant to Section 24 of this Agreement.”

     2. Collateral Security. Section 6(b) of the Loan Agreement is hereby amended by deleting the last sentence thereof and substituting the following therefor:

     “From time to time, Borrower will cause to be executed and delivered to Agent additional Collateral Documents if Agent reasonably deems such are necessary to insure perfection or maintenance of Lenders’ security interests and Liens in not less than 80% of the Engineered Value of the Oil and Gas Properties which are included in the Borrowing Base then in effect.”

     3. Events of Default. The following is hereby added to the end of Section 14 of the Loan Agreement, “Events of Default”:

     “After the exercise of remedies provided for in this Agreement, the Collateral Documents or any of the other Loan Documents (or after the Loans have automatically become immediately due and payable as set forth in this Section 14), any amounts received on account of the Notes or any Loans shall be applied by Agent in the following order:

First, to payment of that portion of the amounts owed hereunder and under the other Loan Documents constituting fees, indemnities, expenses and other amounts (including fees, charges and disbursements of counsel to Agent) payable to Agent in its capacity as such;

Second, to payment of that portion of the amounts owed hereunder constituting fees, indemnities and other amounts (other than principal, interest and Letter of Credit fees) payable to Lenders (including fees, charges and disbursements of counsel to the respective Lenders), ratably among them in proportion to the respective amounts described in this clause Second payable to Agent and Lenders;

Third, to payment of that portion of the amounts due hereunder constituting accrued and unpaid Letters of Credit Fees and interest on the Loans, ratably among Lenders, in proportion to the respective amounts described in this clause Third payable to them;

Fourth, to payment of that portion of the amounts owed hereunder constituting unpaid principal of the Loans, unpaid Reimbursement Obligations, the maximum amounts which Lenders might then or thereafter be called upon to advance under all Letters of Credit then outstanding and settlements under Rate Management Transactions ratably among Lenders in proportion to the respective amounts described in this clause Fourth held by them; and

Last, the balance, if any, after all of the amounts due hereunder, under the Loans and under the other Loan Documents have been indefeasibly paid in full, to Borrower, or as otherwise required by applicable law.

If an amount of an undrawn Letter of Credit or other contingent amount is included in the foregoing and such Letter of Credit or other contingent amount expires and the resulting obligations are lower than the amount that was included in the forgoing application of payments, the Agent shall revise the calculation under the forgoing application of payments, and the Lenders and other parties receiving such payments shall be obligated to refund any excess payment to the Agent to be applied in accordance with the revised calculation of the application of payments.”

     4. Agent and Lenders; Consultation with Counsel. Section 15(c) of the Loan Agreement is hereby amended by deleting “FROST” from line 5 thereof and inserting “JPMORGAN” in its place.

     5. Increase to Borrowing Base and Commitment. As of the date hereof, the Borrowing Base and Commitment under the Loan Agreement are increased to $260,000,000.

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     6. Assignments of Commitment. Prior to giving effect to this Amendment, JPMorgan Chase Bank, N.A., BNP Paribas, KeyBank National Association, The Frost National Bank and Royal Bank of Canada (the “Existing Lenders”) each has a Commitment Percentage as set out below under the heading “Existing Lender Commitments.” The Existing Lenders desire to assign to Wells Fargo Bank, N.A. (the “New Lender”), a percentage of each Existing Lender’s Commitment Percentage of its obligations as a Lender under the Loan Agreement, such that after giving effect to such assignments and as of the date hereof, the respective Commitment Percentages of the Existing Lenders and the New Lender will be as set forth below under the heading “Revised Lender Commitments” and on Schedule I attached hereto and made a part hereof and of the Loan Agreement, as amended hereby. Agent and Borrower hereby consent to the assignments by Existing Lenders of such portion of each of their rights and obligations as a Lender under the Loan Agreement to the New Lender. Effective as of the date hereof such acquisition of a portion of the Existing Lenders’ Commitments by the New Lender shall be deemed to have been consummated pursuant to the terms of the Assignment and Acceptance Agreement attached as Exhibit D to the Loan Agreement (which is incorporated herein by reference as if fully set forth herein) as if the Existing Lenders and the New Lender had executed Assignment and Acceptance Agreements with respect to such assignments.

	Existing Lender Commitments					Revised Lender Commitments
Lenders	Percentage			Amount		Percentage			Amount
JPMorgan Chase Bank, N.A.		22.5	%	$	45,000,000		21.09	%	$	54,843,750
BNP Paribas		20.00	%	$	40,000,000		15.38	%	$	40,000,000
KeyBank National Association		20.00	%	$	40,000,000		18.75	%	$	48,750,000
Royal Bank of Canada		20.00	%	$	40,000,000		18.75	%	$	48,750,000
The Frost National Bank		17.5	%	$	35,000,000		16.41	%	$	42,656,250
Wells Fargo Bank, N.A.		N/A			N/A		9.62	%	$	25,000,000
TOTAL		100.00	%	$	200,000,000		100.00	%	$	260,000,000

     7. Schedule I. Effective as of the date hereof, Schedule I to the Loan Agreement is deleted in its entirety and Schedule I attached hereto is substituted therefor.

     8. Replacement Notes. As of the date hereof there shall be executed and delivered by Borrower to each of the Existing Lenders and the New Lenders, if requested, replacement Notes, in the form of Exhibit “B” attached hereto reflecting the percentage of each Lender’s Pro Rata Part of the Facility Amount. Promptly upon receipt of a replacement Note, each Lender shall deliver to Borrower all existing Notes held by each such Lender.

     9. Notes. Notwithstanding Sections 3(a) and 3(b) of the Loan Agreement referencing that the Loans shall be evidenced by Notes payable to each Lender in the aggregate face amount of the Facility Amount, the delivery of such a Note to the Lenders shall be at each Lender’s discretion. Any Lender may request that Loans made by it be evidenced by a Note. In such event, the Borrower shall prepare, execute and deliver to such Lender a Note payable to the

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order of such Lender in the form of Exhibit “B” to the Loan Agreement. Thereafter, the Loans evidenced by such Note and interest thereon shall at all times (including after assignment pursuant to Section 29 of the Loan Agreement) be represented by one or more Notes in such form payable to the order of the payee named therein. Irrespective of the Facility Amount, no Lender shall ever be obligated to advance on the Commitment any amount in excess of its Commitment then in effect.

     10. Conditions Precedent. The effectiveness of this Amendment is subject to the satisfaction of the following conditions precedent, unless specifically waived in writing by Lenders:

     (a) The Amendment. Borrower, each Guarantor and each Lender shall have duly and validly executed and delivered this Amendment to Agent.

     (b) Replacement Notes. If requested by any Lender, and upon the delivery to Borrower of the terminated existing Notes, Borrower shall have duly and validly executed the Notes payable to each of the Lender signatories hereto in termination and replacement of the existing Notes.

     (c) Representations and Warranties. The representations and warranties contained in the Loan Agreement and in the other Loan Documents shall be true and correct in all material respects as of the date hereof, as if made on the date hereof.

     (e) No Default. No Default or Event of Default shall have occurred and be continuing.

     (f) Corporate/Partnership Proceedings. All corporate and/or partnership proceedings, taken in connection with the transactions contemplated by this Amendment and all documents, instruments and other legal matters incident thereto shall be satisfactory to Agent, and its legal counsel.

     (g) Fees. In consideration for the agreements set forth herein, Borrower shall have paid to Agent any fees payable to Agent and/or Lenders pursuant to or in connection with the fee letter agreement of even date herewith between Borrower and Agent.

     11. Ratification by Guarantors. Each Guarantor hereby ratifies and reaffirms all of its obligations under its Guaranty Agreement (the “Guaranty”) of Borrower’s obligations under the Loan Agreement, as amended hereby. Each Guarantor also hereby agrees that nothing in this Amendment shall adversely affect any right or remedy of Lenders under the Guaranty and that the execution and delivery of this Amendment shall in no way change or modify its obligations as guarantor under the Guaranty. Although each Guarantor has been informed by Borrower of the matters set forth in this Amendment and such Guarantor has acknowledged and agreed to the same, such Guarantor understands that Agent has no duty to notify such Guarantor or to seek such Guarantor’s acknowledgment or agreement, and nothing contained herein shall create such a duty as to any transaction hereafter.

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     12. Representations and Warranties. By executing this Amendment, Borrower hereby represents, warrants and certifies to Lenders that, as of the date hereof, (a) there exists no Event of Default or events which, with notice or lapse of time, would constitute an Event of Default; (b) Borrower has performed and complied with all agreements and conditions contained in the Loan Agreement or the other Loan Documents which are required to be performed or complied with by Borrower; and (c) the representations and warranties contained in the Loan Agreement and the other Loan Documents are true in all material respects, with the same force and effect as though made on and as of the date hereof (except to the extent that such representations and warranties related solely to an earlier date).

     13. Confirmation and Ratification. Except as affected by the provisions set forth herein, the Loan Agreement shall remain in full force and effect and is hereby ratified and confirmed by all parties. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of Lenders under the Loan Agreement or the other Loan Documents.

     14. Reference to Loan Agreement. Each of the Loan Agreement and the Loan Documents, and any and all other agreements, documents or instruments now or hereafter executed and delivered pursuant to the terms hereof or pursuant to the terms of the Loan Agreement, as amended hereby, are hereby amended so that any reference in the Loan Agreement, the Loan Documents and such other documents to the Loan Agreement shall mean a reference to the Loan Agreement as amended hereby.

     15. Multiple Counterparts. This Amendment may be executed in a number of identical separate counterparts, each of which for all purposes is to be deemed an original, but all of which shall constitute, collectively, one agreement. No party to this Amendment shall be bound hereby until a counterpart of this Amendment has been executed by all parties hereto. Delivery of an executed counterpart of a signature page of this Amendment by telecopy shall be effective as delivery of a manually executed counterpart of this Amendment.

     16. Governing Law. THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF TEXAS.

     17. Final Agreement. THE LOAN AGREEMENT, AS AMENDED BY THIS AMENDMENT, AND ALL PROMISSORY NOTES AND OTHER LOAN DOCUMENTS EXECUTED PURSUANT THERETO OR HERETO, REPRESENT THE FINAL AGREEMENT AMONG THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN OR AMONG ANY OF THE PARTIES.

     Please signify your acceptance to the foregoing terms and provisions by executing a copy of this Amendment at the space provided below.

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Very truly yours, BORROWER: APPROACH RESOURCES INC., a Delaware corporation
By:	/s/ J. Ross Craft
	J. Ross Craft, President and Chief Executive Officer
GUARANTORS: APPROACH OIL & GAS INC., a Delaware corporation
By:	/s/ J. Ross Craft
	J. Ross Craft, President and Chief Executive Officer
APPROACH RESOURCES I, LP, a Texas limited partnership
By:	Approach Operating, LLC, a Delaware limited liability company, its general partner
By:	Approach Resources Inc., a Delaware corporation, its sole member
By:	/s/ J. Ross Craft
	J. Ross Craft, President and Chief Executive Officer

[Signature Pages]

ACCEPTED AND AGREED TO effective as of the date and year first above written: AGENT: JPMORGAN CHASE BANK, N.A.
By:	/s/ Michael A. Kamauf
	Michael A. Kamauf, Authorized Officer
LENDERS: JPMORGAN CHASE BANK, N.A.
By:	/s/ Michael A. Kamauf
	Michael A. Kamauf, Authorized Officer

[Signature Pages]

BNP PARIBAS, Lender and Syndication Agent
By:	/s/ Michaela Braun
	Name:	Michaela Braun
	Title:	Director
By:	/s/ Greg Smothers
	Name:	Greg Smothers
	Title:	Director

[Signature Pages]

KEYBANK NATIONAL ASSOCIATION, Lender and Documentation Agent
By:	/s/ David Morris
	Name:	David Morris
	Title:	Vice President

[Signature Pages]

THE FROST NATIONAL BANK
By:	/s/ Alex Zemkoski
	Alex Zemkoski, Vice President

[Signature Pages]

ROYAL BANK OF CANADA
By:	/s/ Jay T. Sartain
	Name:	Jay T. Sartain
	Title:	Authorized Signatory

[Signature Pages]

WELLS FARGO BANK, N.A.
By:	/s/ Catherine Stacy
	Name:	Catherine Stacy
	Title:	Vice President

[Signature Pages]

SCHEDULE I

	Commitment Amount		Percentage Commitment
JPMorgan Chase Bank, NA	$	54,843,750.00		21.09	%
BNP Paribas	$	40,000,000.00		15.38	%
Key Bank National Association	$	48,750,000.00		18.75	%
Royal Bank of Canada	$	48,750,000.00		18.75	%
The Frost National Bank	$	42,656,250.00		16.41	%
Wells Fargo Bank, N.A.	$	25,000,000.00		9.62	%
TOTAL	$	260,000,000.00		100.00	%

EXHIBIT “B”

REVOLVING NOTE

$_________________ Dallas, Texas October 7, 2011

     FOR VALUE RECEIVED, the undersigned APPROACH RESOURCES INC., a Delaware corporation (“Borrower”), hereby unconditionally promises to pay to the order of __________________ (“Lender”) at the offices of JPMORGAN CHASE BANK, N.A. (“Agent”) in Dallas County, Texas, the principal sum of _______ MILLION AND NO/100 DOLLARS ($_________________), or so much thereof as may be advanced by Lender and outstanding at any time or from time to time pursuant to the Credit Agreement (as hereinafter defined) in lawful money of the United States of America together with interest from the date hereof until paid at the rates specified in the Credit Agreement. All payments of principal and interest due hereunder are payable at the offices of Agent at 2200 Ross Avenue, Third Floor, Dallas, Texas 75201, Attention: Kimberly A. Bourgeois, or at such other address as Agent shall designate in writing to Borrower.

     The principal and all accrued interest on this Note shall be due and payable in accordance with the terms and provisions of the Credit Agreement.

     This Note is executed pursuant to that certain Credit Agreement dated January 18, 2008 by and among Borrower, Agent and the other Lenders parties thereto, as amended (as amended, the “Credit Agreement”) and is one of the Notes referred to therein. Reference is made to the Credit Agreement and the Loan Documents (as that term is defined in the Credit Agreement) for a statement of prepayment rights and obligations of Borrower, for a statement of the terms and conditions under which the due date of this Note may be accelerated and for statements regarding other matters affecting this Note (including without limitation the obligations of the holder hereof to advance funds hereunder, principal and interest payment due dates, voluntary and mandatory prepayments, exercise of rights and remedies, payment of attorneys’ fees, court costs and other costs of collection and certain waivers by Borrower and others now or hereafter obligated for payment of any sums due hereunder). Upon the occurrence of an Event of Default (as that term is defined in the Credit Agreement and Loan Documents) Agent may declare forthwith to be entirely and immediately due and payable the principal balance hereof and the interest accrued hereon, and Lender shall have all rights and remedies of a Lender under the Credit Agreement and Loan Documents. This Note may be prepaid in accordance with the terms and provisions of the Credit Agreement.

     Regardless of any provision contained in this Note, the holder hereof shall never be entitled to receive, collect or apply, as interest on this Note, any amount in excess of the Maximum Rate (as such term is defined in the Credit Agreement), and, if the holder hereof ever receives, collects, or applies as interest any such amount which would be excessive interest, it shall be deemed a partial prepayment of principal and treated hereunder as such; and, if the indebtedness evidenced hereby is paid in full, any remaining excess shall forthwith be paid to Borrower. In determining whether or not the interest paid or payable under any specific

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contingency exceeds the Maximum Rate, Borrower and the holder hereof shall, to the maximum extent permitted under applicable law (i) characterize any non-principal payment as an expense, fee or premium rather than as interest, (ii) exclude voluntary prepayments and the effects thereof, and (iii) spread the total amount of interest throughout the entire contemplated term of the obligations evidenced by this Note and/or referred to in the Credit Agreement so that the interest rate is uniform throughout the entire term of this Note; provided that, if this Note is paid and performed in full prior to the end of the full contemplated term thereof and if the interest received for the actual period of existence thereof exceeds the Maximum Rate, the holder hereof shall refund to Borrower the amount of such excess or credit the amount of such excess against the indebtedness evidenced hereby, and, in such event, the holder hereof shall not be subject to any penalties provided by any laws for contracting for, charging, taking, reserving or receiving interest in excess of the Maximum Rate.

     If any payment of principal or interest on this Note shall become due on a day other than a Business Day (as such term is defined in the Credit Agreement), such payment shall be made on the next succeeding Business Day and such extension of time shall in such case be included in computing interest in connection with such payment.

     If this Note is placed in the hands of an attorney for collection, or if it is collected through any legal proceeding at law or in equity or in bankruptcy, receivership or other court proceedings, Borrower agrees to pay all costs of collection, including, but not limited to, court costs and reasonable attorneys’ fees.

     Borrower and each surety, endorser, guarantor and other party ever liable for payment of any sums of money payable on this Note, jointly and severally waive presentment and demand for payment, notice of intention to accelerate the maturity, protest, notice of protest and nonpayment, as to this Note and as to each and all installments hereof, and agree that their liability under this Note shall not be affected by any renewal or extension in the time of payment hereof, or in any indulgences, or by any release or change in any security for the payment of this Note, and hereby consent to any and all renewals, extensions, indulgences, releases or changes.

     This Note renews and replaces, but does not extinguish, the amounts remaining unpaid on that certain promissory note dated May 4, 2011, executed by Borrower and payable to the order of Lender. [This paragraph does not apply to the Wells Fargo Bank, N.A. Note.]

     THIS NOTE SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE APPLICABLE LAWS OF THE UNITED STATES OF AMERICA AND THE LAWS OF THE STATE OF TEXAS. BORROWER AGREES THAT THIS NOTE IS PERFORMABLE IN TARRANT COUNTY, TEXAS AND THAT SUCH COUNTY IS PROPER VENUE FOR ANY ACTION OR PROCEEDING INVOLVING THIS NOTE TO THE EXCLUSION OF ALL OTHER VENUES.

     THIS INSTRUMENT SECURES A LINE OF CREDIT USED PRIMARILY FOR BUSINESS, COMMERCIAL OR AGRICULTURAL PURPOSES.

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     THIS WRITTEN NOTE, THE CREDIT AGREEMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENTS BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

     EXECUTED as of the date and year first above written.

BORROWER: APPROACH RESOURCES INC., a Delaware corporation
By:
	Steven P. Smart, Executive Vice President and
	Chief Financial Officer

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EX-99.1

Exhibit 99.1

Canaccord Genuity 5th Annual Global Energy Conference OCTOBER 12-13, 2011

Forward-looking statements This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of management regarding plans, strategies, objectives, anticipated financial and operating results of the Company, including as to the Company's Wolffork shale resource play, estimated oil and gas in place and recoverability of the oil and gas, estimated reserves and drilling locations, capital expenditures, typical well results and well profiles, and production and operating expenses guidance included in the presentation. These statements are based on certain assumptions made by the Company based on management's experience and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and believed to be reasonable by management. When used in this presentation, the words "will," "potential," "believe," "intend," "expect," "may," "should," "anticipate," "could," "estimate," "plan," "predict," "project," "target," "profile," "model," or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. In particular, careful consideration should be given to the cautionary statements and risk factors described in the Company's Annual Report on Form 10-K for the year ended December 31, 2010. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. The Securities and Exchange Commission ("SEC") permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. The Company uses the terms "estimated ultimate recovery" or "EUR," reserve or resource "potential," "upside," "oil and gas in place" or "OGIP," "OIP" or "GIP," and other descriptions of volumes of reserves potentially recoverable through additional drilling or recovery techniques that the SEC's rules may prohibit the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized by the Company. EUR estimates, potential drilling locations, resource potential and OGIP estimates have not been risked by the Company. Actual locations drilled and quantities that may be ultimately recovered from the Company's interest may differ substantially from our estimates. There is no commitment by the Company to drill all of the drilling locations that have been attributed these quantities. Factors affecting ultimate recovery include the scope of the Company's ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, type/decline curves, per well EUR, OGIP and resource potential may change significantly as development of the Company's oil and gas assets provides additional data. Type/decline curves, estimated EURs, typical well related oil and gas in place, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, OGIP, recovery factors and costs prove correct. The Company has very limited production experience with these projects, and accordingly, such estimates may change significantly as results from more wells are evaluated. Estimates of resource potential, EURs and OGIP do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. IRR estimates assume NYMEX forward-curve gas pricing and Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic or G&A costs. Cautionary statements regarding oil and gas quantities

Approach Resources Inc. Notes: Proved reserves and acreage as of 6/30/2011. All Boe and Mcfe calculations are based on a 6 to 1 conversion ratio. Enterprise value is equal to market capitalization using the closing price of $18.35 per share on 10/7/2011, plus net debt as of 6/30/2011. AREX OVERVIEW ASSET OVERVIEW Enterprise value $614.7 MM High quality reserve base 66.8 MMBoe proved reserves 97% Permian Basin 55% Oil & NGLs Permian core operating area 158,700 gross (140,400 net) acres 500+ MMBoe gross, unrisked resource potential Extensive inventory of drilling and recompletion opportunities Strong balance sheet to execute plan Borrowing base increased to $260 MM from $200 MM

Note: 2011E production and production mix based on the midpoint of production guidance. See "F&D Costs Reconciliation" slide in appendix for reconciliation. Track Record of Reserve and Production Growth RESERVE GROWTH PRODUCTION GROWTH MY'11 proved reserves up 32% to 66.8 MMBoe Oil & NGL reserves up 44% to 36.9 MMBbls Replaced 1,598% of reserves during 1H'11 at an all-in F&D cost of $9.45/Boe 8.4 MMBoe proved reserves booked to Wolffork oil shale resource play Balanced production mix in 2011 and beyond 98% Permian Basin 2011 targets: 50%+ Production growth 55% Oil and NGLs; 45% natural gas production mix 55% oil & ngls 55% oil & ngls proved reserves (mmboe) production (mboe/d) 2004-2011E CAGR: 46% 2004-MY'11 CAGR: 34%

Midland Basin Delaware Basin Central Basin Platform Northwest Shelf Eastern Shelf Wolffork Play 250 miles by 300 miles 1st commercial oil accumulation (Westbrook) discovered in 1921 Over 30 billion barrels of oil produced over last 90 years Largest oil and gas producing area in Lower 48 Over 1,300 oil reservoirs and 30 plays identified Approximately 80% of producing reservoirs <10,000' Over 450 US rigs are active in Permian Source: USGS, Bureau of Economic Geology, Baker Hughes and IHS. Permian Basin - World Class Petroleum Basin PERMIAN BASIN

AREX Acreage Position - Favorably Located in the Permian Basin

AREX Acreage Position - Permian Basin Large, primarily contiguous acreage position 158,700 gross (140,400 net) acres (~76% NRI) Low acreage cost ~$350 per acre Low-risk, long-life reserve base 64.8 MMBoe proved reserves 57% liquids (51% proved developed) Significant potential reserves 500+ MMBoe gross, unrisked reserve potential 2,900+ potential horizontal, vertical and recompletion targets Additional upside potential in downspacing opportunities 2011 Program - $130 MM 2 vertical rigs and 1 horizontal rig De-risk acreage position with horizontal and vertical pilot program Acquire 3-D seismic data Note: other large independents with Wolffork / Wolfberry activities nearby include PXD, DVN and CXO

Wolfcamp Shale Name Convention - Southern Midland Basin Wolfcamp shale name conventions are based on investor presentations of AREX (10/18/2010), EP (5/24/2011) and PXD (9/7/2011).

Clearfork A Clearfork B Clearfork C Hydrocarbon bearing zone Wolffork Hydrocarbon Column - Over 2,500' Thick AREX Baker A 112

Wolffork Oil Shale Resource Play Sutton Crockett Irion Reagan Schleicher Pangea West Northern & Central Pangea 59,000 gross acres Continue pilot program Encouraging results from recent pilot wells 85,000 gross acres Begin vertical development (from pilot) Establish horizontal development Southern Pangea 15,000 gross acres 3-D seismic underway Begin horizontal drilling 4Q 2011 Vertical pilot - 2nd phase Horizontal pilot Horizontal drilling in progress Horizontal on drilling order Drilling depth to top of Wolfcamp Legend

Vertical Wolffork Economics Play Type Wolffork Avg. EUR 110 MBoe Avg. Well Cost $1.2 MM F&D $10.91/Boe Potential Locations 1,825 Gross Resource Potential 200+ MMBoe (CHART) VERTICAL WOLFFORK BTAX IRR SENSITIVITIES Note: Potential locations based on 20 acre spacing. Economics assume NYMEX gas strip 7/2011 and NGL price based on 50% of oil WTI price. Target Clearfork and Wolfcamp zones Drilling depth < 7,000' ~75% of EUR comprised of oil and NGLs Beginning vertical Wolffork development program 1 active rig in NE Pangea

Vertical Wolffork Recompletion Economics Play Type Wolffork Recompletions Avg. EUR 93 MBoe Avg. Well Cost $750 M F&D $8.06/Boe Potential Locations 190 Gross Resource Potential 17+ MMBoe VERTICAL WOLFFORK RECOMPLETIONS BTAX IRR SENSITIVITIES Target Clearfork and Wolfcamp zones Commingle with existing production ~75% of EUR comprised of oil and NGLs Increasing recompletions to 4 per month beginning October 2011 Note: Potential locations based on 20 to 40 acre spacing. Economics assume NYMEX gas strip 7/2011 and NGL price based on 50% of oil WTI price. (CHART)

(CHART) Vertical Wolffork Well Profile Type/decline curves, estimated EURs, typical well related oil and gas in place, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, OGIP, recovery factors and costs prove correct. The Company has very limited production experience with these projects, and accordingly, such estimates may change significantly as results from more wells are evaluated. Estimates of resource potential, EURs and OGIP do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. IRR estimates assume NYMEX forward-curve gas pricing and Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic or G&A costs. IP Profile 58 BO, 11 Bbls NGLs, 64 Mcf gas Avg. EUR 110 MBoe Annual Decline 62% 29% 20% 15% 12% 10% 9% 8% 7% 6%

Vertical Canyon Wolffork Economics Play Type Canyon Wolffork Avg. EUR 193 MBoe Avg. Well Cost $1.5 MM F&D $7.77/Boe Potential Locations 440 Gross Resource Potential 85 MMBoe VERTICAL CANYON WOLFFORK BTAX IRR SENSITIVITIES Note: Potential locations based on 40 acre spacing. Economics assume NYMEX gas strip 7/2011 and NGL price based on 50% of oil WTI price. 1 active rig in Pangea (CHART)

(CHART) Vertical Canyon Wolffork Well Profile Annual Decline 68% 32% 21% 16% 12% 10% 9% 8% 7% 6% Type/decline curves, estimated EURs, typical well related oil and gas in place, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, OGIP, recovery factors and costs prove correct. The Company has very limited production experience with these projects, and accordingly, such estimates may change significantly as results from more wells are evaluated. Estimates of resource potential, EURs and OGIP do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. IRR estimates assume NYMEX forward-curve gas pricing and Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic or G&A costs. IP Profile 66 BO, 52 Bbls NGLs, 315 Mcf gas Avg. EUR 193 MBoe

Vertical Horizontal Eagle Ford 49,500 323,813 6.5x Niobrara 40,000 290,000 7.3x Wolfcamp 80,000 450,000 5.6x Well EUR (Boe) Oil Shale Play Potential Uplift Notes: Eagle Ford and Niobrara well EURs from industry publications. Wolfcamp well EUR is based on AREX estimates. Horizontal Wolfcamp - Enhancing Wolfcamp Value

Horizontal Wolfcamp Economics Play Type Horizontal Wolfcamp Avg. EUR 450 MBoe Targeted Well Cost $5.5 MM F&D $12.22/Boe Potential Locations 500 Gross Resource Potential 225 MMBoe HORIZONTAL WOLFCAMP BTAX IRR SENSITIVITIES (CHART) Horizontal drilling improves recoveries and returns Target Wolfcamp zone 7,000'+ lateral length, 20+ frac stages ~74% of EUR comprised of oil and NGLs Recent horizontal pilot results encouraging Transitioning to development program - 1 active rig in Pangea Note: Potential locations based on 1,000-foot spacing between each horizontal well. Economics assume NYMEX gas strip 7/2011 and NGL price based on 50% of oil WTI price. Recent horizontal Wolfcamp well results University 45 A 701H - 6,859' lateral, 21 frac stages Initial 24-hour flow rate 693 BOEPD, 94% liquids (613 BO, 41 Bbls NGLs, 237 Mcf gas) Cinco Terry G 701H - 7,609' lateral, 23 frac stages Initial 24-hour flow rate 328 BOEPD, 76% liquids (168 BO, 81 Bbls NGLs, 473 Mcf gas)

(CHART) Horizontal Wolfcamp Well Profile Annual Decline 62% 31% 21% 16% 13% 11% 9% 8% 7% 6% Type/decline curves, estimated EURs, typical well related oil and gas in place, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, OGIP, recovery factors and costs prove correct. The Company has very limited production experience with these projects, and accordingly, such estimates may change significantly as results from more wells are evaluated. Estimates of resource potential, EURs and OGIP do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. IRR estimates assume NYMEX forward-curve gas pricing and Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic or G&A costs. IP Profile 230 BO, 47 Bbls NGLs, 285 Mcf gas Avg. EUR 450 MBoe

Summary - AREX Total Resource Potential Play Type Locations Avg. EUR (MBoe) F&D ($/Boe) Gross Resource Potential (MMBoe) Horizontal Wolfcamp 500 450 12.22 225 Vertical Wolffork 1,825 110 10.91 200 Vertical Canyon Wolffork 440 193 7.77 85 Vertical Wolffork Recompletions 190 93 8.06 17 500+ MMBoe Total Gross Resource Potential 500+ MMBoe Total Gross Resource Potential 500+ MMBoe Total Gross Resource Potential 500+ MMBoe Total Gross Resource Potential 500+ MMBoe Total Gross Resource Potential Type/decline curves, estimated EURs, typical well related oil and gas in place, recovery factors and well costs represent Company estimates based on evaluation of petrophysical analysis, core data and well logs, well performance from limited drilling and recompletion results and seismic data, and have not been reviewed by independent engineers. These are presented as hypothetical recoveries if assumptions and estimates regarding recoverable hydrocarbons, OGIP, recovery factors and costs prove correct. The Company has very limited production experience with these projects, and accordingly, such estimates may change significantly as results from more wells are evaluated. Estimates of resource potential, EURs and OGIP do not constitute reserves, but constitute estimates of contingent resources which the SEC has determined are too speculative to include in SEC filings. IRR estimates assume NYMEX forward-curve gas pricing and Company-generated EUR and decline curve estimates based on Company drilling and completion cost estimates that do not include land, seismic or G&A costs.

Concentrated geographic footprint focused on West Texas Midland Basin oil/liquids-rich plays 140,400+ net, primarily contiguous acres, 100% operated More than 525 wells drilled by Approach since 2004, with a 93%+ success rate Established basin infrastructure Strong growth track record at competitive costs Historical production and reserve growth driven by Canyon Sands liquids-rich gas play Future growth from vertical Wolffork and horizontal Wolfcamp plays Low-cost operator with best-in-class F&D and lifting costs Developing significant resource potential from vertical Wolffork and horizontal Wolfcamp plays Gross, unrisked resource potential totals more than 500+ MMBoe Additional upside potential from down-spacing opportunities Strong balance sheet to execute development plan $260 MM borrowing base Key Takeaways

Financial Framework

2Q 2011 Highlights 2Q 2011 FINANCIAL HIGHLIGHTS Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, Three Months Ended June 30, 2011 2011 2010 2010 Revenues ($M) $ 29,123 $ 13,155 Net income ($M) $ 7,990 $ 1,551 Net income per diluted share $ 0.28 $ 0.07 Adjusted net income (non-GAAP) ($M) $ 6,516 $ 2,806 Adjusted net income per diluted share $ 0.23 $ 0.13 EBITDAX (non-GAAP) ($M) $ 20,999 $ 10,345 EBITDAX per diluted share $ 0.73 $ 0.49 Realized price ($/Boe) $ 47.90 $ 35.36 Production (MBoe/d) 6.7 4.1 Notes: See "Adjusted Net Income" and "EBITDAX" reconciliation slides in appendix for reconciliation of adjusted net income and EBITDAX, respectively. Realized price excludes commodity derivatives. AREX 2Q 2011 SUMMARY 7th Consecutive quarter of production growth 2Q'11 production 6.7 MBoe/d Proved reserves increase 32% to 66.8 MMBoe Oil & NGL reserves increase 44% to 36.9 MMBbls Reserve mix now 55% oil & NGLs Improving well results from horizontal Wolfcamp pilot program Horizontal Wolfcamp and vertical Wolffork plays add over 500 MMBoe of gross, unrisked resource potential

2Q 2011 Operating Highlights DELIVERING Q/Q PRODUCTION GROWTH OPERATING HIGHLIGHTS production (mboe/d) 56% oil & ngls Q2'11 production up 63% to 6.7 MBoe/d Oil & NGL production up 203% to 340 MBbls Drilled 15 wells, completed 16 wells, and 5 wells waiting on completion Horizontal Wolfcamp well results University 45 A 701H - 6,859' lateral, 21 frac stages Initial 24-hour flow rate 693 BOEPD, 94% liquids (613 BO, 41 Bbls NGLs, 237 Mcf gas) Cinco Terry G 701H - 7,609' lateral, 23 frac stages Initial 24-hour flow rate 328 BOEPD, 76% liquids (168 BO, 81 Bbls NGLs, 473 Mcf gas)

Current 2011Guidance Current 2011Guidance Current 2011Guidance Current 2011Guidance Production Total (MBoe) 2,300 - 2,450 2,300 - 2,450 2,300 - 2,450 Percent Oil & NGLs 55% 55% 55% Operating costs and expenses ($/per Boe) Lease operating $ 4.25 - 5.50 4.25 - 5.50 4.25 - 5.50 Severance and production taxes $ 2.35 - 3.00 2.35 - 3.00 2.35 - 3.00 Exploration $ 4.00 - 5.00 4.00 - 5.00 4.00 - 5.00 General and administrative $ 6.25 - 6.75 6.25 - 6.75 6.25 - 6.75 Depletion, depreciation and amortization $ 12.00 - 15.00 12.00 - 15.00 12.00 - 15.00 Capital expenditures ($MM) Approximately $220 Approximately $220 Approximately $220 2011 Operating and Financial Guidance Guidance is forward-looking information that is subject to a number of risks and uncertainties, many of which are beyond the Company's control. See slide 2, "Forward- looking statements," for additional information.

Natural gas (NYMEX - Henry Hub) 2011 Price swaps contracted for 230,000 MMBtu/month at $4.86/MMBtu June 2011 - December 2011 Price swaps contracted for 200,000 MMBtu/month at $4.74/MMBtu 65% of estimated 2011 natural gas production hedged at weighed average price of $4.82/MMBtu(1) Natural gas (WAHA - Basis Differential) 2011 Basis swaps contracted for 300,000 MMBtu/month at $(0.53)/MMBtu Oil (NYMEX - West Texas Intermediate) May 2011 - December 2011 Collars contracted for 1,000 Bbls/d Floor $100.00 - Ceiling $127.00 (1) Based on midpoint of 2011 production guidance. 2011 Hedge Position CURRENT HEDGE POSITION

Appendix Non-gaap reconciliations

(in thousands, except per-share amounts) Three Months EndedJune 30, Three Months EndedJune 30, Three Months EndedJune 30, Three Months EndedJune 30, 2011 2011 2010 2010 Net income $ 7,990 $ 1,551 Adjustments for certain items: Unrealized (gain) loss on commodity derivatives (2,231) 1,901 Gain on sale of oil and gas properties (3) ^ Related income tax effect 760 (646) Adjusted net income $ 6,516 $ 2,806 Adjusted net income per diluted share $ 0.23 $ 0.13 The amounts included in the calculation of adjusted net income and adjusted net income per diluted share below were computed in accordance with GAAP. We believe adjusted net income and adjusted net income per diluted share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items whose timing or amount cannot be reasonably determined. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. Adjusted Net Income Reconciliation (Unaudited)

We define EBITDAX as net income, plus (1) exploration expense, (2) depletion, depreciation and amortization expense, (3) share-based compensation expense, (4) unrealized (gain) loss on commodity derivatives, (5) gain on sale of oil and gas properties, (6) interest expense, and (7) income taxes. EBITDAX is not a measure of net income or cash flow as determined by GAAP. The amounts included in the calculation of EBITDAX were computed in accordance with GAAP. EBITDAX is presented herein and reconciled to the GAAP measure of net income because of its wide acceptance by the investment community as a financial indicator of a company's ability to internally fund development and exploration activities. This measure is provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and posted on our website. (in thousands, except per-share amounts) Three Months EndedJune 30, Three Months EndedJune 30, Three Months EndedJune 30, Three Months EndedJune 30, 2011 2011 2010 2010 Net income $ 7,990 $ 1,551 Exploration 280 187 Depletion, depreciation and amortization 7,987 5,010 Share-based compensation 1,713 416 Unrealized (gain) loss on commodity derivatives (2,231) 1,901 Gain on sale of oil and gas properties (3) ^ Interest expense, net 863 550 Income tax provision 4,400 730 EBITDAX $ 20,999 $ 10,345 EBITDAX per diluted share $ 0.73 $ 0.49 EBITDAX Reconciliation (Unaudited)

We believe that providing measures of finding and development, or F&D, cost is useful to assist an evaluation of how much it costs the Company, on a per Boe basis, to add proved reserves. However, these measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP (including the notes), included in our SEC filings and to be included in our Annual Report on Form 10-K and to be filed with the SEC on or before March 15, 2012. Due to various factors, including timing differences, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods before the periods in which related increases in reserves are recorded and development costs may be recorded in periods after the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases (or decreases) in reserves independent of the related costs of such increases. As a result of the above factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in our filings with the SEC, we cannot assure you that the Company's future F&D costs will not differ materially from those set forth above. Further, the methods we use to calculate F&D costs may differ significantly from methods used by other companies to compute similar measures. As a result, our F&D costs may not be comparable to similar measures provided by other companies. The following tables reflect the reconciliation of our estimated finding and development costs to the information required by paragraphs 11 and 21 of ASC 932-235. F&D Costs Reconciliation (Unaudited) Reserve Summary (MBoe) Balance - 12/31/2010 50,715 Extensions & discoveries 8,910 Purchases 10,497 Revisions (2,196) Production (1,077) Balance - 6/30/2011 66,849 Cost Summary ($M) Property acquisition Unproved properties $ 15,440 Exploration properties 93 93 Exploration costs 4,914 4,914 Development costs 72,061 72,061 Working Interest Acquisition 70,181 70,181 Total 162,689 162,689 Finding & development costs ($/Boe) Finding & development costs ($/Boe) Finding & development costs ($/Boe) All-in F&D costs $ 9.45 Drill-bit F&D cost $ 8.64 Reserve replacement ratio (%) Reserve replacement ratio (%) Reserve replacement ratio (%) Net reserve adds (MBoe) 17,211 1H'11 Production (MBoe) (1,077) Reserve replacement 1,598%