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): December 13, 2016

 

 

GULFPORT ENERGY CORPORATION

(Exact Name of Registrant as Specified in Charter)

 

 

 

Delaware   000-19514   73-1521290

(State or other jurisdiction

of incorporation)

 

(Commission

File Number)

 

(I.R.S. Employer

Identification Number)

14313 North May Avenue

Suite 100

Oklahoma City, OK

  73134
(Address of principal executive offices)   (Zip code)

(405) 848-8807

(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 is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions:

 

Written communications pursuant to Rule 425 under the Securities Act

 

Soliciting material pursuant to Rule 14a-12 under the Exchange Act

 

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

 

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

 

 

 


Item 1.01 Entry into a Material Definitive Agreement.

Purchase Agreement

Gulfport Energy Corporation, a Delaware corporation (“Gulfport”), and Gulfport’s wholly-owned subsidiary, SCOOP Acquisition Company, LLC, entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with Vitruvian II Woodford, LLC, an unrelated third-party seller (the “Seller” or “Vitruvian”), dated as of December 13, 2016, to acquire certain assets of the Seller for a total purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash and approximately 18.8 million in shares of Gulfport’s common stock subject to certain adjustments. The transactions contemplated by the Purchase Agreement are referred to herein as the “Pending Acquisition.” Gulfport intends to fund the cash portion of the purchase price for the Pending Acquisition with the net proceeds from its concurrent equity and notes offerings described in more detail under Item 8.01 below. Any remaining net proceeds will be used for general corporate purposes, including the funding of Gulfport’s capital development plans.

The assets subject to the Pending Acquisition include 46,400 net surface acres, with multiple producing zones including the Woodford and Springer formations, in Grady, Stephens and Garvin Counties, Oklahoma. The properties subject to the Pending Acquisition are located primarily in the over-pressured liquids-rich to dry gas windows of the play and include approximately 183 Mmcfepd of net production for October 2016 based on information provided by the Seller. The Pending Acquisition also includes 48 producing horizontal wells and an additional interest in over 150 non-operated horizontal wells. Four rigs are currently operating on the acreage. Based on the estimates prepared by the Seller as of September 30, 2016 and audited by Netherland, Sewell & Associates, Inc., the estimated proved reserves attributable to the acreage subject to the Pending Acquisition are approximately 1.1 Tcfe. In connection with the closing of the Pending Acquisition, Gulfport will enter into a registration rights agreement with the Seller, providing for certain demand and piggyback registration rights with respect to the shares to be issued to Vitruvian in the Pending Acquisition.

The closing of the Pending Acquisition is subject to completion of due diligence and the satisfaction or waiver of the closing conditions set forth in the Purchase Agreement. The Pending Acquisition is expected to close in February 2017.

The Purchase Agreement is filed as Exhibit 2.1 to this Current Report on Form 8-K and incorporated herein by reference, and the foregoing description of the Purchase Agreement is qualified in its entirety by reference to such exhibit.

Amendment to Credit Facility

On December 13, 2016, Gulfport, as borrower, entered into a seventh amendment to its secured revolving credit facility (the “Credit Facility”) with The Bank of Nova Scotia, as administrative agent, and certain lenders party thereto (the “Seventh Amendment”). The Seventh Amendment (i) extends the maturity date of the Credit Facility to December 13, 2021, (ii) increases the applicable rate for all loans by 0.5%, (iii) increases the permitted amount of senior notes to $1.6 billion and provides that any future senior notes issuances will reduce the facility’s borrowing base by 25% of the amount of such issuance (net of any proceeds used to repurchase or redeem senior notes), (iv) increases the minimum recognized value of Gulfport’s proved mineral interests that must be mortgaged under the facility from 80% to 85%, and (v) requires Gulfport to grant perfected security interests over certain deposit and securities accounts.

The preceding summary of the Seventh Amendment is qualified in its entirety by reference to the full text of such agreement, a copy of which is attached as Exhibit 10.1 hereto and 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 in Item 1.01 above with respect to the Seventh Amendment is incorporated herein by reference, as applicable.

Item 3.02 Unregistered Sales of Equity Securities.

Pursuant to the Purchase Agreement, Gulfport intends to issue approximately 18.8 million shares of Gulfport’s common stock to the Seller at the closing of the Pending Acquisition. The shares of Gulfport’s common stock to be issued to Vitruvian, as described in this Item 3.02, will be issued in reliance upon the exemption from the registration requirements of the Securities Act of 1933, as amended (the “Securities Act”), provided by Section 4(a)(2) of the Securities Act as sales by an issuer not involving any public offering.

The information set forth in Item 1.01 with respect to the Pending Acquisition is incorporated herein by reference.

Item 7.01 Regulation FD Disclosure.

Information Regarding Pending Acquisition

On December 14, 2016, Gulfport issued a press release announcing the Pending Acquisition. A copy of the press release is attached hereto as Exhibit 99.1. On December 14, 2016, Gulfport also posted certain information relating to the Pending Acquisition and the Seller under the “Investors” section of Gulfport’s website.

Item 8.01. Other Events.

Equity Offering

On December 14, 2016, Gulfport issued a press release announcing that it commenced an underwritten public offering (the “Equity Offering”) of 29,000,000 shares of its common stock, subject to market and other conditions, to fund a portion of the purchase price for the Pending Acquisition. The underwriters will have an option to purchase up to an additional 4,350,000 shares from Gulfport (collectively, the “Public Shares”). The Public Shares will be issued under an effective automatic shelf registration statement on Form S-3 filed by Gulfport with the Securities and Exchange Commission (the “SEC”) on December 14, 2016, and a prospectus, which will consist of a base prospectus filed with the SEC on December 14, 2016, and a preliminary prospectus supplement and a prospectus supplement which have not yet been filed with the SEC. A copy of this press release is attached hereto as Exhibit 99.2.

This report shall not constitute an offer to sell or the solicitation of an offer to buy these securities, nor shall there be any sale of these securities in any state or jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of such state or jurisdiction. The Equity Offering may only be made by means of a prospectus supplement and related base prospectus.

Notes Offering

On December 14, 2016, Gulfport issued a press release announcing that it proposes to offer, subject to market conditions and other factors, $600.0 million aggregate principal amount of its Senior Notes due 2025 (the “Notes”) to fund a portion of the purchase price for the Pending Acquisition and for general corporate purposes, which may include the funding of a portion of Gulfport’s capital development plans. The Notes will be offered to qualified institutional buyers pursuant to Rule 144A under the Securities Act, and to certain non-U.S. persons in accordance with Regulation S under the Securities Act (the “Notes Offering”). A copy of the press release is attached hereto as Exhibit 99.3 and is incorporated herein by reference.

The Notes will not be registered under the Securities Act or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from such registration requirements. This report is neither an offer to sell nor a solicitation of an offer to buy any of these securities and shall not constitute an offer, solicitation or sale in any jurisdiction in which such offer, solicitation or sale is unlawful.


Financial Information with Respect to Seller

Included in this filing as Exhibit 99.4 are the historical audited financial statements of the Seller for the periods described in Item 9.01(a) below, the notes related thereto and the Report of Independent Auditors. Also included in this filing as Exhibit 99.4 are the historical unaudited financial statements of the Seller for the periods described in Item 9.01(a) below and the notes related thereto.

Included in this filing as Exhibit 99.5 is the unaudited pro forma consolidated financial information described in Item 9.01(b) below.

Report of Independent Petroleum Engineer

Included in this filing as Exhibits 99.6, 99.7 and 99.8 are the reports of independent petroleum engineer Netherland, Sewell & Associates, Inc. (“NSAI”) as of December 31, 2015, 2014 and 2013, respectively. Included in this filing as Exhibit 99.9 is a letter from NSAI auditing the proved reserves and future revenue estimates prepared by the Seller as of September 30, 2016.

Item 9.01. Financial Statements and Exhibits.

(a) Financial Statements of Business Acquired.

 

    Audited financial statements of Vitruvian II Woodford, LLC, comprised of the balance sheets as of December 31, 2015 and 2014, and the related statements of operations, changes in members’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015, and the related notes to the financial statements, attached as Exhibit 99.4 hereto.

 

    Unaudited financial statements of Vitruvian II Woodford, LLC, comprised of the balance sheet as of December 31, 2015 and September 30, 2016, the related statement of operations for the nine months ended September 30, 2016 and 2015, the related statement of changes in members’ equity for the nine months ended September 30, 2016, the related statement of cash flows for the nine months ended September 30, 2016 and 2015, and the related notes to the unaudited financial statements, attached as Exhibit 99.4 hereto.

(b) Pro Forma Financial Statements

The following unaudited pro forma combined financial information of Gulfport, giving effect to the Pending Acquisition and the related financing transactions, is included in Exhibit 99.5 hereto:

 

    Unaudited Pro Forma Consolidated Balance Sheet as of September 30, 2016.

 

    Unaudited Pro Forma Consolidated Statement of Operations for the year ended December 31, 2015 and the nine months ended September 30, 2016.

(d) Exhibits

 

Number

  

Exhibit

  2.1    Purchase and Sale Agreement, dated as of December 13, 2016, by and among Gulfport Energy Corporation, SCOOP Acquisition Company, LLC and Vitruvian II Woodford, LLC.*
10.1    Seventh Amendment to Amended and Restated Credit Agreement, dated as of December 13, 2016, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto.
23.1    Consent of PricewaterhouseCoopers LLP.


Number

  

Exhibit

23.2    Consent of Netherland, Sewell & Associates, Inc.
99.1    Press Release dated December 14, 2016 entitled “Gulfport Energy Corporation Announces Entry into the SCOOP Play with Complementary Acquisition of Approximately 85,000 Net Effective Acres.”
99.2    Press Release dated December 14, 2016 entitled “Gulfport Energy Corporation Launches Common Stock Offering.”
99.3    Press Release dated December 14, 2016 entitled “Gulfport Energy Corporation Launches Proposed $600 Million Offering of Senior Notes.”
99.4    Historical audited and unaudited financial statements of Vitruvian II Woodford, LLC.
99.5    Unaudited pro forma combined financial information.
99.6    Netherland, Sewell & Associates, Inc. Estimates of Reserves and Future Revenue as of December 31, 2015.
99.7    Netherland, Sewell & Associates, Inc. Estimates of Reserves and Future Revenue as of December 31, 2014.
99.8    Netherland, Sewell & Associates, Inc. Estimates of Reserves and Future Revenue as of December 31, 2013.
99.9    Netherland, Sewell & Associates, Inc. letter auditing the internal estimates prepared by Vitruvian II Woodford, LLC as of September 30, 2016.

 

* The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission.


SIGNATURE

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 thereunto duly authorized.

 

   

GULFPORT ENERGY CORPORATION

Date: December 15, 2016     By:  

/s/ Keri Crowell

     

Keri Crowell

Chief Accounting Officer


Exhibit Index

 

Number

  

Exhibit

  2.1    Purchase and Sale Agreement, dated as of December 13, 2016, by and among Gulfport Energy Corporation, SCOOP Acquisition Company, LLC and Vitruvian II Woodford, LLC.*
10.1    Seventh Amendment to Amended and Restated Credit Agreement, dated as of December 13, 2016, among Gulfport Energy Corporation, as borrower, The Bank of Nova Scotia, as administrative agent, and the lenders party thereto.
23.1    Consent of PricewaterhouseCoopers LLP.
23.2    Consent of Netherland, Sewell & Associates, Inc.
99.1    Press Release dated December 14, 2016 entitled “Gulfport Energy Corporation Announces Entry into the SCOOP Play with Complementary Acquisition of Approximately 85,000 Net Effective Acres.”
99.2    Press Release dated December 14, 2016 entitled “Gulfport Energy Corporation Launches Common Stock Offering.”
99.3    Press Release dated December 14, 2016 entitled “Gulfport Energy Corporation Launches Proposed $600 Million Offering of Senior Notes.”
99.4    Historical audited and unaudited financial statements of Vitruvian II Woodford, LLC.
99.5    Unaudited pro forma combined financial information.
99.6    Netherland, Sewell & Associates, Inc. Estimates of Reserves and Future Revenue as of December 31, 2015.
99.7    Netherland, Sewell & Associates, Inc. Estimates of Reserves and Future Revenue as of December 31, 2014.
99.8    Netherland, Sewell & Associates, Inc. Estimates of Reserves and Future Revenue as of December 31, 2013.
99.9    Netherland, Sewell & Associates, Inc. letter auditing the internal estimates prepared by Vitruvian II Woodford, LLC as of September 30, 2016.

 

* The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission.

Exhibit 2.1

 

PURCHASE AND SALE AGREEMENT

between

VITRUVIAN II WOODFORD, LLC

as Seller

and

SCOOP ACQUISITION COMPANY, LLC

as Buyer

and

GULFPORT ENERGY CORPORATION

as Parent

dated

December 13, 2016


TABLE OF CONTENTS

 

              Page  
ARTICLE I   

DEFINITIONS AND INTERPRETATION

     1   
           1.1    Defined Terms      1   
  1.2    References and Rules of Construction      1   
ARTICLE II   

PURCHASE AND SALE

     2   
  2.1    Purchase and Sale      2   
  2.2    Excluded Assets      3   
  2.3    Revenues and Expenses      3   
ARTICLE III   

PURCHASE PRICE

     4   
  3.1    Purchase Price      4   
  3.2    Deposit      4   
  3.3    Adjustments to Cash Purchase Price      5   
  3.4    Adjustment Methodology      6   
  3.5    Preliminary Settlement Statement      6   
  3.6    Escrow      7   
  3.7    Final Settlement Statement      8   
  3.8    Disputes      9   
  3.9    Allocated Values      9   
  3.10    Allocation for Imbalances at Closing      9   
ARTICLE IV   

REPRESENTATIONS AND WARRANTIES OF SELLER

     10   
  4.1    Organization, Existence and Qualification      10   
  4.2    Authorization, Approval and Enforceability      10   
  4.3    No Conflicts      10   
  4.4    Consents      10   
  4.5    Bankruptcy      11   
  4.6    Brokers’ Fees      11   
  4.7    Litigation      11   
  4.8    Material Contracts      11   
  4.9    No Violation of Laws      12   
  4.10    Preferential Purchase Rights      12   
  4.11    Royalties, Etc      12   
  4.12    Imbalances      13   
  4.13    Current Commitments      13   
  4.14    Asset Taxes      13   
  4.15    Wells      13   
  4.16    Non-Consent Operations      14   
  4.17        Notices of Violation      14   

 

i


   4.18    Accredited Investor; Investment Intent      14   
   4.19    ERISA      15   

ARTICLE V

  

REPRESENTATIONS AND WARRANTIES OF BUYER

     15   
   5.1    Organization, Existence and Qualification      15   
   5.2    Authorization, Approval and Enforceability      15   
            5.3    No Conflicts      15   
   5.4    Consents      16   
   5.5    Bankruptcy      16   
   5.6    Litigation      16   
   5.7    Financing      16   
   5.8    Regulatory      16   
   5.9    Independent Evaluation      17   
   5.10        Brokers’ Fees      17   
   5.11    Accredited Investor      17   
   5.12    Issuance of Parent Shares      17   
   5.13    Capitalization      17   
   5.14    SEC Reports      18   
   5.15    Investment Company      18   
   5.16    Nasdaq Listing      18   
   5.17    Form S-3 Eligibility      19   
   5.18    Absence of Certain Changes or Events      19   

ARTICLE VI

  

CERTAIN AGREEMENTS

     19   
   6.1    Conduct of Business by Seller      19   
   6.2    Conduct of Business by Parent.      20   
   6.3    Governmental Bonds      21   
   6.4    Required Information      22   
   6.5    Amendment to Schedules      22   
   6.6    Government Filings      22   
   6.7    Parent Share Restriction      23   
   6.8    Listing of Equity Consideration      23   
   6.9    Transition Services Agreement.      23   

ARTICLE VII

  

BUYER PARTIES’ CONDITIONS TO CLOSING

     23   
   7.1    Representations      23   
   7.2    Performance      24   
   7.3    No Legal Proceedings      24   
   7.4    Title Defects and Environmental Defects      24   
   7.5    Closing Deliverables      24   
   7.6    Government Consents      24   

ARTICLE VIII

  

SELLER’S CONDITIONS TO CLOSING

     24   

 

ii


  8.1    Representations      24   
  8.2    Performance      24   
  8.3    No Legal Proceedings      24   
  8.4    Title Defects and Environmental Defects      25   
  8.5    Closing Deliverables      25   
           8.6    Government Consents      25   
ARTICLE IX   

CLOSING

     25   
  9.1    Date of Closing      25   
  9.2    Place of Closing      25   
  9.3    Closing Obligations      25   
  9.4    Records      27   

ARTICLE X

  

ACCESS/DISCLAIMERS

     28   
  10.1    Access      28   
  10.2    Confidentiality      30   
  10.3    Disclaimers      30   

ARTICLE XI

  

TITLE MATTERS; CASUALTY; TRANSFER RESTRICTIONS

     32   
  11.1    Seller’s Title      32   
  11.2    Notice of Title Defects; Defect Adjustments      33   
  11.3    Casualty and Condemnation Loss      38   
  11.4    Preferential Purchase Rights and Consents to Assign      39   

ARTICLE XII

  

ENVIRONMENTAL MATTERS

     41   
  12.1    Notice of Environmental Defects      41   
  12.2    NORM, Asbestos, Wastes and Other Substances      44   

ARTICLE XIII

  

ASSUMPTION; INDEMNIFICATION; SURVIVAL

     45   
  13.1    Assumption by Buyer      45   
  13.2    Indemnities of Seller      45   
  13.3    Indemnities of Buyer      46   
  13.4    Limitation on Liability      46   
  13.5    Express Negligence      47   
  13.6    Exclusive Remedy      47   
  13.7    Indemnification Procedures      48   
  13.8    Survival      49   
  13.9    Waiver of Right to Rescission      50   
  13.10        Insurance      50   
  13.11    Non-Compensatory Damages      50   
  13.12    Disclaimer of Application of Anti-Indemnity Statutes      51   

 

iii


ARTICLE XIV   
TERMINATION, DEFAULT AND REMEDIES      51   
   14.1    Right of Termination      51   
   14.2    Effect of Termination      51   
            14.3    Return of Documentation and Confidentiality      52   
ARTICLE XV   

MISCELLANEOUS

     53   
   15.1    Appendices, Exhibits and Schedules      53   
   15.2    Expenses and Taxes      53   
   15.3    Assignment      55   
   15.4    Preparation of Agreement      55   
   15.5    Publicity      55   
   15.6    Notices      56   
   15.7    Further Cooperation      57   
   15.8    Filings, Notices and Certain Governmental Approvals      57   
   15.9    Entire Agreement; Conflicts      57   
   15.10    Parties in Interest      58   
   15.11        Amendment      58   
   15.12    Waiver; Rights Cumulative      58   
   15.13    Governing Law; Jurisdiction      58   
   15.14    Severability      59   
   15.15    Removal of Name      59   
   15.16    Counterparts      59   
   15.17    Like-Kind Exchange      59   

 

iv


LIST OF EXHIBITS AND SCHEDULES

 

Annex I

           Defined Terms

Exhibit A-1

           Leases

Exhibit A-2

           Fee Minerals

Exhibit A-3

           Surface Fee Interests

Exhibit A-4

           Production Office

Exhibit B

           Wells

Exhibit C

           Excluded Assets

Exhibit D

           Form of Assignment and Bill of Sale

Exhibit E

           Form of Mineral Deed

Exhibit F

           Form of Surface Deed

Exhibit G

           Form of Assignment and Assumption Agreement

Exhibit H

           Form of Registration Rights Agreement

Schedule 3.3

           Pre-Paid Operating Costs

Schedule 3.9

           Allocated Values

Schedule 3.10

           Allocation for Imbalances

Schedule 4.4

           Consents

Schedule 4.7

           Litigation

Schedule 4.8

           Material Contracts

Schedule 4.9

           Violation of Laws

Schedule 4.10

           Preferential Purchase Rights

Schedule 4.11

           Royalties, Etc.

Schedule 4.12

           Imbalances

Schedule 4.13

           Current Commitments

Schedule 4.14

           Asset Taxes

Schedule 4.15

           Force Pooling

Schedule 4.16

           Non-Consent Operations

Schedule 4.17

           Notices of Violations

Schedule 6.1

           Conduct of Business

Schedule 6.2

           Conduct of Business by Parent

Schedule 6.3

           Governmental Bonds

 

v


PURCHASE AND SALE AGREEMENT

This PURCHASE AND SALE AGREEMENT (this “ Agreement ”) is executed as of the 13th day of December, 2016 (the “ Execution Date ”), and is between (i) Vitruvian II Woodford, LLC, a Delaware limited liability company (“ Seller ”), (ii) SCOOP Acquisition Company, LLC, a Delaware limited liability company (“ Buyer ”) and (iii) Gulfport Energy Corporation, a Delaware corporation (“ Parent ”, and, together with Buyer, “ Buyer Parties ” and each a “ Buyer Party ”). Seller, Buyer and Parent are each referred to as a “ Party ” and collectively referred to as the “ Parties .”

RECITALS

Seller desires to sell and assign, and Buyer desires to purchase, all of Seller’s right, title and interest in and to the Assets (as defined hereinafter) effective as of the Effective Time (as defined hereinafter).

NOW , THEREFORE , for and in consideration of the mutual promises contained herein, the benefits to be derived by each Party hereunder, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Seller, Buyer and Parent hereby agree as follows:

ARTICLE I

DEFINITIONS AND INTERPRETATION

1.1 Defined Terms . Capitalized terms used herein shall have the meanings set forth in Annex I , unless the context otherwise requires.

1.2 References and Rules of Construction . All references in this Agreement to Appendices, Exhibits, Schedules, Articles, Sections, subsections and other subdivisions refer to the corresponding Appendices, Exhibits, Schedules, Articles, Sections, subsections and other subdivisions of or to this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any Articles, Sections, subsections and other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement, and shall be disregarded in construing the language hereof. The words “this Agreement,” “herein,” “hereby,” “hereunder” and “hereof,” and words of similar import, refer to this Agreement as a whole and not to any particular Article, Section, subsection or other subdivision unless expressly so limited. The words “this Article,” “this Section,” and “this subsection,” and words of similar import, refer only to Article, Section or subsection hereof in which such words occur. References in this Agreement to any agreement, including this Agreement, refer to such agreement as it may be amended, supplemented or otherwise modified from time to time. Wherever the words “include,” “includes” or “including” are used in this Agreement, they shall be deemed to be followed by the words “without limiting the foregoing in any respect.” All references to “$” or “dollars” shall be deemed references to United States Dollars. Each accounting term not defined herein will have the meaning given to it under GAAP as interpreted as of the Execution Date. Pronouns in masculine, feminine or neuter genders shall be construed to state and include any other gender, and words, terms and titles (including terms defined herein) in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires.

 

1


ARTICLE II

PURCHASE AND SALE

2.1 Purchase and Sale . Subject to the terms and conditions of this Agreement, Seller agrees to sell, and Buyer agrees to purchase, as of the Effective Time, all of Seller’s right, title and interest in and to the assets described in Section 2.1(a) through Section 2.1(l) below (such right, title and interest, less and except the Excluded Assets, collectively, the “ Assets ”):

(a) the oil and gas leases of Seller described on Exhibit A-1 and any other oil, gas, and mineral leases and subleases, royalties, overriding royalties, net profits interests and carried interests (to the extent relating to such leasehold), and, without limiting the foregoing, the other rights (of whatever character, whether legal or equitable, and whether vested or contingent) to the Hydrocarbons in, on, under, and that may be produced therefrom and the lands described therein, together with any and all other right, title and interest of Seller in and to the leasehold estates created thereby subject to the terms, conditions, covenants and obligations set forth in such leases and/or on Exhibit A-1 (Seller’s interest in such leases, the “ Leases ”);

(b) all rights and interests in, under or derived from all unitization, communitization and pooling agreements, declarations and orders (including statutory forced pooling agreements, declarations and orders) in effect with respect to any of the Leases and the units created thereby (Seller’s interest in such units, the “ Units ”);

(c) the wells set forth on Exhibit B (Seller’s interest in such wells, the “ Wells ”) and all Hydrocarbons produced therefrom or allocated thereto from and after the Effective Time; all Hydrocarbons in storage or existing in pipelines, plants and/or tanks (including inventory) as of the Effective Time (whether produced before or after the Effective Time); and all Hydrocarbons attributable to Seller’s right to make up underproduction;

(d) the fee mineral interests described on Exhibit A-2 (the “ Fee Minerals ”);

(e) the surface estate in and covering each tract of land described on Exhibit  A-3 and all improvements, fixtures, facilities and appurtenances located thereon or relating thereto (including all field offices located thereon and described on Exhibit A-3 ) (the “ Surface Fee Interests ”);

(f) the real property lease related to the production office located in Lindsay, Oklahoma and described on Exhibit A-4 and all vehicles and inventory located thereon and described on Exhibit A-4 (the “ Production Office ”);

(g) to the extent that they may be assigned, subject to Section  11.4(b)(iv) , all Applicable Contracts and all rights thereunder;

 

2


(h) to the extent that they may be assigned, subject to Section  11.4(b)(iv) , all permits, licenses, servitudes, easements and rights-of-way to the extent used or held for use in connection with the ownership or operation of any of the Leases, Wells, Units or other Assets;

(i) all equipment, machinery, fixtures and other personal, movable and mixed property, operational and nonoperational, used or held for use in connection with the Wells, Leases, Units or other Assets, including pipelines, gathering systems, manifolds, well equipment, casing, tubing, pumps, motors, fixtures, machinery, compression equipment, flow lines, processing and separation facilities, pads, structures, materials and other items used or held for use in the operation thereof, in each case, regardless of the location thereof (collectively, the “ Personal Property ”);

(j) except to the extent transfer thereof is subject to a fee payable to a Third Party (other than an Affiliate of Seller) that Buyer has not agreed in writing to pay or a consent that has not been obtained, all geological or geophysical information or seismic data related to Leases or Wells which is owned by or on behalf of Seller or its Affiliates and any geological or geophysical information or seismic data related to the Leases or Wells licensed from Third Parties (collectively, the “ Seismic Data ”).

(k) all Imbalances relating to the Assets; and

(l) the following, to the extent relating to Seller’s ownership and operation of the Assets and in Seller’s or its Affiliates’ possession or control (collectively the “ Records ”): all title records; title opinions; well logs; well tests; well files; mud logs; directional surveys; core reports; daily drilling records; machinery and equipment maintenance files; health, environmental and safety information and records; production and accounting records in Excel format reflecting current ownership decks, well master files, division of interest files, Working Interest owner name and address files, revenue and joint interest billing account information; and other lease files, land files, and contract files.

2.2 Excluded Assets . Seller shall reserve and retain all of the Excluded Assets.

2.3 Revenues and Expenses . Subject to Section 3.7(b) , Seller shall remain entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds) and shall remain responsible (by payment, through the adjustments to the Cash Purchase Price hereunder or otherwise) for all Operating Expenses, in each case, attributable to the Assets for the period of time prior to the Effective Time. Subject to Section 3.7(b) , and subject to the occurrence of Closing, Buyer shall be entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds), and shall be responsible (by payment, through the adjustments to the Cash Purchase Price hereunder or otherwise) for all Operating Expenses, in each case, attributable to the Assets for the period of time from and after the Effective Time. “ Operating Expenses ” means all operating expenses (including costs of insurance) and all capital expenditures incurred in the ownership and operation of the Assets in the ordinary course of business and, where applicable, in accordance with the relevant operating or unit agreement, if any, and overhead costs charged to the Assets under the relevant operating or unit agreement, if any, but excluding Liabilities attributable to (A) personal injury or death attributable to the ownership of, or Seller’s, its Affiliate’s or a Third

 

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Party’s operation of the Assets; (B) disposal of Hazardous Substances off-site of the Assets; (C) obligations with respect to Imbalances; (D) obligations with respect to Environmental Conditions, Environmental Defects and Liabilities imposed under Environmental Laws with respect to the Assets; (E) Asset Taxes, Income Taxes or Transfer Taxes; or (F) actions taken by Seller to cure any Title Defect, Environmental Condition or Environmental Defect under Article  XI or Article  XII . After Closing, each Party shall be entitled to participate in all joint interest audits and other audits of Operating Expenses for which such Party is entirely or in part responsible under the terms of this Section  2.3 . For the purposes of this Section  2.3 and Article III , surface or facility use or sharing fees, insurance premiums, and other Operating Expenses that are paid periodically shall be prorated based on the number of days in the applicable period falling before the Effective Time, or on or after the Effective Time.

ARTICLE III

PURCHASE PRICE

3.1 Purchase Price . The purchase price for (a) the transfer of the Assets and the transactions contemplated hereby and (b) the assumption by Buyer of the Assumed Obligations shall be One Billion Eight Hundred Fifty Million and No/100 Dollars ($1,850,000,000.00) (the “ Purchase Price ”). The Purchase Price consists of (i) One Billion Three Hundred Fifty Million and No/100 Dollars ($1,350,000,000.00) in cash or other immediately available funds (the “ Cash Purchase Price ”), and (ii) Eighteen Million Eight Hundred Thirty Two Thousand and Eight Hundred Fifty Three (18,832,853) shares (the “ Equity Consideration ”) of Parent Common Stock (the “ Parent Shares ”). Notwithstanding the foregoing, to the extent that Parent sells Parent Common Stock after the date hereof for net proceeds to the Company of less than $26.55 per share (such lesser amount being the “ Lowest Market Price ”), the number of shares issued pursuant to this Section  3.1 shall equal $500,000,000 divided by the Lowest Market Price; provided , however , that the total number of shares to be issued to Seller shall in no event exceed 19.9% of the outstanding shares of Parent Common Stock immediately prior to the Closing Date. The Cash Purchase Price (and resulting Purchase Price) shall be subject to adjustment both prior to, and after, Closing as set forth herein. The Parent Shares issued to Seller at the Closing shall be subject to adjustment in the event of stock split, combination, re-classification, recapitalization, exchange, stock dividend, or other distribution payable in Parent Common Stock with respect to shares of Parent Common Stock that occurs prior to Closing and shall be issued in the name of Seller.

3.2 Deposit . Within two (2) Business Days of the execution of this Agreement, Parent has deposited by wire transfer in same day funds into an account (the “ Escrow Account ”) with U.S. Bank National Association (the “ Escrow Agent ”) the sum of One Hundred Eighty Five Million and No/100 Dollars ($185,000,000.00), to be held, invested, and disbursed in accordance with the terms of this Agreement and an escrow agreement (the “ Escrow Agreement ”) of even date herewith (such amount, excluding any interest earned thereon, the “ Deposit ”). The Deposit shall be handled in accordance with Sections  3.6 and 14.2 . Parent agrees that it is a party to the Escrow Agreement for the benefit of Buyer and that any rights it has pursuant to the Escrow Agreement and the deposits made into the Escrow Account are held by Parent for the benefit of Buyer, to be exercised solely in accordance with the terms and conditions of this Agreement. Without limiting the foregoing, Parent agrees to give any and all instructions required to be given to the Escrow Agent by Parent or Buyer pursuant to the trms of this Agreement.

 

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3.3 Adjustments to Cash Purchase Price . The Cash Purchase Price shall be adjusted as follows, and the resulting amount shall be herein called the “ Adjusted Cash Purchase Price ”:

(a) The Cash Purchase Price shall be adjusted upward by the following amounts (without duplication):

(i) an amount equal to the value of all merchantable Hydrocarbons attributable to the Assets in storage or existing in pipelines, plants and/or tanks (including inventory, and linefill valued at one million six hundred thousand dollars ($1,600,000), but excluding basic sediment and water, tank bottoms, and other linefill or line pack Hydrocarbons) and upstream of the pipeline connection or upstream of the sales meter as of the Effective Time, the value to be based upon the actual sales price therefor to a Third Party, less Burdens on such production;

(ii) an amount equal to all Operating Expenses (excluding, for the avoidance of doubt, any Asset Taxes, Income Taxes and Transfer Taxes) paid by or on behalf of Seller that are attributable to the Assets and are incurred during the period following the Effective Time, whether paid before (but only to the extent set forth on Schedule 3.3 ) or after the Effective Time, including (A) bond and insurance premiums paid by or on behalf of Seller with respect to the period following the Effective Time and (B) Burdens, but excluding, without limitation, lease bonuses, rental payments, and similar payments paid prior to the Effective Time;

(iii) the portion of the Overhead Costs attributable to the Assets that are incurred from and after the Effective Time up to the Closing Date;

(iv) the amount of all Asset Taxes allocated to Buyer in accordance with Section  15.2 but paid or otherwise economically borne by Seller;

(v) subject to Section  3.10 , and without limiting Buyer’s rights with respect to Section  4.12 , an amount equal to $3,548,768 as complete and final settlement of all Well Imbalances attributable to the Assets;

(vi) any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by Seller and Buyer.

(b) The Cash Purchase Price shall be adjusted downward by the following amounts (without duplication):

(i) an amount equal to all proceeds actually received by or on behalf of Seller attributable to the sale of Hydrocarbons (1) produced from or allocable to the Assets during the period from and following the Effective Time or (2) contained in storage or existing in pipelines, plants and/or tanks (including inventory) as of the Effective Time for which an upward adjustment to the Cash Purchase Price was made pursuant to Section 3.3(a)( i ) , in each case, less Burdens (other than Operating Expenses and other expenses taken into account pursuant to Section 3.3(a) , Asset Taxes, Income Taxes and Transfer Taxes) directly incurred in earning or receiving such proceeds, and any other income earned with respect to the Assets and attributable to periods from and after the Effective Time (excluding the effects of any Hedge Contract);

 

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(ii) an amount determined under Section 11.2(d)(i) with respect to Title Defects, if applicable;

(iii) an amount determined under Section 12.1(c)(i) with respect to Environmental Defects, if applicable;

(iv) the Allocated Value of the Assets excluded from the transactions contemplated hereby pursuant to Section 11.4(a)( i ) , Section 11.4(b)( i ) or Section  12.1(c)(ii) ;

(v) the amount of all Asset Taxes allocated to Seller in accordance with Section  15.2 but paid or otherwise economically borne by Buyer;

(vi) an amount equal to all proceeds from sales of Hydrocarbons relating to the Assets and payable to owners of Working Interests, royalties, overriding royalties and other similar interests (in each case) that are held by Seller or its Affiliates in suspense as of the Closing Date;

(vii) an amount equal to all Third Party cash call payments, revenues, and other prepaid amounts held by or on behalf of Seller or its Affiliates with respect to the ownership or operation of the Assets from and after the Effective Time, to the extent that such amounts are not transferred to such Third Party prior to Closing or to Buyer’s exclusive possession and control at Closing; and

(viii) any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by Seller and Buyer.

3.4 Adjustment Methodology . When available, actual figures will be used for the adjustments to the Cash Purchase Price at Closing. To the extent actual figures are not available, estimates will be used subject to final adjustments in accordance with Section  3.6 and Section  3.8 . For purposes of allocating production (and accounts receivable with respect thereto), under Section  2.3 and Section  3.3 , (i) liquid Hydrocarbons shall be deemed to be “produced from or allocable to” the Assets when they are produced into the tank batteries related to each Well, and (ii) gaseous Hydrocarbons shall be deemed “produced from or allocable to” the Assets when they pass through the delivery point sales meters or similar meters at the point of entry into the pipelines through which they are gathered or transported from the applicable Well. Seller shall utilize reasonable interpolative procedures to arrive at an allocation of production when exact meter readings are not available.

3.5 Preliminary Settlement Statement . Not less than five (5) Business Days prior to Closing, Seller shall prepare and submit to Buyer for review a draft settlement statement (the “ Preliminary Settlement Statement ”) that shall set forth the Adjusted Cash Purchase Price, reflecting each adjustment made in accordance with this Agreement as of the date of preparation of such Preliminary Settlement Statement and the calculation of the adjustments used to determine such amount, together with the designation of Seller’s accounts for the wire transfers of funds as required by Section  3.1 and Section  9.3(e) . Within two (2) Business Days after receipt of the Preliminary Settlement Statement, Buyer will deliver to Seller a written report containing all changes, with explanation therefor, that Buyer proposes to be made to the Preliminary Settlement Statement. The Parties shall in good faith attempt to agree on the

 

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Preliminary Settlement Statement as soon as possible after Seller’s receipt of Buyer’s written report. The Preliminary Settlement Statement, as agreed upon by the Parties, will be used to adjust the Cash Purchase Price at Closing; provided that if the Parties do not agree upon an adjustment set forth in the Preliminary Settlement Statement, then the amount of such adjustment used to adjust the Cash Purchase Price at Closing shall be that amount set forth in the draft Preliminary Settlement Statement delivered by Seller to Buyer pursuant to this Section  3.5 , other than with respect to adjustments to the Purchase Price pursuant to Section 3.3(b)(ii) , 3.3(b)(iii), 3.3(b)(iv) .

3.6 Escrow .

(a) At Closing, (i) the Indemnity Escrow shall be deposited with the Escrow Agent into the Escrow Account and shall be maintained in the Escrow Account until the end of the Survival Period and so long thereafter as may be required to resolve any claims asserted by Buyer in accordance with the procedure set forth in Section  3.6(b) (the “ Escrow Maintenance Period ”); provided, however , that the Indemnity Escrow may be released, in whole or in part, from time to time or replaced by Seller with cash, in each case in accordance with Sections  3.6(b) , (c), and (d) .

(b) Concurrently with notice to Seller specifying in reasonable details the basis therefor, Buyer may, prior to the end of the Survival Period, give written notice to the Escrow Agent of any amounts, including any claim for indemnification under Section  13.2 , to which Buyer is entitled from Seller hereunder. To the extent that it is finally determined that Buyer is entitled to any such amount, and such claim is not satisfied by Seller within five (5) Business Days of such final determination, the Parties shall cause the Escrow Agent to distribute, without offset or counterclaim, such amount to Buyer from the Indemnity Escrow using the VWAP Price, which distribution shall satisfy such claim only up to the amount so distributed to Buyer. Subject to the foregoing, any such notice or distribution shall not constitute an election of remedies or relieve the obligations of any Party hereunder.

(c) On a date that is six (6) months after the Closing Date, the Parties shall cause the Escrow Agent to disburse a portion of the Indemnity Escrow equal to the positive difference (if any) between sixty-six percent (66%) of the then-current amount of the Indemnity Escrow (valued based on the VWAP Price), minus the aggregate amount of all unresolved claims made by Buyer as of such date pursuant to Section  3.6(b) ; provided, however , that in no event shall any such distribution cause the value of the Indemnity Escrow, based on the VWAP Price to be less than Parent Shares worth, and/or, if applicable, cash equal to, ninety two million dollars ($92,000,000). On and after the end of the Survival Period, and, from time to time upon final determination of any claim made by Buyer pursuant to Section  3.6(b) , the Parties shall cause the Escrow Agent to disburse a portion of the Indemnity Escrow equal to the positive difference (if any) between then-current amount of the Indemnity Escrow, minus the aggregate amount of all unresolved claims made by Buyer pursuant to Section  3.6(b) .

(d) Seller shall have an option exercisable from time to time (but not to exceed three instances) to replace all or any portion of the Parent Shares being held as the Indemnity Escrow with cash equal to the VWAP Price of such Parent Shares, and at such time

 

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such Parent Shares shall be released from escrow to Seller and such cash shall become the “Indemnity Escrow” (or part of it as applicable). Following any such replacement, notwithstanding anything in this Agreement to the contrary, the VWAP Price shall no longer be relevant to addressing claims relating to the Indemnity Escrow to the extent settled in cash. Seller shall bear, and pay as and when due, all costs, fees, and expenses of the Escrow Agent in connection with any such replacement. If the Indemnity Escrow consists of cash and Parent Shares, claims, if any, shall be satisfied out of cash or Parent Shares, as elected by Seller, and the disbursements contemplated by Section 3.6(c) shall be made in cash or Parent Shares, as elected by Seller.

(e) Notwithstanding the foregoing, any amount funded into the Escrow Account in connection with Title Defects or Environmental Defects pursuant to Article  XI or Article  XII , respectively, shall be retained in the Escrow Account until all disputes relating to the Title Defects or Environmental Defects with respect to which such amount was funded have been resolved and, if Seller has elected to cure such Title Defect or Environmental Defect, the Cure Period has elapsed. Any such amount shall be disbursed from the Escrow Account to the Party entitled thereto in accordance with Article  XI with respect to Title Defects and Article  XII with respect to Environmental Defects.

(f) The Parties shall issue such joint written notices, and otherwise take such actions, as may be reasonably necessary from time to time to cause the Escrow Agent to distribute amounts in the Escrow Account in accordance with this Section  3.6 .

3.7 Final Settlement Statement .

(a) On or before one hundred twenty (120) days after Closing, a final settlement statement (the “ Final Settlement Statement ”) will be prepared by Seller, based on actual income and expenses during the Interim Period and which takes into account all final adjustments made to the Cash Purchase Price and shows the resulting final Cash Purchase Price (the “ Final Cash Purchase Price ”). The Final Settlement Statement shall set forth the actual proration of the amounts required by this Agreement. As soon as practicable, and in any event within thirty (30) days, after receipt of the Final Settlement Statement, Buyer shall return to Seller a written report containing any proposed changes to the Final Settlement Statement and an explanation of any such changes and the reasons therefor (the “ Dispute Notice ”). Other than with respect to adjustments to the Purchase Price pursuant to Sections 3.3(b)(ii) , (iii) , and (iv)  and, without limiting Section 15.2(d), any changes not so specified in the Dispute Notice shall be deemed waived, and Seller’s determinations with respect to all such elements of the Final Settlement Statement that are not addressed specifically in the Dispute Notice shall prevail. If Buyer fails to timely deliver a Dispute Notice to Seller containing changes Buyer proposes to be made to the Final Settlement Statement, the Final Settlement Statement as delivered by Seller will be deemed to be correct and mutually agreed upon by the Parties, and will, without limiting Section 15.2(d) , be final and binding on the Parties and not subject to further audit or arbitration, in each case, other than with respect to adjustments to the Purchase Price pursuant to Sections 3.3(b)(ii) , (iii) , and (iv) . If the Final Cash Purchase Price set forth in the Final Settlement Statement is mutually agreed upon by Seller and Buyer, the Final Settlement Statement and the Final Cash Purchase Price, shall, without limiting Section 15.2(d) , be final and binding on the Parties hereto. Any difference in the Adjusted Purchase

 

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Price as paid at Closing pursuant to the Preliminary Settlement Statement and the Final Cash Purchase Price shall be paid by the owing Party to the owed Party within ten (10) days after final determination of such owed amounts in accordance herewith. All amounts to be paid pursuant to this Section  3.7 shall be delivered in United States currency and shall bear interest at five (5) percent from the Closing until paid by wire transfer of immediately available funds to the account specified in writing by the relevant Party.

(b) Subject to matters for which a Party has an indemnity obligation pursuant to Article  XIII and any other adjustments to the Purchase Price that remain outstanding pursuant to Sections 3.3(b)(ii) , (iii) , and (iv) , and subject to Section  13.2(h) , the Final Settlement Statement shall be the final accounting for any and all revenues, proceeds and Operating Expenses, and there shall be no adjustment for any revenues, proceeds or Operating Expenses between the Parties following the Final Settlement Statement.

3.8 Disputes . If Seller and Buyer are unable to resolve the matters addressed in the Dispute Notice (if any), each of Buyer and Seller shall, within fifteen (15) Business Days after the delivery of such Dispute Notice, summarize its position with regard to such dispute and submit such summaries to the Houston, Texas office of Ernst & Young LLP or such other Person as the Parties may mutually select (the “ Accounting Arbitrator ”), together with the Dispute Notice, the Final Settlement Statement and any other documentation such Party may desire to submit. Within ten (10) Business Days after receiving the Parties’ respective submissions, the Accounting Arbitrator shall render a decision with respect to the matters addressed in the Dispute Notice, provided that, in rendering its decision, the Accounting Arbitrator shall be bound by the terms of this Agreement; shall not award less than the amount claimed in Seller’s position or more than the amount claimed in Buyer’s position with respect to each matter addressed in any Dispute Notice, based on the materials submitted to the Accounting Arbitrator as described above. The Accounting Arbitrator shall act as an expert for the limited purpose of determining the specific matters raised in a Dispute Notice and may not award damages or penalties to any Party with respect to any matter. Any decision rendered by the Accounting Arbitrator pursuant hereto shall be final, conclusive and binding on Seller and Buyer and will be enforceable against the Parties in any court of competent jurisdiction. The costs of the Accounting Arbitrator shall be borne one-half by Buyer and one-half by Seller.

3.9 Allocated Values . Buyer and Seller agree that the Purchase Price (as adjusted herein) shall be allocated among the Assets as set forth in Schedule 3.9 to this Agreement (the “ Allocated Values ”). The Allocated Value for any Asset shall be increased or decreased, as applicable, by a share of each adjustment to the Purchase Price under Sections  3.3(a)( i ) - (v) and 3.3(b)( i ), (v) , (vi) and (vii) . The share of each adjustment allocated to a particular Asset shall be obtained by allocating that adjustment among the various Assets on a pro-rata basis in proportion to the portion of the unadjusted Purchase Price allocated to each such Asset on Schedule  3.9 . Buyer and Seller agree that such allocation is reasonable and shall not take any position inconsistent therewith, including in notices to Preferential Purchase Right holders.

3.10 Allocation for Imbalances at Closing . If, prior to Closing, either Party discovers an error in the Imbalances set forth in Schedule 4.12 , then the Cash Purchase Price shall be further adjusted at Closing pursuant to the methodology set forth on Schedule 3.10 , and Schedule  4.12 will be deemed amended immediately prior to Closing to reflect the Imbalances for which the Cash Purchase Price is so adjusted.

 

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ARTICLE IV

REPRESENTATIONS AND WARRANTIES OF SELLER

Subject to the matters specifically listed or disclosed in the Schedules to this Agreement, Seller represents and warrants to Buyer Parties the following:

4.1 Organization, Existence and Qualification . Seller is a limited liability company duly formed and validly existing under the Laws of the State of Delaware. Seller has all requisite power and authority to own and operate its property (including its interests in the Assets) and to carry on its business as now conducted. Seller is duly licensed or qualified to do business as a foreign limited liability company in all jurisdictions in which it carries on business or owns assets and such qualification is required by Law, except where the failure to be so qualified would not have a Material Adverse Effect.

4.2 Authorization, Approval and Enforceability . Seller has full power and authority to enter into and perform this Agreement, the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery and performance by Seller of this Agreement have been duly and validly authorized and approved by all necessary limited liability company action on the part of Seller. Assuming the due authorization, execution and delivery by the other parties to such documents, this Agreement is, and the Transaction Documents to which Seller is a party, when executed and delivered by Seller, will be, the valid and binding obligations of Seller and enforceable against Seller in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

4.3 No Conflicts . Assuming, for the purposes of clause (b) of this Section  4.3 , the receipt of all Consents and the waiver of, or compliance with, all Preferential Purchase Rights, the execution, delivery and performance by Seller of this Agreement and the Transaction Documents to which it is a party and the consummation of the transactions contemplated herein and therein will not (a) conflict with or result in a breach of any provisions of the organizational documents of Seller, (b) except for Permitted Encumbrances, result in a default or the creation of any Encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license or other Applicable Contract to which Seller is a party or by which Seller or the Assets may be bound or (c) violate any Law applicable to Seller or any of the Assets, except in the case of clauses (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not have a Material Adverse Effect.

4.4 Consents . Except (a) as set forth in Schedule  4.4 , (b) for Customary Post-Closing Consents, (c) under Contracts for the purchase, sale, gathering, or transportation of Hydrocarbons from the Assets that are terminable upon not greater than sixty (60) days’ notice without payment of any fee, (d) for Preferential Purchase Rights and (e) for any consents required under the HSR Act, there are no restrictions on assignment, including requirements for

 

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consents from Third Parties to any assignment (in each case), that Seller is required to obtain in connection with the transfer of the Assets by Seller to Buyer or the consummation of the transactions contemplated by this Agreement by Seller (each, a “ Consent ”).

4.5 Bankruptcy . There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Seller’s Knowledge, threatened in writing against Seller.

4.6 Brokers Fees . Seller has incurred no liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Buyer or any Affiliate of Buyer shall have any responsibility.

4.7 Litigation . Except as set forth in Schedule  4.7 , there is no suit, action, litigation or arbitration before any Governmental Authority pending or, to Seller’s Knowledge, threatened in writing against Seller or the Assets operated by Seller or its Affiliates or, to Seller’s Knowledge, the Assets operated by any Third Party or that could reasonably be expected to materially impair or materially delay Seller’s ability to perform its obligations under this Agreement.

4.8 Material Contracts .

(a) Except for Contracts entered into in accordance with Section  6.1 , Schedule  4.8 sets forth all Applicable Contracts of the type described below (collectively, the “ Material Contracts ”) as of the Execution Date:

(i) any Applicable Contract that can reasonably be expected to result in aggregate payments by Seller of more than $100,000 during the current or any subsequent calendar year (based solely on the terms thereof and current volumes, without regard to any expected increase in volumes or revenues);

(ii) any Applicable Contract that can reasonably be expected to result in aggregate revenues to Seller of more than $100,000 during the current or any subsequent calendar year (based solely on the terms thereof and current volumes, without regard to any expected increase in volumes or revenues);

(iii) any facilities use or Hydrocarbon purchase and sale, transportation, processing or similar Applicable Contract that is not terminable without penalty upon sixty (60) days’ or less notice or contains minimum throughput obligations, demand charges, or acreage dedications;

(iv) any indenture, mortgage, loan, credit or sale-leaseback or similar Applicable Contract that can reasonably be expected to result in aggregate payments by Seller during the current or any subsequent calendar year or that would be binding on the Assets or Buyer’s ownership or operation thereof after Closing;

(v) any Applicable Contract that constitutes a lease under which Seller is the lessor or the lessee of real or Personal Property which lease (A) cannot be terminated by Seller without penalty upon sixty (60) days’ or less notice and (B) involves an annual base rental of more than $50,000;

 

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(vi) any farmout agreement, participation agreement, exploration agreement, purchase and sale agreement (limited, however, to those purchase and sale agreements pursuant to which Seller or its successor has an active obligation to sell all or a portion of the Assets), development agreement or similar Applicable Contract;

(vii) any joint operating agreement or unit operating agreement; and

(viii) any Applicable Contract between Seller and any Affiliate of Seller that will not be terminated prior to Closing.

(b) Except as set forth in Schedule  4.8 and except for such matters that would not have a Material Adverse Effect, there exists no default under any Material Contract by Seller, its Affiliate, or, to Seller’s Knowledge, by any other Person that is a party to such Material Contract, and no event has occurred that with notice or lapse of time or both would constitute any default under any such Material Contract by Seller, its Affiliate, or, to Seller’s Knowledge, any other Person who is a party to such Material Contract. Neither Seller nor its Affiliate has not received any written notice from a Third Party of the exercise of any premature termination, price redetermination, market-out or curtailment provision under any Material Contract.

(c) Prior to the Execution Date, Seller has made available to Buyer and its representatives true and complete copies of each Material Contract and all amendments and modifications thereto.

4.9 No Violation of Laws . Except as set forth in Schedule  4.9 , neither Seller, its Affiliate, nor, to Seller’s Knowledge, any applicable Third Party operator is in material violation of any applicable Laws with respect to its ownership and operation of the Assets. For the avoidance of doubt, this Section  4.9 does not include any matters with respect to Environmental Laws or Laws related to Taxes, which shall be exclusively addressed in Section  4.17, Article XII and Section  4.14 , respectively.

4.10 Preferential Purchase Rights . Except as set forth in Schedule  4.10 , there are no preferential purchase rights, rights of first refusal or other similar rights that are applicable to the transfer of the Assets in connection with the transactions contemplated hereby (each a “ Preferential Purchase Right ”).

4.11 Royalties, Etc . Except for such items that are being held in suspense for which the Cash Purchase Price is adjusted pursuant to Section 3.3(b)(vi) or being held in suspense by any Third Party operator, and except as set forth on Schedule  4.11 , Seller and/or its Affiliate (and, to Seller’s Knowledge, any applicable Third Party operator) has paid all material Burdens with respect to the Assets, or if not paid, is contesting such Burdens in good faith in the normal course of business as set forth in Schedule 4.11 . Schedule  4.11 contains a correct and complete list of all Leases operated by Seller or its Affiliates which (a) are currently held by payment of shut-in royalties, reworking operations, any substitute for production in paying quantities, or any other means other than production in paying quantities, or (b) will expire, terminate, or otherwise be materially impaired absent actions by or on behalf of Seller or its successor in interest (other than continued production in paying quantities) on or before a date that is ninety (90) days after the Closing Date. Seller is, and, to Seller’s Knowledge, all applicable Third Party operators are, in material compliance with the terms of all of the Leases.

 

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4.12 Imbalances . Schedule  4.12 sets forth all material Imbalances associated with the Assets as of the Effective Time. Seller has not received or given any notice under a gas balancing, lifting or similar agreement or procedure that an Imbalance constitutes all of a Person’s share of ultimately recoverable reserves in any balancing area.

4.13 Current Commitments . Schedule  4.13 sets forth, as of the Execution Date, all Seller-approved authorizations for expenditure and other approved capital commitments, individually in excess of $350,000 net to Seller’s applicable interest (the “ AFEs ”), relating to the Assets for which all of the activities anticipated in such AFEs have not been completed by the Execution Date.

4.14 Asset Taxes . Except as set forth in Schedule  4.14 , (a) all material Asset Taxes that have become due and payable have been properly paid, (b) all material Tax Returns with respect to Asset Taxes required to be filed have been timely filed and such Tax Returns are true and correct in all material respects, (c) none of the Assets is subject to any tax partnership agreement or is otherwise treated, or required to be treated, as held in an arrangement requiring a partnership income Tax Return to be filed under Subchapter K of Chapter 1 of Subtitle A of the Code, (d) there is not currently in effect any extension or waiver of any statute of limitations of any jurisdiction regarding the assessment or collection of any Asset Tax, (e) there are no audits, litigation or other administrative or judicial proceedings pending or, to Seller’s Knowledge, threatened in writing, against any of the Assets or against Seller with respect to the Assets, by any Governmental Authority with respect to Asset Taxes, (f) there are no Encumbrances for Taxes on any of the Assets except for Taxes not yet due, (g) Seller has complied with all escheat or unclaimed property laws with respect to funds or property received in connection with the operation of the Assets by Seller, and (h) Seller (or, if Seller is classified as an entity disregarded as separate from another Person, then such Person) is not a foreign person within the meaning of Section 1445 of the Code.

4.15 Wells. There is no well operated by Seller on the Assets (a) with respect to which there is an order from a Governmental Authority requiring that such well be plugged and abandoned or (b) that is neither in use for purposes of production or injection, nor suspended or temporarily abandoned in accordance with applicable Law, that has not been plugged and abandoned in accordance with applicable Law. To Seller’s Knowledge, there are no Wells or Personal Property on the Assets that have been plugged and abandoned or Decommissioned in a manner that does not comply with applicable Laws. All Wells drilled by Seller or its Affiliates have been, and Seller has no Knowledge that any Well drilled by a Third Party operator has not been, drilled and completed at legal locations and within the limits permitted by the relevant Leases, Applicable Contracts, and pooling or unit agreements or orders. All currently producing Wells and material Personal Property operated by Seller or its Affiliates are in, and Seller has no Knowledge that any Well or any material Personal Property operated by a Third Party are not in, an operable state of repair adequate to maintain normal operations in accordance with past practices, ordinary wear and tear excepted. As of the Execution Date, except as set forth on Schedule 4.15 , there are no force pooling applications that Seller has received written certified notice of pending with respect to Assets operated by Third Parties before the Oklahoma Corporation Commission.

 

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4.16 Non-Consent Operations . Except as set forth on Schedule  4.16 , Seller has not elected not to participate in any operation or activity proposed with respect to the Assets which could result in any of Seller’s interest in such Assets becoming subject to a penalty or forfeiture as a result of such election not to participate in such operation or activity. Schedule  4.16 contains a complete and accurate list of the status of any payout balances maintained by Seller or its Affiliates for each Asset which is subject to a reversion or other adjustment at any level of cost recovery or Hydrocarbon production from or attributable to such Asset, as of the dates shown on such schedule with respect to such Asset.

4.17 Notices of Violation . Except as shown on Schedule  4.17 :

(a) neither Seller, its Affiliate, nor, to Seller’s Knowledge, the operator of any Asset, has received a written notice from any applicable Governmental Authority of any condition on or with respect to such Asset which would constitute a material violation of, or require a material remediation under, Environmental Laws, and to Seller’s Knowledge, no such condition exists;

(b) Seller or its Affiliates has, and Seller has no Knowledge that a Third Party operator does not have, all material permits, licenses, approvals, consents, certificates and other authorizations currently required by Environmental Laws or by any Governmental Authority or third Person with respect to the operation of the Assets by Seller; and

(c) Neither Seller, its Affiliate, nor, to Seller’s Knowledge, any Third Party operator has entered into written agreements, consents, orders, decrees, judgments, licenses, or permit conditions with any Governmental Authority that relate to the future use of any Asset and that require material Remediation or materially restrict or curtail further operation of the Assets.

4.18 Accredited Investor; Investment Intent . Seller is (a) an experienced and knowledgeable investor, (b) able to bear the economic risks of its acquisition and ownership of the Parent Shares, and (c) is capable of evaluating (and has evaluated) the merits and risks of investing in the Parent Shares and its acquisition and ownership thereof. Seller is an “accredited investor,” as such term is defined in Rule 501 of Regulation D promulgated under the Securities Act, and is acquiring the Parent Shares for its own account and not with a view to a sale or distribution thereof in violation of the Securities Act, and the rules and regulations thereunder or any other securities Laws. Seller acknowledges and understands that (a) the acquisition of the Parent Shares has not been registered under the Securities Act in reliance on an exemption therefrom and (b) that the Parent Shares will, upon its acquisition by Seller, be characterized as “restricted securities” under state and federal securities Laws and may not be sold, transferred, offered for sale, pledged, hypothecated, or otherwise disposed of, except pursuant to an effective registration statement under the Securities Act or pursuant to an exemption from the registration requirements of the Securities Act, and in compliance with applicable state and federal securities Laws.

 

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4.19 ERISA . Neither Seller nor any of its subsidiaries maintains, contributes to, is required to contribute to, or has any liability with respect to a plan that is subject to Title IV of the Employee Retirement Income Security Act of 1974, as amended (“ ERISA ”) and, within the six (6) years preceding the Closing Date, neither Seller nor any of its subsidiaries have sponsored, maintained, contributed to, or been required to contribute to a plan subject to Title IV of ERISA. There are no existing, or, to Seller’s Knowledge, potential future, Liabilities, liens or Encumbrances on the Assets arising under Title IV of ERISA and no facts exist that would reasonably be expected to result in the imposition of a Liability, lien or Encumbrance on the Assets that may arise under Title IV of ERISA.

ARTICLE V

REPRESENTATIONS AND WARRANTIES OF BUYER

Buyer Parties represent and warrant to Seller the following:

5.1 Organization, Existence and Qualification . Buyer is a limited liability company duly formed, validly existing, and in good standing under the Laws of the State of Delaware and has all requisite limited liability company power and authority to own and operate its property and to carry on its business as now conducted. Parent is a corporation duly incorporated, validly existing, and in good standing under the Laws of the State of Delaware and has all requisite corporate power and authority to own and operate its property and to carry on its business as now conducted. Each Buyer Party is duly licensed or qualified to do business as a foreign corporation or limited liability company, as applicable, in all jurisdictions in which it carries on business or owns assets and such qualification is required by Law except where the failure to be so qualified would not reasonably be expected to have a material adverse effect (a) on the financial condition, business or results of operations of such Buyer Party and its subsidiaries, taken as a whole or (b) upon the ability of such Buyer Party to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

5.2 Authorization, Approval and Enforceability . Each Buyer Party has all requisite corporate power and authority to enter into and perform this Agreement, the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery and performance by such Buyer Party of this Agreement and the Transaction Documents to which it is a party have been duly and validly authorized and approved by all necessary limited liability company or corporate, as applicable, action on the part of such Buyer Party. Assuming the due authorization, execution and delivery by the other parties to such documents, this Agreement is, and the Transaction Documents to which such Buyer Party is a party, when executed and delivered by such Buyer Party, will be, the valid and binding obligations of such Buyer Party and enforceable against Buyer in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

5.3 No Conflicts .

(a) The execution, delivery and performance by each Buyer Party of this Agreement and the Transaction Documents to which it is a party and the consummation of the

 

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transactions contemplated herein and therein will not (a) conflict with or result in a breach of any provisions of the organizational or other governing documents of such Buyer Party, (b) result in a default or the creation of any Encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage, indenture, license or other agreement to which such Buyer Party is a party or by which such Buyer Party or any of its property may be bound or (c) violate any Law applicable to such Buyer Party or any of its property, except in the case of clauses (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not, individually or in the aggregate, reasonably be expected to have a material adverse effect upon the ability of such Buyer Party to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

(b) The transactions contemplated hereby (including the issuance of Parent Common Stock to Seller as Equity Consideration) do not require any vote of the stockholders of Buyer under applicable Law, the rules and regulations of the NASDAQ or the organizational or other governing documents of each Buyer Party.

5.4 Consents . Excluding consents from Third Parties required to transfer the Assets to Buyer at Closing and any consents required under the HSR Act, there are no consents or other restrictions on assignment, including requirements for consents from Third Parties to any assignment, (in each case) that any Buyer Party is required to obtain in connection with the consummation of the transactions contemplated by this Agreement by such Buyer Party.

5.5 Bankruptcy . There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by Buyer or, to Buyer’s Knowledge, threatened in writing against a Buyer Party or any subsidiary of a Buyer Party. Neither Buyer Party is insolvent.

5.6 Litigation . As of the Execution Date, there is no investigation, lawsuit, action, litigation or arbitration by any Person or before any Governmental Authority pending, or to Buyer’s Knowledge, threatened in writing against a Buyer Party or any of its subsidiaries that has or would have an adverse effect upon the ability of such Buyer Party to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

5.7 Financing . Buyer Parties have immediately available cash in an amount sufficient to pay the Deposit upon Buyer Parties’ execution of this Agreement, and shall have at Closing immediately available cash in an amount sufficient to pay the Adjusted Cash Purchase Price.

5.8 Regulatory . At Closing, Buyer will be qualified per applicable Law to own and assume operatorship of the Assets in all jurisdictions where the Assets are located, and the consummation of the transactions contemplated by this Agreement will not cause Buyer to be disqualified as such an owner or operator, in each case except where such failure to do so would not reasonably be expected to have a material adverse effect upon the ability of such Buyer Party to consummate the transactions contemplated by this Agreement or perform its obligations hereunder. To the extent required by any applicable Laws, Buyer will at or prior to Closing have obtained such lease bonds, area-wide bonds or any other surety bonds as may be required by, and in accordance with, all applicable Laws governing the ownership and operation of the Assets and

 

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will have filed such reports required for such ownership and/or operation with all Governmental Authorities having jurisdiction over such ownership and/or operation, in each case except where such failure to do so would not reasonably be expected to have a material adverse effect upon the ability of such Buyer Party to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

5.9 Independent Evaluation . Each Buyer Party (a) is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities, (b) is capable of evaluating, and hereby acknowledges that it has so evaluated, the merits and risks of the Assets, Buyer’s acquisition, ownership, and operation thereof, and its obligations hereunder, and (c) is able to bear the economic risks associated with the Assets, Buyer’s acquisition, ownership, and operation thereof, and its obligations hereunder. In making its decision to enter into this Agreement and to consummate the transactions contemplated hereby, each Buyer Party (i) has relied or shall rely solely on its own independent investigation and evaluation of the Assets and the advice of its own legal, Tax, economic, environmental, engineering, geological and geophysical advisors and the express provisions of this Agreement and not on any comments, statements, projections or other materials made or given by any representatives or consultants or advisors of Seller, and (ii) has satisfied itself through its own due diligence as to the environmental and physical condition of and contractual arrangements and other matters affecting the Assets.

5.10 Brokers Fees . None of Buyer, Parent, or their respective Affiliates has incurred any liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement or the Transaction Documents for which Seller or any of Seller’s Affiliates has or shall have any responsibility.

5.11 Accredited Investor . Buyer is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, as amended, and will acquire the Assets for its own account and not with a view to a sale, distribution or other disposition thereof in violation of the Securities Act of 1933, as amended, and the rules and regulations thereunder, any applicable state blue sky Laws or any other applicable securities Laws.

5.12 Issuance of Parent Shares . The issuance of the Parent Shares pursuant to this Agreement has been duly authorized and upon consummation of the transactions contemplated by this Agreement, the Parent Shares will have been validly issued, fully paid, non-assessable and issued without application of preemptive rights, will have the rights, preferences and privileges specified in Parent’s Amended and Restated Certificate of Incorporation, as amended, and will be free and clear of all liens and restrictions, other than the restrictions imposed by this Agreement and applicable securities laws.

5.13 Capitalization . As of December 8, 2016, the authorized capital stock of Parent consisted solely of (a) 200,000,000 shares of Parent Common Stock, of which 125,453,243 shares were issued and outstanding, and (b) 5,000,000 shares of preferred stock, par value $0.01 per share, no shares of which were issued and outstanding. No other class of capital stock of Parent is authorized, issued, reserved for issuance or outstanding. All outstanding shares of capital stock of Parent are duly authorized, validly issued, fully paid and non-assessable. Except as disclosed in the Parent SEC Reports, there are no (i) securities convertible into or

 

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exchangeable or exercisable for shares of Parent capital stock, (ii) subscriptions, options, warrants, calls, rights, convertible securities or other contracts, agreements or commitments of any kind or character obligating Parent to issue, transfer or sell any of its capital stock, (iii) any equity equivalents or any agreements, arrangements or understandings granting any person any rights in Parent similar to capital stock. There are no outstanding obligations of Parent to repurchase, redeem or otherwise acquire any Parent capital stock. All securities of Parent have been issued in compliance with all applicable state and federal securities laws. Parent has, and at Closing will have, sufficient authorized shares of Parent Common Stock to enable it to issue the Parent Shares at Closing.

5.14 SEC Reports . Parent has filed and made available to Seller via EDGAR all forms, reports and other documents publicly filed by Parent with the Securities and Exchange Commission under the Securities Act or the Exchange Act, since January 1, 2015. All such forms, reports and other documents, including any audited or unaudited financial statements and any notes thereto or schedules included therein (including those that Parent may file after the Execution Date and prior to the Closing Date) are referred to herein as the “ Parent SEC Reports .” The Parent SEC Reports (a) were filed on a timely basis, (b) comply in all material respects with the applicable requirements of the Securities Act, the Exchange Act and the rules and regulations of the Securities and Exchange Commission thereunder and (c) did not, at the time they were filed, contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements therein, in the light of the circumstances under which they were made, not misleading. As of their respective dates, the financial statements included in the Parent SEC Reports (x) comply in all material respects with applicable accounting requirements and with the published rules and regulations of the Securities and Exchange Commission with respect thereto, (y) were prepared in accordance with GAAP (except as may be indicated in the notes thereto or, in the case of unaudited statements, as permitted by Form 10-Q promulgated by the Securities and Exchange Commission), and (z) fairly present (subject in the case of unaudited statements to normal, recurring and year-end audit adjustments) in all material respects the consolidated financial position and status of the business of Parent as of the dates thereof and the consolidated results of its operations and cash flows for the periods then ended.

5.15 Investment Company . Neither Buyer nor Parent is an entity required to register as an investment company or a company controlled by an entity required to register as an investment company within the meaning of the Investment Company Act of 1940, as amended.

5.16 Nasdaq Listing . The Parent Common Stock is listed on the NASDAQ Global Select Market, and Parent has not received any notice of delisting. Subject to the filing of a supplemental listing application with the NASDAQ Global Select Market, the issuance and sale of the Parent Shares does not contravene the NASDAQ Global Select Market rules and regulations. There is no suit, action, proceeding or investigation pending or, to each Buyer Party’s Knowledge, threatened against either Buyer Party by the NASDAQ or the SEC with respect to any intention by such entity to deregister the Parent Common Stock or prohibit or terminate the listing of Parent Common Stock on the NASDAQ. Parent has taken no action that is designed to terminate the registration of Parent Common Stock under the Exchange Act.

 

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5.17 Form S-3 Eligibility . As of the Execution Date, (a) Parent is eligible to register the resale of the Parent Shares for resale by Seller under Form S-3 promulgated under the Securities Act and (b) is a “well-known seasoned issuer” as defined in Rule 405 promulgated under the Securities Act.

5.18 Absence of Certain Changes or Events . Since September 30, 2016, there has not been any event, change, effect or development that, individually or in the aggregate, would be reasonably likely to have a Parent Material Adverse Effect.

ARTICLE VI

CERTAIN AGREEMENTS

6.1 Conduct of Business by Seller.

(a) Except (w) as set forth in Schedule 6.1 , (x) for the operations covered by the AFEs and other capital commitments described in Schedule 4.13 , (y) for actions taken in connection with emergency situations constituting an immediate threat to health, safety or the environment or reasonably necessary to avoid the imminent termination of a lease capable of producing in paying quantities, and (z) as expressly contemplated by this Agreement or as expressly consented to in writing by Buyer (which consent shall not be unreasonably delayed, withheld or conditioned), Seller shall, from and after the Execution Date and until Closing:

(i) maintain, and if Seller is the operator thereof, operate, the Assets in the usual, regular and ordinary manner consistent with its past practice;

(ii) maintain the books of account and Records relating to the Assets in the usual, regular and ordinary manner, in accordance with the usual accounting practices of Seller;

(iii) use reasonable efforts to maintain all Leases in full force and effect;

(iv) use reasonable efforts to maintain in full force and effect all material permits and authorizations granted by a Government Authority with respect to the Assets.

(b) Except (w) as set forth in Schedule 6.1 , (x) for the operations covered by the AFEs and other capital commitments described in Schedule 4.13 , (y) for actions taken in connection with emergency situations constituting an immediate threat to health, safety or the environment or reasonably necessary to avoid the imminent termination of a lease capable of producing in paying quantities, and (z) as expressly contemplated by this Agreement or as expressly consented to in writing by Buyer (which consent shall not be unreasonably delayed, withheld or conditioned), Seller shall, from and after the Execution Date and until Closing:

(i) not propose any operation reasonably expected to cost Seller in excess of $350,000;

 

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(ii) not consent to, or elect not to participate in, any operation proposed by a Third Party that is reasonably expected to cost Seller in excess of $350,000;

(iii) not enter into an Applicable Contract that, if entered into on or prior to the Execution Date, would be required to be listed in Schedule 4.8 , or terminate (unless such Material Contract terminates pursuant to its stated terms) or materially amend or change the terms of any Material Contract;

(iv) not transfer, sell, mortgage, pledge or dispose of, or otherwise encumber or alienate in any way, any portion of the Assets other than (A) the transfer, sale and/or disposal of Hydrocarbons in the ordinary course of business, (B) sales of equipment that is no longer necessary or desirable in the operation of the Assets or for which replacement equipment of comparable or better quality has been obtained, (C) disposals of Assets where the consideration is less than $200,000 per disposal or $500,000 in the aggregate for all such disposals and (E) Permitted Encumbrances;

(v) not reduce or terminate existing insurance or make an election to be excluded from coverages provided by a Third Party operator for the joint account under any joint operating or unit operating agreement;

(vi) not settle, waive, or compromise any suit, claim, arbitration, or other proceeding against the Seller involving the Assets, other than any such claims (or series of related claims) seeking solely monetary damages of less than $200,000 in the aggregate; and

(vii) not commit to do any of the foregoing or take any action (or fail to take any action) that would cause Seller to breach Section 6.1(a) , subject to the standards and exceptions set forth therein.

(c) Buyer Parties acknowledge that Seller owns undivided interests in certain of the properties comprising the Assets that it is not the operator thereof, and Buyer Parties agree that the acts or omissions of any other Working Interest owner (including any operator) or any other Person who is not Seller or an Affiliate of Seller shall not constitute a breach of the provisions of this Section  6.1 , and no action required by a vote of Working Interest owners shall constitute such a breach so long as Seller has voted its interest in a manner that complies with the provisions of this Section  6.1 .

6.2 Conduct of Business by Parent.

(a) Except (x) as set forth in Schedule 6.2 or (y) as expressly contemplated by this Agreement or as expressly consented to in writing by Seller (which consent shall not be unreasonably delayed, withheld or conditioned), Parent shall, from and after the Execution Date and until Closing, conduct Parent’s businesses in the usual, regular and ordinary manner consistent with its past practice.

(b) Except (x) as set forth in Schedule 6.2 or (y) as expressly contemplated by this Agreement or as expressly consented to in writing by Seller (which consent shall not be unreasonably delayed, withheld or conditioned), Parent shall, from and after the Execution Date and until Closing:

 

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(i) not (A) declare, set aside or pay any dividends on, or make any other distribution in respect of any outstanding capital stock of, or other equity interests in, Parent or its subsidiaries, except for dividends and distributions (1) by a direct or indirect subsidiary of Parent to Parent or a direct or indirect subsidiary of Parent or (2) pursuant to the organizational or other governing documents of Parent or its subsidiaries as in effect on the date hereof, (B) split, combine or reclassify any capital stock of, or other equity interests in, Parent or any of its subsidiaries, or (C) purchase, redeem or otherwise acquire, or offer to purchase, redeem or otherwise acquire, any capital stock of, or other equity interests in, Parent, except as required by the terms of any capital stock or equity interest of a subsidiary or as contemplated by any Parent Stock Plan or employment agreement of Parent in each case existing as of the date hereof;

(ii) not issue any Parent Common Stock or securities convertible into Parent Common Stock other than under the Parent Stock Plan;

(iii) not consummate, authorize, recommend, propose or announce an intention to adopt a plan of complete or partial liquidation or dissolution of Parent or any of its subsidiaries;

(iv) not change in any material respect their material accounting principles, practices or methods, except as required by GAAP or statutory accounting requirements or similar principles in non-U.S. jurisdictions or as disclosed in any Parent SEC Reports; and

(v) not commit to do any of the foregoing.

6.3 Governmental Bonds.

(a) Buyer acknowledges that none of the bonds, letters of credit and guarantees, if any, set forth on Schedule 6.3 , posted by Seller or its Affiliates with Governmental Authorities and relating to the Assets (the “ Governmental Bonds ”) are transferable to Buyer. On or before the Closing Date, Buyer shall obtain, or cause to be obtained in the name of Buyer, replacements for such Governmental Bonds to the extent such replacements are necessary for Buyer’s ownership of the Assets. In addition, at or prior to Closing, Buyer shall deliver to Seller evidence of the posting of bonds or other security with all applicable Governmental Authorities meeting the requirements of such Governmental Authorities to own and, if applicable, operate the Assets.

(b) The Parties shall cooperate reasonably (without the obligation to expend any sums, or undertake any obligations for a Third Party, other than as set forth in Section 6.3(a)) to obtain the release or cancellation of any Government Bonds posted by Seller and/or any Affiliate of Seller with respect to the Assets. In the event that any Governmental Authority does not permit the cancellation of any Governmental Bond posted by Seller and/or any Affiliate of Seller with respect to the Assets, and a Governmental Authority takes action against, and recovers amounts under, any such Governmental Bond posted by Seller, which amounts would otherwise be the responsibility of Buyer under this Agreement, Buyer shall promptly refund any such amounts to Seller.

 

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6.4 Required Information . Seller shall provide to Parent on or before December 14, 2016 the audited balance sheets of Seller as of December 31, 2014 and 2015 and the audited income statements, statements of comprehensive income, statements of cash flows and members’ equity for each of the three fiscal years ended December 31, 2013, 2014 and 2015 (audited by independent auditor), and unaudited interim financials for the nine months ended September 30, 2016 (and the comparable period in 2015), in each case, as customarily presented for significant acquisitions in offerings registered with the Securities and Exchange Commission (it being acknowledged that Seller shall not be required to prepare any pro forma and forward-looking statements) (the “ Required Pre-Closing Information ”). Seller shall cause the personnel of Seller, and Seller’s Affiliates, and shall request its independent auditors, to cooperate with Parent in the preparation and disclosure of such Required Pre-Closing Information and shall request its independent auditors provide customary “comfort letters” to any underwriter or purchaser in the Buyer Financing and to consent to be named an expert in any offering memorandum, private placement memorandum or prospectus used in the Purchase Financing. Seller shall provide the Required Pre-Closing Information on or before the Closing Date.

6.5 Amendment to Schedules . Buyer Parties agree that, with respect to the representations and warranties of Seller contained in this Agreement, Seller shall have the continuing right until Closing to add, supplement or amend the Schedules to its representations and warranties with respect to any matter hereafter arising or discovered which, if existing on the Execution Date or thereafter, would have been required to be set forth or described in such Schedules. For all purposes of this Agreement, including for purposes of determining whether the conditions set forth in Article VII have been fulfilled and Seller’s indemnity obligations in Article  XIII , the Schedules to Seller’s representations and warranties contained in this Agreement shall be deemed to include only that information contained therein on the Execution Date and shall be deemed to exclude all information contained in any addition, supplement or amendment thereto. Without limiting the foregoing, Seller’s indemnity obligations in Article  XIII shall apply regardless of the knowledge of Buyer Parties of any breach of any provision of this Agreement, or any fact or circumstance that could constitute such a breach, and the failure of any Buyer Party to take any action with respect to an addition, supplement or amendment shall not be deemed a waiver of any breaches of, or inaccuracy in, Seller’s representations and warranties or otherwise diminish or impair the rights of Buyer hereunder.

6.6 Government Filings . Each Party shall, (a) in a timely manner, but in any event within ten (10) days after the Execution Date, make all required filings, including any filings required under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (as amended, the “ HSR Act ”), and prepare applications to, and conduct negotiations with, each Governmental Authority as to which such filings, applications, or negotiations are necessary or appropriate in the consummation of the transactions contemplated hereby; and (b) provide such information as the other may reasonably request in order to make such filings, prepare such applications, and conduct such negotiations. Each Party shall cooperate with, and use all reasonable efforts to assist the other with respect to such filings, applications, and negotiations, and, without limiting the foregoing, consult with the other Party prior to taking any material substantive position with respect to filings under the HSR Act, in any written submission to, or, to the extent practicable, in any discussions with, any Governmental Authority. Notwithstanding anything to the contrary in this Agreement, Buyer shall be responsible for all filing fees with respect to such filings under the HSR Act; except that all fees payable in connection with any filing in which Seller is the

 

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Acquiring Person within the meaning of the HSR Act and the applicable regulations thereunder shall be paid and borne by Seller. Subject to applicable Law, and except as required to the contrary by a Governmental Authority, neither Party shall agree to extend any waiting period under the HSR Act or enter into any agreement with any Governmental Authority not to consummate the transactions contemplated by this Agreement, in whole or in part, in each case, without the prior written consent of the other Party (such consent not to be unreasonably withheld, delayed, or conditioned).

6.7 Parent Share Restriction . During the period beginning on the Closing Date and ending sixty (60) days after the Closing Date (excluding the Closing Date for purposes of calculating such date) for one-third of the Parent Shares and ending ninety (90) days after the Closing Date (excluding the Closing Date for purposes of calculating such date) for all of the Parent Shares, Seller will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any Parent Shares or securities convertible into or exchangeable or exercisable for any Parent Shares, enter into a transaction which would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of the Parent Shares, whether any such transaction is to be settled by delivery of the Parent Shares or such other securities, in cash or otherwise, or publicly disclose the intention to make any such offer, sale, pledge or disposition, or to enter into any such transaction, swap, hedge or other arrangement.

6.8 Listing of Equity Consideration . Parent shall take all action necessary to cause the Parent Common Stock to be issued to Seller as Equity Consideration to be approved for listing on the NASDAQ prior to the Closing Date, subject to official notice of issuance.

6.9 Transition Services Agreement . From and after the Execution Date, the Parties shall use commercially reasonable efforts to negotiate a Transition Services Agreement to be executed and delivered prior to Closing pursuant to which Seller shall continue to provide, for a mutually agreeable period and for a mutually agreeable fee, certain services with respect to the Assets to Buyer, as provided prior to the Closing.

ARTICLE VII

BUYER PARTIES’ CONDITIONS TO CLOSING

The obligations of Buyer Parties to consummate the transactions provided for herein are subject, at the option of Buyer Parties, to the fulfillment by Seller or waiver by Buyer, on or prior to Closing of each of the following conditions:

7.1 Representations . The representations and warranties of Seller set forth in Article IV shall be true and correct (without regard to materiality or Material Adverse Effect qualifiers) on and as of the Closing Date, as though such representations `and warranties had been made or given on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except for those breaches, if any, of such representations and warranties that in the aggregate would not have a Material Adverse Effect.

 

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7.2 Performance . Seller shall have materially performed or complied with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by Seller is required prior to or at the Closing Date.

7.3 No Legal Proceedings . No material suit, action, litigation or other proceeding instituted by any Third Party shall be pending before any Governmental Authority seeking to restrain, prohibit, enjoin or declare illegal, or seeking substantial damages in connection with, the transactions contemplated by this Agreement.

7.4 Title Defects and Environmental Defects . In each case subject to the Individual Title Defect Threshold, the Individual Environmental Threshold and the Aggregate Deductible, as applicable, the sum of (a) all Title Defect Amounts determined under Section  11.2(g) prior to Closing, less the sum of all Title Benefit Amounts determined under Section  11.2(h) prior to Closing, plus (b) all Remediation Amounts for Environmental Defects determined under Article  XII prior to Closing, plus (c) the aggregate of all reductions to the Purchase Price under Section  11.4 , plus (d) the amount of any Casualty Loss (whether or not compensated by insurance) shall be less than fifteen percent (15%) of the Purchase Price.

7.5 Closing Deliverables . Seller shall have delivered (or be ready, willing and able to deliver at Closing) to the applicable Buyer Party the documents and other items required to be delivered by Seller under Section  9.3 .

7.6 Government Consents . All consents required under the HSR Act for the transfer of the Assets from Seller to Buyer shall have been granted, or the necessary waiting period shall have expired or been terminated early by the relevant Governmental Authority.

ARTICLE VIII

SELLER’S CONDITIONS TO CLOSING

The obligations of Seller to consummate the transactions provided for herein are subject, at the option of Seller, to the fulfillment by the applicable Buyer Party or waiver by Seller on or prior to Closing of each of the following conditions:

8.1 Representations . The representations and warranties of Buyer Parties set forth in Article  V shall be true and correct in all material respects (without regard to materiality qualifiers) on and as of the Closing Date, with the same force and effect as though such representations and warranties had been made or given on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date).

8.2 Performance . Each Buyer Party shall have materially performed or complied with all obligations, agreements and covenants contained in this Agreement as to which performance or compliance by such Buyer Party Buyer is required prior to or at the Closing Date.

8.3 No Legal Proceedings . No material suit, action, litigation or other proceeding instituted by any Third Party shall be pending before any Governmental Authority seeking to restrain, prohibit or declare illegal, or seeking substantial damages in connection with, the transactions contemplated by this Agreement.

 

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8.4 Title Defects and Environmental Defects . In each case subject to the Individual Title Defect Threshold, the Individual Environmental Threshold and the Aggregate Deductible, as applicable, the sum of (a) all Title Defect Amounts determined under Section  11.2(g) prior to Closing, less the sum of all Title Benefit Amounts determined under Section  11.2(h) prior to Closing, plus (b) all Remediation Amounts for Environmental Defects determined under Article  XII prior to Closing, plus (c) the aggregate of all reductions to the Purchase Price under Section  11.4 , plus (d) the amount of any Casualty Loss (whether or not compensated by insurance) shall be less than fifteen percent (15%) of the Purchase Price.

8.5 Closing Deliverables . Each Buyer Party shall have delivered (or be ready, willing and able to deliver at Closing) to Seller the documents and other items required to be delivered by such Buyer Party under Section  9.3 .

8.6 Government Consents . All consents required under the HSR Act for the transfer of the Assets from Seller to Buyer shall have been granted, or the necessary waiting period shall have expired or been terminated early by the relevant Governmental Authority.

ARTICLE IX

CLOSING

9.1 Date of Closing . Subject to the conditions in Article VII and Article VIII , the sale by Seller and the purchase by Buyer of the Assets pursuant to this Agreement (the “ Closing ”) shall occur on the later of (a) February 17, 2017, or (b) two (2) Business Days following the satisfaction or waiver of the conditions in Article VII and Article VIII, provided that termination will not occur until the date described in Section 14.1(a), or on such date as Buyer and Seller may agree upon in writing. The date on which the Closing actually occurs shall be the “ Closing Date .”

9.2 Place of Closing . Closing shall be held at the offices of Vinson & Elkins LLP, at 1001 Fannin Street, Suite 2500, Houston, Texas 77002, or such other place as mutually agreed upon by the Parties.

9.3 Closing Obligations . At Closing, the following documents shall be delivered and the following events shall occur, the execution of each document and the occurrence of each event being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

(a) Seller and Buyer shall execute, acknowledge and deliver the Assignment in sufficient counterparts to facilitate recording in the applicable counties covering the Assets.

(b) Seller and Buyer shall execute, acknowledge and deliver the Deeds in sufficient counterparts to facilitate recording in the applicable counties.

 

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(c) Seller and Buyer shall execute and deliver assignments, on appropriate forms, of federal Leases, state Leases and Indian Leases included in the Assets in sufficient counterparts to facilitate filing with the applicable Governmental Authority.

(d) Seller and Buyer shall execute and deliver the Preliminary Settlement Statement.

(e) (i) Parent shall deliver to the Escrow Agent, the amounts required by Section  3.6 ; (ii) Buyer shall deliver to Seller, to the accounts designated in the Preliminary Settlement Statement, the Adjusted Purchase Price after giving effect to the Deposit and the amounts required to be delivered to the Escrow Agent pursuant to Section  3.6 , in each case, in same day funds; and (iii) Parent and Seller shall deliver to the Escrow Agent, joint written instructions directing the Escrow Agent to deliver the Deposit to Seller, to the accounts designated in the Preliminary Settlement Statement.

(f) Seller shall deliver, on forms supplied by Buyer and reasonably acceptable to Seller, transfer orders or letters in lieu thereof directing all purchasers of production to make payment to Buyer of proceeds attributable to production from the Assets from and after the Effective Time, for delivery by Buyer to the purchasers of production.

(g) Seller (or, if Seller is classified as an entity disregarded as separate from another Person, then such Person) shall deliver an executed statement that meets the requirements set forth in Treasury Regulation §1.1445-2(b)(2).

(h) To the extent required under any applicable Law or Governmental Authority for any federal or state Lease, Seller and Buyer shall deliver federal and state change of operator forms designating Buyer as the operator of the Wells and the Leases currently operated by Seller.

(i) An authorized officer of Seller shall execute and deliver a certificate, dated as of Closing Date, certifying that the conditions set forth in Section  7.1 and Section  7.2 have been fulfilled.

(j) An authorized officer of each Buyer Party shall execute and deliver a certificate, dated as of Closing, certifying that the conditions set forth in Section  8.1 and Section  8.2 have been fulfilled.

(k) Seller shall deliver a recordable release in a form reasonably acceptable to Buyer of all mortgage liens, security interests and financing statements, in each case securing indebtedness for borrowed money by Seller or its Affiliates that encumber the Assets.

(l) Buyer shall execute and deliver to Seller an Assignment and Assumption Agreement, substantially in the form attached hereto as Exhibit H with respect to that certain Gas Purchase Agreement dated effective as of March 12, 2014 between Seller and Woodford Express, LLC.

(m) Buyer shall deliver any instruments and documents required by Section  6.3 .

 

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(n) Each Party shall deliver to the other notices of approval pursuant to a filing or application under Section  6.6 .

(o) Seller shall deliver to Buyer a certificate duly executed by the secretary or any assistant secretary of Seller, dated as of Closing, (i) attaching and certifying on behalf of Seller complete and correct copies of (A) the certificate of formation, operating agreement, and other organizational documents of Seller, each as in effect as of the Closing; (B) resolutions of the Board of Directors of Seller authorizing the execution, delivery and performance by Seller of this Agreement, the Transaction Documents, and the transactions contemplated hereby; and (C) any required approval by the members of Seller of this Agreement, the Transaction Documents, and the transactions contemplated hereby; and (ii) certifying on behalf of Seller the incumbency of each officer or manager of Seller executing this Agreement or any Transaction Document.

(p) Buyer shall deliver to Seller a certificate duly executed by the secretary or any assistant secretary of Buyer, dated as of Closing, (i) attaching and certifying on behalf of Buyer complete and correct copies of (A) the certificate of incorporation, bylaws, and other organizational documents of Buyer, each as in effect as of the Closing; (B) resolutions of the Board of Directors of Buyer authorizing the execution, delivery and performance by Buyer of this Agreement, the Transaction Documents, and the transactions contemplated hereby; and (C) any required approval by the shareholders of Buyer of this Agreement, the Transaction Documents, and the transactions contemplated hereby; and (ii) certifying on behalf of Buyer the incumbency of each officer or manager of Buyer executing this Agreement or any Transaction Document.

(q) Parent shall deliver to Seller a certificate evidencing the Parent Shares, free and clear of all liens and restrictions, other than restrictions imposed by this Agreement and applicable securities laws.

(r) Seller and Buyer shall execute, acknowledge and deliver the Registration Rights Agreement.

(s) Seller and Buyer shall execute and deliver any other agreements, instruments and documents which are required by other terms of this Agreement to be executed and/or delivered at Closing.

9.4 Records . In addition to the obligations set forth under Section  9.3 above, but notwithstanding anything herein to the contrary, no later than thirty (30) Business Days after the termination of the Transition Services Agreement (or, if there is no Transition Services Agreement, the Closing), Seller shall make the Records available to Buyer consistent with each Record’s current form and format as maintained by Seller as of the Effective Time, for pickup from Seller’s offices during normal business hours; provided that Seller shall retain originals of the Records; provided , further , that Seller shall not be required to conduct processing, conversion, compiling or any other further work with respect to the delivery of copies of the Records pursuant to this Section  9.4 .

 

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ARTICLE X

ACCESS/DISCLAIMERS

10.1 Access .

(a) From and after the Execution Date and up to and including the Closing Date (or earlier termination of this Agreement), but subject to the other provisions of this Section  10.1 , Seller shall (i) afford to Buyer and its authorized representatives (“ Buyer s Representatives ”) reasonable access, during normal business hours, to the Assets operated by Seller and all Records in Seller’s or any of its Affiliates’ possession at such time (together with personnel and representatives of Seller and its Affiliates responsible for the business conducted by Seller or its Affiliates with the Assets) and (ii) use commercially reasonable efforts to request and obtain any consents or waivers necessary for Buyer and Buyer’s Representatives to gain access to those Assets not operated by Seller ( provided that Sellers shall not be obligated to expend any monies), in each case to the extent necessary to conduct the title or environmental review described in this Agreement. All investigations and due diligence conducted by Buyer or any Buyer’s Representative shall be conducted at Buyer’s sole cost, risk and expense and any conclusions made from any examination done by Buyer or any Buyer’s Representative shall result from Buyer’s own independent review and judgment.

(b) From the Execution Date to the Title Claim Date, Buyer’s inspection right with respect to the Environmental Condition of the Assets shall be limited to a Phase I Environmental Site Assessment of the Assets, conducted by Enviro Clean Group, L.L.C. or its Affiliate or another reputable environmental consulting or engineering firm approved in advance in writing by Seller and may include only visual inspections and record reviews relating to the Assets. In conducting such inspection, Buyer shall not operate any equipment, including leak detection, or conduct any testing or sampling of soil, groundwater or other materials (including any testing or sampling for Hazardous Substances, Hydrocarbons or NORM). With respect to Assets operated by Seller, if a Phase I Environmental Site Assessment determines that Phase II sampling is necessary in order for Buyer to prove the existence of an Environmental Defect or establish the Remediation Amount with respect to the applicable Asset and Seller denies any reasonable request by Buyer to conduct any such sampling or invasive activities, the Buyer shall have the right to exclude such Asset from the Assets conveyed to Buyer at Closing and reduce the Purchase Price by the Allocated Value of such Asset. Buyer acknowledges that Seller can only provide Buyer access to Assets operated and controlled by Seller and that, subject to Seller’s obligation to use commercially reasonable efforts to obtain access for Buyer or its representatives to non-operated Assets pursuant to Section  10.1(a)(ii) , any inability or delay in accessing such Assets not operated and controlled by Seller will not extend the time period allowed under this Agreement for the Environmental Site Assessment of such Assets. Seller or Seller’s designee shall have the right to be present during any stage of the assessment. Buyer shall give Seller reasonable prior written notice before entering onto any of the Assets, and Seller or its designee shall have the right to accompany Buyer and Buyer’s Representatives whenever they are on site on the Assets.

(c) Buyer shall reasonably coordinate its access rights, environmental property assessments and physical inspections of the Assets with Seller to minimize any inconvenience to or interruption of the conduct of business by Seller. Buyer shall abide by

 

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Seller’s safety rules, regulations and operating policies while conducting its due diligence evaluation of the Assets, including any environmental or other inspection or assessment of the Assets and, to the extent required by Seller, execute and deliver any generally-applicable access or boarding agreement required by Seller before conducting Buyer’s assessment on such Assets in accordance with this Section  10.1 . Buyer hereby defends, indemnifies and holds harmless the Seller Indemnified Parties from and against any and all Liabilities arising out of, resulting from or relating to any field visit, environmental property assessment or other due diligence activity conducted by Buyer or any Buyer’s Representative with respect to the Assets, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, IN WHOLE OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF, OR THE VIOLATION OF LAW BY, ANY SELLER INDEMNIFIED PARTY, EXCEPTING ONLY LIABILITIES TO THE EXTENT ACTUALLY RESULTING FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY SELLER INDEMNIFIED PARTY .

(d) Buyer acknowledges that any entry into Seller’s offices or onto the Assets shall be at Buyer’s sole risk, cost and expense, and, subject to the terms hereof, that none of the Seller Indemnified Parties shall be liable in any way for any injury, loss or damage arising out of such entry that may occur to Buyer or any of Buyer’s Representatives pursuant to this Agreement. Buyer hereby fully waives and releases any and all Liabilities against all of the Seller Indemnified Parties for any injury, death, loss or damage to any of Buyer’s Representatives or their property in connection with Buyer’s due diligence activities, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, IN WHOLE OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF, OR THE VIOLATION OF LAW BY, ANY SELLER INDEMNIFIED PARTY, EXCEPTING ONLY LIABILITIES ACTUALLY RESULTING FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY SELLER INDEMNIFIED PARTY .

(e) Notwithstanding anything to the contrary in Section  12.1(a) , Buyer agrees to provide to Seller promptly, but in no event less than five (5) days after receipt or creation, copies of all final reports and test results prepared by Buyer and/or any of Buyer’s Representatives which contain data collected or generated from Buyer’s due diligence with respect to the Assets, but excluding any materials protected by attorney work product or other legal privilege. Seller shall not be deemed by its receipt of said documents or otherwise to have made any representation or warranty, express, implied or statutory, as to the condition of the Assets or to the accuracy of said documents or the information contained therein.

(f) Upon completion of Buyer’s due diligence, Buyer shall at its sole cost and expense and without any cost or expense to Seller or its Affiliates (i) repair all damage done to the Assets in connection with Buyer’s and/or any of Buyer’s Representatives’ due diligence, (ii) restore the Assets to the approximate same condition as, or better condition than, they were prior to commencement of any such due diligence and (iii) remove all equipment, tools and other property brought onto the Assets in connection with such due diligence. Any material disturbance to the Assets (including the leasehold associated therewith) resulting from such due diligence will be promptly corrected by Buyer at Buyer’s sole cost and expense.

 

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(g) During all periods that Buyer and/or any of Buyer’s Representatives are on the Assets, Buyer shall maintain, at its sole expense and with insurers reasonably satisfactory to Seller, policies of insurance of the types and in the amounts reasonably requested by Seller. Coverage under all insurance required to be carried by Buyer hereunder will (i) be primary insurance, (ii) list the Seller Indemnified Parties as additional insureds, (iii) waive subrogation against the Seller Indemnified Parties and (iv) provide for ten (10) days’ prior written notice to Seller in the event of cancellation, expiration or modification of the policy or reduction in coverage. Upon request by Seller, Buyer shall provide evidence of such insurance to Seller prior to entering the Assets.

10.2 Confidentiality . Buyer acknowledges that, pursuant to its right of access to the Records or the Assets, Buyer and/or Buyer’s Representatives will become privy to proprietary and confidential information of Seller or its Affiliates, and Buyer shall maintain the confidentiality of such information in accordance with the terms of the Confidentiality Agreement; provided, however, if Closing should occur, the foregoing confidentiality restriction on Buyer shall terminate (except as to (a) such portion of the Assets that are not conveyed to Buyer pursuant to the provisions of this Agreement, (b) the Excluded Assets and (c) information related to Seller or its Affiliates or to assets other than the Assets). Buyer hereby adopts and agrees to be bound by the terms of the Confidentiality Agreement with the same force and effect as if Buyer was originally a party thereto and originally subject thereto, and Buyer shall be subject to the same obligations and Gulfport Buckeye LLC therein.

10.3 Disclaimers .

(a) EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY SET FORTH IN ARTICLE IV, SECTION 11.1(b),  IN THE ASSIGNMENT, THE DEEDS OR THE CERTIFICATE TO BE DELIVERED AT CLOSING PURSUANT TO SECTION  9.3(i)  (I) SELLER MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED, AND (II)  SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO BUYER OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO BUYER BY ANY SELLER INDEMNIFIED PARTY).

(b) EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE IV , SECTION 11.1(b) , IN THE ASSIGNMENT, THE DEEDS OR THE CERTIFICATE TO BE DELIVERED AT CLOSING PURSUANT TO SECTION  9.3(i), AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (I)  TITLE TO ANY OF THE ASSETS, (II)  THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION RELATING TO THE ASSETS, (III)  THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (IV)

 

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ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES TO BE GENERATED BY THE ASSETS, (V) THE PRODUCTION OF OR ABILITY TO PRODUCE HYDROCARBONS FROM THE ASSETS, (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY SELLER OR THIRD PARTIES WITH RESPECT TO THE ASSETS, (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ITS AFFILIATES, OR ITS OR THEIR RESPECTIVE EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT. EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE IV, SECTION 11.1(b), IN THE ASSIGNMENT, THE DEEDS OR THE CERTIFICATE TO BE DELIVERED AT CLOSING PURSUANT TO SECTION  9.3(i), SELLER FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY OF THE ASSETS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT BUYER SHALL BE DEEMED TO BE OBTAINING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS BUYER DEEMS APPROPRIATE.

(c) SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY. SUBJECT TO BUYER’S RIGHTS UNDER SECTION 12.1 , BUYER SHALL BE DEEMED TO BE TAKING THE ASSETS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION, AND BUYER HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS BUYER DEEMS APPROPRIATE.

(d) SELLER AND BUYER AGREE THAT, TO THE EXTENT REQUIRED BY APPLICABLE LAW TO BE EFFECTIVE, THE DISCLAIMERS OF

 

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CERTAIN REPRESENTATIONS AND WARRANTIES CONTAINED IN THIS SECTION  10.3 ARE “ CONSPICUOUS ” DISCLAIMERS FOR THE PURPOSE OF ANY APPLICABLE LAW.

ARTICLE XI

TITLE MATTERS; CASUALTY; TRANSFER RESTRICTIONS

11.1 Seller’s Title .

(a) General Disclaimer of Title Warranties and Representations . Except for the special warranty of title as set forth in the Assignment and the Deed, and without limiting Buyer’s remedies for Title Defects set forth in this Article  XI or Seller’s other representations and warranties in Article IV , Seller makes no warranty or representation, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Assets, and Buyer hereby acknowledges and agrees that Buyer’s sole remedy for any defect of title, including any Title Defect, with respect to any of the Assets (i) before Closing, shall be as set forth in Section  11.2 and (ii) after Closing, shall be pursuant to the special warranty of title set forth in the Assignment.

(b) Special Warranty of Title . If Closing occurs, then effective as of the Closing Date and until the end of the Survival Period, Seller, pursuant to the Assignment and the Deed will warrant Defensible Title, without duplication, to (i) the Wells set forth on Exhibit B (limited to any currently producing formations), and (ii) survey sections set forth on Schedule 3.9 , to the extent that the interests in such survey sections are contributed to by the Leases set forth on Exhibit A-1 (the “ Sections ”) (limited to the applicable Target Formations), unto Buyer against every Person whomsoever lawfully claiming or to claim the same or any part thereof by, through or under Seller or its Affiliates, but not otherwise, subject, however, to the Permitted Encumbrances; provided, however , that, except with respect to any liability of Seller for any claim asserted in writing by Buyer to Seller in accordance with Section  11.1(c) on or before the expiration of the Survival Period for breach of such special warranty, such special warranty shall cease and terminate at the end of such Survival Period.

(c) Recovery on Special Warranty .

(i) Buyer’s Assertion of Title Warranty Breaches . Prior to the expiration of the Survival Period, Buyer shall furnish Seller a Title Defect Notice meeting the requirements of Section 11.2(a) setting forth any matters which Buyer intends to assert as a breach of Seller’s special warranty in the Assignment. For all purposes of this Agreement, Buyer shall be deemed to have waived, and Seller shall have no further liability for, any breach of Seller’s special warranty that Buyer fails to assert by a Title Defect Notice given to Seller on or before the expiration of the Survival Period. Buyer agrees to reasonably cooperate (but without the obligation to expend any funds or undertake any obligations) with any attempt by Seller to cure any such Title Defect, which attempted cure shall be at Seller’s sole cost, risk, and expense.

(ii) Limitations on Special Warranty . For purposes of Seller’s special warranty of title, the value of the Sections and/or Wells set forth in Schedule 3.9, as appropriate

 

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((1) for a Well, limited to any currently producing formations, and (2) for a Section, limited to the applicable Target Formations set forth on Schedule 3.9 for such Section), shall be deemed to be the Allocated Value thereof, as adjusted herein. Recovery on Seller’s special warranty of title shall be limited to an amount (without any interest accruing thereon) equal to the reduction in the Purchase Price to which Buyer would have been entitled had Buyer asserted the defect giving rise to such breach of Seller’s special warranty of title as a Title Defect prior to the Title Claim Date pursuant to Section 11.2, but without limiting Buyer’s rights to recover from Seller costs arising out of, or relating to, such breach, including reasonable attorneys’ fees incurred to defend title to the relevant Asset.

11.2 Notice of Title Defects; Defect Adjustments .

(a) Title Defect Notices . Buyer must deliver, no later than 5 p.m. CST on February 9, 2017 (the “ Title Claim Date ”), claim notices to Seller meeting the requirements of this Section  11.2(a) (collectively, the “ Title Defect Notices ” and, individually, a “ Title Defect Notice ”) setting forth any matters which, in Buyer’s reasonable opinion, constitute Title Defects and which Buyer intends to assert as a Title Defect pursuant to this Section 11.2(a) . For all purposes of this Agreement and notwithstanding anything herein to the contrary (other than as set forth in Section  11.1(b) ), Buyer shall be deemed to have waived, and Seller shall have no liability for, any Title Defect which Buyer fails to assert as a Title Defect by a properly delivered Title Defect Notice received by Seller on or before the Title Claim Date. To be effective, each Title Defect Notice shall be in writing, and shall include (i) a description of the alleged Title Defect and the Well or Section (including the legal description of such Well or affected Leases contributing to such Section), or portion thereof, affected by such Title Defect (each a “ Title Defect Property ”), (ii) the Allocated Value of each Title Defect Property, (iii) supporting documents in Buyer’s possession or control reasonably necessary for Seller to verify the existence of such alleged Title Defect, and (v) the amount by which Buyer reasonably believes the Allocated Value of each Title Defect Property is reduced by such alleged Title Defect and the computations upon which Buyer’s belief is based. To give Seller an opportunity to commence reviewing and curing Title Defects, Buyer agrees to use reasonable efforts to give Seller, on or before the end of each calendar week prior to the Title Claim Date, written notice of all alleged Title Defects (as well as any claims that would be claims under the special warranty set forth in Section  11.1 ) discovered by Buyer during the preceding calendar week, which notice may be preliminary in nature and supplemented prior to the Title Claim Date; provided that neither the failure to provide such notice, nor the contents of any such notice shall be actionable or give rise to any rights in favor of Seller, and Seller may not submit any such notice (or the fact that no such notice was submitted) to the Title Arbitrator pursuant to Section  11.2(j) .

(b) Title Benefit Notices . Seller shall have the right, but not the obligation, to deliver to Buyer on or before the Title Claim Date with respect to each Title Benefit a notice (a “ Title Benefit Notice ”) including (i) a description of the alleged Title Benefit and the Asset, or portion thereof, affected by such alleged Title Benefit (each a “ Title Benefit Property ”), and (ii) the amount by which Seller reasonably believes the Allocated Value of such Title Benefit Property is increased by such alleged Title Benefit and the computations upon which Seller’s belief is based. Except as set forth in Section  11.2 (a) , Seller shall be deemed to have waived all Title Benefits for which a Title Benefit Notice has not been delivered on or before the Title Claim Date.

 

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(c) Seller s Right to Cure . Seller shall have the right, but not the obligation, to attempt, at its sole cost and risk, to cure at any time prior to one hundred twenty (120) days after Closing (the “ Cure Period ”), any Title Defects of which it has been advised by Buyer. During the period of time from Closing to the expiration of the Cure Period, Buyer agrees to afford Seller and its officers, employees and other authorized representatives reasonable access, during normal business hours, to the Assets and all Records in Buyer’s or any of its Affiliates’ possession in order to facilitate Seller’s attempt to cure any such Title Defects. If Seller elects in writing prior to Closing to cure any Title Defect, the Title Defect Amount alleged by Buyer with respect to such Title Defect shall, subject to Section  11.2( i ) , be funded into the Escrow Account at Closing and distributed in accordance with the terms of this Article  XI . An election by Seller to attempt to cure a Title Defect shall be without prejudice to its rights under Section 11.2(j) and shall not constitute an admission against interest or a waiver of Seller’s right to dispute the existence, nature or value of, or cost to cure, the alleged Title Defect.

(d) Remedies for Title Defects . Subject to Section  11.2( i ) and to Seller’s continuing right to dispute the existence of a Title Defect and/or the Title Defect Amount asserted with respect thereto, and subject to the rights of the Parties with respect to Section  7.4 and Section  8.4 , in the event that any Title Defect timely asserted by Buyer in accordance with Section  11.2(a) is not waived in writing by Buyer or cured during the Cure Period:

(i) the Cash Purchase Price or Final Cash Purchase Price, as applicable, shall be reduced by the Title Defect Amount determined pursuant to Section  11.2(g) or Section  11.2(j) ; or

(ii) if Buyer, in its sole and absolute discretion agrees, Seller may elect to indemnify Buyer against all Liability (up to the Allocated Value of the applicable Title Defect Property) resulting from such Title Defect with respect to such Title Defect Property pursuant to an indemnity agreement in a form and substance mutually agreed upon by the Parties (a “ Title Indemnity Agreement ”).

(e) Remedies for Title Benefits . With respect to each Title Benefit Property reported under Section  11.2(b) , the increase in the Allocated Value for such Title Benefit Property caused by such Title Benefit, as determined pursuant to Section  11.2(h) or Section 11.2(j) (the “ Title Benefit Amount ”) shall serve to offset the amount of any reduction in the Purchase Price due to Title Defects pursuant to Section  11.2(d) . In no event shall a Title Benefit result in an increase to the Purchase Price.

(f) Exclusive Remedy . Except as set forth in Section  11.1(b) and without limiting Seller’s representations and warranties in Article IV and Buyer’s rights under this Agreement with respect to Section  7.4 , the provisions set forth in Section  11.2(d) shall be the exclusive right and remedy of Buyer with respect to Seller’s failure to have Defensible Title with respect to any Asset or any other title matter.

 

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(g) Title Defect Amount . The amount by which the Allocated Value of a Title Defect Property is reduced as a result of the existence of a Title Defect shall be the “ Title Defect Amount ” and shall be determined in accordance with the following terms and conditions (without duplication):

(i) if Buyer and Seller agree on the Title Defect Amount, then that amount shall be the Title Defect Amount;

(ii) if the Title Defect is an Encumbrance that is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from the Title Defect Property;

(iii) if the Title Defect represents a discrepancy between (A) Seller’s Net Revenue Interest for any Title Defect Property and (B) the Net Revenue Interest set forth for such Title Defect Property on Exhibit B or Schedule 3.9 , as applicable, and Seller’s Working Interest is correspondingly and proportionately reduced as a result of such Title Defect, then the Title Defect Amount shall be the product of the Allocated Value of such Title Defect Property multiplied by a fraction, the numerator of which is the Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest set forth for such Title Defect Property on Exhibit B or Schedule 3.9 , as applicable;

(iv) if the Title Defect represents an increase of (A) Seller’s Working Interest for any Title Defect Property over (B) the Working Interest set forth for such Title Defect Property in Exhibit B , then the Title Defect Amount shall be the product of the Allocated Value of such Title Defect Property multiplied by a fraction, the numerator of which is the Working Interest increase and the denominator of which is the Working Interest set forth for such Title Defect Property in Exhibit B ;

(v) if the Title Defect represents a discrepancy where (A) the actual Net Acres for any Title Defect Property, as to the applicable Target Formations, is less than (B) the Net Acres for such Title Defect Property, as to the applicable Target Formations, stated on Schedule 3.9 , then the Title Defect Amount shall be the product obtained by multiplying, with respect to each affected Lease contributing to such Section, (1) such difference in Net Acres, to the extent attributable to such affected Lease by (2) the Allocated Value (reduced to a per Net Acre dollar amount as to the applicable Target Formations) for such Title Defect Property set forth on Schedule 3.9 by (3) a fraction, the numerator of which is the actual Net Revenue Interest of such affected Lease and the denominator of which is the average Net Revenue Interest for such Section set forth on Schedule 3.9 ;

(vi) if the Title Defect represents an obligation or Encumbrance upon or other defect in title to the Title Defect Property of a type not described above, then the Title Defect Amount shall be determined by taking into account the Allocated Value of the Title Defect Property, the portion of the Title Defect Property affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the Title Defect Property, the values placed upon the Title Defect by Buyer and Seller and such other reasonable factors as are necessary to make a proper evaluation;

 

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(vii) the Title Defect Amount with respect to a Title Defect Property shall be determined without duplication of any costs or losses included in another Title Defect Amount hereunder; and

(viii) notwithstanding anything to the contrary in this Article  XI , the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property shall not exceed the Allocated Value of such Title Defect Property.

(h) Title Benefit Amount . The Title Benefit Amount resulting from a Title Benefit shall be determined in accordance with the following methodology, terms and conditions (without duplication):

(i) if Buyer and Seller agree on the Title Benefit Amount, then that amount shall be the Title Benefit Amount;

(ii) if the Title Benefit represents a discrepancy between (A) Seller’s Net Revenue Interest for any Title Benefit Property and (B) the Net Revenue Interest set forth for such Title Benefit Property on Exhibit B or Schedule 3.9 , as applicable, then the Title Benefit Amount shall be the product of the Allocated Value of such Title Benefit Property multiplied by a fraction, the numerator of which is the Net Revenue Interest increase and the denominator of which is the Net Revenue Interest set forth for such Title Benefit Property on Exhibit B or Schedule 3.9 , as applicable;

(iii) if the Title Benefit represents a decrease of (A) Seller’s Working Interest for any Title Benefit Property over (B) the Working Interest set forth for such Title Benefit Property in Exhibit B , then the Title Benefit Amount shall be the product of the Allocated Value of such Title Benefit Property multiplied by a fraction, the numerator of which is the Working Interest decrease and the denominator of which is the Working Interest set forth for such Title Benefit Property in Exhibit B ;

(iv) if the Title Benefit represents a discrepancy where (A) the actual Net Acres for any Title Benefit Property, as to the applicable Target Formations, is greater than (B) the Net Acres for such Title Benefit Property, as to the applicable Target Formations, stated on Schedule 3.9 , then the Title Benefit Amount shall be the product obtained by multiplying, with respect to each affected Lease contributing to such Section, (1) such difference in Net Acres, to the extent attributable to such affected Lease by the Allocated Value (reduced to a per Net Acre dollar amount as to the applicable Target Formations) for such Title Benefit Property set forth on Schedule 3.9 by (3) a fraction, the numerator of which is the actual Net Revenue Interest of such affected Lease and the denominator of which is the average Net Revenue Interest for such Section set forth on Schedule 3.9 ; and

(v) if the Title Benefit is of a type not described above, then the Title Benefit Amounts shall be determined by taking into account the Allocated Value of Title Benefit Property, the portion of such Title Benefit Property affected by such Title Benefit, the legal effect of the Title Benefit, the potential economic effect of the Title Benefit over the life of such Title Benefit Property, the values placed upon the Title Benefit by Buyer and Seller and such other reasonable factors as are necessary to make a proper evaluation.

 

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(i) Title Defect Threshold and Deductible . Notwithstanding anything herein to the contrary, (i) in no event shall there be any adjustments to the Cash Purchase Price or other remedies provided by Seller for any individual Title Defect for which the Title Defect Amount does not exceed $125,000 (the “ Individual Title Defect Threshold ”); and (ii) in no event shall there be any adjustment to the Cash Purchase Price or other remedies provided by Seller for any Title Defect for which the Title Defect Amount exceeds the Individual Title Defect Threshold unless (A) the amount of the sum of (1) the aggregate Title Defect Amounts of all such Title Defects that exceed the Individual Title Defect Threshold (but excluding any Title Defect Amounts attributable to Title Defects cured by Seller), plus (2) the aggregate Remediation Amounts of all Environmental Defects that exceed the Individual Environmental Threshold (but excluding any Environmental Defects cured by Seller), exceeds (B) the Aggregate Deductible, after which point Buyer shall be entitled to adjustments to the Cash Purchase Price or other applicable remedies available hereunder, but only to the extent that the amount by which the aggregate amount of such Title Defect Amounts and Remediation Amounts exceeds the Aggregate Deductible. For the avoidance of doubt, if Seller indemnifies Buyer with respect to any Title Defect Property pursuant to a Title Indemnity Agreement (if permitted pursuant to Section  11.2(d)(ii) ) in each case the Title Defect Amount related to such Title Defect Property will not be counted towards the Aggregate Deductible and will not be considered for purposes of Section  7.4 and/or Section  8.4 .

(j) Title Dispute Resolution . Seller and Buyer shall attempt to agree on matters regarding (i) all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts, and (ii) the adequacy of any curative materials provided by Seller to cure an alleged Title Defect (the “ Disputed Title Matters ”) prior to Closing. If Seller and Buyer are unable to agree by Closing (or by the end of the Cure Period if Seller elects to attempt to cure a Title Defect after Closing), the Title Defect Amount alleged by Buyer with respect to such Title Defect shall, subject to Section  11.2( i ) , be funded into the Escrow Account at Closing and distributed in accordance with the terms of this Article  XI and the Disputed Title Matters shall be exclusively and finally resolved pursuant to this Section  11.2(j) . There shall be a single arbitrator, who shall be a title attorney with at least fifteen (15) years’ experience in oil and gas titles involving properties in the regional area in which the Title Defect Properties are located, as selected by mutual agreement of Buyer and Seller within fifteen (15) days after the Closing or the end of the Cure Period, as applicable (the “ Title Arbitrator ”). The Title Arbitrator must (a) be a neutral party who has never been an officer, director or employee of or performed material work for a Party or any Party’s Affiliate within the preceding five (5) year period and (b) agree in writing to keep strictly confidential the specifics and existence of the dispute as well as all proprietary records of the Parties reviewed by the Title Arbitrator in the process of resolving such dispute. Absent such mutual agreement between Buyer and Seller as to the Title Arbitrator, the Title Arbitrator shall be chosen by the Houston office of the American Arbitration Association. Each of Buyer and Seller shall submit to the Title Arbitrator its proposed resolution of the Disputed Title Matter. The Title Arbitrator shall be limited to awarding only one or the other of the two proposed resolutions. The arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section  11.2(j) . The Title Arbitrator’s determination shall be made within twenty (20) days after submission of the Disputed Title Matters and shall be final and binding upon both Parties, without right of appeal. In making his determination with

 

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respect to any Disputed Title Matter, the Title Arbitrator shall be bound by the rules set forth in Section  11.2(g) and Section  11.2(h) and, subject to the foregoing, may consider such other matters as, in the opinion of the Title Arbitrator, are necessary to make a proper determination. The Title Arbitrator, however, may not award Buyer a greater Title Defect Amount than the Title Defect Amount claimed by Buyer in its applicable Title Defect Notice. The Title Arbitrator shall act as an expert for the limited purpose of determining the specific Disputed Title Matter submitted by either Party and may not award damages, interest or penalties to either Party with respect to any matter. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case to the Title Arbitrator. Each of Seller and Buyer shall bear one-half of the costs and expenses of the Title Arbitrator. To the extent that the award of the Title Arbitrator with respect to any Title Defect Amount or Title Benefit Amount is not taken into account as an adjustment to the Cash Purchase Price pursuant to Section  3.5 or Section  3.7(a) , then, within ten (10) days after the Title Arbitrator delivers written notice to Buyer and Seller of his award with respect to a Title Defect Amount or a Title Benefit Amount, and, subject to Section  11.2(i) , (i) Buyer shall pay to Seller the amount, if any, so awarded by the Title Arbitrator to Seller, and (ii) Seller shall pay to Buyer the amount, if any, so awarded by the Title Arbitrator to Buyer; provided, however , that, if such amount was paid to the Escrow Agent at Closing pursuant to Section  3.6 , the Parties shall cause the Escrow Agent to disburse the applicable amount in accordance with this Section  11.2 . Nothing herein shall operate to cause Closing to be delayed on account of any arbitration conducted pursuant to this Section  11.2(j) (other than Sections  8.4 and 7.4 ).

11.3 Casualty and Condemnation Loss .

(a) Notwithstanding anything in this Article XI to the contrary, from and after the Effective Time, if Closing occurs, Buyer shall assume all risk of loss with respect to production of Hydrocarbons through normal depletion (including watering out of any well, collapsed casing or sand infiltration of any well) and the depreciation of Personal Property due to ordinary wear and tear, in each case, with respect to the Assets, and Buyer shall not assert such matters as Casualty Losses or Title Defects hereunder.

(b) If, after the Execution Date but prior to the Closing Date, any portion of the Assets is damaged or destroyed by fire or other casualty or is taken in condemnation or under right of eminent domain (each, a “ Casualty Loss ”), and the Closing thereafter occurs, Seller, at Closing, shall pay to Buyer all sums paid to Seller by Third Parties by reason of any Casualty Loss insofar as with respect to the Assets and shall assign, transfer and set over to Buyer or subrogate Buyer to all of Seller’s right, title and interest (if any) in insurance claims, unpaid awards, and other rights against Third Parties (excluding any Liabilities, other than insurance claims, of or against any Seller Indemnified Parties) arising out of such Casualty Loss insofar as with respect to the Assets; provided , however , that Seller shall reserve and retain (and Buyer shall assign to Seller) all right, title, interest and claims against Third Parties for the recovery of Seller’s costs and expenses incurred prior to Closing in repairing such Casualty Loss and/or pursuing or asserting any such insurance claims or other rights against Third Parties.

 

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11.4 Preferential Purchase Rights and Consents to Assign.

(a) With respect to each Preferential Purchase Right set forth in Schedule 4.10 , Seller, on or before five (5) Business Days after the Execution Date, shall send to the holder of each such Preferential Purchase Right a notice in material compliance with the contractual provisions applicable to such Preferential Purchase Right and otherwise in form and substance reasonably satisfactory to Buyer. Any Preferential Purchase Right must be exercised subject to all terms and conditions set forth in this Agreement, including the successful Closing of this Agreement on the dates certain set forth herein. The consideration payable under this Agreement for any particular Asset for purposes of Preferential Purchase Right notices shall be the Allocated Value for such Asset, adjusted as set forth in this Agreement.

(i) If, prior to Closing, any holder of a Preferential Purchase Right notifies Seller that it intends to consummate the purchase of the Asset to which its Preferential Purchase Right applies, then the Asset subject to such Preferential Purchase Right shall be excluded from the Assets to be assigned to Buyer at Closing (but only to the extent of the portion of such Asset affected by the Preferential Purchase Right), and the Cash Purchase Price shall be reduced by the Allocated Value of the Asset (or portion thereof) so excluded. Seller shall be entitled to all proceeds paid by any Person exercising a Preferential Purchase Right prior to Closing. If such holder of such Preferential Purchase Right thereafter fails to consummate the purchase of the Asset (or portion thereof) covered by such Preferential Purchase Right on or before sixty (60) days following the Closing Date, no suit or other proceeding by such Person with respect the Preferential Purchase Right is pending or threatened, and such Person has not disputed the Preferential Purchase Right in any respect (including the Allocated Value of the Asset subject thereto), subject to satisfaction of the conditions precedent in Article VII , (A) Seller shall so notify Buyer, (B) Buyer shall purchase, on or before ten (10) days following receipt of such notice, such Asset (or portion thereof) that was so excluded from the Assets to be assigned to Buyer at Closing, under the terms of this Agreement and for a price equal to the amount by which the Cash Purchase Price was reduced at Closing with respect to such excluded Asset (or portion thereof), adjusted as set forth in Section  3.3 and (C) Seller shall assign to Buyer the Asset (or portion thereof) so excluded at Closing pursuant to an instrument in substantially the same form as the Assignment. If, as of Closing, the time for exercising a Preferential Purchase Right has not expired and such Preferential Purchase Right has not been exercised or waived, then the Asset subject to such Preferential Purchase Right shall be excluded from the Assets to be assigned to Buyer at Closing (but only to the extent of the portion of such Asset affected by the Preferential Purchase Right), and the Purchase Price shall be reduced by the Allocated Value of the Asset (or portion thereof) so excluded, and Seller shall, at its sole expense, continue to use reasonable efforts to obtain the waiver of the Preferential Purchase Right and shall continue to be responsible for the compliance therewith. In the event that a Preferential Purchase Right with respect to an Asset deleted and excluded from the transactions contemplated by this Agreement at Closing pursuant the foregoing is waived or the time for exercise of such right has expired pursuant to its terms within sixty (60) days after the Closing Date, and no suit or other proceeding by the holder of such Preferential Purchase Right with respect thereto is pending or threatened, and such Person has not disputed the Preferential Purchase Right in any respect (including the Allocated Value of the Asset subject thereto), subject to satisfaction of the conditions precedent in Article VII , (A) Seller shall so notify Buyer, (B) Buyer shall purchase, on

 

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or before ten (10) days following receipt of such notice, such Asset (or portion thereof) that was so excluded from the Assets to be assigned to Buyer at Closing, under the terms of this Agreement and for a price equal to the amount by which the Purchase Price was reduced at Closing with respect to such excluded Asset (or portion thereof), adjusted as set forth in Section  3.3 and (C) Seller shall assign to Buyer the Asset (or portion thereof) so excluded at Closing pursuant to an instrument in substantially the same form as the Assignment.

(ii) All Assets for which any applicable Preferential Purchase Right has been waived, or as to which the period to exercise the applicable Preferential Purchase Right has expired without exercise by the holder thereof, in each case, prior to Closing, shall be sold to Buyer at Closing pursuant to the provisions of this Agreement.

(b) With respect to each Consent set forth in Schedule 4.4 and each other Consent applicable to the transactions contemplated in this Agreement, Seller, on or before five (5) Business Days after the Execution Date (unless Buyer has comments on the form in which case such date shall be extended), shall send to the holder of each such Consent a notice in material compliance with the contractual provisions applicable to such Consent (and otherwise in form and substance reasonably satisfactory to Buyer) seeking such holder’s consent to the transactions contemplated hereby.

(i) If (A) Seller fails to obtain a Consent prior to Closing and the failure to obtain such Consent would cause (1) the assignment of the Assets affected thereby to Buyer to be void or (2) the termination of a Lease or Contract under the express terms thereof (including terms permitting termination for a breach of a provision such Lease or Contract, including the Consent provision thereof) or (B) a Consent requested by Seller is denied in writing, then, in each case, the Asset (or portion thereof) affected by such un-obtained Consent shall be excluded from the Assets to be assigned to Buyer at Closing, and the Cash Purchase Price shall be reduced by the Allocated Value of such Asset (or portion thereof) so excluded, and Seller shall continue to use commercially reasonable efforts (provided that Seller shall not be required to incur any costs) to obtain the relevant Consent after Closing. In the event that a Consent (with respect to an Asset excluded pursuant to this Section 11.4(b)( i ) ) that was not obtained prior to Closing is obtained within one hundred eighty (180) days following Closing, then, subject to the conditions precedent in Article VII , within ten (10) days after such Consent is obtained (x) Buyer shall purchase the Asset (or portion thereof) that was so excluded as a result of such previously un-obtained Consent and pay to Seller the amount by which the Purchase Price was reduced at Closing with respect to the Asset (or portion thereof) so excluded and (y) Seller shall assign to Buyer the Asset (or portion thereof) so excluded at Closing pursuant to an instrument in substantially the same form as the Assignment.

(ii) If (A) Seller fails to obtain a Consent prior to Closing and the failure to obtain such Consent would not cause (1) the assignment of the Asset (or portion thereof) affected thereby to Buyer to be void or (2) the termination of a Lease or Contract under the express terms thereof (including terms permitting termination for a breach of a provision such Lease or Contract, including the Consent provision thereof) and (B) such Consent requested by Seller is not denied in writing by the holder thereof, then the Asset (or portion thereof) subject to such un-obtained Consent shall nevertheless be assigned by Seller to Buyer at Closing as part of the Assets and Buyer shall have no claim against, and Seller shall have no Liability for, the failure to obtain such Consent.

 

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(iii) Prior to Closing, Seller and Buyer shall use their commercially reasonable efforts to obtain all Consents applicable to the Assets; provided , however , that neither Party shall be required to incur any Liability or pay any money in order to obtain any such Consent. Subject to the foregoing, Buyer agrees to cooperate reasonably with Seller in order to facilitate the process of obtaining such Consents.

(iv) In cases in which the Asset subject to an unobtained Consent is an Asset other than a Lease, Well or Unit, and Buyer is assigned the Lease, Well or Unit to which such Asset relates, but such Asset is not transferred to Buyer due to the unwaived Consent requirement, Buyer and Seller shall continue after Closing to use commercially reasonable efforts to obtain the consent so that such Asset can be transferred to Buyer upon receipt of the consent, and, if permitted pursuant to applicable Law and agreement, such Asset shall be held by Seller for the benefit of Buyer, Buyer shall pay all amounts due thereunder or with respect thereto, and Buyer shall be responsible for the performance of any obligations under or with respect to such Asset to the extent that Buyer has been transferred the other Assets to which such Asset relates and that are necessary to such performance until the applicable consent is obtained.

ARTICLE XII

ENVIRONMENTAL MATTERS

12.1 Notice of Environmental Defects .

(a) Environmental Defects Notice . Buyer must deliver no later than 5 p.m. CST on February 9, 2017 (the “ Environmental Claim Date ”) claim notices to Seller meeting the requirements of this Section  12.1(a) (collectively, the “ Environmental Defect Notices ” and, individually, an “ Environmental Defect Notice ”) setting forth any matters which, in Buyer’s reasonable opinion, constitute Environmental Defects and which Buyer intends to assert as Environmental Defects pursuant to this Section  12.1 . To be effective, each Environmental Defect Notice shall be in writing and shall include (i) a description of the matter constituting the alleged Environmental Condition (including the applicable Environmental Law violated or implicated thereby) and the Assets affected by such alleged Environmental Condition, (ii) the Allocated Value of the Assets (or portions thereof) affected by such alleged Environmental Condition, (iii) supporting documents in Buyer’s possession or control that are reasonably necessary for Seller to verify the existence of such alleged Environmental Condition, and (iv) a calculation of the Remediation Amount (itemized in reasonable detail) that Buyer asserts is attributable to such alleged Environmental Defect. Notwithstanding anything contained in this Agreement to the contrary, and for the avoidance of doubt, any Environmental Defect asserted by Buyer pursuant to this Section 12.1(a) shall be limited to the Assets only, and Buyer shall not have the right to assert environmental defects with respect to any other assets, properties or operations. For all purposes of this Agreement, but without waiver or limitation of Seller’s representations and warranties in Article IV or indemnity obligations in Section  13.2 , Buyer shall be deemed to have waived, and Seller shall have no liability for, (A) any Environmental Defect which Buyer fails to assert as an Environmental Defect by a properly delivered Environmental Defect Notice received by Seller on or before

 

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the Environmental Claim Date, and/or (B) any Environmental Defect affecting any assets, properties or operations other than the Assets (other than contribution requirements in accordance with the applicable operating agreements), in each case, with such liabilities being “ Buyer’s Environmental Liabilities .” Buyer’s calculation of the Remediation Amount included in the Environmental Defect Notice must describe in reasonable detail the Remediation proposed for the alleged Environmental Condition that gives rise to the asserted Environmental Defect and identify all assumptions used by Buyer in calculating the Remediation Amount, including the standards that Buyer asserts must be met to comply with Environmental Laws. To give Seller an opportunity to commence reviewing and curing Environmental Defects, Buyer agrees to use reasonable efforts to give Seller, on or before the end of each calendar week prior to the Environmental Claim Date, written notice of all alleged Environmental Defects discovered by Buyer during the preceding calendar week, which notice may be preliminary in nature and supplemented prior to the Environmental Claim Date; provided that neither the failure to provide such notice, nor the contents of any such notice shall be actionable or give rise to any rights in favor of Seller, and Seller may not submit any such notice (or the fact that no such notice was submitted) to the Environmental Arbitrator pursuant to Section 12.1(f) .

(b) Seller s Right to Cure . With respect to any Asset excluded from the Closing pursuant to Section  12.1(c)(ii) , Seller shall have the right, but not the obligation, at its sole cost, risk, and expense, to attempt to cure any asserted Environmental Defect on or before the expiration of the Cure Period. During the period of time from Closing to the expiration of the Cure Period, Buyer agrees to afford Seller and its officers, employees and other authorized representatives reasonable access, during normal business hours, to all Records in Buyer’s or any of its Affiliates’ possession in order to facilitate Seller’s attempt to cure any such Environmental Defects. The Allocated Value of any Environmental Defect that Seller elects in writing to cure in accordance with this Section  12.1(b) prior to Closing shall, subject to Section  12.1(e) , be funded into the Escrow Account at Closing and distributed in accordance with the terms of this Article  XII . An election by Seller to attempt to cure an Environmental Defect shall be without prejudice to its rights under Section 12.1(f) and shall not constitute an admission against interest or a waiver of Seller’s right to dispute the existence, nature or value of, or cost to cure, the alleged Environmental Defect.

(c) Remedies for Environmental Defects . Subject to Section 12.1(e) and to Seller’s continuing right to dispute the existence of an Environmental Defect and/or the Remediation Amount asserted with respect thereto, and subject to the rights of the Parties with respect to Section  7.4 and Section  8.4 , in the event that any Environmental Defect timely asserted by Buyer in accordance with Section  12.1(a) is not waived in writing by Buyer or cured during the Cure Period:

(i) Unless Section  12.1(c)(ii) or (iii)  applies, the Purchase Price shall be reduced by the Remediation Amount;

(ii) subject to Section  12.1(b), if the Remediation Amount exceeds the Allocated Value of any affected Asset, at the election of either Buyer or Seller, Seller shall retain the entirety of the Asset that is subject to such Environmental Defect, together with all associated Assets, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Asset and such associated Assets; or

 

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(iii) subject to Buyer’s consent (in its sole and absolute discretion), Seller may elect to indemnify Buyer against all Liability resulting from such Environmental Defect with respect to the Assets pursuant to an indemnity agreement in a form and substance mutually agreeable to the Parties (each, an “ Environmental Indemnity Agreement ”).

If Seller elects the option set forth in clause (i) above, Buyer shall be deemed to have assumed responsibility for all of the costs and expenses attributable to the Remediation of the Environmental Condition attributable to such Environmental Defect and for all Liabilities with respect thereto and such responsibility of Buyer shall be deemed to constitute part of the Assumed Obligations hereunder.

(d) Exclusive Remedy . Except for Buyer’s rights under this Agreement with respect to Section  7.4, and without limitation or of Seller’s representations and warranties in Article IV or indemnity obligations in Section  13.2 , the provisions set forth in Section  12.1(b) shall be the exclusive right and remedy of Buyer with respect to any Environmental Defect with respect to any Asset or other environmental matter.

(e) Environmental Deductibles . Notwithstanding anything herein to the contrary, (i) in no event shall there be any adjustment to the Cash Purchase Price or other remedies provided by Seller for any individual Environmental Defect for which the Remediation Amount does not exceed $125,000 (the “ Individual Environmental Threshold ”); and (ii) in no event shall there be any adjustment to the Cash Purchase Price or other remedies provided by Seller for any Environmental Defect for which the Remediation Amount exceeds the Individual Environmental Threshold unless (A) the amount of the sum of (1) the aggregate Remediation Amounts of all such Environmental Defects that exceed the Individual Environmental Threshold (but excluding any Remediation Amounts attributable to any Environmental Defects cured by Seller), plus (2) the aggregate Title Defect Amounts of all Title Defects that exceed the Individual Title Defect Threshold (but excluding any Title Defect Amounts attributable to Title Defects cured by Seller), exceeds (B) the Aggregate Deductible, after which point Buyer shall be entitled to adjustments to the Cash Purchase Price or other applicable remedies available hereunder, but only with respect to the amount by which the aggregate amount of such Remediation Amounts and Title Defect Amounts exceeds the Aggregate Deductible. For the avoidance of doubt, if Seller indemnifies Buyer with respect to any Environmental Defect Property pursuant to an Environmental Indemnity Agreement or retains any Assets pursuant to Section 12.1(c)(ii) , the Remediation Amounts relating to such retained Assets will not be counted towards the Aggregate Deductible and will not be considered for purposes of Section  7.4 and/or Section  8.4 .

(f) Environmental Dispute Resolution . Seller and Buyer shall attempt to agree on (i) all Environmental Defects and Remediation Amounts prior to Closing and (ii) the adequacy of any cure by Seller of any asserted Environmental Defect prior to the end of the Cure Period (items (i) and (ii), collectively, the “ Disputed Environmental Matters ”). If Seller and Buyer are unable to agree by Closing (or by the end of the Cure Period if Seller elects to attempt to cure an asserted Environmental Defect after Closing), the Remediation Amount

 

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alleged by Buyer with respect to such affected Asset shall, subject to Section  12.1(e) , be funded into the Escrow Account at Closing and distributed in accordance with the terms of this Article  XII and the Disputed Environmental Matters shall be exclusively and finally resolved by arbitration pursuant to this Section  12.1(f) . There shall be a single arbitrator, who shall be an environmental attorney with at least fifteen (15) years’ experience in environmental matters involving oil and gas producing properties in the regional area in which the affected Assets are located, as selected by mutual agreement of Buyer and Seller within fifteen (15) days after the Closing Date or the end of the Cure Period, as applicable, or, absent such agreement, by the Houston office of the American Arbitration Association (the “ Environmental Arbitrator ”). The arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section  12.1 . The Environmental Arbitrator’s determination shall be made within twenty (20) days after submission of the matters in dispute and shall be final and binding upon both Parties, without right of appeal. In making his determination, the Environmental Arbitrator shall be bound by the rules set forth in this Section  12.1 and, subject to the foregoing, may consider such other matters as in the opinion of the Environmental Arbitrator are necessary or helpful to make a proper determination. The Environmental Arbitrator, however, may not award Buyer any greater Remediation Amount than the Remediation Amount claimed by Buyer in its applicable Environmental Defect Notice. The Environmental Arbitrator shall act as an expert for the limited purpose of determining the specific Disputed Environmental Matters submitted by either Party and may not award damages, interest or penalties to either Party with respect to any matter. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case to the Environmental Arbitrator. Each of Seller and Buyer shall bear one-half of the costs and expenses of the Environmental Arbitrator. To the extent that the award of the Environmental Arbitrator with respect to any Remediation Amount is not taken into account as an adjustment to the Cash Purchase Price pursuant to Section  3.5 or Section 3.7(a) , then, within ten (10) days after the Environmental Arbitrator delivers written notice to Buyer and Seller of his award with respect to any Remediation Amount, and, subject to Section  12.1(e) , (i) Buyer shall pay to Seller the amount, if any, so awarded by the Environmental Arbitrator to Seller, and (ii) Seller shall pay to Buyer the amount, if any, so awarded by the Environmental Arbitrator to Buyer; provided, however , that, if such amount was paid to the Escrow Agent at Closing pursuant to Section  3.6 , the Parties shall cause the Escrow Agent to disburse the applicable amount in accordance with this Section  12.1(f) . Nothing herein shall operate to cause Closing to be delayed on account of any arbitration conducted pursuant to this Section  12.1(f) , and, to the extent any adjustments are not agreed upon by the Parties as of Closing, the Cash Purchase Price shall not be adjusted therefor at Closing and subsequent adjustments to the Cash Purchase Price, if any, will be made pursuant to Section  3.6 or this Section 12.1(f) .

12.2 NORM, Asbestos, Wastes and Other Substances . Buyer acknowledges that the Assets have been used for exploration, development, and production of oil and gas and that there may be petroleum, produced water, wastes or other substances or materials located in, on or under the Assets or associated with the Assets. Equipment and sites included in the Assets may contain asbestos, NORM or other Hazardous Substances. NORM may affix or attach itself to the inside of wells, materials and equipment as scale, or in other forms. The wells, materials and equipment located on the Assets or included in the Assets may contain NORM, asbestos and

 

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other wastes or Hazardous Substances. NORM containing material and/or other wastes or Hazardous Substances may have come in contact with various environmental media, including, water, soils or sediment. Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of environmental media, wastes, asbestos, NORM and other Hazardous Substances from the Assets. The presence of NORM or asbestos-containing materials that are non-friable cannot be claimed as an Environmental Defect, except to the extent constituting a violation of Environmental Laws.

ARTICLE XIII

ASSUMPTION; INDEMNIFICATION; SURVIVAL

13.1 Assumption by Buyer . Without limiting Buyer’s rights to indemnity under this Article  XIII , or the Retained Liabilities and Buyer’s rights under any Title Indemnity Agreement or Environmental Indemnity Agreement, from and after Closing, Buyer assumes and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid and discharged) all obligations and Liabilities, known or unknown, arising from, based upon, related to or associated with the Assets, regardless of whether such obligations or Liabilities arose prior to, on or after the Effective Time, including obligations and Liabilities relating in any manner to the use, ownership or operation of the Assets, including obligations to (a) furnish makeup gas and/or settle Imbalances, (b) pay Working Interests, royalties, overriding royalties and other interest owners’ revenues or proceeds attributable to sales of Hydrocarbons, including those held in suspense (including those amounts for which the Cash Purchase Price was adjusted pursuant to Section 3.3(b)(vi) ), (c) Decommission the Assets (the “ Decommissioning Obligations ”), (d) clean up and/or remediate the Assets in accordance with applicable Contracts and Laws, (e) perform all obligations applicable to or imposed on the lessee, owner or operator under the Leases and the Applicable Contracts, or as required by Law, and (f) subject to Article  XII , Environmental Conditions, Environmental Defects and Liabilities imposed under Environmental Laws with respect to the Assets, (all of said obligations and Liabilities described in this Section  13.1 , including in clauses (a) through (f) herein, but less and except the Retained Liabilities, being referred to as the “ Assumed Obligations ”).

13.2 Indemnities of Seller . Effective as of Closing, subject to the limitations set forth in Section  13.4 and Section  13.8 or otherwise in this Agreement, Seller shall be responsible for, shall pay on a current basis, and hereby agrees to defend, indemnify, hold harmless and forever release Buyer, Parent and their respective Affiliates, and all of its and their respective equity holders, partners, members, directors, officers, managers, employees, agents and representatives (collectively, the “ Buyer Indemnified Parties ”) from and against any and all Liabilities, whether or not relating to Third Party Claims or incurred in the investigation or defense of any of the same or in asserting, preserving or enforcing any of their respective rights hereunder, arising from, based upon, related to or associated with:

(a) any breach by Seller of any of its representations or warranties contained in Article  IV ;

(b) any breach by Seller of any of its covenants or agreements under this Agreement;

 

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(c) any Liabilities to Third Parties for personal injury or death attributable to Seller’s operation of the Assets prior to the Closing Date;

(d) any Liabilities attributable to Third Party Claims against Seller relating to Seller’s payment of or accounting for Burdens on production attributable to Hydrocarbons produced from the Assets during the period of time prior to the Effective Time;

(e) except for water disposal, any Liabilities arising from disposal of Hazardous Substances off-site of the Assets by Seller prior to the Effective Time;

(f) any and all Seller Taxes;

(g) any Liabilities arising out of, or relating to, the Excluded Assets and any oil and gas properties removed from the Assets pursuant to the terms of this Agreement;

(h) any Liabilities that are the responsibility of Seller under Sections  2.3 ;

The matters described in Sections  13.2(f) and 13.2(g) (but only to the extent of and any oil and gas properties removed from the Assets pursuant to the terms of this Agreement) are referred to herein as the “ Retained Liabilities ”).

13.3 Indemnities of Buyer . Effective as of Closing, Buyer and its successors and assigns shall assume and be responsible for, shall pay on a current basis, and hereby agrees to defend, indemnify, hold harmless and forever release Seller and its Affiliates, and all of its and their respective equity holders, partners, members, directors, officers, managers, employees, agents and representatives (collectively, the “ Seller Indemnified Parties ”) from and against any and all Liabilities, whether or not relating to Third Party Claims or incurred in the investigation or defense of any of the same or in asserting, preserving or enforcing any of their respective rights hereunder, arising from, based upon, related to or associated with:

(a) any breach by Buyer of any of its representations or warranties contained in Article  V ;

(b) any breach by Buyer of any of its covenants or agreements under this Agreement; or

(c) the Assumed Obligations.

13.4 Limitation on Liability.

(a) Seller shall not have any liability for any indemnification under Section  13.2 of this Agreement (i) for any individual Liability unless the amount with respect to such Liability exceeds $125,000, and (ii) until and unless the aggregate amount of all Liabilities for which Claim Notices are delivered by Buyer exceeds the Indemnity Deductible, and then only to the extent such Liabilities exceed the Indemnity Deductible; provided that any indemnification for Seller Taxes shall not be subject to any limitations set forth in this Section  13.4 .

 

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(b) Notwithstanding anything to the contrary contained in this Agreement, (i) Seller shall not be required to indemnify Buyer for aggregate Liabilities in excess of an amount equal to fifteen percent (15%) of the Purchase Price and (ii) indemnity claims against Seller shall be satisfied first out of the Indemnity Escrow unless Seller elects to satisfy such claims in cash directly.

(c) Notwithstanding the foregoing, the limitations in Section  13.4(a) and (b)  shall not apply to the Retained Liabilities (or Seller’s obligations under Section  13.2 with respect thereto), Seller’s indemnity obligations in Sections 13.2(c), 13.2(d), 13.2(e), or 13.2(h), or the Specified Representations. For the purposes of Seller’s obligations under Section  13.2 , representations, warranties, covenants, and agreements herein that are qualified by materiality or Material Adverse Effect shall be deemed not to be so qualified.

(d) Notwithstanding anything to the contrary contained in this Agreement, Seller shall not be required to indemnify Buyer under Section  13.2(a) with respect to any breach by Seller of any representation or warranty set forth in Section  4.14 to the extent attributable to any Asset Tax allocable to Buyer under Section  15.2 , except for any penalties, interest or additions to Tax imposed with respect to such Asset Tax by a Governmental Authority as a result of such breach.

13.5 Express Negligence . EXCEPT AS OTHERWISE PROVIDED IN SECTION 6.3 AND SECTION 10.1 , THE DEFENSE, INDEMNIFICATION, HOLD HARMLESS, RELEASE AND ASSUMED OBLIGATIONS PROVISIONS PROVIDED FOR IN THIS AGREEMENT SHALL BE APPLICABLE WHETHER OR NOT THE LIABILITIES, LOSSES, COSTS, EXPENSES AND DAMAGES IN QUESTION AROSE OR RESULTED SOLELY OR IN PART FROM THE GROSS, SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OR VIOLATION OF LAW OF OR BY ANY INDEMNIFIED PARTY. BUYER AND SELLER ACKNOWLEDGE THAT THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS “ CONSPICUOUS .”

13.6 Exclusive Remedy . Notwithstanding anything to the contrary contained in this Agreement, the Parties agree that, from and after Closing, Section  2.3 , Section  3.6 , Section  6.3 , Section  10.1 , Section 11.1(b), Section  13.2 and Section  13.3 , any Title Indemnity Agreement or Environmental Indemnity Agreement entered into by the Parties, and the other Transaction Documents, contain the Parties’ exclusive remedies against each other with respect to the transactions contemplated hereby, including breaches of the representations, warranties, covenants and agreements of the Parties contained in this Agreement or in any document or certificate delivered pursuant to this Agreement. Except as specified in Section 11.1(b) , Section  13.2 and any Title Indemnity Agreement or Environmental Indemnity Agreement entered into by the Parties, effective as of Closing, Buyer, on its own behalf and on behalf of the Buyer Indemnified Parties, hereby releases, remises and forever discharges Seller and its Affiliates and all of such Persons’ equity holders, partners, members, directors, officers, employees, agents and representatives from any and all suits, legal or administrative proceedings, claims, demands, damages, losses, costs, Liabilities, interest or causes of action whatsoever, at Law or in equity, known or unknown, which Buyer or the Buyer Indemnified Parties might now or subsequently have, based on, relating to or arising out of this Agreement,

 

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the transactions contemplated by this Agreement, the ownership, use or operation of any of the Assets prior to Closing or the condition, quality, status or nature of any of the Assets prior to Closing, including rights to contribution under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, and any similar Environmental Law, breaches of statutory or implied warranties, nuisance or other tort actions, rights to punitive damages, common law rights of contribution and rights under insurance maintained by Seller or any of its Affiliates (except as provided in Section 11.3(b) ).

13.7 Indemnification Procedures . All claims for indemnification under Section  6.3 , Section  10.1 , Section  13.2 and Section  13.3 shall be asserted and resolved as follows:

(a) For purposes of Section  6.3 , Section  10.1 and this Article  XIII , the term “ Indemnifying Party ” when used in connection with particular Liabilities shall mean the Party or Parties having an obligation to indemnify the other Party and/or other Persons with respect to such Liabilities pursuant to Section  6.3 , Section  10.1 or this Article  XIII , and the term “ Indemnified Party ” when used in connection with particular Liabilities shall mean the Party and/or other Persons having the right to be indemnified with respect to such Liabilities by the Indemnifying Party pursuant to Section  6.3 , Section  10.1 or this Article  XIII .

(b) To make a claim for indemnification under Section  6.3 , Section  10.1 , Section  13.2 or Section  13.3 , an Indemnified Party shall notify the Indemnifying Party of its claim under this Section  13.7 , including the specific details of and specific basis under this Agreement for its claim (the “ Claim Notice ”). In the event that the claim for indemnification is based upon a claim by a Third Party against the Indemnified Party (a “ Third Party Claim ”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has actual knowledge of the Third Party Claim and shall enclose a copy of all papers (if any) served with respect to the Third Party Claim; provided that the failure of any Indemnified Party to give notice of a Third Party Claim as provided in this Section  13.7(b) shall not relieve the Indemnifying Party of its obligations under Section  6.3 , Section  10.1 , Section  13.2 or Section  13.3 (as applicable) except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively defend against the Third Party Claim or otherwise materially prejudices the Indemnifying Party’s ability to defend against the Third Party Claim. In the event that the claim for indemnification is based upon an inaccuracy or breach of a representation, warranty, covenant or agreement, the Claim Notice shall specify the representation, warranty, covenant or agreement that was inaccurate or breached.

(c) In the case of a claim for indemnification based upon a Third Party Claim, the Indemnifying Party shall have thirty (30) days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its obligation to defend and indemnify the Indemnified Party against such Third Party Claim at the sole cost and expense of the Indemnifying Party. The Indemnified Party is authorized, prior to and during such thirty (30) day period, at the expense of the Indemnifying Party, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party.

(d) If the Indemnifying Party admits its obligation to defend and indemnify the Indemnified Party against a Third Party Claim, it shall have the right and obligation to

 

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diligently defend, at its sole cost and expense, the Indemnified Party against such Third Party Claim; provided, however, that the Indemnifying Party shall in no event have the right to defend against any Third Party Claim to the extent such Third Party Claim (i) seeks an injunction or non-monetary or equitable relief against the Indemnified Party, or (ii) seeks monetary damages in an amount in excess of the then remaining amount of the cap on Liabilities set forth in Section  13.4 hereof. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof. If requested by the Indemnifying Party, the Indemnified Party agrees to cooperate in contesting any Third Party Claim which the Indemnifying Party elects to contest. The Indemnified Party may participate in, but not control, at its own expense, any defense or settlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section  13.7(d) . An Indemnifying Party shall not, without the written consent of the Indemnified Party, (i) settle any Third Party Claim or consent to the entry of any judgment with respect thereto which does not include an unconditional written release of the Indemnified Party from all Liability in respect of such Third Party Claim or (ii) settle any Third Party Claim or consent to the entry of any judgment with respect thereto in any manner that may materially and adversely affect the Indemnified Party (other than as a result of money damages covered by the indemnity).

(e) If the Indemnifying Party does not admit its obligation or admits its obligation to defend and indemnify the Indemnified Party against a Third Party Claim, but fails to diligently prosecute, indemnify against or settle the Third Party Claim, then the Indemnified Party shall have the right to defend against the Third Party Claim at the sole cost and expense of the Indemnifying Party, with counsel of the Indemnified Party’s choosing, subject to the right of the Indemnifying Party to admit its liability and assume the defense of the Third Party Claim at any time prior to settlement or final determination thereof. If the Indemnifying Party has not yet admitted its obligation to defend and indemnify the Indemnified Party against a Third Party Claim, the Indemnified Party shall send written notice to the Indemnifying Party of any proposed settlement and the Indemnifying Party shall have the option for ten (10) days following receipt of such notice to (i) admit in writing its obligation to indemnify the Indemnified Party from and against the liability and consent to such settlement, (ii) if liability is so admitted, reject, in its reasonable judgment, the proposed settlement, or (iii) deny liability. Any failure by the Indemnifying Party to respond to such notice shall be deemed to be an election under subsection (iii) above.

(f) In the case of a claim for indemnification not based upon a Third Party Claim, the Indemnifying Party shall have thirty (30) days from its receipt of the Claim Notice to (i) cure the Liabilities complained of, (ii) admit its liability for such Liability or (iii) dispute the claim for such Liabilities. If the Indemnifying Party does not notify the Indemnified Party within such thirty (30) day period that it has cured the Liabilities or that it disputes the claim for such Liabilities, the Indemnifying Party shall be deemed to dispute the claim for such Liabilities.

13.8 Survival .

(a) Except for the Specified Representations, the representations and warranties of the Parties in Article  IV and Article V and the covenants and agreements of the Parties in Sections  6.1 shall survive Closing for a period of twelve (12) months. The Specified

 

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Representations (other than the representations and warranties set forth in Section  4.14 ) shall survive Closing without time limit. The representations and warranties set forth in Section  4.14 and the covenants set forth in Section  15.2 shall terminate sixty (60) days after the end of the applicable statute of limitations period. Subject to the foregoing and Section  13.8(b) , the remainder of this Agreement shall survive Closing without time limit. Representations, warranties, covenants and agreements shall be of no further force or effect after the date of their expiration; provided that there shall be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation, warranty, covenant or agreement prior to its expiration date.

(b) The indemnities in Section  13.2(a) , Section  13.2(b) , Section  13.3(a) and  Section  13.3(b) shall terminate as of the expiration date of each respective representation, warranty, covenant or agreement that is subject to indemnification, except in each case as to matters for which a specific written claim for indemnity has been delivered to the Indemnifying Party on or before such expiration date. Seller’s indemnities in Sections 13.2(c) , 13.2(d) , 13.2(e) , 13.2(g) (other than with respect to and any oil and gas properties removed from the Assets pursuant to the terms of this Agreement) and Section  13.2(h) , shall terminate twelve (12) months after the Closing. Seller’s indemnities in Section  13.2(f) shall terminate sixty (60) days after the end of the applicable statute of limitations period, and Seller’s indemnities in Section  13.2(g) with respect to oil and gas properties removed from the Assets pursuant to the terms of this Agreement shall survive Closing without time limit. Buyer’s indemnities in Section  6.3 , Section  10.1 and Section  13.3(c) shall survive Closing without time limit and shall be deemed covenants running with the Assets ( provided that Buyer and its successors and assigns shall not be released from any of, and shall remain jointly and severally liable to the Seller Indemnified Parties for, the obligations and Liabilities of Buyer under such Sections of this Agreement upon any transfer or assignment of any Asset).

13.9 Waiver of Right to Rescission . Seller and Buyer acknowledge that, following Closing, the payment of money, as limited by the terms of this Agreement, shall be adequate compensation for breach of any representation, warranty, covenant or agreement contained herein or for any other claim arising in connection with or with respect to the transactions contemplated by this Agreement. As the payment of money shall be adequate compensation, following Closing, Buyer and Seller waive any right to rescind this Agreement or any of the transactions contemplated hereby.

13.10 Insurance . The amount of any Liabilities for which any of the Buyer Indemnified Parties is entitled to indemnification under this Agreement or in connection with or with respect to the transactions contemplated by this Agreement shall be reduced by any corresponding insurance proceeds from insurance policies carried by a Party realized or that could reasonably be expected to be realized by such Party if a claim were properly pursued under the relevant insurance arrangements.

13.11 Non-Compensatory Damages . None of the Buyer Indemnified Parties nor the Seller Indemnified Parties shall be entitled to recover from Seller or Buyer, as applicable, or their respective Affiliates, any special, indirect, consequential, punitive, exemplary, remote or speculative damages (including damages for lost profits of any kind) arising under or in connection with this Agreement or the transactions contemplated hereby, except to the extent any

 

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such Party suffers such damages to a Third Party, which damages (including costs of defense and reasonable attorneys’ fees incurred in connection with defending against such damages) shall not be excluded by this provision as to recovery hereunder. Subject to the preceding sentence, each of Buyer, on behalf of each of the Buyer Indemnified Parties, and Seller, on behalf of each of the Seller Indemnified Parties, waives any right to recover any special, indirect, consequential, punitive, exemplary, remote or speculative damages (including damages for lost profits of any kind) arising in connection with or with respect to this Agreement or the transactions contemplated hereby.

13.12 Disclaimer of Application of Anti-Indemnity Statutes . The Parties acknowledge and agree that the provisions of any anti-indemnity statute relating to oilfield services and associated activities shall not be applicable to this Agreement and/or the transactions contemplated hereby.

ARTICLE XIV

TERMINATION, DEFAULT AND REMEDIES

14.1 Right of Termination . This Agreement and the transactions contemplated herein may be terminated at any time prior to Closing:

(a) by Seller or Buyer if Closing shall not have occurred on or before March 17, 2017; or

(b) by Seller in its sole discretion if Parent has failed to deposit with the Escrow Agent the entirety of the Deposit within the time period specified in Section  3.2 .

provided , however , that no Party shall have the right to terminate this Agreement pursuant to Section  14.1 if such Party or its Affiliates are at such time in material breach of any provision of this Agreement.

14.2 Effect of Termination.

(a) If the obligation to close the transactions contemplated by this Agreement is terminated pursuant to any provision of Section  14.1 hereof, then, except as provided in Section  3.2 and except for the provisions of Sections 10.1(c) through 10.1(g) , 10.2 , 10.3 , 13.11 , this Section  14.2 , Section  14.3 , Article I and Article  XV (other than Sections  15.2(b) through 15.2(h) , 15.7 , 15.8, 15.15 and 15.17 ) and such of the defined terms set forth in Annex I to give context to such Sections, this Agreement shall forthwith become void.

(b) If (i) all conditions precedent to the obligations of Buyer set forth in Article VII (other than those actions or deliveries to occur at Closing or contingent upon the satisfaction of other conditions precedent set forth in Article VII at Closing) have been met, or waived by Buyer, and (ii) the transactions contemplated by this Agreement are not consummated because of: (A) the failure of Buyer to perform in any material respect any of its obligations hereunder (including a failure to proceed with Closing if all conditions precedent to the obligations of Buyer set forth in Article VII (other than those actions or deliveries to occur at Closing or contingent upon the satisfaction of other conditions precedent set forth in Article VII at Closing) have been met, or waived by Buyer), or (B) the failure of any of Buyer’s

 

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representations or warranties hereunder to be true and correct in all material respects (without regard to materiality qualifiers) as of the Execution Date and/or as of the Closing (or anticipated Closing if Seller is ready, willing and able to close in such instance), then, in such event, Seller shall have the right, as its sole and exclusive remedy, to terminate this Agreement pursuant to Section  14.1 and retain the Deposit together with any interest or income thereon, free of any claims by Buyer with respect thereto as liquidated damages. It is expressly stipulated by the Parties that the actual amount of damages resulting from such a termination would be extremely difficult or impossible to determine accurately because of (among other things) the unique nature of the Assets and the uncertainties of applicable commodity markets, and the amount of the Deposit is a fair and reasonable estimate by the Parties of such damages.

(c) If (i) all conditions precedent to the obligations of Seller set forth in Article VIII (other than those actions or deliveries to occur at Closing or contingent upon the satisfaction of other conditions precedent set forth in Article VIII at Closing) have been met, or waived by Seller, and (ii) the transactions contemplated by this Agreement are not consummated because of: (A) the failure of Seller to perform in any material respect any of its obligations hereunder (including a failure to proceed with Closing if all conditions precedent to the obligations of Seller set forth in Article VIII (other than those actions or deliveries to occur at Closing or contingent upon the satisfaction of other conditions precedent set forth in Article VIII at Closing) have been met, or waived by Seller), or (B) the failure of any of Seller’s representations or warranties hereunder to be true and correct in all material respects (without regard to materiality qualifiers) as of the Execution Date and/or as of the Closing (or anticipated Closing if Buyer is ready, willing and able to close in such instance), then Buyer, without limiting Buyer’s other remedies at law or equity, including the right to specifically enforce Seller’s obligation to convey the Assets, shall be entitled to the delivery of the Deposit together with any interest or income actually earned thereon, free of any claims by Seller with respect thereto after the termination of this Agreement.

(d) If this Agreement is terminated by the mutual written agreement of the Parties, or this Agreement is otherwise terminated pursuant to Section  14.1 and the Closing does not occur on or before the Closing Date for any reason other than as set forth in Section  14.2(b) , then Buyer shall be entitled to the delivery of the Deposit together with any interest or income actually earned thereon, free of any claims by Seller with respect thereto after the termination of this Agreement.

(e) In this event that this Agreement terminates under Section  14.1 , the Parties shall execute and deliver joint written instructions to the Escrow Agent to disburse the Deposit, together with any interest or income thereon, in accordance with this Section  14.2 .

14.3 Return of Documentation and Confidentiality . Upon termination of this Agreement, Buyer shall return to Seller all title, engineering, geological and geophysical data, environmental assessments and/or reports, maps and other information furnished by or on behalf of Seller to Buyer or prepared by or on behalf of Buyer in connection with its due diligence investigation of the Assets, in each case in accordance with the Confidentiality Agreement, and an officer of Buyer shall certify same to Seller in writing.

 

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ARTICLE XV

MISCELLANEOUS

15.1 Appendices, Exhibits and Schedules . All of the Appendices, Exhibits and Schedules referred to in this Agreement are hereby incorporated into this Agreement by reference and constitute a part of this Agreement. Each Party to this Agreement and its counsel has received a complete set of Appendices, Exhibits and Schedules prior to and as of the execution of this Agreement.

15.2 Expenses and Taxes .

(a) Except as otherwise specifically provided herein, all fees, costs and expenses incurred by Buyer or Seller in negotiating this Agreement or in consummating the transactions contemplated by this Agreement shall be paid by the Party incurring the same, including legal and accounting fees, costs and expenses.

(b) Seller shall be allocated and bear all Asset Taxes attributable to (i) any Tax period ending prior to the Effective Time and (ii) the portion of any Straddle Period ending immediately prior to the Effective Time. Buyer shall be allocated and bear all Asset Taxes attributable to (x) any Tax period beginning at or after the Effective Time and (y) the portion of any Straddle Period beginning at the Effective Time.

(c) For purposes of determining the allocations described in Section 15.2(b) , (i) Asset Taxes that are attributable to the severance or production of Hydrocarbons (other than such Asset Taxes described in clause (iii) below) shall be allocated to the period in which the severance or production giving rise to such Asset Taxes occurred, (ii) Asset Taxes that are based upon or related to income or receipts or imposed on a transactional basis (other than such Asset Taxes described in clause (i) above or (iii) below), shall be allocated to the period in which the transaction giving rise to such Asset Taxes occurred, and (iii) Asset Taxes that are ad valorem, property or other Asset Taxes imposed on a periodic basis pertaining to a Straddle Period shall be allocated between the portion of such Straddle Period ending immediately prior to the Effective Time and the portion of such Straddle Period beginning at the Effective Time by prorating each such Asset Tax based on the number of days in the applicable Straddle Period that occur before the date on which the Effective Time occurs, on the one hand, and the number of days in such Straddle Period that occur on or after the date on which the Effective Time occurs, on the other hand. For purposes of clause (iii) of the preceding sentence, the period for such Asset Taxes shall begin on the date on which ownership of the applicable Assets gives rise to liability for the particular Asset Tax and shall end on the day before the next such date.

(d) To the extent the actual amount of an Asset Tax is not known at the time an adjustment is to be made with respect to such Asset Tax pursuant to Sections 3.3 , 3.5 or 3.7 , as applicable, the Parties shall utilize the most recent information available in estimating the amount of such Asset Tax for purposes of such adjustment. To the extent the actual amount of an Asset Tax (or the amount thereof paid or economically borne by a Party) is ultimately determined to be different than the amount (if any) that was taken into account in the Final Settlement Statement as finally determined pursuant to Section 3.7 , timely payments will be made from one Party to the other to the extent necessary to cause each Party to bear the amount of such Asset Tax that is allocable to such Party under this Section 15.2 .

 

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(e) Subject to Buyer’s indemnification rights under Section  13.2 , after the Closing Date, Buyer shall (i) be responsible for paying any Asset Taxes relating to any Tax period that ends before or includes the Effective Time that become due and payable after the Closing Date and shall file with the appropriate Governmental Authority any and all Tax Returns required to be filed after the Closing Date with respect to such Asset Taxes, (ii) submit each such Tax Return to Seller for its review and comment reasonably in advance of the due date therefor and (iii) timely file any such Tax Return, incorporating any comments received from Seller prior to the due date therefor. The Parties agree that (x) this Section 15.2(e) is intended to solely address the timing and manner in which certain Tax Returns relating to Asset Taxes are filed and the Asset Taxes shown thereon are paid to the applicable taxing authority, and (y) nothing in this Section 15.2(e) shall be interpreted as altering the manner in which Asset Taxes are allocated to and economically borne by the Parties (except for any penalties, interest or additions to Tax imposed as a result of any breach by Buyer of its obligations under this Section 15.2(e) , which shall be borne by Buyer).

(f) All required documentary, filing and recording fees and expenses in connection with the filing and recording of the assignments, conveyances or other instruments required to convey title to the Assets to Buyer shall be borne by Buyer. Any and all sales, use, transfer, stamp, documentary, registration or similar Taxes incurred or imposed with respect to the transactions described in this Agreement (collectively, “ Transfer Taxes ”) shall be borne by Buyer; provided that Seller shall pay or cause to be paid to the applicable Governmental Authorities any Transfer Taxes that it is required by Law to collect and remit. Buyer shall indemnify and hold Seller harmless from and against such Transfer Taxes within thirty (30) days of Seller’s written demand therefor. Seller and Buyer shall reasonably cooperate in good faith to minimize, to the extent permissible under applicable Law, the amount of any such Transfer Taxes.

(g) The Parties shall cooperate fully, as and to the extent reasonably requested by the other Party, in connection with the filing of Tax Returns and any audit, litigation, or other proceeding with respect to Taxes relating to the Assets. Such cooperation shall include the retention and (upon the other Party’s request) the provision of records and information that are relevant to any such Tax Return or audit, litigation or other proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided under this Agreement. The Parties agree to retain all books and records with respect to Tax matters pertinent to the Assets relating to any Tax period beginning before the Closing Date until the expiration of the statute of limitations of the respective Tax periods and to abide by all record retention agreements entered into with any Governmental Authority.

(h) Buyer and Seller shall use commercially reasonable efforts to agree to an allocation of the Purchase Price, the Assumed Obligations, and any other items properly treated as consideration for U.S. federal income Tax purposes among the Assets in accordance with Section 1060 of the Code and the Treasury Regulations promulgated thereunder within thirty (30) days after the date that the Final Settlement Statement is delivered pursuant to Section  3.7 .

 

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In the event that Seller and Buyer are unable to resolve any disagreement with respect to such allocation, the Parties shall submit the dispute to the Accounting Arbitrator in accordance with the procedures set forth in Section  3.7 to resolve such dispute. If Seller and Buyer reach an agreement with respect to the allocation, (i) Buyer and Seller shall use commercially reasonable efforts to update the allocation in accordance with Section 1060 of the Code following any adjustment to the Cash Purchase Price pursuant to this Agreement, and (ii) Buyer and Seller shall, and shall cause their Affiliates to, report consistently with the allocation, as adjusted, on all Tax Returns, including Internal Revenue Service Form 8594 (Asset Acquisition Statement under Section 1060), which Buyer and Seller shall timely file with the IRS, and neither Seller nor Buyer nor their respective Affiliates shall take any position on any Tax Return that is inconsistent with such allocation, as adjusted, unless otherwise required by applicable Law; provided, however, that neither Party shall be unreasonably impeded in its ability and discretion to negotiate, compromise and/or settle any Tax audit, claim or similar proceedings in connection with such allocation.

15.3 Assignment . Subject to the provisions of Section  15.17 , this Agreement may not be assigned or otherwise transferred (including by change of control, merger, consolidation, or stock purchase) by either Party without the prior written consent of the other Party. In the event one Party consents to any such assignment, such assignment shall not relieve the other Party of any obligations and responsibilities hereunder, including obligations and responsibilities arising following such assignment. Any assignment or other transfer by Buyer or its successors and assigns of any of the Assets shall not relieve Buyer or its successors or assigns of any of their obligations (including indemnity obligations) hereunder, as to the Assets so assigned or transferred.

15.4 Preparation of Agreement . Both Seller and Buyer and their respective counsel participated in the preparation of this Agreement. In the event of any ambiguity in this Agreement, no presumption shall arise based on the identity of the draftsman of this Agreement.

15.5 Publicity . Seller and Buyer shall promptly consult with each other with regard to all press releases or other public or private announcements issued or made at or prior to Closing concerning this Agreement or the transactions contemplated herein, and, except as may be required by applicable Laws or the applicable rules and regulations of any Governmental Authority or stock exchange, neither Buyer nor Seller shall issue any such press release or other public or private announcement without the prior written consent of the other Party, which shall not be unreasonably withheld or delayed. The Parties shall be obligated to hold all specific terms and provisions of this Agreement strictly confidential until the expiration of the two (2)-year period after the Closing; provided , however , that the foregoing shall not restrict disclosures by the Buyer Party or Seller that are required by applicable securities or other Laws or regulations or the applicable rules of any stock exchange having jurisdiction over the disclosing Party or its Affiliates, provided that such disclosures shall be made only to the extent required thereunder, prevent Buyer or Seller from recording the Assignment and any federal or state assignments delivered at Closing or from complying with any disclosure requirements of Governmental Authorities that are applicable to the transfer of the Assets from Seller to Buyer, prevent Buyer or Seller from making any disclosure of information relating to this Agreement if made in a manner, under conditions and to Persons that would be permitted under the Confidentiality Agreement so long as such Person continues to hold such information confidential on the same

 

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terms as set forth in this Section  15.5 and prevent Seller from making disclosures in connection with complying with Preferential Purchase Rights and other transfer restrictions applicable to the transactions contemplated hereby.

15.6 Notices . All notices and communications required or permitted to be given hereunder shall be given in writing and shall be delivered personally, or sent by bonded overnight courier, or mailed by U.S. Express Mail, Federal Express or United Parcel Service Express Delivery or by certified or registered United States Mail with all postage fully prepaid, or sent by facsimile transmission ( provided any such facsimile transmission is confirmed either orally or by written confirmation), or sent by electronic mail (“ email ”) transmission ( provided that receipt of such email is requested and received, excluding automatic receipts) addressed to the appropriate Party at the address for such Party shown below or at such other address as such Party shall have theretofore designated by written notice delivered to the Party giving such notice:

 

If to Seller:

Vitruvian II Woodford, LLC

4 Waterway Square, Suite 400

The Woodlands, Texas 77380

Attention: W. Mark Blumenshine

Fax #: 832.458.3104

Email: mark.blumenshine@vexpl.com

If to Buyer or Parent:

SCOOP Acquisition Company, LLC

14313 N. May Ave.

Oklahoma City, OK 73134

Attention: Paul Heerwagen

Fax #: 405.848.8816

Email: pheerwagen@gulfport

Copy to:

Gulfport Energy Corporation

14201 Caliber Dr.

Oklahoma City, OK 73134

Attention: Lester Zitkus

Fax #: 405.848.8816

Email: lzitkus@gulfport

Any notice given in accordance herewith shall be deemed to have been given when delivered to the addressee in person, or by courier, or transmitted by facsimile or email transmission during normal business hours on a Business Day (or if delivered or transmitted after normal business hours on a Business Day or on a day other than a Business Day, then on the next

 

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Business Day), or upon actual receipt by the addressee during normal business hours on a Business Day after such notice has either been delivered to an overnight courier or deposited in the United States Mail or with Federal Express or United Parcel Service, as the case may be (or if delivered after normal business hours on a Business Day or on a day other than a Business Day, then on the next Business Day). Either Party may change their contact information for notice by giving written notice to the other Party in the manner provided in this Section  15.6 . If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

15.7 Further Cooperation . After Closing, Buyer and Seller shall execute and deliver, or shall cause to be executed and delivered, from time to time such further instruments of conveyance and transfer, and shall take such other actions as any Party may reasonably request, to convey and deliver the Assets to Buyer, to perfect Buyer’s title thereto, and to accomplish the orderly transfer of the Assets to Buyer in the manner contemplated by this Agreement.

15.8 Filings, Notices and Certain Governmental Approvals . Promptly after Closing, (a) Buyer shall record all assignments executed at Closing in the records of the applicable Governmental Authority (including any federal or state agencies, if applicable), (b) Buyer shall actively pursue the unconditional approval of all applicable Governmental Authorities of the assignment of the Assets to Buyer and (c) Buyer shall actively pursue all other consents and approvals that may be required in connection with the assignment of the Assets to Buyer and the assumption of the Liabilities assumed by Buyer hereunder, in each case, that shall not have been obtained prior to Closing. Buyer obligates itself to take any and all action required by any Governmental Authority in order to obtain such unconditional approval, including the posting of any and all bonds or other security that may be required in excess of its existing lease, pipeline or area-wide bond.

15.9 Entire Agreement; Conflicts . THIS AGREEMENT, THE APPENDICES, EXHIBITS AND SCHEDULES HERETO, THE TRANSACTION DOCUMENTS AND THE CONFIDENTIALITY AGREEMENT COLLECTIVELY CONSTITUTE THE ENTIRE AGREEMENT BETWEEN THE PARTIES PERTAINING TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ALL PRIOR AGREEMENTS, UNDERSTANDINGS, NEGOTIATIONS AND DISCUSSIONS, WHETHER ORAL OR WRITTEN, OF THE PARTIES PERTAINING TO THE SUBJECT MATTER HEREOF. THERE ARE NO WARRANTIES, REPRESENTATIONS OR OTHER AGREEMENTS BETWEEN THE PARTIES RELATING TO THE SUBJECT MATTER HEREOF EXCEPT AS SPECIFICALLY SET FORTH IN THIS AGREEMENT AND THE CERTIFICATES DELIVERED PURSUANT TO SECTIONS 9.3(i) AND 9.3(j), AND NEITHER SELLER NOR BUYER SHALL BE BOUND BY OR LIABLE FOR ANY ALLEGED REPRESENTATION, PROMISE, INDUCEMENT OR STATEMENTS OF INTENTION NOT SO SET FORTH. IN THE EVENT OF A CONFLICT BETWEEN (A) THE TERMS AND PROVISIONS OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY SCHEDULE OR EXHIBIT HERETO OR (B) THE TERMS AND PROVISIONS OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY TRANSACTION DOCUMENT, THE TERMS AND

 

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PROVISIONS OF THIS AGREEMENT SHALL GOVERN AND CONTROL; PROVIDED , HOWEVER , THAT THE INCLUSION IN ANY OF THE SCHEDULES AND EXHIBITS HERETO OR ANY TRANSACTION DOCUMENT OF TERMS AND PROVISIONS NOT ADDRESSED IN THIS AGREEMENT SHALL NOT BE DEEMED A CONFLICT, AND ALL SUCH ADDITIONAL PROVISIONS SHALL BE GIVEN FULL FORCE AND EFFECT, SUBJECT TO THE PROVISIONS OF THIS SECTION  15.9 .

15.10 Parties in Interest . The terms and provisions of this Agreement shall be binding upon and inure to the benefit of Seller and Buyer and their respective successors and permitted assigns. Notwithstanding anything contained in this Agreement to the contrary, nothing in this Agreement, expressed or implied, is intended to confer on any Person other than the Parties or their respective successors and permitted assigns, or the Parties’ respective related Indemnified Parties hereunder any rights, remedies, obligations or Liabilities under or by reason of this Agreement; provided that only a Party and its successors and permitted assigns will have the right to enforce the provisions of this Agreement on its own behalf or on behalf of any of its related Indemnified Parties (but shall not be obligated to do so).

15.11 Amendment . This Agreement may be amended, restated, supplemented or otherwise modified only by an instrument in writing executed by all Parties specifically referring to the terms to be amended, restated, supplemented and/or modified and expressly identified as an amendment, restatement, supplement or modification.

15.12 Waiver; Rights Cumulative . Any of the terms, covenants, representations, warranties or conditions hereof may be waived only by a written instrument executed by or on behalf of the Party waiving compliance. No course of dealing on the part of Seller or Buyer or their respective officers, employees, agents, or representatives, and no failure by Seller or Buyer to exercise any of its rights under this Agreement, shall, in any such case, operate as a waiver thereof or affect in any way the right of such Party at a later time to enforce the performance of such provision. No waiver by any Party of any condition, or any breach of any term, covenant, representation or warranty contained in this Agreement, in any one or more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation or warranty. The rights of Seller and Buyer under this Agreement shall be cumulative, and the exercise or partial exercise of any such right shall not preclude the exercise of any other right.

15.13 Governing Law; Jurisdiction .

(a) This Agreement and any claim, controversy or dispute arising under or related to this Agreement or the transactions contemplated hereby or the rights, duties and relationship of the parties hereto and thereto, shall be governed by and construed and enforced in accordance with the laws of the State of Texas, excluding any conflicts of law, rule or principle that might refer construction of provisions to the Laws of another jurisdiction.

(b) The Parties agree that the appropriate, exclusive and convenient forum for any disputes between any of the Parties arising out of this Agreement, the Transaction Documents or the transactions contemplated hereby shall be in any federal court in Harris County, Texas and each of the Parties irrevocably submits to the jurisdiction of such courts

 

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solely in respect of any proceeding arising out of or related to this Agreement. The Parties further agree that the Parties shall not bring suit with respect to any disputes arising out of this Agreement, the Transaction Documents or the transactions contemplated hereby in any court or jurisdiction other than the above specified courts. The Parties further agree, to the extent permitted by Law, that a final and nonappealable judgment against a Party in any action or proceeding contemplated above shall be conclusive and may be enforced in any other jurisdiction within or outside the United States by suit on the judgment, a certified or exemplified copy of which shall be conclusive evidence of the fact and amount of such judgment.

(c) To the extent that any Party or any of its Affiliates has acquired, or hereafter may acquire, any immunity from jurisdiction of any court or from any legal process (whether through service or notice, attachment prior to judgment, attachment in aid of execution, execution or otherwise) with respect to itself or its property, such Party (on its own behalf and on behalf of its Affiliates) hereby irrevocably (i) waives such immunity in respect of its obligations with respect to this Agreement and (ii) submits to the personal jurisdiction of any court described in Section 15.13(b) .

(d) THE PARTIES HERETO AGREE THAT THEY HEREBY KNOWINGLY, VOLUNTARILY AND INTENTIONALLY IRREVOCABLY WAIVE THE RIGHT TO TRIAL BY JURY IN ANY ACTION BASED HEREON, OR ARISING OUT OF, UNDER, OR IN CONNECTION WITH THIS AGREEMENT, THE TRANSACTION DOCUMENTS OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY.

15.14 Severability . If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of Law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any adverse manner to any Party. Upon such determination that any term or other provision is invalid, illegal or incapable of being enforced, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

15.15 Removal of Name . As promptly as practicable, but in any case within thirty (30) days after the Closing Date, Buyer shall to the extent reasonably practicable eliminate the names “Vitruvian Exploration”, “Vitruvian” and any variants thereof from the Assets and, except with respect to such grace period for eliminating existing usage, shall have no right to use any logos, trademarks or trade names belonging to Seller or any of its Affiliates.

15.16 Counterparts . This Agreement may be executed in any number of counterparts, and each such counterpart hereof shall be deemed to be an original instrument, but all of such counterparts shall constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile or other electronic transmission shall be deemed an original signature hereto.

15.17 Like-Kind Exchange . Buyer and Seller agree that either or both of Seller and Buyer may elect to treat the acquisition or sale of the Assets as an exchange of like-kind property

 

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under Section 1031 of the Code (an “ Exchange ”); provided that the Closing shall not be delayed by reason of the Exchange. Each Party agrees to use reasonable efforts to cooperate with the other Party in the completion of such an Exchange including an Exchange subject to the procedures outlined in Treasury Regulation Section 1.1031(k)-1 and/or Internal Revenue Service Revenue Procedure 2000-37. Each of Seller and Buyer shall have the right at any time prior to Closing to assign all or a part of its rights under this Agreement to a qualified intermediary (as that term is defined in Treasury Regulation Section 1.1031(k)-1(g)(4)(iii)) or an exchange accommodation titleholder (as that term is defined in Internal Revenue Service Revenue Procedure 2000-37) to effect an Exchange. Each Party acknowledges and agrees that neither an assignment of a Party’s rights under this Agreement nor any other actions taken by a Party or any other person in connection with the Exchange shall release any Party from, or modify, any of its liabilities and obligations (including indemnity obligations to each other) under this Agreement, and no Party makes any representations as to any particular tax treatment that may be afforded to any other Party by reason of such assignment or any other actions taken in connection with the Exchange. Any Party electing to treat the acquisition or sale of the Assets as an Exchange shall be obligated to pay all additional costs incurred hereunder as a result of the Exchange, and in consideration for the cooperation of the other Party, the Party electing Exchange treatment shall agree to pay all costs associated with the Exchange and to indemnify and hold the other Party, its Affiliates, and their respective former, current and future partners, members, shareholders, owners, officers, directors, managers, employees, agents and representatives harmless from and against any and all liabilities and taxes arising out of, based upon, attributable to or resulting from the Exchange or transactions or actions taken in connection with the Exchange that would not have been incurred by the other Party but for the electing Party’s Exchange election.

[ Remainder of page intentionally left blank. Signature page follows. ]

 

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IN WITNESS WHEREOF , the Parties have executed this Agreement as of the date first written above.

 

SELLER:
VITRUVIAN II WOODFORD, LLC
By:  

/s/ Richard F. Lane

Name:   Richard F. Lane
Title:   President & Chief Executive Officer

 

 

 

[ S IGNATURE P AGE TO P URCHASE AND S ALE A GREEMENT ]

 

S-1


IN WITNESS WHEREOF , the Parties have executed this Agreement as of the date first written above.

 

BUYER:
SCOOP ACQUISITION COMPANY, LLC
BY: GULFPORT ENERGY CORPORATION, ITS SOLE MEMBER
By:  

/s/ Michael G. Moore

Name:   Michael G. Moore
Title:   Chief Executive Officer and President

 

 

 

[ S IGNATURE P AGE TO P URCHASE AND S ALE A GREEMENT ]

 

S-1


IN WITNESS WHEREOF , the Parties have executed this Agreement as of the date first written above.

 

PARENT:
GULFPORT ENERGY CORPORATION
By:  

/s/ Michael G. Moore

Name:   Michael G. Moore
Title:   Chief Executive Officer and President

 

 

 

[ S IGNATURE P AGE TO P URCHASE AND S ALE A GREEMENT ]

 

S-1


ANNEX I

DEFINED TERMS

Accounting Arbitrator ” shall have the meaning set forth in Section  3.8 .

Adjusted Cash Purchase Price ” shall have the meaning set forth in Section  3.3 .

AFEs ” shall have the meaning set forth in Section  4.13 .

Affiliate ” shall mean, with respect to any Person, any other Person that, directly or indirectly, through one or more intermediaries, controls or is controlled by, or is under common control with, another Person. The term “ control ” and its derivatives with respect to any Person mean the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities, by contract or otherwise. Notwithstanding anything to the contrary herein, in the case of Seller, the term “Affiliate” or “Affiliated” (whether or not capitalized) means only Vitruvian Exploration II, LLC and any subsidiaries of Seller; in the case of Buyer, the term “Affiliate” or “Affiliated” (whether or not capitalized) means only any subsidiaries of Parent.

Aggregate Deductible ” shall mean an amount equal to three percent (3%) of the Purchase Price.

Agreement ” shall have the meaning set forth in the introductory paragraph herein.

Allocated Values ” shall have the meaning set forth in Section  3.9 .

Applicable Contracts ” shall mean all Contracts to which Seller is a party or is bound to the extent relating to any of the Assets and (in each case) that will be binding on Buyer after Closing, including: communitization agreements; unitization agreements; net profits agreements; production payment agreements; area of mutual interest agreements; surface use agreements, joint development agreements, joint venture agreements; confidentiality agreements; farmin and farmout agreements; bottom hole agreements; crude oil, condensate and natural gas purchase and sale, gathering, transportation and marketing agreements; hydrocarbon storage agreements; acreage contribution agreements; operating agreements; balancing agreements; processing agreements; saltwater disposal agreements; facilities or equipment leases; and other similar contracts and agreements, but exclusive of any master service agreements and Contracts relating to the Excluded Assets.

Asset Taxes ” shall mean ad valorem, property, excise, severance, production, sales, use, or similar Taxes based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons or the receipt of proceeds therefrom, but excluding, for the avoidance of doubt, Income Taxes and Transfer Taxes.

Assets ” shall have the meaning set forth in Section  2.1 .

 

A NNEX I


Assignment ” shall mean the Assignment and Bill of Sale from Seller to Buyer, pertaining to the Assets, substantially in the form attached to this Agreement as Exhibit D .

Assumed Obligations ” shall have the meaning set forth in Section  13.1 .

Burden ” shall mean any and all royalties (including lessor’s royalty), overriding royalties, production payments, net profits interests and other burdens upon, measured by or payable out of production (excluding, for the avoidance of doubt, any Taxes).

Business Day ” shall mean a day (other than a Saturday or Sunday) on which commercial banks in Houston, Texas are generally open for business.

Buyer ” shall have the meaning set forth in the introductory paragraph herein.

Buyer Indemnified Parties ” shall have the meaning set forth in Section  13.2 .

Buyer Financing ” shall mean any third party financing for the Cash Purchase Price.

Buyer Parties ” shall have the meaning set forth in the introductory paragraph herein.

Buyer’s Representatives ” shall have the meaning set forth in Section  10.1(a) .

Cash Purchase Price ” shall have the meaning set forth in Section  3.1 .

Casualty Loss ” shall have the meaning set forth in Section 11.3(b) .

Claim Notice ” shall have the meaning set forth in Section  13.7(b) .

Closing ” shall have the meaning set forth in Section  9.1 .

Closing Date ” shall have the meaning set forth in Section  9.1 .

Code ” shall mean the Internal Revenue Code of 1986, as amended, and any successor statute.

Confidentiality Agreement ” shall mean that certain Confidentiality Agreement between Seller and Gulfport Buckeye LLC, dated effective as of October 17, 2016 and that certain Confidentiality Agreement between Parent and Seller as of the date hereof.

Consent ” shall have the meaning set forth in Section  4.4 .

Contract ” shall mean any written contract, agreement or any other legally binding arrangement, but excluding, however, any Lease, easement, right-of-way, permit or other instrument creating or evidencing an interest in the Assets or any real or immovable property related to or used in connection with the operations of any Assets.

Cure Period ” shall have the meaning set forth in Section  11.2(c) .

 

A NNEX I


Customary Post-Closing Consents ” shall mean the consents and approvals from Governmental Authorities for the assignment of the Assets to Buyer that are customarily obtained after the assignment of properties similar to the Assets.

Decommission ” and “ Decommissioning ” shall mean all dismantling and decommissioning activities and obligations as are required by Law, any Governmental Authority or agreements including all well plugging, replugging and abandonment, facility dismantlement and removal, pipeline and flowline removal, dismantlement and removal of all other property of any kind related to or associated with operations or activities and associated site clearance, site restoration and site remediation.

Decommissioning Obligations ” shall have the meaning set forth in Section  13.1 .

Deeds ” shall mean the Mineral Deed and the Surface Deed.

Defensible Title ” shall mean such title of record in the relevant county real property records (together with the records of any other relevant Governmental Authority) (other than with respect to title derived from force pooling orders under applicable Law) of Seller with respect to the Wells set forth on Exhibit B , and the Sections set forth on Schedule 3.9 , that, as of the Title Claim Date, and subject to Permitted Encumbrances:

(a) with respect to each Well set forth on Exhibit B (limited to any currently producing formations), entitles Seller to receive not less than the Net Revenue Interest set forth on Exhibit B for such Well, throughout the life of such Well, except for (i) decreases in connection with those operations in which Seller or its successors or assigns may from and after the Execution Date elect to be a non-consenting co-owner in accordance with Section  6.1 , (ii) decreases resulting from the establishment or amendment from and after the Execution Date of pools or units in accordance with Section  6.1 , (iii) decreases required to allow other Working Interest owners to make up past underproduction or pipelines to make up past under deliveries, and (iv) as otherwise expressly set forth on Exhibit B ;

(b) with respect to each Well set forth on Exhibit B (limited to any currently producing formations), obligates Seller to bear not more than the Working Interest set forth on Exhibit B for such Well, throughout the life of such Well, except (i) increases resulting from contribution requirements with respect to defaulting co-owners under applicable operating agreements, (ii) increases to the extent that such increases are accompanied by a proportionate increase in Seller’s Net Revenue Interest, and (iii) as otherwise expressly set forth on Exhibit B ;

(c) with respect to each Section set forth on Schedule 3.9 (limited to the applicable Target Formations), entitles Seller to receive not less than the average Net Revenue Interest set forth on Schedule 3.9 for such Section, calculated for such Section as a whole, except for (i) decreases in connection with those operations in which Seller or its successors or assigns may from and after the Execution Date elect to be a non-consenting co-owner owner in accordance with Section  6.1 , (ii) decreases resulting from the establishment or amendment from and after the Execution Date of pools or units

 

A NNEX I


owner in accordance with Section  6.1 , (iii) decreases required to allow other Working Interest owners to make up past underproduction or pipelines to make up past under deliveries, and (iv) as otherwise expressly set forth on Exhibit A-1 or Schedule 3.9 , as applicable;

(d) with respect to each Section (limited to the applicable Target Formations), entitles Seller to receive not less than the Net Acres set forth on Schedule 3.9 for such Section, except for (i) decreases in connection with those operations in which Seller or its successors or assigns may from and after the Execution Date elect to be a non-consenting co-owner, (ii) decreases resulting from the establishment or amendment from and after the Execution Date of pools or units, (iii) decreases required to allow other Working Interest owners to make up past underproduction or pipelines to make up past under deliveries, and (iv) as otherwise expressly set forth on Exhibit A-1 or Schedule 3.9 , as applicable; and

(e) is free and clear of all Encumbrances.

Deposit ” shall have the meaning set forth in Section  3.2 .

Dispute Notice ” shall have the meaning set forth in Section  3.7(a) .

Disputed Environmental Matters ” shall have the meaning set forth in Section 12.1(f) .

Disputed Title Matters ” shall have the meaning set forth in Section 11.2(j) .

Effective Time ” shall mean 7:00 a.m. (Central Standard Time) on October 1, 2016.

email ” shall have the meaning set forth in Section  15.6 .

Encumbrance ” shall mean any lien, mortgage, security interest, pledge, charge or similar encumbrance.

Environmental Arbitrator ” shall have the meaning set forth in Section  12.1(f) .

Environmental Claim Date ” shall have the meaning set forth in Section  12.1(a) .

Environmental Condition ” shall mean (a) a condition prior to the Environmental Claim Date with respect to the air, soil, subsurface, surface waters, ground waters and/or sediments that causes an Asset (or Seller with respect to an Asset) not to be in compliance with any Environmental Law or (b) the existence prior to the Environmental Claim Date with respect to the Assets or their operation thereof of any environmental pollution, contamination or degradation where remedial or corrective action is presently required (or if known, would be presently required) under Environmental Laws.

Environmental Defect ” shall mean an Environmental Condition with respect to an Asset.

Environmental Defect Notice ” shall have the meaning set forth in Section  12.1(a) .

 

A NNEX I


Environmental Indemnity Agreement ” shall have the meaning set forth in Section 12.1(c)(iii) .

Environmental Laws ” shall mean all applicable Laws in effect as of the Execution Date relating to pollution or the protection of the environment, including those Laws relating to the storage, handling and use of chemicals and other Hazardous Substances and those Laws relating to the generation, processing, treatment, storage, transportation, disposal or other management thereof. The term “Environmental Laws” does not include (a) good or desirable operating practices or standards that may be employed or adopted by other oil and gas well operators or recommended by a Governmental Authority, or (b) the Occupational Safety and Health Act of 1970, 29 U.S.C. § 651 et seq. , as amended, or any other Law governing worker health or safety.

Equity Consideration ” shall have the meaning set forth in Section  3.1 .

ERISA ” shall have the meaning set forth in Section  4.19 .

ERISA Affiliate ” shall have the meaning set forth in Section  4.19.

Escrow Account ” shall have the meaning set forth in Section  3.2 .

Escrow Agent ” shall have the meaning set forth in Section  3.2 .

Escrow Agreement ” shall have the meaning set forth in Section  3.2 .

Escrow Maintenance Period ” shall have the meaning set forth in Section  3.6(a) .

Exchange ” shall have the meaning set forth in Section  15.17 .

Exchange Act ” means the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

Excluded Assets ” shall mean

(a) all of Seller’s corporate minute books, financial records and other business records that relate to Seller’s business generally (including the ownership and operation of the Assets);

(b) to the extent that they do not relate to the Assumed Obligations for which Buyer is providing indemnification hereunder, all trade credits, all accounts, all receivables of Seller and all other proceeds, income or revenues of Seller attributable to the Assets and attributable to any period of time prior to the Effective Time;

(c) to the extent that they do not relate to the Assumed Obligations for which Buyer is providing indemnification hereunder, Seller’s right with respect to all claims and causes of action of Seller arising under or with respect to any Contract that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds);

 

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(d) subject to Section  11.3 and to the extent that they do not relate to the Assumed Obligations for which Buyer is providing indemnification hereunder, all rights and interests of Seller (i) under any policy or agreement of insurance or indemnity, (ii) under any bond or (iii) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events or damage to or destruction of property;

(e) Seller’s rights with respect to all Hydrocarbons produced and sold from the Assets with respect to all periods prior to the Effective Time, except as specifically described in Section  2.1(c) ;

(f) any and all claims of Seller or its Affiliates for refunds of, credits attributable to, loss carryforwards with respect to, or similar Tax assets relating to (i) Asset Taxes attributable to any period (or portion thereof) ending prior to the Effective Time, (ii) Income Taxes, (iii) Taxes attributable to the Excluded Assets and (iv) any other Taxes relating to the ownership or operation of the Assets or the production of Hydrocarbons or the receipt of proceeds therefrom that are attributable to any period (or portion thereof) ending prior to the Effective Time;

(g) to the extent Seller is the operator under an operating agreement or pooling order covering any Asset, the right to collect Operating Expenses actually paid by Seller on behalf of other joint interest owners of such Asset that are attributable to the periods from and after the Effective Time until Closing, but only to the extent there is no corresponding adjustment to the Purchase Price pursuant to Section 3.3(a)(ii);

(h) all of Seller’s personal computers and associated peripherals and all of Seller’s radio and telephone equipment;

(i) all of Seller’s proprietary computer software, patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property;

(j) all documents and instruments of Seller that may be protected by an attorney-client privilege or any attorney work product doctrine;

(k) subject to Section  11.4(b)(iv) , all data of Seller that cannot be disclosed to Buyer as a result of confidentiality arrangements under agreements with Third Parties;

(l) all audit rights of Seller arising under any of the Applicable Contracts or otherwise with respect to any period prior to the Effective Time or to any of the Excluded Assets, except for any Imbalances assumed by Buyer;

(m) all geophysical and other seismic and related technical data and information relating to the Assets which Seller may not disclose, assign or transfer under its existing agreements and licenses without making any additional payments or incurring any liabilities or obligations which Buyer has not agreed in writing to pay or incur;

(n) correspondence between Seller or any of its representatives and documents prepared or received by Seller or its Affiliates, in each case, with respect to any of the prospective purchasers or the transactions contemplated by this Agreement;

 

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(o) any offices, office leases and any personal property located in or on such offices or office leases (other than the Production Office and the office lease related thereto);

(p) any Hedge Contracts;

(q) any debt instruments of Seller;

(r) all of Seller’s personnel files and records;

(s) the monies held by Seller for which the Cash Purchase Price was adjusted pursuant to Section 3.3(b)(vi) ;

(t) any assets described in Section 2.1(g) or Section 2.1(h) that are not assignable; and

(u) any assets described on Exhibit C .

Execution Date ” shall have the meaning set forth in the introductory paragraph herein.

Fee Minerals ” shall have the meaning set forth in Section 2.1(d) .

Final Cash Purchase Price ” shall have the meaning set forth in Section  3.7(a) .

Final Settlement Statement ” shall have the meaning set forth in Section  3.7(a) .

GAAP ” shall mean generally accepted accounting principles in the United States as interpreted as of the Execution Date.

Governmental Authority ” shall mean any federal, state, local, municipal, tribal or other government; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, regulatory or taxing authority or power, and any court or governmental tribunal, including any tribal authority having or asserting jurisdiction.

Governmental Bonds ” shall have the meaning set forth in Section  6.3 .

Hazardous Substances ” shall mean any pollutants, contaminants, toxic or hazardous or extremely hazardous substances, materials, wastes, constituents, compounds or chemicals that are regulated by, or may form the basis of Liability under, any Environmental Laws, including NORM and other substances referenced in Section  12.2 .

Hedge Contract ” shall mean any Contract to which Seller or any of its Affiliates is a party with respect to any swap, forward, future or derivative transaction or option or similar agreement, whether exchange traded, “over-the-counter” or otherwise, involving, or settled by reference to, one or more rates, currencies, commodities, equity or debt instruments or securities, or economic, financial or pricing indices or measures of economic, financial or pricing risk or value or any similar transaction or any combination of these transactions.

HSR Act ” shall have the meaning set forth in Section  6.6 .

 

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Hydrocarbons ” shall mean oil and gas and other hydrocarbons produced or processed in association therewith.

Imbalances ” shall mean all Well Imbalances and Pipeline Imbalances.

Income Taxes ” shall mean any income, franchise and similar Taxes.

Indemnified Party ” shall have the meaning set forth in Section  13.7(a) .

Indemnifying Party ” shall have the meaning set forth in Section  13.7(a) .

Indemnity Deductible ” shall mean an amount equal to three percent (3%) of the Purchase Price.

Indemnity Escrow ” shall mean 5,225,989 Parent Shares.

Individual Environmental Threshold ” shall have the meaning set forth in Section  12.1(e) .

Individual Title Defect Threshold ” shall have the meaning set forth in Section  11.2(i) .

Interim Period ” shall mean that period of time commencing with the Effective Time and ending at 7:00 a.m. (Central Standard Time) on the Closing Date.

Knowledge ” shall mean (a) with respect to Seller, the actual knowledge (without investigation) of the following Persons: Richard Lane, John Thaeler, Brian Rickmers, Mark Blumenshine, and Reese Mitchell; and (b) with respect to Buyer or Parent, the actual knowledge (without investigation) of the following Persons: Mike Moore, Aaron Gaydosik, Paul Heerwagen, and Lester Zitkus.

Law ” shall mean any applicable statute, law, rule, regulation, ordinance, order, code, ruling, writ, injunction, decree or other official act of or by any Governmental Authority.

Leases ” shall have the meaning set forth in Section  2.1(a) .

Liabilities ” shall mean any and all claims, obligations, causes of action, payments, charges, judgments, assessments, liabilities, losses, damages, penalties, fines and costs and expenses, including any attorneys’ fees, legal or other expenses incurred in connection therewith and including liabilities, costs, losses and damages for personal injury or death or property damage or environmental damage or Remediation.

Lowest Market Price ” shall have the meaning set forth in Section  3.1 .

Material Adverse Effect ” shall mean an event or circumstance that, individually or in the aggregate, results in a material adverse effect on the ownership, operation or value of the Assets taken as a whole and as currently operated as of the Execution Date or a material adverse effect on the ability of Seller to consummate the transactions contemplated by this Agreement and perform its obligations hereunder; provided , however , that a Material Adverse Effect shall

 

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not include any material adverse effect resulting from: (a) entering into this Agreement or the announcement of the transactions contemplated by this Agreement; (b) any action or omission of Seller taken in accordance with the terms of this Agreement without the violation thereof or with the prior written consent of Buyer; (c) changes in general market, economic, financial or political conditions (including changes in commodity prices, fuel supply or transportation markets, interest or rates) in the area in which the Assets are located, the United States or worldwide, to the extent that they do not disproportionately impact the Assets; (d) changes in conditions or developments generally applicable to the oil and gas industry in the area where the Assets are located, to the extent that they do not disproportionately impact the Assets; (e) acts of God, including hurricanes, tornados, storms or other naturally occurring events; (f) acts or failures to act of Governmental Authorities to the extent they do not disproportionately impact the Assets; (g) civil unrest, any outbreak of disease or hostilities, terrorist activities or war or any similar disorder; (h) matters that are cured or no longer exist by the earlier of Closing and the termination of this Agreement; (i) a change in Laws and any interpretations thereof from and after the Execution Date to the extent that they do not disproportionately impact the Assets; (j) any reclassification or recalculation of reserves in the ordinary course of business; (k) changes in the prices of Hydrocarbons; (l) changes in service costs generally applicable to the oil and gas industry in the United States; (m) strikes and labor disturbances; and (n) natural declines in well performance.

Material Contracts ” shall have the meaning set forth in Section  4.8(a) .

Mineral Deed ” shall mean the Mineral Deed pertaining to the Fee Minerals, substantially in the form attached as Exhibit E .

Net Acres ” shall mean, as computed separately with respect to each Section, in each case with respect to the applicable Target Formations set forth on Schedule 3.9 only, (i) the number of gross acres in the lands covered by such Section, multiplied by (ii) the undivided percentage interest in oil, gas and other minerals covered by such Section in such lands, multiplied by (iii) Seller’s portion of such undivided percentage interest that is burdened with the obligation to bear and pay costs and expenses.

Net Revenue Interest ” shall mean, with respect to each Well or Section set forth on Exhibit B or Schedule 3.9 , as applicable (for a Well, limited to any currently producing formations and, for a Section, limited to the applicable Target Formations), the interest in and to all Hydrocarbons produced, saved and sold from or allocated to such Well or Section (for a Well, limited to any currently producing formations and, for a Section, limited to the applicable Target Formations), after giving effect to all Burdens.

NORM ” shall mean naturally occurring radioactive material.

Operating Expenses ” shall have the meaning set forth in Section  2.3 .

Overhead Costs ” shall mean (a) with respect to those Assets that are operated by Seller and are burdened by an existing joint operating agreement covering such Assets, the amount representing Seller’s share of the overhead or general and administrative fee payable to the operator as set forth in the accounting procedures attached to such joint operating agreement,

 

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which amount is attributable to such Assets during the Interim Period, and (b) with respect to those Assets that are operated by Seller and are not burdened by an existing joint operating agreement, an amount equal to a portion of $15,300 per Well per month undergoing drilling or completion operations and $1,530 per producing Well per month attributable to such Assets during the Interim Period, in each case net to Seller’s interests in the relevant Asset.

Parent Common Stock ” means the common stock, par value $0.01 per share, of Parent, as traded on the NASDAQ Global Select Market under the trading symbol “GPOR.”

Parent Material Adverse Effect ” shall mean an event or circumstance that, individually or in the aggregate, results in a material adverse effect (a) to the financial condition, business or results of operations of Parent and its subsidiaries, taken as a whole; provided, however , that a Parent Material Adverse Effect shall not include any material adverse effect resulting from: (i) entering into this Agreement or the announcement of the transactions contemplated by this Agreement; (ii) any action or omission of Parent taken in accordance with the terms of this Agreement without the violation thereof or with the prior written consent of Seller; (iii) changes in general market, economic, financial or political conditions (including changes in commodity prices, fuel supply or transportation markets, interest or rates) in the area in which Parent’s assets are located, the United States or worldwide; (iv) changes in conditions or developments generally applicable to the oil and gas industry in the area where Parent’s assets are located; (v) acts of God, including hurricanes, tornados, storms or other naturally occurring events; (vi) acts or failures to act of Governmental Authorities; (vii) civil unrest, any outbreak of disease or hostilities, terrorist activities or war or any similar disorder; (viii) matters that are cured or no longer exist by the earlier of Closing and the termination of this Agreement; (ix) a change in Laws and any interpretations thereof from and after the Execution Date; (x) any reclassification or recalculation of reserves in the ordinary course of business; (xi) changes in service costs generally applicable to the oil and gas industry in the United States; (xi) strikes and labor disturbances; and (xiii) natural declines in well performance; provided that in each case, the changes and effects described in clauses (iii)  or (iv) of this definition do not disproportionately affect Parent’s assets, taken as a whole or (b) on the ability of Parent to consummate the transactions contemplated by this Agreement or perform its obligations hereunder .

Parent SEC Reports ” shall have the meaning set forth in Section  5.14 .

Parent Shares ” shall have the meaning set forth in Section  3.1 .

Parent Stock Plan ” shall mean Parent’s Amended and Restated 2005 Stock Incentive Plan and 2013 Restated Stock Incentive Plan.

Party and “ Parties ” shall have the meaning set forth in the introductory paragraph herein.

Permitted Encumbrances ” shall mean:

(a) the terms and conditions of all Leases and all Burdens if, throughout the productive life of the relevant Asset, the net cumulative effect of such Leases and Burdens (i) does not operate to reduce the Net Revenue Interest of Seller with respect to any Well or Section set forth on Exhibit B or Schedule 3.9 , as applicable, to an amount less than the Net

 

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Revenue Interest set forth on Exhibit B or Schedule 3.9 , as applicable, for such Well or Section, (ii) does not obligate Seller to bear a Working Interest with respect to any Well set forth on Exhibit B in any amount greater than the Working Interest set forth on Exhibit B for such Well (unless the Net Revenue Interest for such Well is greater than the Net Revenue Interest set forth on Exhibit B in the same or greater proportion as any increase in such Working Interest), and (iii) does not operate to reduce the Net Acres of Seller with respect to any Section set forth on Schedule 3.9 to an amount less than the Net Acres set forth on Schedule 3.9 for such Section;

(b) preferential rights to purchase and required consents to assignment and similar agreements;

(c) liens for Taxes not yet due or delinquent or, if delinquent, that are being contested in good faith in the normal course of business and set forth on Schedule 4.14 ;

(d) Customary Post-Closing Consents;

(e) conventional rights of reassignment upon intent to abandon;

(f) all applicable Laws and all rights reserved to or vested in any Governmental Authority (i) to control or regulate any Asset in any manner; (ii) by the terms of any right, power, franchise, grant, license or permit, or by any provision of Law, to terminate such right, power, franchise, grant, license or permit or to purchase, condemn, expropriate or recapture or to designate a purchaser of any of the Assets; (iii) to use such property in a manner which does not materially impair the use of such property for the purposes for which it is currently owned and operated; or (iv) to enforce any obligations or duties affecting the Assets to any Governmental Authority with respect to any franchise, grant, license or permit;

(g) rights of a common owner of any interest in rights-of-way, permits or easements held by Seller and such common owner as tenants in common or through common ownership;

(h) easements, conditions, covenants, restrictions, servitudes, permits, rights-of-way, surface leases and other rights in the Assets for the purpose of operations, facilities, roads, alleys, highways, railways, pipelines, transmission lines, transportation lines, distribution lines, power lines, telephone lines, removal of timber, grazing, logging operations, canals, ditches, reservoirs and other like purposes, or for the joint or common use of real estate, rights-of-way, facilities and equipment, which, in each case, do not materially impair the operation or use of the Assets as currently operated and used;

(i) vendors, carriers, warehousemen’s, repairmen’s, mechanics’, workmen’s, materialmen’s, construction or other like liens arising by operation of Law in the ordinary course of business or incident to the construction or improvement of any property in respect of obligations which are not yet due or which are being contested in good faith by appropriate proceedings by or on behalf of Seller;

(j) liens created under Leases and/or operating agreements or by operation of Law in respect of obligations that are not yet due or that are being contested in good faith by appropriate proceedings by or on behalf of Seller;

 

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(k) any Encumbrance affecting the Assets that is discharged by Seller at or prior to Closing;

(l) any matters expressly referenced and set forth on Exhibit  A-1 and all litigation set forth in Schedule  4.7 ;

(m) mortgage liens burdening a lessor’s interest in the Assets, provided that no suit for the foreclosure thereof or exercise of remedies thereunder is pending or threatened;

(n) the terms and conditions of all Contracts (including the Applicable Contracts) if the net cumulative effect of such Contracts throughout the productive life of the relevant Asset (i) does not operate to reduce the Net Revenue Interest of Seller with respect to any Well or Section set forth on Exhibit B or Schedule 3.9 , as applicable, to an amount less than the Net Revenue Interest set forth on Exhibit B or Schedule 3.9 , as applicable, for such Well or Section, (ii) does not obligate Seller to bear a Working Interest with respect to any Well set forth on Exhibit B in any amount greater than the Working Interest set forth on Exhibit B for such Well (unless the Net Revenue Interest for such Well is greater than the Net Revenue Interest set forth on Exhibit B in the same or greater proportion as any increase in such Working Interest), and (iii) does not operate to reduce the Net Acres of Seller with respect to any Section set forth on Schedule 3.9 to an amount less than the Net Acres set forth on Schedule 3.9 for such Section; and

(o) all other Encumbrances, instruments, obligations, defects and irregularities affecting the Assets that, individually or in the aggregate, throughout the productive life of the relevant Asset, (i) are not such as to materially interfere with the operation or use of any of the Assets (as currently operated and used), (ii) do not reduce the Net Revenue Interest of Seller with respect to any Well or Section set forth on Exhibit B or Schedule 3.9 , as applicable, to an amount less than the Net Revenue Interest set forth on Exhibit B or Schedule 3.9 , as applicable, for such Well or Section, (iii) do not obligate Seller to bear a Working Interest in any amount greater than the Working Interest set forth on Exhibit B for such Well (unless the Net Revenue Interest for such Well is greater than the Net Revenue Interest set forth on Exhibit B in the same or greater proportion as any increase in such Working Interest), and (iv) do not operate to reduce the Net Acres of Seller with respect to any Section set forth on Schedule 3.9 to an amount less than the Net Acres set forth on Schedule 3.9 for such Section.

Person ” shall mean any individual, firm, corporation, company, partnership, limited liability company, joint venture, association, trust, unincorporated organization, Governmental Authority or any other entity.

Personal Property ” shall have the meaning set forth in Section  2.1(i) .

Pipeline Imbalance ” shall mean any marketing imbalance between the quantity of Hydrocarbons attributable to the Assets required to be delivered by Seller under any Contract relating to the purchase and sale, gathering, transportation, storage, processing (including any production handling and processing at a separation facility) or marketing of Hydrocarbons and the quantity of Hydrocarbons attributable to the Assets actually delivered by Seller pursuant to the relevant Contract, together with any appurtenant rights and obligations concerning production balancing at the delivery point into the relevant sale, gathering, transportation, storage or processing facility.

 

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Phase I Environmental Site Assessment ” means an environmental site assessment performed pursuant to ASTM Standard E1527, or any similar environmental assessment that does not involve any invasive, sampling or testing activities.

Preferential Purchase Right ” shall have the meaning set forth in Section  4.10 .

Preliminary Settlement Statement ” shall have the meaning set forth in Section  3.5 .

Production Office ” shall have the meaning set forth in Section 2.1(f) .

Purchase Price ” shall have the meaning set forth in Section  3.1 .

Records ” shall have the meaning set forth in Section  2.1(l) .

Registration Rights Agreement ” means that certain Registration Rights Agreement, dated as of the Closing Date, in the form attached hereto as Exhibit I .

Remediation ” shall mean, with respect to an Environmental Condition, the implementation and completion of any remedial, removal, response, construction, closure, disposal or other corrective actions, including monitoring and reporting, to the extent but only to the extent required under Environmental Laws to correct or remove such Environmental Condition.

Remediation Amount ” shall mean, with respect to an Environmental Condition, the present value as of the Closing Date (using an annual discount rate of ten percent (10%)) of the cost (net to Seller’s interest prior to the consummation of the transactions contemplated by this Agreement) of the most cost-effective Remediation of such Environmental Condition, plus any fines, penalties, charges and damages imposed by any Governmental Authority prior to the end of the Cure Period with respect to such Environmental Condition unless Seller has agreed with Buyer that Seller will bear such fines, penalties and damages.

Required Pre-Closing Information ” shall have the meaning set forth in Section  6.4 .

Retained Liabilities ” shall have the meaning set forth in Section  13.2(h) .

Sections ” shall have the meaning set forth in Section  11.1(b) .

Seismic Data ” shall have the meaning set forth in Section 2.1(j) .

Seller ” shall have the meaning set forth in the introductory paragraph of this Agreement.

Seller Indemnified Parties ” shall have the meaning set forth in Section  13.3 .

Seller Taxes ” shall mean (a) all Income Taxes imposed by any applicable Law on Seller, (b) Asset Taxes allocable to Seller pursuant to Section  15.2 (taking into account, and without duplication of, (i) such Asset Taxes effectively borne by Seller as a result of adjustments

 

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to the Cash Purchase Price made pursuant to Sections 3.3 , 3.5 and 3.7, as applicable, and (ii) any payments made from one Party to the other in respect of Asset Taxes pursuant to Section 15.2(d) ), (c) any Taxes imposed on or with respect to the ownership or operation of the Excluded Assets and (d) any and all Taxes (other than the Taxes described in clauses (a), (b) or (c) of this definition) imposed on or with respect to the ownership or operation of the Assets or the production of Hydrocarbons or the receipt of proceeds therefrom for any Tax period (or portion thereof) ending before the Effective Time.

Specified Representations ” shall mean the representations and warranties in Sections  4.1 , 4.2 , 4.3, 4.5, 4.6 , 4.14, 5.1 , 5.2 , 5.9 , 5.10 and 5.11 .

Springer Shale Formation ” shall mean the stratigraphic equivalent of the geological formation identified on the electric log of the Seller operated Turner Trust 2N5W #1-12H Well (API # 35137270570000 & located in Section 12, Township 2 North, Range 5 West, Stephens County, Oklahoma), with the top of the Springer Shale Formation found at the measured depth of 13,965’ and the base of the Springer Shale Formation (being the top of the Caney Shale) found at the measured depth of 15,540’, recognizing that the actual top and base depths will vary across the area where the Assets are located.

Straddle Period ” shall mean any Tax period beginning before and ending after the Effective Time.

Surface Deed ” shall mean the Surface Deed pertaining to the Surface Fee Interests, substantially in the form attached as Exhibit F .

Surface Fee Interests ” shall have the meaning set forth in Section 2.1(e) .

Survival Period ” means the period of time commencing as of the Closing Date and ending at 5 p.m. Central Standard Time on the twelve (12) month anniversary thereof.

Target Formations ” shall mean the Woodford Shale Formation and the Springer Shale Formation.

Tax Return ” shall mean any return, declaration, report, claim for refund, or information return or statement relating to Taxes, including any schedule or attachment thereto, and including any amendment thereof.

Taxes ” shall mean any taxes, assessments and other governmental charges in the nature of a tax imposed by any Governmental Authority, including income, profits, gross receipts, ad valorem, real property, personal property, transfer, sales, use, customs, duties, franchise, excise, withholding, severance, production, estimated or other tax, including any interest, penalty or addition thereto.

Third Party ” shall mean any Person other than a Party to this Agreement or an Affiliate of a Party to this Agreement.

Third Party Claim ” shall have the meaning set forth in Section  13.7(b) .

 

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Title Arbitrator ” shall have the meaning set forth in Section  11.2(j) .

Title Benefit ” shall mean, (a) with respect to each Well set forth on Exhibit B , any right, circumstance or condition that operates to (i) increase the Net Revenue Interest of Seller above that shown for such Well on Exhibit B, to the extent the same does not cause a greater than proportionate increase in Seller’s Working Interest therein above that shown on Exhibit B or (ii) to decrease the Working Interest of Seller in any Well below that shown for such Well on Exhibit B , to the extent the same causes a decrease in Seller’s Working Interest that is proportionately greater than the decrease in Seller’s Net Revenue Interest therein below that shown on Exhibit B ; and (b) with respect to each Section shown on Schedule 3.9 , or any other property included in the Assets, as applicable, as to the Target Formation, any right, circumstance or condition that operates to increase the Net Acres of Seller above that shown for such Section or other property shown on Schedule 3.9 , if applicable.

Title Benefit Amount ” shall have the meaning set forth in Section  11.2(e) .

Title Benefit Notice ” shall have the meaning set forth in Section  11.2(b) .

Title Benefit Property ” shall have the meaning set forth in Section  11.2(b) .

Title Claim Date ” shall have the meaning set forth in Section  11.2(a) .

Title Defect ” shall mean any Encumbrance, defect or other matter that causes Seller not to have Defensible Title in and to the Wells set forth on Exhibit B , or the Sections set forth on Schedule 3.9 , as of the Effective Time, without duplication; provided that the following shall not be considered Title Defects:

(a) defects arising out of the lack of corporate or other entity authorization unless Buyer provides affirmative evidence that such corporate or other entity action was not authorized and results in another Person’s actual and superior claim of title to the relevant Asset;

(b) defects based on a gap in Seller’s chain of title in the applicable federal, state or county records, unless such gap is affirmatively shown to exist in such records by an abstract of title, title opinion or landman’s title chain which documents shall be included in a Title Defect Notice;

(c) defects based upon the failure to record any federal, state or Indian Leases or any assignments of interests in such Leases in any applicable county records;

(d) defects based on the failure to recite marital status in a document or omission of successors or heirship or estate proceedings;

(f) defects based upon the exercise of any Preferential Purchase Rights or failure to obtain any Consents;

(g) defects arising from any prior oil and gas lease relating to the lands covered by a Lease not being surrendered of record, if such document is dated earlier

 

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than January 1, 1980, unless Buyer provides affirmative evidence that such prior oil and gas lease is still in effect and results in another Person’s actual and superior claim of title to the relevant Lease or Well;

(h) defects that affect only which Person has the right to receive royalty payments (rather than the amount or the proper payment of such royalty payment);

(i) defects based solely on: (i) lack of information in Seller’s files; (ii) references to an unrecorded document(s) to which neither Seller nor any Affiliate is a party, if such document is dated earlier than January 1, 1960 and is not in Seller’s files, unless Buyer provides affirmative evidence such document results in another Person’s actual and superior claim of title to the relevant Lease or Well; or (iii) Tax assessment, Tax payment or similar records (or the absence of such activities or records);

(j) defects or irregularities that do not, individually or in the aggregate, materially detract from the value of, or materially interfere with the use or ownership of the Assets, and that would customarily be waived by a prudent purchaser of oil and gas properties;

(k) defects arising out of lack of survey, unless a survey is expressly required by applicable Laws;

(l) defects that have been cured by applicable Laws of limitations or presumptions;

(m) defects or irregularities resulting from or related to probate proceedings or he lack thereof, which defects or irregularities have been outstanding for twenty (20) years or more;

(n) defects or irregularities resulting solely from or related solely to the failure to have recorded assignments of beneficial interests in Leases within working interest units created pursuant to operating agreements, but only to the extent that a Memorandum of Operating Agreement or similar document is filed of record sufficient to provide notice to Third Parties under applicable law; provided that Buyer agrees that Seller may cure any failure to have such a Memorandum or similar document filed by filing a stipulation of interest executed by Seller in the applicable county records (without, for the avoidance of doubt, the need to have such stipulation executed by any other party);

(o) defects to the extent affecting any depths other than the Target Formations; and

(p) defects or irregularities resulting from liens, production payments, or mortgages that have expired by their own terms.

Title Defect Amount ” shall have the meaning set forth in Section  11.2(g) .

Title Defect Notice ” shall have the meaning set forth in Section  11.2(a) .

 

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Title Defect Property ” shall have the meaning set forth in Section  11.2(a) .

Title Indemnity Agreement ” shall have the meaning set forth in Section  11.2(d)(ii) .

Transaction Documents ” shall mean those documents executed pursuant to or in connection with this Agreement.

Transfer Taxes ” shall have the meaning set forth in Section  15.2(f) .

Transition Services Agreement ” shall mean the Transition Services Agreement pertaining to the Assets referenced in Section 6.9.

Units ” shall have the meaning set forth in Section  2.1(b) .

VWAP Price ” shall mean $26.55.

Wells ” shall have the meaning set forth in Section  2.1(c) .

Well Imbalance ” shall mean any imbalance at the wellhead between the amount of Hydrocarbons produced from a Well and allocable to the interests of Seller therein and the shares of production from the relevant Well to which Seller is entitled, together with any appurtenant rights and obligations concerning future in kind and/or cash balancing at the wellhead.

Woodford Shale Formation ” shall mean the stratigraphic equivalent of the geological formation identified on the electric log of the Seller operated Turner Trust 2N5W #1-12H Well (API # 35137270570000 & located in Section 12, Township 2 North, Range 5 West, Stephens County, Oklahoma), with the top of the Woodford Shale Formation found at the measured depth of 15,965’ and the base of the Woodford Shale Formation (being the top of the Hunton Limestone) found at the measured depth of 16,411’, recognizing that the actual top and base depths will vary across the area where the Assets are located.

Working Interest ” shall mean, with respect to any Well set forth on Exhibit B (limited to any currently producing formations), the interest in and to such currently producing formations for such Well that is burdened with the obligation to bear and pay costs and expenses of maintenance, development and operations on or in connection with such currently producing formations for such Well, but without regard to the effect of any Burdens.

 

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Exhibit 10.1

 

 

SEVENTH AMENDMENT TO

AMENDED AND RESTATED CREDIT AGREEMENT

Dated as of December 13, 2016

among

GULFPORT ENERGY CORPORATION,

as Borrower,

THE BANK OF NOVA SCOTIA,

as Administrative Agent

and

The Lenders Party Hereto

THE BANK OF NOVA SCOTIA, KEYBANK NATIONAL ASSOCIATION,

and PNC BANK, NATIONAL ASSOCIATION,

as Joint Lead Arrangers and Joint Bookrunners

KEYBANK NATIONAL ASSOCIATION and

PNC BANK, NATIONAL ASSOCIATION,

as Co-Syndication Agents

CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH,

WELLS FARGO BANK, N.A. and

BARCLAYS BANK PLC,

as Co-Documentation Agents

 

 


SEVENTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT

THIS SEVENTH AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (this “Amendment” ) is entered into as of December 13, 2016, among GULFPORT ENERGY CORPORATION , a Delaware corporation ( “Borrower” ), THE BANK OF NOVA SCOTIA, as Administrative Agent ( “Administrative Agent” ) and L/C Issuer, and the financial institutions defined below as the Existing Lenders and the Exiting Lender, and MORGAN STANLEY SENIOR FUNDING, INC., and BOKF, NA DBA BANK OF OKLAHOMA , as new Lenders ( “New Lenders” ).

R E C I T A L S

A.    Borrower, the financial institutions signing as Lenders thereto, Administrative Agent and the other agents party thereto are parties to an Amended and Restated Credit Agreement dated as of December 27, 2013, as amended by a First Amendment to Amended and Restated Credit Agreement dated as of April 23, 2014, a Second Amendment to Amended and Restated Credit Agreement dated as of November 26, 2014, a Third Amendment to Amended and Restated Credit Agreement dated as of April 10, 2015, a Fourth Amendment to Amended and Restated Credit Agreement and Limited Consent and Waiver dated as of May 29, 2015, a Fifth Amendment to Amended and Restated Credit Agreement dated as of September 18, 2015, and a Sixth Amendment to Amended and Restated Credit Agreement dated as of February 19, 2016 (collectively, the “Original Credit Agreement” ; the Original Credit Agreement as amended by this Amendment is referred to herein as the “Credit Agreement” ).

B.    The parties desire to amend the Original Credit Agreement as hereinafter provided.

NOW, THEREFORE, in consideration of these premises and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree as follows:

1.     Same Terms . All terms used herein that are defined in the Original Credit Agreement shall have the same meanings when used herein, unless the context hereof otherwise requires or provides. In addition, from and after the Effective Date, (i) all references in the Original Credit Agreement and, where appropriate in the context, in the other Loan Documents to the “Agreement” shall mean the Original Credit Agreement, as amended and waived by this Amendment, as the same may hereafter be amended and waived from time to time, and (ii) all references in the Loan Documents to the “Loan Documents” shall mean the Loan Documents, as amended and waived by the Modification Papers, as the same may hereafter be amended and waived from time to time. In addition, the following terms have the meanings set forth below:

“Effective Date” means the date on which the conditions specified in Section  2 below are satisfied (or waived in writing by the Administrative Agent).

“Existing Lenders” means The Bank of Nova Scotia, KeyBank National Association, Credit Suisse AG, Barclays Bank PLC, Wells Fargo Bank, N.A., ZB, N.A. dba Amegy Bank, Compass Bank, PNC Bank, National Association, U.S. Bank National Association, Associated Bank, N.A. and IberiaBank.

“Exiting Lender” means BNP Paribas.

“Modification Papers” means this Amendment, the Ohio Mortgage Amendments, and all of the other documents and agreements executed in connection with the transactions contemplated by this Amendment.

 

SEVENTH AMENDMENT – Page 1


“New Lenders” has the meaning specified in the opening paragraph.

New Notes” has the meaning specified in Section  7 .

“October 2016 Reserve Report” has the meaning set forth in Section  4 .

“Ohio Mortgage Amendments” has the meaning set forth in Section 8(b) .

2.     Conditions Precedent . The obligations and agreements of the Lenders as set forth in this Amendment are subject to the satisfaction, unless waived in writing by Administrative Agent, of each of the following conditions (and upon such satisfaction, this Amendment shall be deemed to be effective as of the Effective Date):

(a)     Seventh Amendment to Credit Agreement . This Amendment shall have been duly executed and delivered by each of the parties hereto.

(b)     New Notes . Borrower shall have executed and delivered the New Notes to the New Lenders.

(c)     Upfront Fee . Borrower shall have paid Adminstrative Agent for the account of the Lenders the previous agreed upfront fees.

(d)     Fees and Expenses . Administrative Agent shall have received payment of all out-of-pocket fees and expenses (including reasonable attorneys’ fees and expenses) incurred by Administrative Agent in connection with the preparation, negotiation and execution of the Modification Papers.

3.     Amendments to Original Credit Agreement . On the Effective Date, the Original Credit Agreement shall be deemed to be amended as follows:

(a)    The pricing grid contained in the definition of “Applicable Rate” in Section  1.01 of the Original Credit Agreement shall be amended to read in its entirety as follows:

 

Applicable Rate  

Applicable

Usage Level

   Commitment fee     Eurodollar Rate
Loans and Letters
of Credit
    Base Rate Loans  

Level 1

     0.375     2.00     1.00

Level 2

     0.375     2.25     1.25

Level 3

     0.50     2.50     1.50

Level 4

     0.50     2.75     1.75

Level 5

     0.50     3.00     2.00

(b)    The following definitions set forth in Section  1.01 of the Original Credit Agreement shall be amended to read in their respective entireties as follows:

“Arranger” means, collectively, Scotiabank, Keybank National Association and PNC Bank, National Association, each in its capacity as joint lead arranger and joint bookrunner.

 

SEVENTH AMENDMENT – Page 2


“Defaulting Lender” means, subject to Section 2.15(b) , any Lender that (a) has failed to (i) fund all or any portion of its Loans within two Business Days of the date such Loans were required to be funded hereunder unless such Lender notifies the Administrative Agent and the Borrower in writing that such failure is the result of such Lender’s determination that one or more conditions precedent to funding (each of which conditions precedent, together with any applicable default, shall be specifically identified in such writing) has not been satisfied, or (ii) pay to the Administrative Agent, the L/C Issuer or any other Lender any other amount required to be paid by it hereunder (including in respect of its participation in Letters of Credit) within two Business Days of the date when due, (b) has notified the Borrower, the Administrative Agent or the L/C Issuer in writing that it does not intend to comply with its funding obligations hereunder, or has made a public statement to that effect (unless such writing or public statement relates to such Lender’s obligation to fund a Loan hereunder and states that such position is based on such Lender’s determination that a condition precedent to funding (which condition precedent, together with any applicable default, shall be specifically identified in such writing or public statement) cannot be satisfied), (c) has failed, within three Business Days after written request by the Administrative Agent or the Borrower, to confirm in writing to the Administrative Agent and the Borrower that it will comply with its prospective funding obligations hereunder ( provided that such Lender shall cease to be a Defaulting Lender pursuant to this clause (c) upon receipt of such written confirmation by the Administrative Agent and the Borrower), or (d) has, or has a direct or indirect parent company that has, (i) become the subject of a proceeding under any Debtor Relief Law, (ii) had appointed for it a receiver, custodian, conservator, trustee, administrator, assignee for the benefit of creditors or similar Person charged with reorganization or liquidation of its business or assets, including the Federal Deposit Insurance Corporation or any other state or federal regulatory authority acting in such a capacity, or (iii) become the subject of a Bail-In Action; provided that a Lender shall not be a Defaulting Lender solely by virtue of the ownership or acquisition of any equity interest in that Lender or any direct or indirect parent company thereof by a Governmental Authority so long as such ownership interest does not result in or provide such Lender with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Lender (or such Governmental Authority) to reject, repudiate, disavow or disaffirm any contracts or agreements made with such Lender. Any determination by the Administrative Agent that a Lender is a Defaulting Lender under clauses (a) through (d) above shall be conclusive and binding absent manifest error, and such Lender shall be deemed to be a Defaulting Lender (subject to Section  2.15(b) ) upon delivery of written notice of such determination to the Borrower, the L/C Issuer and each Lender.

“Maturity Date” means December 13, 2021; provided however that if such date is not a Business Day, the Maturity Date shall be the next preceding Business Day.

“Senior Notes” means any unsecured Indebtedness of Borrower (and any unsecured Guarantees thereof by the Guarantors) in an aggregate principal amount not exceeding $1,600,000,000.

(c)    Section 1.01 of the Original Credit Agreement shall be amended by adding the following definitions in appropriate alphabetical order to read in their respective entireties as follows:

 

SEVENTH AMENDMENT – Page 3


“Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable EEA Resolution Authority in respect of any liability of an EEA Financial Institution.

“Bail-In Legislation” means, with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule.

“EEA Financial Institution” means (a) any credit institution or investment firm established in any EEA Member Country which is subject to the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of an institution described in clause (a)  of this definition, or (c) any financial institution established in an EEA Member Country which is a subsidiary of an institution described in clauses (a)  or (b) of this definition and is subject to consolidated supervision with its parent.

“EEA Member Country” means any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

“EEA Resolution Authority” means any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor Person), as in effect from time to time.

“Excluded Accounts” means accounts exclusively used for payroll, payroll taxes or other employee wage and benefit payments, accounts exclusively holding assets subject to an escrow or purchase price adjustment mechanism, and accounts that exclusively hold funds belonging to, or for the benefit of, a Person other than a Loan Party, and accounts having average daily collected balances not greater than $2,500,000 during the most recently completed calendar quarter (or for any account opened after the most recently completed calendar quarter, that will have an average daily collected balance not greater than $2,500,000 as of the end of the calendar quarter during which such account was opened).

Write-Down and Conversion Powers” means, with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule.

(d)    The figure “80%” shall be changed to “85%” in Section 2.13(a) and in Section 2.13(e) of the Original Credit Agreement.

(e)     Section 4.05(e) of the Original Credit Agreement shall be amended to read in its entirety as follows:

 

SEVENTH AMENDMENT – Page 4


(e)    In the event of an issuance of Senior Notes after the Closing Date, then, upon consummation of such issuance, the then effective Borrowing Base shall be reduced by 25% of the principal amount of such Senior Notes offering except to the extent that the proceeds of such Senior Notes are used to repay, redeem, purchase, repurchase, refinance, defease or otherwise satisfy previously issued Senior Notes, or to the extent that such Senior Notes are issued in exchange for previously issued Senior Notes, and in each case, to pay accrued and unpaid interest on, and prepayment premiums in respect of, such previously issued Senior Notes and fees and expenses relating to the issuance of such Senior Notes and such repayment, redemption, purchase, repurchase, refinancing, defeasance, satisfaction or exchange of such previously issued Senior Notes.    For avoidance of doubt, the 25% reduction described in this subsection (e) may be reduced or waived with the consent of Required Lenders.

(f)    Article VIII of the Original Credit Agreement shall be amended by adding a new Section 8.16 thereto in proper order to read in its entirety as follows:

8.16.     Maintenance of Deposit Accounts . (a) Open or maintain any deposit account, securities account or commodity account at or with any banking or other financial institution other than a Lender, except for those accounts listed on Part 2 on Exhibit A to the Seventh Amendment to this Agreement dated as of December 13, 2016 (the “Seventh Amendment” ), which accounts may remain open pending closure in the ordinary close of business, or (b) establish or maintain a deposit account, securities account or commodity account (other than Excluded Accounts), without delivering to the Administrative Agent a control agreement signed by the Administrative Agent, the depository bank, the other parties thereto and the applicable Loan Party, and otherwise in form and substance reasonably satisfactory to the Administrative Agent, (1) in the case of any account listed on Part 1 of Exhibit A to the Seventh Amendment, within sixty (60) days after the Effective Date (as defined in the Seventh Amendment), or (2) in the case of any account other than an Excluded Account opened after such Effective Date, within thirty (30) days after such account is opened.

(g)    Article XI of the Original Credit Agreement shall be amended by adding a new Section 11.25 thereto in proper order to read in its entirety as follows:

11.25     Acknowledgement and Consent to Bail-In of EEA Financial Institutions . Notwithstanding anything to the contrary in any Loan Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any EEA Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the write-down and conversion powers of an EEA Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)    the application of any Write-Down and Conversion Powers by an EEA Resolution Authority to any such liabilities arising hereunder which may be payable to it by any party hereto that is an EEA Financial Institution; and

(b)    the effects of any Bail-In Action on any such liability, including, if applicable:

(i) a reduction in full or in part or cancellation of any such liability;

 

SEVENTH AMENDMENT – Page 5


(ii) a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such EEA Financial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Loan Document; or

(iii) the variation of the terms of such liability in connection with the exercise of the write-down and conversion powers of any EEA Resolution Authority.

4.     Reaffirmation of Borrowing Base . The Borrowing Base is hereby reaffirmed at $700,000,000. This redetermination of the Borrowing Base constitutes the scheduled periodic redetermination of the Borrowing Base with respect to the Reserve Report dated October 1, 2016 (the “October 2016 Reserve Report” ), pursuant to Section 4.02(a) of the Credit Agreement, and is not a special redetermination pursuant to Section 4.03 of the Credit Agreement. The Borrowing Base shall remain at this amount until next redetermined in accordance with Article IV of the Credit Agreement.

5.    [Reserved.]

6.     Concerning the New Lenders and the Exiting Lender .

(a)    The New Lenders have become Lenders upon their execution of this Amendment, and on the Effective Date, the New Lenders shall assume all rights and obligations of a Lender under the Credit Agreement. The Administrative Agent, the Lenders and the Borrower hereby consent to each New Lender’s acquisition of an interest in the Aggregate Commitments and its Applicable Percentage. The Administrative Agent and the Borrower hereby consent to the reallocation set forth herein. The Administrative Agent, the Lenders and the Borrower hereby waive (a) any requirement that an Assignment and Assumption or any other documentation be executed in connection with such reallocation, and (b) the payment of any processing and recordation fee to the Administrative Agent. In connection herewith, each of the Existing Lenders and the Exiting Lender irrevocably sells and assigns to each New Lender, and each New Lender, severally and not jointly, hereby irrevocably purchases and assumes from the Existing Lenders and the Exiting Lender, as of the Effective Date, so much of each Existing Lender’s and the Exiting Lender’s Commitment, outstanding Loans and participations in Letters of Credit, and rights and obligations in its capacity as a Lender under the Original Credit Agreement and any other documents or instruments delivered pursuant thereto (including without limitation any guaranties and, to the extent permitted to be assigned under applicable law, all claims (including without limitation contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity), suits, causes of action and any other right of any Existing Lender or the Exiting Lender against any Person, whether known or unknown, arising under or in connection with the Original Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby), such that each Existing Lender’s and each New Lender’s Commitment, Applicable Percentage of the outstanding Loans and participations in Letters of Credit, and rights and obligations as a Lender shall be equal to its Applicable Percentage and Commitment set forth on Schedule  2.01 to this Amendment, and the Exiting Lender shall have no Commitment or Applicable Percentage. The Exiting Lender, each Existing Lender and each New Lender agree that the provisions of the form of Assignment and Assumption attached as Exhibit  D to the Credit Agreement shall apply to it as applicable depending on whether it is the assignee or assignor of such “Commitments” as applicable. Each party hereto agrees to execute an Assignment and Assumption or related ancillary documentation to give effect to the foregoing if requested by the Administrative Agent. Further, on the Effective Date, the Exiting Lender is released of its “Commitment” under the Credit Agreement.

 

SEVENTH AMENDMENT – Page 6


(b)    Upon the Effective Date, all Loans and participations in Letters of Credit of the Existing Lenders and the Exiting Lender outstanding immediately prior to the Effective Date shall be, and hereby are, restructured, rearranged, renewed, extended and continued as provided in this Amendment and shall continue as Loans and participations in Letters of Credit of each Existing Lender and each New Lender under the Credit Agreement, and the Exiting Lender shall have been repaid the Applicable Percentage of its outstanding Loans immediately prior to the Effective Date, and it shall not have any participations in any Letter of Credit.

(c)    Each New Lender represents and warrants to the Administrative Agent, for the benefit of the Lenders including the Exiting Lender, as follows:

(i)    it has received a copy of the Original Credit Agreement, together with copies of the most recent financial statements of the Borrower delivered pursuant thereto;

(ii)    it has, independently and without reliance upon any Lender or any related party of the Administrative Agent or any Lender (an “Agent-Related Person” ) and based on such documents and information as it has deemed appropriate, made its own appraisal of and investigation into the business, prospects, operations, property, financial and other condition and creditworthiness of the Loan Parties and their respective Subsidiaries, and all applicable bank or other regulatory laws relating to the transactions contemplated by the Credit Agreement, and made its own decision to enter into the Credit Agreement and to extend credit to the Borrower and the other Loan Parties under the Credit Agreement;

(iii)    it will, independently and without reliance upon any Lender or any Agent-Related Person and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit analysis, appraisals and decisions in taking or not taking action under the Credit Agreement and the other Loan Documents, and to make such investigations as it deems necessary to inform itself as to the business, prospects, operations, property, and other condition and creditworthiness of the Borrower and the other Loan Parties.

(d)    Each New Lender acknowledges, for the benefit of the Administrative Agent and the Lenders including the Exiting Lender, as follows:

(i)    no Lender or Agent-Related Person has made any representation or warranty to it, and no act by the Administrative Agent hereafter taken, including any consent to and acceptance of any assignment or review of the affairs of any Loan Party or any Affiliate thereof, shall be deemed to constitute any representation or warranty by any Lender or any Agent-Related Person to any Lender as to any matter, including whether Agent-Related Persons have disclosed material information in their possession;

(ii)    except for notices, reports and other documents expressly required to be furnished to the Lenders by the Administrative Agent pursuant to the Original Credit Agreement, the Administrative Agent shall not have any duty or responsibility to provide any Lender with any credit or other information concerning the business, prospects, operations, property, financial and other condition or creditworthiness of any of the Loan Parties or any of their respective Affiliates which may come into the possession of any Agent-Related Person; and

 

SEVENTH AMENDMENT – Page 7


(iii)    on the Effective Date, subject to the satisfaction or waiver of the conditions to effectiveness set forth in Section  2 of this Amendment, it shall be deemed automatically to have become a party to the Credit Agreement and have all rights and obligations of a Lender under the Original Credit Agreement and the other Loan Documents, each as amended by the Modification Papers, as if it were an original Lender signatory thereto.

(e)    On the Effective Date, each New Lender agrees to be bound by the terms and conditions set forth in the Original Credit Agreement and the other Loan Documents, each as amended by the Modification Papers, applicable to the Lenders as if it were an original Lender signatory thereto (and expressly makes the appointment set forth in, and agrees to the obligations imposed under, Article X of the Original Credit Agreement).

7.     New Notes . On the Effective Date, the New Lenders shall become Lenders and the maximum Commitments of all Lenders shall be as set forth on Schedule  2.01 to this Amendment. Accordingly, on the Effective Date, Borrower shall issue Notes ( “New Notes” ) in the form of Exhibit  B attached to the Original Credit Agreement to the New Lenders.

8.     Post-Closing Obligations .

(a)     Control Agreements . Within sixty (60) days after the Effective Date (or such later date which Administrative Agent has agreed to in writing), Borrower shall, and shall cause each applicable Subsidiary to, deliver duly executed control agreements required to comply with Section 8.16 of the Credit Agreement covering the accounts listed on Exhibit A hereto.

(b)     Amendment of Ohio Oil and Gas Mortgages . Within thirty (30) days after the date of this Amendment (or such later date which Administrative Agent has agreed to in writing), Borrower shall have executed and delivered to Administrative Agent amendments of the Oil and Gas Mortgages listed on Exhibit B hereto which reflect the amended Maturity Date of December 13, 2021 (the “Ohio Mortgage Amendments” ).

(c)     Mortgage Coverage . Within thirty (30) days from the Effective Date (or such longer time as determined by Administrative Agent) Borrower shall mortgage to Administrative Agent additional oil and gas properties evaluated in the October 2016 Reserve Report such that the aggregated Recognized Value of all oil and gas properties then under mortgage is at least 85% of the Recognized Value of all Proved Mineral Interests evaluated in the October 2016 Reserve Report.

(d)     Title Assurances . Within thirty (30) days (or such longer time as determined by Administrative Agent) Borrower shall provide to Administrative Agent title opinions and/or other title information and data reasonably acceptable to Administrative Agent so that Administrative Agent shall have received reasonably acceptable title assurances for at least 80% of the Recognized Value of all Proved Mineral Interests evaluated in the October 2016 Reserve Report.

9.     Authorization of Administrative Agent to Amend Collateral Documents . Section  11.01 of the Credit Agreement provides that the Loan Documents, in addition to the Credit Agreement, may be amended with the consent of the Majority Lenders. There are inconsistencies in the use of the term “Secured Parties” when used in the Collateral Documents and when used in this Credit Agreement.

 

SEVENTH AMENDMENT – Page 8


The Lenders authorize the Administrative Agent to amend the Collateral Documents to conform the definition of “Secured Parties” as used therein to the definition of “Secured Parties” as used in this Credit Agreement.

10.     Certain Representations . Borrower represents and warrants that, as of the Effective Date: (a) Borrower has full power and authority to execute the Modification Papers to which it is a party and such Modification Papers constitute the legal, valid and binding obligation of Borrower enforceable in accordance with their terms, except as enforceability may be limited by general principles of equity and applicable bankruptcy, insolvency, reorganization, moratorium, and other similar laws affecting the enforcement of creditors’ rights generally; (b) no authorization, approval, consent or other action by, notice to, or filing with, any Governmental Authority or other Person is required for the execution, delivery and performance by Borrower thereof; and (c) no Default has occurred and is continuing or will result from the consummation of the transactions contemplated by this Amendment. In addition, Borrower represents that after giving effect to the Modification Papers, all representations and warranties contained in the Credit Agreement and the other Loan Documents are true and correct in all material respects (provided that any such representations or warranties that are, by their terms, already qualified by reference to materiality shall be true and correct without regard to such additional materiality qualification) on and as of the Effective Date as if made on and as of such date except to the extent that any such representation or warranty expressly relates to an earlier date, in which case such representation or warranty is true and correct in all material respects (or true and correct without regard to such additional materiality qualification, as applicable) as of such earlier date.

11.     No Further Amendments . Except as previously amended or waived in writing or as amended or waived hereby, the Original Credit Agreement shall remain unchanged and all provisions shall remain fully effective between the parties.

12.     Acknowledgments and Agreements . Borrower acknowledges that on the date hereof all outstanding Obligations, in each case as amended and waived hereby, are payable in accordance with their terms, and Borrower waives any defense, offset, counterclaim or recoupment with respect thereto. Borrower, Administrative Agent, L/C Issuer and each Lender do hereby adopt, ratify and confirm the Original Credit Agreement, as amended and waived hereby, and acknowledge and agree that the Original Credit Agreement, as amended and waived hereby, is and remains in full force and effect. Borrower acknowledges and agrees that its liabilities and obligations under the Original Credit Agreement and under the other Loan Documents, in each case as amended and waived hereby, are not impaired in any respect by this Amendment.

13.     Limitation on Agreements . The consents, waivers and modifications set forth herein are limited precisely as written and shall not be deemed (a) to be a consent under or a waiver of or an amendment to any other term or condition in the Original Credit Agreement or any of the other Loan Documents, or (b) to prejudice any other right or rights that Administrative Agent or the Lenders now have or may have in the future under or in connection with the Original Credit Agreement and the other Loan Documents, each as amended and waived hereby, or any of the other documents referred to herein or therein. The Modification Papers shall constitute Loan Documents for all purposes.

14.     Confirmation of Security . Borrower hereby confirms and agrees that all of the Collateral Documents that presently secure the Obligations shall continue to secure, in the same manner and to the same extent provided therein, the payment and performance of the Obligations as described in the Original Credit Agreement as modified by this Amendment.

15.     Counterparts . This Amendment may be executed in any number of counterparts, each of which when executed and delivered shall be deemed an original, but all of which constitute one instrument. In making proof of this Amendment, it shall not be necessary to produce or account for more than one counterpart thereof signed by each of the parties hereto.

 

SEVENTH AMENDMENT – Page 9


16.     Incorporation of Certain Provisions by Reference . The provisions of Section 11.15 of the Original Credit Agreement captioned “Governing Law, Jurisdiction; Etc.” and Section 11.16 of the Original Credit Agreement captioned “Waiver of Right to Trial by Jury” are incorporated herein by reference for all purposes.

17.     Entirety, Etc . This Amendment, the other Modification Papers and all of the other Loan Documents embody the entire agreement between the parties. THIS AMENDMENT, THE OTHER MODIFICATION PAPERS AND ALL OF THE OTHER LOAN DOCUMENTS 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 AMONG THE PARTIES.

[This space is left intentionally blank. Signature pages follow.]

 

SEVENTH AMENDMENT – Page 10


IN WITNESS WHEREOF, the parties hereto have executed this Amendment to be effective as of the date and year first above written.

 

BORROWER
GULFPORT ENERGY CORPORATION
By:  

/s/ Aaron Gaydosik

  Aaron Gaydosik
  Chief Financial Officer

 

SEVENTH AMENDMENT – Signature Page S-1


ADMINISTRATIVE AGENT:

THE BANK OF NOVA SCOTIA,

as Administrative Agent and L/C Issuer

By:  

/s/ Alan Dawson

  Alan Dawson
  Director
LENDERS:

THE BANK OF NOVA SCOTIA,

as a Lender

By:  

/s/ Alan Dawson

  Alan Dawson
  Director

 

SEVENTH AMENDMENT – Signature Page S-2


KEYBANK NATIONAL ASSOCIATION,

as a Lender

By:  

/s/ George E. McKean

Name: George E. McKean

Title:   Senior Vice President

 

SEVENTH AMENDMENT – Signature Page S-3


CREDIT SUISSE AG,

Cayman Islands Branch,

as a Lender

By:  

/s/ Nupur Kumar

Name:   Nupur Kumar
Title:   Authorized Signatory

By:

 

/s/ Warren Van Heyst

Name:  

Warren Van Heyst

Title:   Authorized Signatory

 

SEVENTH AMENDMENT – Signature Page S-4


BARCLAYS BANK PLC,

as a Lender

By:

 

/s/ Christopher Aitkin

Name:   Christopher Aitkin
Title:   Assistant Vice President

 

SEVENTH AMENDMENT – Signature Page S-5


WELLS FARGO BANK, N.A.,

as a Lender

By:

 

/s/ Matthew W. Coleman

Name:   Matthew W. Coleman
Title:   Director

 

SEVENTH AMENDMENT – Signature Page S-6


ZB, N.A. dba AMEGY BANK,

as a Lender

By:

 

/s/ Jill McSorley

Name:   Jill McSorley
Title:   Senior Vice President – Amegy Bank Division

 

SEVENTH AMENDMENT – Signature Page S-7


COMPASS BANK,

as a Lender

By:

 

/s/ Gabriela Azcarate

Name:   Gabriela Azcarate
Title:   Vice President

 

SEVENTH AMENDMENT – Signature Page S-8


PNC BANK, NATIONAL ASSOCIATION,

as a Lender

By:

 

/s/ Sandra Aultman

Name:   Sandra Aultman
Title:   Managing Director

 

SEVENTH AMENDMENT – Signature Page S-9


U.S. BANK NATIONAL ASSOCIATION,

as a Lender

By:

 

/s/ Nicholas T. Hanford

Name:   Nicholas T. Hanford
Title:   Vice President

 

SEVENTH AMENDMENT – Signature Page S-10


ASSOCIATED BANK, N.A.,

as a Lender

By:

 

/s/ Kyle Lewis

Name:   Kyle Lewis
Title:   Vice President

 

SEVENTH AMENDMENT – Signature Page S-11


IBERIABANK,

as a Lender

By:

 

/s/ Moni Collins

Name:   Moni Collins
Title:   Senior Vice President

 

SEVENTH AMENDMENT – Signature Page S-12


MORGAN STANLEY SENIOR FUNDING, INC.,

as a Lender

By:

 

/s/ Michael King

Name:   Michael King
Title:   Vice President

 

SEVENTH AMENDMENT – Signature Page S-13


BOKF, NA DBA BANK OF OKLAHOMA,

as a Lender

By:

 

/s/ John Krenger

Name:   John Krenger
Title:   Vice President

 

SEVENTH AMENDMENT – Signature Page S-14


BNP PARIBAS,

as an Exiting Lender, agreeing solely to Sections 1, 2, 6, 15, 16 and 17 and no other sections or provisions hereunder; however, Section 10 shall inure to benefit of BNP Paribas

By:  

/s/ Ann Rhoads

Name:   Ann Rhoads
Title:   Managing Director
By:  

/s/ Vincent Trapet

Name:   Vincent Trapet
Title:   Director

 

SEVENTH AMENDMENT – Signature Page S-15


SCHEDULE 2.01

Commitments and Applicable Percentages

 

Lender

   Applicable Percentage    

Commitment

 

The Bank of Nova Scotia

     11.428571429   $ 80,000,000   

KeyBank National Association

     10.714285714   $ 75,000,000   

PNC Bank, National Association

     10.714285714   $ 75,000,000   

Credit Suisse AG, Cayman Islands Branch

     9.285714286   $ 65,000,000   

Barclays Bank PLC

     9.285714286   $ 65,000,000   

Wells Fargo Bank, N.A.

     9.285714286   $ 65,000,000   

Compass Bank

     7.142857143   $ 50,000,000   

U.S. Bank National Association

     7.142857143   $ 50,000,000   

ZB, N.A. dba Amegy Bank

     7.142857143   $ 50,000,000   

IberiaBank

     5.000000000   $ 35,000,000   

Morgan Stanley Senior Funding, Inc.

     4.285714286   $ 30,000,000   

Associated Bank, N.A.

     4.285714286   $ 30,000,000   

BOKF, NA dba Bank of Oklahoma

     4.285714286   $ 30,000,000   

BNP Paribas

     0.000000000   $ 0   

TOTAL:

     100.00000000   $ 700,000,000   

Maximum Facility Amount: $1,500,000,000

 

Schedule 2.01 – Page Solo


EXHIBIT A

Deposit Accounts – Part 1

 

Account Name

  

Account Number

  

Bank

   Purpose of Account

1. Gulfport MM Sweep

   *    *    Investment

2. Gulfport Operating

   *    *    Operating

3. Gulfport Buckeye

   *    *    Operating

4. Gulfport Buckeye Revenue

   *    *    Revenue

5. Gulfport Energy Corporation

   *    *    Investment

6. Gulfport Energy Corporation

   *    *    Investment

7. Gulfport Energy Corporation

   *    *    Investment

8. Gulfport Energy Corporation

   *    *    Investment

9. Gulfport Revenue

   *    *    Revenue

Deposit Accounts – Part 2

 

Account Name

  

Account Number

  

Bank

   Purpose of Account

1. Grizzly Holdings Inc. - CAD

   *    *    Operating

2. Grizzly Holdings Inc. - US

   *    *    Operating

3. Gulfport - Revenue

   *    *    Revenue

4. Puma Resources

   *    *    Operating

5. Gulfport - Operating

   *    *    Operating

6. Blackhawk Midstream LLC

   *    *    Operating

7. Gulfport Energy Corporation - LC

   *    *    Letter of Credit

8. Gator Marine Ivanhoe, Inc.

   *    *    Operating

9. Jaguar Resources

   *    *    Operating

10. Gator Marine, Inc.

   *    *    Operating

11. Westhawk Minerals LLC

   *    *    Operating

12. Gulfport - Payroll

   *    *    Payroll

 

Exhibit A – Page Solo


EXHIBIT B

Ohio Oil and Gas Mortgages

 

1. Open-End Mortgage, Security Agreement, Assignment of Production and Financing Statement by Gulfport Energy Corporation, as Mortgagor to The Bank of Nova Scotia, as Administrative Agent for the benefit of Secured Parties dated as of April 23, 2014, recorded as follows:

 

County/State

  

Recording Data

  

Date of
Recording

 

Belmont County, Ohio

  

Book 478, Page 302

Instrument No. 201400007635

     05/21/2014   

Carroll County, Ohio

  

Book 102, Page 3440

Instrument No. 201400002988

     05/21/2014   

Guernsey County, Ohio

  

Book 516, Page 1560

Instrument No. 201400004023

     05/22/2014   

Harrison County, Ohio

  

Book 221, Page 1531

Instrument No. 201400003527

     07/29/2014   

Monroe County, Ohio

  

Book 275, Page 248

Instrument No. 201400075784

     05/21/2014   

 

2. Open-End Mortgage, Security Agreement, Assignment of Production and Financing Statement by Gulfport Energy Corporation, as Mortgagor to The Bank of Nova Scotia, as Administrative Agent for the benefit of Secured Parties dated as of March 7, 2016, recorded as follows:

 

County/State

  

Recording Data

  

Date of
Recording

 

Noble County, Ohio

  

Book 279, Page 552

Instrument No. 201600071536

     03/15/2016   

 

3. Open-End Mortgage, Security Agreement, Assignment of Production and Financing Statement by Gulfport Energy Corporation, as Mortgagor to The Bank of Nova Scotia, as Administrative Agent for the benefit of Secured Parties dated as of May 24, 2016, recorded as follows:

 

County/State

  

Recording Data

  

Date of
Recording

 

Jefferson County, Ohio

  

Vol. 1197, Page 182

     06/24/2016   

 

Exhibit B – Page Solo

Exhibit 23.1

Consent of Independent Accountants

We hereby consent to the incorporation by reference in the Registration Statements on Form S-8 (File No. 333-206564, File No. 333-135728, File No. 333-129178, and File No. 333-55738) and on Form S-3 File No. 333-215078, of Gulfport Energy Corporation of our report dated February 24, 2016 relating to the financial statements of Vitruvian II Woodford, LLC, which appears in this Current Report on Form 8-K of Gulfport Energy Corporation dated December 15, 2016. We also consent to the reference to us under the heading “Experts” in such Registration Statements.

/s/ PricewaterhouseCoopers LLP

Houston, TX

December 15, 2016

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM CONSULTANTS

We hereby consent to (i) the inclusion in this Form 8-K of Gulfport Energy Corporation (“Form 8-K”), of our reports dated February 3, 2016, March 10, 2015 and February 3, 2014, on oil and gas reserves of Vitruvian Exploration II, LLC, an affiliate of Vitruvian II Woodford, LLC, as of December 31, 2015, 2014 and 2013, respectively, (ii) the inclusion of our letter dated November 11, 2016 auditing the proved reserves and future revenue estimates prepared by Vitruvian II Woodford, LLC as of September 30, 2016 and to (iii) all references to our firm in the Form 8-K and to the incorporation by reference of said reports and the audit letter in the Registration Statements of Gulfport Energy Corporation on Forms S-8 (File No. 333-206564, effective August 25, 2015; File No. 333-135728, effective July 12, 2006; File No. 333-129178, effective October 21, 2005; and File No. 333-55738, effective February 16, 2001) and on Form S-3 (File No. 333-215078, automatically effective December 14, 2016). We also consent to the references to our firm contained in the Registration Statements, including under the caption “Experts.”

 

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:  

/s/ Danny D. Simmons

  Danny D. Simmons, P.E.
  President and Chief Operating Officer

Houston, Texas

December 14, 2016

Exhibit 99.1

 

LOGO

Press Release

 

Gulfport Energy Corporation Announces Entry into the SCOOP Play with Complementary Acquisition of Approximately 85,000 Net Effective Acres

OKLAHOMA CITY (December 14, 2016) Gulfport Energy Corporation (Nasdaq: GPOR) (“Gulfport” or the “Company”) today announced that the Company has entered into a definitive agreement with Vitruvian II Woodford, LLC (“Vitruvian”), a portfolio company of Quantum Energy Partners, to acquire approximately 46,400 net surface acres in the core of the SCOOP, including approximately 183 MMcfe per day of net production for October 2016 for a total purchase price of $1.85 billion.

Acquisition Highlights

 

    Substantially contiguous acreage position totaling approximately 85,000 net effective acres, which includes rights to 46,400 Woodford acres and 38,600 Springer acres, in Grady, Stephens and Garvin Counties, Oklahoma, with approximately 80% held by production.

 

    Stacked-pay potential with approximately 1,750 gross drilling locations, including over 775 gross locations with internal rates of return of approximately 75%, targeting the Woodford and Springer intervals with significant upside potential through infill drilling and additional prospective zones.

 

    Existing production of approximately 183 MMcfe per day in the month of October 2016.

 

    Total estimated proved reserves at September 30, 2016 were 1.1 Tcfe.

As of December 13, 2016, Gulfport entered into a definitive agreement with Vitruvian to acquire approximately 46,400 net surface acres with multiple producing zones, including the Woodford and Springer formations, in Grady, Stephens and Garvin Counties, Oklahoma. Given the potential for numerous producing intervals across this high-quality position, Gulfport has


identified approximately 1,750 gross drilling locations, composed of only Woodford and Springer zones with significant upside potential through infill drilling and additional prospective zones present on the acreage. The acquired properties are located primarily in the over-pressured liquids-rich to dry gas windows of the play and include approximately 183 Mmcfepd of net production for October 2016. The transaction also includes 48 producing horizontal wells and an additional interest in over 150 non-operated horizontal wells. Four rigs are currently operating on the acreage and Gulfport currently intends to maintain a four rig cadence in the play during 2017 and add an additional two rigs at the beginning of 2018. Based on the estimated internal reserve report prepared by Vitruvian as of September 30, 2016 and audited by Netherland, Sewell & Associates, Inc., the estimated proved reserves attributable to the acreage are approximately 1.1 Tcfe. The acquisition is expected to close in February 2017, subject to the satisfaction of certain closing conditions.

Consideration in the transaction includes a total purchase price of approximately $1.85 billion, consisting of $1.35 billion in cash and approximately 18.8 million in shares of Gulfport common stock privately placed to the sellers, subject to adjustment. The Company intends to fund the cash portion of the acquisition through potential debt and equity financings prior to closing.

Chief Executive Officer and President, Michael G. Moore commented, “Today is a defining day for Gulfport Energy. Combining Vitruvian’s high-quality SCOOP position with our prolific Utica assets will transform our company and solidify Gulfport with core positions in two of North America’s high-return natural gas basins. In Vitruvian, we believe we have found a prolific stacked pay resource with strong production history, a multi-year, high-return drilling inventory – an opportunity with significant upside from both a resource and operational perspective. The asset consists of a low-risk, substantially contiguous acreage position in the core of the SCOOP. This acquisition is not only additive to our Company but in our opinion truly one-of-a-kind. The transaction is expected to be accretive to cash flow and net asset value per share and provides us with a blocky, sizeable and scalable footprint in a new operating area.”

Vitruvian CEO and President, Richard F. Lane commented, “We are pleased to be part of this significant transaction, both for the complementary asset it represents for Gulfport and for the achievement it represents for Vitruvian’s employees and stakeholders. We plan to work closely with the Gulfport team to ensure a seamless transition of the asset to Gulfport.”

President of Quantum Energy Partners, Dheeraj Verma, commented, “We are excited about this transaction and believe that the combination of these assets will provide Mike and his team with more opportunities for margin expansion and cash flow growth immediately. We are quite optimistic about the value creation potential here and look forward to participating in this upside as a shareholder of the combined company.”

BofA Merrill Lynch acted as exclusive financial advisor to Gulfport in connection with the transaction and Akin Gump Strauss Hauer & Feld LLP served as Gulfport’s legal counsel. Jefferies acted as financial advisor to Vitruvian in connection with the transaction and Vinson & Elkins served as Vitruvian’s legal counsel.

About Gulfport

Gulfport Energy Corporation is an Oklahoma City-based independent oil and natural gas exploration and production company with its principal producing properties located in the Utica Shale of Eastern Ohio and along the Louisiana Gulf Coast. In addition, Gulfport holds a sizeable acreage position in the Alberta Oil Sands in Canada through its 24.9% interest in Grizzly Oil Sands ULC.

Forward Looking Statements

Certain statements included in this press release are intended as “forward-looking statements.” These statements include assumptions, expectations, predictions, intentions or beliefs about future events, particularly the consummation of the pending transaction described above. Gulfport cautions that actual future events and results may vary materially from those expressed or implied in any forward-looking statements. Specifically, Gulfport cannot assure you that the proposed transaction described above will be consummated on the terms Gulfport currently contemplates, if at all. Information concerning these and other factors can be found in Gulfport’s filings with the SEC, including its Forms 10-K, 10-Q and 8-K, which can be obtained free of charge on the SEC’s web site at http://www.sec.gov.


Any forward-looking statements made in this press release speak only as of the date of this release and, except as required by law, Gulfport undertakes no obligation to update any forward-looking statement contained in this press release, even if Gulfport’s expectations or any related events, conditions or circumstances change. Gulfport is not responsible for any changes made to this release by wire or Internet services.

Investor & Media Contact:

Paul K. Heerwagen IV – Vice President, Corporate Development

pheerwagen@gulfportenergy.com

405-242-4888

Jessica R. Wills – Manager, Investor Relations and Research

jwills@gulfportenergy.com

405-242-4888

Exhibit 99.2

 

LOGO

Press Release

 

Gulfport Energy Corporation Launches Common Stock Offering

OKLAHOMA CITY (December 14, 2016) Gulfport Energy Corporation (NASDAQ: GPOR) (“Gulfport”) today announced the commencement of an underwritten public offering of 29,000,000 shares of its common stock, subject to market and other conditions. The underwriters will have a 30-day option to purchase up to an additional 4,350,000 shares from Gulfport. Gulfport intends to use the net proceeds from this offering, together with the net proceeds from its concurrent debt offering, (i) primarily to fund the cash portion of the purchase price for its previously announced pending acquisition of certain assets of Vitruvian II Woodford, LLC and (ii) for general corporate purposes, which may include the funding of a portion of its capital development plans. If the pending acquisition is not consummated, or to the extent that the purchase price is reduced due to a purchase price adjustment under the related purchase agreement, Gulfport intends to use any such proceeds for general corporate purposes, including the funding of a portion of its capital development plans.

Credit Suisse Securities (USA) LLC and BofA Merrill Lynch are acting as joint book-running managers in the offering. Copies of the preliminary prospectus supplement for the offering may be obtained on the website of the Securities and Exchange Commission, www.sec.gov, or by contacting (i) Credit Suisse Securities (USA) LLC, Prospectus Department, at One Madison Avenue, New York, New York 10010, or by telephone at (800) 221-1037, or (ii) BofA Merrill Lynch at NC1-004-03-43, 200 North College Street, 3rd floor, Charlotte, North Carolina 28255-0001, Attn: Prospectus Department, or by email at dg.prospectus_requests@baml.com.

The common stock will be issued and sold pursuant to an effective automatic shelf registration statement on Form S-3 previously filed with the Securities and Exchange Commission. This press release shall not constitute an offer to sell or the solicitation of an offer to buy these securities, nor shall there be any sale of these securities in any state or jurisdiction in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of such state or jurisdiction. This offering may only be made by means of a prospectus supplement and related base prospectus.

About Gulfport

Gulfport Energy Corporation is an Oklahoma City-based independent oil and natural gas exploration and production company with its principal producing properties located in the Utica Shale of Eastern Ohio and along the Louisiana Gulf Coast. In addition, Gulfport holds a sizeable acreage position in the Alberta Oil Sands in Canada through its 24.9% interest in Grizzly Oil Sands ULC.


Forward Looking Statements

Certain statements included in this press release are intended as “forward-looking statements.” These statements include assumptions, expectations, predictions, intentions or beliefs about future events, particularly the consummation of the transactions described above. Gulfport cautions that actual future results may vary materially from those expressed or implied in any forward-looking statements. Specifically, Gulfport cannot assure you that the proposed transaction described above will be consummated on the terms Gulfport currently contemplates, if at all. Information concerning these and other factors can be found in Gulfport’s filings with the SEC, including its Forms 10-K, 10-Q and 8-K, which can be obtained free of charge on the SEC’s web site at http://www.sec.gov.

Any forward-looking statements made in this press release speak only as of the date of this release and, except as required by law, Gulfport undertakes no obligation to update any forward-looking statement contained in this press release, even if Gulfport’s expectations or any related events, conditions or circumstances change. Gulfport is not responsible for any changes made to this release by wire or Internet services.

Investor & Media Contacts:

Paul K. Heerwagen IV – Vice President, Corporate Development

pheerwagen@gulfportenergy.com

405-242-4888

Jessica R. Wills – Manager, Investor Relations and Research

jwills@gulfportenergy.com

405-242-4421

Exhibit 99.3

 

LOGO

Press Release

 

Gulfport Energy Corporation Launches Proposed $600 Million Offering of Senior Notes

OKLAHOMA CITY (December 14, 2016) Gulfport Energy Corporation (NASDAQ: GPOR) (“Gulfport”) today announced that it proposes to offer, subject to market conditions and other factors, $600 million aggregate principal amount of its senior notes due 2025 (the “Notes”) to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”), and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The Notes will be issued under a new indenture and will rank equally with Gulfport’s previously issued senior notes and other senior indebtedness. Gulfport expects to use the net proceeds of the Notes offering, together with the net proceeds from its concurrent equity offering, (i) primarily to fund the cash portion of the purchase price for its previously announced pending acquisition of certain assets of Vitruvian II Woodford, LLC and (ii) for general corporate purposes, which may include the funding of a portion of its capital development plans. If the pending acquisition is not consummated, or to the extent that the purchase price is reduced due to a purchase price adjustment under the related purchase agreement, Gulfport intends to use any such proceeds for general corporate purposes, including the funding of a portion of its capital development plans.

The Notes will be general unsecured senior obligations of Gulfport, will be guaranteed on a senior unsecured basis by certain of Gulfport’s subsidiaries and will pay interest semi-annually.

The Notes will not be registered under the Securities Act or any state securities laws and may not be offered or sold in the United States absent registration or an applicable exemption from such registration requirements.

This announcement is neither an offer to sell nor a solicitation of an offer to buy any of these securities and shall not constitute an offer, solicitation or sale in any jurisdiction in which such offer, solicitation or sale is unlawful.

About Gulfport

Gulfport Energy Corporation is an Oklahoma City-based independent oil and natural gas exploration and production company with its principal producing properties located in the Utica Shale of Eastern Ohio and along the Louisiana Gulf Coast. In addition, Gulfport holds a sizeable acreage position in the Alberta Oil Sands in Canada through its 24.9% interest in Grizzly Oil Sands ULC.


Forward Looking Statements

Certain statements included in this press release are intended as “forward-looking statements.” These statements include assumptions, expectations, predictions, intentions or beliefs about future events, particularly the consummation of the transaction described above. Gulfport cautions that actual future results may vary materially from those expressed or implied in any forward-looking statements. Specifically, Gulfport cannot assure you that the proposed transactions described above will be consummated on the terms Gulfport currently contemplates, if at all. Information concerning these and other factors can be found in Gulfport’s filings with the SEC, including its Forms 10-K, 10-Q and 8-K, which can be obtained free of charge on the SEC’s web site at http://www.sec.gov.

Any forward-looking statements made in this press release speak only as of the date of this release and, except as required by law, Gulfport undertakes no obligation to update any forward-looking statement contained in this press release, even if Gulfport’s expectations or any related events, conditions or circumstances change. Gulfport is not responsible for any changes made to this release by wire or Internet services.

Investor & Media Contacts:

Paul K. Heerwagen IV – Vice President, Corporate Development

pheerwagen@gulfportenergy.com

405-242-4888

Jessica R. Wills – Manager, Investor Relations and Research

jwills@gulfportenergy.com

405-242-4421

Exhibit 99.4

INDEX TO FINANCIAL STATEMENTS

 

     Page  

Vitruvian II Woodford, LLC

  

Audited Financial Statements

  

Report of Independent Auditors

     F-2   

Audited Balance Sheet as of December 31, 2015 and 2014

     F-3   

Audited Statement of Operations for the Years Ended December 31, 2015, 2014 and 2013

     F-4   

Audited Statement of Changes in Members’ Equity for the Years Ended December 31, 2015, 2014 and 2013

     F-5   

Audited Statement of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013

     F-6   

Notes to Audited Financial Statements

     F-7   

Unaudited Financial Statements

  

Unaudited Balance Sheet as of September 30, 2016 and December 31, 2015

     F-23   

Unaudited Statement of Operations for the Nine Months Ended September 30, 2016 and 2015

     F-24   

Unaudited Statement of Changes in Members’ Equity for the Nine Months Ended September 30, 2016

     F-25   

Unaudited Statement of Cash Flows for the Nine Months Ended September 30, 2016 and 2015

     F-26   

Notes to Unaudited Financial Statements

     F-27   

 

F-1


Report of Independent Auditors

To the Board of Directors and Management

of Vitruvian II Woodford, LLC:

We have audited the accompanying financial statements of Vitruvian II Woodford, LLC (the “Company”), which comprise the balance sheets as of December 31, 2015 and 2014, and the related statements of operations, changes in members’ equity and cash flows for the three years in the period ended December 31, 2015.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the Company’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Vitruvian II Woodford, LLC as of December 31, 2015 and 2014, and the results of its operations and its cash flows for the each of the three years in the period ended December 31, 2015 in accordance with accounting principles generally accepted in the United States of America.

/s/PricewaterhouseCoopers LLP

Houston, Texas

February 24, 2016

 

F-2


VITRUVIAN II WOODFORD, LLC

BALANCE SHEET

(In thousands)

 

     December 31,
2015
    December 31,
2014
 

ASSETS

    

Current assets:

    

Cash and cash equivalents

   $ 2,509      $ 7,310   

Accounts receivable:

    

Oil and gas

     16,246        14,902   

Affiliates

     1,177        424   
  

 

 

   

 

 

 

Total accounts receivable

     17,423        15,326   

Derivative contracts

     66,951        42,767   

Prepaid and other current assets

     4,784        4,722   
  

 

 

   

 

 

 

Total current assets

     91,667        70,125   

Property and equipment, at cost:

    

Oil and natural gas properties (full cost method):

    

Proved

     691,464        269,784   

Unproved

     373,597        495,396   

Other property and equipment

     13,434        4,313   
  

 

 

   

 

 

 

Total property and equipment

     1,078,495        769,493   

Less: accumulated depreciation, depletion and amortization

     (243,343     (54,020
  

 

 

   

 

 

 

Net property and equipment

     835,152        715,473   

Deferred financing costs

     2,602        1,155   

Derivative contracts

     14,918        10,348   

Other assets

     28        27   
  

 

 

   

 

 

 

Total assets

   $ 944,367      $ 797,128   
  

 

 

   

 

 

 

LIABILITIES AND MEMBERS’ EQUITY

    

Current liabilities:

    

Accounts payable

   $ 8,761      $ 6,971   

Accrued liabilities

     37,897        36,456   

Royalties and revenue payable

     7,960        5,774   

Current maturities of long-term debt

     31,000        —     
  

 

 

   

 

 

 

Total current liabilities

     85,618        49,201   

Long-term debt

     306,653        165,000   

Asset retirement obligations

     6,184        5,603   
  

 

 

   

 

 

 

Total liabilities

     398,455        219,804   

Commitments and contingencies (Note 11)

    

Members’ equity

     545,912        577,324   
  

 

 

   

 

 

 

Total liabilities and members’ equity

   $ 944,367      $ 797,128   
  

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

F-3


VITRUVIAN II WOODFORD, LLC

STATEMENT OF OPERATIONS

(In thousands)

 

     Year Ended December 31,  
     2015     2014     2013  

Revenues:

      

Oil

   $ 39,972      $ 23,054      $ 11,638   

Natural gas

     53,674        38,084        14,417   

Natural gas liquids

     17,693        17,237        8,175   
  

 

 

   

 

 

   

 

 

 

Total revenues

     111,339        78,375        34,230   
  

 

 

   

 

 

   

 

 

 

Operating expenses:

      

Lease operating

     7,182        5,331        4,367   

Gathering, transportation and processing

     24,306        10,408        4,065   

Production and other taxes

     1,810        2,229        1,846   

Depreciation, depletion and amortization

     49,497        23,008        11,005   

Impairment of oil and natural gas properties

     140,165        —          —     

General and administrative

     6,824        8,960        9,891   
  

 

 

   

 

 

   

 

 

 

Total operating expenses

     229,784        49,936        31,174   
  

 

 

   

 

 

   

 

 

 

Operating income (loss)

     (118,445     28,439        3,056   

Other income (expense):

      

Interest expense

     (11,664     (3,325     (1,574

Interest capitalized

     11,664        3,325        1,558   

Gain (loss) on derivative contracts, net

     87,040        53,506        (1,177

Gain (loss) on sale of assets

     —          (2     16   
  

 

 

   

 

 

   

 

 

 

Total other income (expense)

     87,040        53,504        (1,177
  

 

 

   

 

 

   

 

 

 

Income (loss) before taxes

     (31,405     81,943        1,879   

Income tax expense

     (7     (16     —     
  

 

 

   

 

 

   

 

 

 

Net income (loss)

   $ (31,412   $ 81,927      $ 1,879   
  

 

 

   

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

F-4


VITRUVIAN II WOODFORD, LLC

STATEMENT OF CHANGES IN MEMBERS’ EQUITY

(In thousands)

 

Balance at December 31, 2012

   $  478,518   

Member contributions

     15,000   

Net income

     1,879   
  

 

 

 

Balance at December 31, 2013

   $ 495,397   

Net income

     81,927   
  

 

 

 

Balance at December 31, 2014

     577,324   

Net loss

     (31,412
  

 

 

 

Balance at December 31, 2015

   $ 545,912   
  

 

 

 

The accompanying notes are an integral part of these financial statements.

 

F-5


VITRUVIAN II WOODFORD, LLC

STATEMENT OF CASH FLOWS

(In thousands)

 

     Year Ended December 31,  
     2015     2014     2013  

Cash flows from operating activities:

      

Net income (loss)

   $ (31,412   $ 81,927      $ 1,879   

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

      

Depreciation, depletion and amortization

     49,497        23,008        11,005   

Impairment of oil and natural gas properties

     140,165        —          —     

(Gain) loss on sale of assets

     —          2        (16

(Gain) loss on derivative contracts, net

     (87,040     (53,506     1,177   

Cash receipts (payments) on derivative contract settlements, net

     62,015        1,445        (719

Amortization of deferred financing costs

     1,411        271        137   

Changes in operating assets and liabilities:

      

Accounts receivable—oil and gas

     (1,344     (8,691     (2,670

Accounts receivable—affiliates

     (753     (85     (216

Prepaid and other current assets

     (2,756     (3,867     (2,910

Accounts payable

     1,790        3,543        3,329   

Accrued liabilities

     1,867        1,072        2,366   

Royalties and revenue payable

     2,186        3,030        2,744   

Other liabilities

     (41     (161     (14
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     135,585        47,988        16,092   
  

 

 

   

 

 

   

 

 

 

Cash flows from investing activities:

      

Investments in oil and natural gas properties

     (301,210     (166,196     (51,043

Investments in other property and equipment

     (9,121     (3,478     (873

Proceeds related to post-closing purchase price adjustments

     —          —          36,856   

Proceeds from the sale of assets

     150        29        16   
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (310,181     (169,645     (15,044
  

 

 

   

 

 

   

 

 

 

Cash flows from financing activities:

      

Borrowings under Credit Facility

     172,653        125,000        28,000   

Repayments under Credit Facility

     —          —          (43,000

Member contributions

     —          —          15,000   

Debt issuance costs

     (2,858     (881     (3
  

 

 

   

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     169,795        124,119        (3
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     (4,801     2,462        1,045   

Cash and cash equivalents, beginning of period

     7,310        4,848        3,803   
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 2,509      $ 7,310      $ 4,848   
  

 

 

   

 

 

   

 

 

 

Supplemental cash flow disclosures:

      

Interest paid, net of amounts capitalized

   $ —        $ —        $ —     

Income taxes paid

     7        16        —     

Non-cash investing and financing activities—at period end:

      

Capital expenditures included in accrued liabilities

     32,427        32,521        6,985   

The accompanying notes are an integral part of these financial statements.

 

F-6


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS

(Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.)

References to “we,” “us” and “our” mean Vitruvian II Woodford, LLC (“Woodford”).

 

1. Organization and Description of Operations and Basis of Presentation

Organization

We were formed as a Delaware limited liability company on November 14, 2012 by members of our senior management team and affiliates of Quantum Energy Partners (“Quantum”), a private equity investment firm engaged in the acquisition and development of oil and natural gas properties.

Description of Operations

We are an independent energy company engaged in the acquisition, exploration, development and production of crude oil, natural gas and natural gas liquids (“NGLs”). We operate and have non-operating interests in producing wells within the Woodford and Springer shale formations in the South Central Oklahoma Oil Province, or SCOOP, resource play.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Significant estimates and assumptions include:

 

    estimated future net cash flows from proved reserves;

 

    depreciation, depletion and amortization expense (“DD&A”);

 

    asset retirement obligations (“AROs”);

 

    capitalized general and administrative (“G&A”) expenses and interest;

 

    unevaluated property costs;

 

    fair value of properties acquired and liabilities assumed;

 

    revenue and expense accruals;

 

    fair value of derivative contracts; and

 

    fair value of unit-based compensation.

Actual results may differ from the estimates, judgments and assumptions used in the preparation of our financial statements.

 

F-7


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

 

2. Summary of Significant Accounting Policies

Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and highly liquid investments with original maturities of three months or less from the date of measure.

Restricted Cash

Certain cash balances included in “Other assets” on our balance sheet are classified as restricted and consist of certificates of deposit that serve as collateral for certain performance bonds. These assets will continue to be restricted as long as we conduct oil and natural gas operations.

Accounts Receivable

We routinely assess the recoverability of our accounts receivable, which are comprised of amounts due from (i) purchasers of our oil, natural gas and NGL production and (ii) joint interest owners on properties that we operate. Generally, our oil and gas receivables are collected within 45 to 60 days of production and our joint interest billings are collected within the month after they are billed. We have the ability to withhold future revenue distributions to recover any nonpayment of our joint interest billings.

We establish provisions for losses on accounts receivable if we determine that it is likely that all or part of an outstanding balance will not be collected. As of December 31, 2015 and 2014, we had no allowance for doubtful accounts.

Concentration of Credit Risk

We sell a significant amount of our oil, natural gas and NGL production to a limited number of purchasers. The following table identifies customers from whom we derived 10% or more of receipts from the sale of oil and natural gas during the years ended December 31, 2015 and 2014. We believe that the loss of any of the customers listed below would not result in a material adverse effect on our ability to market future oil and natural gas production.

 

     2015     2014     2013  

Woodford Express, LLC

     49     15     *   

Murphy Energy Corporation

     23     21     14

Southwest Energy LP

     *        29     26

 

* Purchaser did not account for greater than 10% of revenues for the year.

Financial instruments that potentially subject us to concentrations of credit risk include our cash and cash equivalents, accounts receivable and derivative contracts. We attempt to minimize credit risk exposure associated with these instruments by placing our assets and other financial interests with credit-worthy institutions and maintaining credit policies, monitoring procedures and letters of credit or guaranties when considered necessary.

Derivative Contracts

We may periodically enter into derivative contracts to manage our exposure to commodity price and interest rate changes. These derivative contracts may take the form of forward contracts, futures contracts, swaps, collars or options. We do not use derivative contracts for trading purposes.

We record our derivative contracts at fair value and do not designate any of our derivative contracts as hedging instruments for accounting purposes. As such, unrealized gains and losses from changes in the valuation of our unsettled derivative contracts are reported in gain on derivative contracts, net, in our statement of operations.

We are exposed to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. To minimize the credit risk in derivative contracts, we enter into derivative contracts only with counterparties that are lenders under our Credit Facility. As of December 31, 2015, we had no past-due receivables from any counterparty. See Notes 7 and 8 for a discussion of the use of derivative instruments, management of credit risk inherent in derivative instruments and fair value information.

 

F-8


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Deferred Financing Costs

We capitalize costs incurred in connection with obtaining financing and amortize such costs as additional interest expense over the life of the underlying indebtedness.

Oil and Natural Gas Properties

We use the full cost method of accounting for oil and natural gas properties and equipment. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties, including salaries, benefits, interest and other internal costs directly attributable to these activities, are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include costs of drilling exploratory wells and external geological and geophysical costs. Development costs include the cost of drilling development wells and costs of completions, facilities and gathering systems. Costs associated with production, certain geological and geophysical costs and G&A costs that are not capitalized as described above are expensed in the period incurred. During the years ended December 31, 2015, 2014 and 2013 we capitalized $8.1 million, $6.5 million and $5.8 million, respectively, of salaries, benefits and other internal costs that were directly related to the acquisition, exploration and development activities of our unproved properties. We capitalize interest on expenditures made in connection with the exploration and development of unproved properties that are excluded from the amortization base. Interest is capitalized for the period that exploration and development activities are in progress. During the years ended December 31, 2015, 2014 and 2013, we capitalized $11.7 million, $3.3 million and $1.6 million, respectively, of interest.

DD&A of producing oil and natural gas properties is calculated using the units-of-production method, which is calculated by dividing the amortization base by the volume of total proved reserves, multiplied by the volume of oil and natural gas produced during the period. The amortization base includes the sum of proved property costs net of accumulated DD&A, estimated future development costs (future costs to assess and develop proved reserves) and asset retirement costs that are not already included in oil and gas property, less related salvage value. Our DD&A per Mcfe was $1.43, $1.70 and $1.78 for the years ended December 31, 2015, 2014 and 2013, respectively.

Oil and natural gas properties and equipment include costs of unproved properties, which are excluded from the amortization base until it is determined that proved reserves can be assigned to such properties or until such time that management has made an evaluation that impairment has occurred. All costs excluded from the amortization base are reviewed quarterly to determine if impairment has occurred and evaluation of these properties is expected to be completed within ten years. The costs of drilling exploratory dry holes are included in the amortization base immediately upon determination that such wells are not commercial.

Sales of proved and unproved oil and natural gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas.

Impairment of Oil and Gas Properties

Under the full cost method of accounting, we are required to perform a quarterly ceiling test, which establishes a limit on the book value of oil and natural gas properties. The capitalized costs of proved oil and natural gas properties, net of accumulated DD&A and related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of (i) the present value of estimated future net revenues from the projected production of proved oil and natural gas reserves, excluding future cash outflows associated with settling AROs accrued on the balance sheet, calculated using the average oil and natural gas sales price as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged as impairment expense and any write downs are not recoverable or reversible in future periods.

 

F-9


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

 

During the quarter ended December 31, 2015, we recorded an impairment to the carrying value of our oil and natural gas properties of $140.2 million. The lower ceiling values resulted primarily from significant decreases in the trailing twelve-month average prices for oil and natural gas, which significantly reduced proved reserves values.

Other Property and Equipment

Other property and equipment primarily consists of water infrastructure facilities, compressors, furniture, fixtures and other equipment. Other property and equipment is recorded at cost and depreciated using the straight-line method over the estimated useful lives of the respective assets, generally ranging from three to ten years. Leasehold improvements are amortized over the shorter of their economic lives or the lease term. The cost of maintenance and repairs are expensed in the period incurred. Expenditures that extend the life or improve existing property and equipment are capitalized.

Oil and Natural Gas Reserve Quantities

Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable in the future from established reservoirs under current operating and economic parameters. We prepare an estimate of proved reserves on a quarterly basis in conjunction with our DD&A calculation and ceiling test. Proved reserves are calculated based on various factors, including an independent reserve engineer’s report on proved reserves and an economic evaluation of all of our properties on a well-by-well basis.

Reserve quantities and their associated estimated future net cash flows impact depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data; the interpretation of that data; the accuracy of various economic assumptions; and the judgment of the individuals preparing the estimates. Proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas that are eventually recovered.

Asset Retirement Obligations

AROs are legal obligations associated with the plugging and abandonment of our oil and natural gas wells and associated equipment. We record a liability for the ARO and capitalize an equal amount as an increase in the carrying value of the related asset in the period in which our assets are placed in service or acquired. Over time, the ARO liability is accreted to its present value, and the capitalized cost is depleted using the units-of-production method.

Upon initial recognition, AROs are recorded at their fair values using expected present value techniques based on historical experience and third-party proposals for plugging and abandoning wells. The estimated remaining life of each well is based on reserve life estimates and federal and state regulatory requirements. Revisions in estimated AROs may result from changes in estimated inflation rates, service and equipment costs and estimated timing of settlement.

Our AROs relate to the plugging and abandonment of oil and natural gas wellbores and to decommissioning related pipelines and facilities.

Revenue Recognition and Natural Gas Imbalances

We recognize oil and natural gas revenues based on the quantities of our production sold to purchasers at market prices when delivery has occurred, title has transferred and collectability is reasonably assured. We use the sales method of accounting for oil and natural gas revenues from properties with joint ownership. Under this method, we record oil and natural gas revenues based on physical deliveries to our purchasers, which can be different from our entitled share of production. These differences create imbalances that we recognize as a liability only when the estimated remaining recoverable reserves of a property will not be sufficient to enable the under-produced party to recoup its entitled share through production. We do not record receivables for those properties in which we have taken less than our ownership share of production. At December 31, 2015 and 2014, our natural gas imbalances were less than $0.1 million.

 

F-10


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Segment Reporting

We operate in only one segment: the exploration and production of oil, natural gas and NGLs in the United States. All of our operations are conducted in one geographic area of the United States and all of our revenues are derived from customers located in the United States.

Contingencies

Certain conditions may exist as of the date our financial statements are issued, which may result in a loss to us but which will only be resolved when one or more future events occur or fail to occur. In the preparation of our financial statements, management assesses the need for accounting recognition or disclosure of these contingencies, if any, and such assessment inherently involves an exercise in judgment. In assessing loss contingencies related to legal proceedings that are pending against us or unasserted claims that may result in such proceedings, our management and legal counsel evaluate the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.

When applicable, we will accrue an undiscounted liability for contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount within the range is accrued. We do not record a contingent liability when the likelihood of loss is probable but the amount cannot be reasonably estimated or when it is believed to be only reasonably possible or remote.

For contingencies where an unfavorable outcome is reasonably possible and the impact would be material, we disclose the nature of the contingency and, if feasible, an estimate of the possible loss or range of loss. Loss contingencies considered remote are generally not disclosed. See Note 11 for additional information regarding our contingencies.

Income Taxes

As a limited liability company, we are not a taxpaying entity for federal income tax purposes. Our results of operations are included in the taxable income of our members, and, accordingly, we do not recognize any provision for federal income taxes in our financial statements. Income and losses for tax purposes may differ from our financial statement amounts and may be allocated to members on a different basis for tax purposes than for financial statement purposes. The basis of members’ capital reflected in our financial statements does not represent the members’ tax basis of their respective interests.

We are subject to state income tax in Oklahoma associated with certain of our royalty interests and recorded less than $0.1 million of such expense during the years ended December 31, 2015 and 2014. No income tax expense was recorded during the year ended December 31, 2013.

Unit-Based Compensation

Compensation expense related to unit-based payments made to employees is based on the estimated fair value of the equity instruments on the date of grant, net of estimated forfeitures, and is recognized on a straight-line basis over the requisite service period, which is generally the vesting period.

 

3. Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by various accounting standard-setting bodies.

In February 2016, the FASB issued ASU 2016-02, Leases. This new standard introduces a new lease model that requires the recognition of right-of-use assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. The new guidance will be effective for annual periods beginning after December 15, 2018, and interim periods thereafter. Upon adoption of this standard, a modified retrospective

 

F-11


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

 

transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are currently assessing the potential impact of this new standard on our financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-03 which simplifies the presentation of debt issuance costs. This ASU requires companies to present debt issuance costs as a direct deduction from the carrying value of that debt liability for non-revolver type debt. ASU 2015-03 does not impact the recognition and measurement guidance for debt issuance costs. Additionally, in August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest: Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (ASU 2015-15). These ASUs are effective for annual reporting periods beginning after December 15, 2015 and early adoption is permitted. Accordingly, we will adopt this ASU on December 31, 2016. Companies are required to use a retrospective approach, and we currently believe there will not be a material impact on our financial statement disclosures.

In August 2014, the FASB issued ASU 2014-15 which provides guidance regarding disclosures of uncertainties about an entity’s ability to continue as a going concern. The guidance applies prospectively to all entities, requiring management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern and disclose certain information when substantial doubt exists. We currently believe there will not be a material impact on our financial statements when we adopt this guidance for the annual period ending December 31, 2016.

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers, ASU 2014-09. In April and May 2016, the FASB issued additional guidance under ASU 2016-12, addressed implementation issues and provided technical corrections. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings. The guidance is effective for interim and annual periods beginning on or after December 15, 2017. We are currently evaluating the impact of this guidance on our financial statements.

 

4. Acquisitions

In December 2012, we acquired certain oil and natural gas leasehold interests located in Oklahoma from an unaffiliated third-party. The purchase price was subject to post-closing adjustments including the satisfactory completion of title review.

In 2013, we received total net proceeds of $37.5 million resulting from post-closing purchase price adjustments, primarily related to title defects identified during the title due diligence process. As of December 31, 2013, collection of $2.9 million of disputed title defects remained outstanding. During 2014, the disputed title defects were submitted to a dispute resolution process in accordance with the terms of the purchase and sale agreement with the seller. The dispute resolution process ended in a split decision, and we do not expect to receive any amounts related to this matter.

 

5. Oil and Natural Gas Properties

Capitalized Costs

The following table summarizes the capitalized costs of our oil and natural gas properties:

 

     December 31,  
     2015      2014  

Oil and natural gas properties:

     

Proved

   $ 691,464       $ 269,784   

Unproved, excluded from amortization

     373,597         495,396   
  

 

 

    

 

 

 

Total oil and natural gas properties

     1,065,061         765,180   

Less: accumulated DD&A

     (242,266      (53,556
  

 

 

    

 

 

 

Net oil and natural gas properties

   $ 822,795       $ 711,624   
  

 

 

    

 

 

 

 

F-12


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Proved oil and natural gas properties at December 31, 2015 and 2014 includes $5.5 million and $5.3 million, respectively, related to capitalized plugging, abandonment and site restoration costs.

Costs Not Amortized

The following table summarizes the capitalized costs classified within unproved properties that are not subject to amortization at December 31, 2015.

 

     Total      Costs Incurred In  
        2015      2014      2013      2012  

Costs not subject to amortization:

              

Acquisition costs

   $ 312,866       $ 10,501       $ 8,274       $ 3,587       $ 290,504   

Exploration costs

     27,265         23,845         1,778         1,642         —     

Development costs

     578         67         511         —           —     

Capitalized interest

     15,320         11,664         2,531         1,110         15   

Capitalized G&A expenses

     17,568         8,100         4,954         4,130         384   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total unproved properties

   $ 373,597       $ 54,177       $ 18,048       $ 10,469       $ 290,903   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Oil and gas properties not subject to amortization represent investments in unproved properties in which we own an interest. These unproved property costs include unevaluated leasehold acreage, the majority of which is held by production, geological and geophysical data costs associated with leasehold or drilling interests, costs associated with wells in progress at December 31, 2015 and capitalized internal costs. Costs associated with wells in progress are transferred to the amortization base upon the determination of whether proved reserves can be assigned to the properties, which is generally based on drilling results. All costs excluded from the amortization base are associated with our activities in SCOOP and will continue to be transferred to the full cost pool as we further prove and develop the underlying acreage.

Costs Incurred in Oil and Natural Gas Activities

The following table summarizes the costs incurred related to our oil and natural gas producing activities for the years ended December 31, 2015, 2014 and 2013:

 

     December 31,  
     2015      2014      2013  

Acquisition costs:

        

Proved

   $ 92       $ 16       $ 49   

Unproved

     10,350         10,871         5,033   

Exploration costs

     280,447         157,910         57,061   

Development costs

     8,992         24,008         309   
  

 

 

    

 

 

    

 

 

 

Total costs incurred

   $ 299,881       $ 192,805       $ 62,452   
  

 

 

    

 

 

    

 

 

 

 

6. Long Term Debt

We have a senior secured revolving credit agreement (the “Credit Facility”) with Wells Fargo Bank, N.A. (“Wells Fargo”) as administrative agent and other lenders. During 2015, we amended this agreement such that it now provides funding up to $650.0 million under two tranches: (i) Tranche A, which matures December 27, 2017, is subject to a borrowing base and is secured by a first lien on substantially all of our assets and (ii) Tranche B, which matures May 31, 2016, is supported by unfunded capital commitments of our equity sponsors. At December 31, 2015, we had a total of $337.7 million of principal outstanding under Tranche A and Tranche B, $31.0 million of which is classified under current maturity of long-term debt on our balance sheet.

Borrowing Base

The amount we may borrow under Tranche A is limited by a borrowing base based on our oil and natural gas properties, proved reserves, total indebtedness and other factors consistent with customary lending criteria. The borrowing base is re-determined quarterly through April 1, 2016 and at least semi-annually thereafter. As of December 31, 2015, the borrowing bases for Tranche A and Tranche B were $295.0 million and $75.0 million, respectively. The borrowing base for Tranche B was reduced to $50.0 million on January 31, 2016 in accordance with the Credit Facility.

 

F-13


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Interest

Interest on borrowings is calculated using the adjusted base rate (“ABR”) or the London Interbank Offering Rate (“LIBOR”), plus an applicable margin. The applicable margin ranges from 1.0% to 2.75% for ABR loans and from 2.0% to 3.75% for LIBOR loans, depending on the percentage of the total borrowing base utilization level. In addition to interest, we pay various fees, including a commitment fee equal to 0.50% per annum on the unutilized commitment, which is included within interest expense on our statement of operations. The weighted average interest rate on loan amounts outstanding during the years ended December 31, 2015, 2014 and 2013 was 3.81%, 3.00% and 3.08%, respectively.

Covenants

The Credit Facility contains certain covenants that restrict the payment of cash dividends, borrowings other than from the Credit Facility, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the prior consent of the lenders. We are subject to various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio, a maximum leverage ratio and ratios related to the amounts borrowed under Tranche B. The Credit Facility also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs and we are unable to cure such default as allowed by the Credit Facility, the lenders will be able to accelerate the maturity of the Credit Facility and exercise other rights and remedies.

Letters of Credit

From time to time, we may request the issuance of letters of credit for our own account. Letters of credit are subject to a fee of 25 basis points and accrue interest at a rate equal to the margin associated with LIBOR borrowings. At December 31, 2015, we had a letter of credit outstanding of $5.3 million, which reduces the amount available to borrow under the Credit Facility.

 

7. Asset Retirement Obligations

We record an ARO for our future plugging, abandonment and site restoration costs related to our oil and natural gas properties. The changes in our AROs for the years ended December 31, 2015, 2014 and 2013 are presented in the table below:

 

     December 31,  
     2015      2014      2013  

Beginning balance

   $ 5,733       $ 5,583       $ 1,159   

Acquisitions

     10         —           —     

Additions

     241         69         33   

Settlements

     (59      (250      (29

Revisions to estimates

     —           11         4,112   

Accretion expense

     338         320         308   
  

 

 

    

 

 

    

 

 

 

Ending balance

   $ 6,263       $ 5,733       $ 5,583   
  

 

 

    

 

 

    

 

 

 

The amount of the above obligation expected to be incurred during 2016 is $0.1 million and is included in accrued liabilities on our balance sheet.

 

8. Financial Instruments

In the normal course of business, we are exposed to certain risks including changes in the prices of oil, natural gas and NGLs which may impact the cash flows associated with the sale of our future oil and natural gas production.

 

F-14


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

 

We enter into derivative contracts with lenders under our Credit Facility that consist of either a single derivative instrument or a combination of instruments to manage our exposure to these risks. As of December 31, 2015, our commodity derivative instruments consisted of fixed price swaps, costless collars and three-way collars, which are described below:

Fixed Price Swaps : Under a swap contract, we will receive payment if the settlement price is less than the fixed price and would be required to make a payment to the counterparty is the settlement price is greater than the fixed price.

Costless Collars : A collar consists of a sold call option (ceiling) and a purchased put option (floor) and allows us to benefit from increases in commodity prices up to the ceiling price of the contract and protects us from decreases in commodity prices below the floor price. At settlement, the counterparty is required to make a payment to us if the settlement price is below the floor price, while we are required to make a payment to the counterparty if the settlement price is above the ceiling price. If the settlement price is between the floor price and ceiling price, no payments are due from either party.

Three-Way Collars : Three-way collars consist of a standard costless collar contract described above plus a put option sold by us with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the settlement price is below the sold put option price. By combining the standard costless collar contract with the additional sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard costless collar and the additional sold put price if the settlement price is equal to or less than the additional sold put price. If the settlement price is greater than the additional sold put price, the result is the same as it would have been with a standard costless collar only.

The table below presents our open commodity derivative contracts at December 31, 2015, none of which were designated as hedging instruments. Volumes are presented in million British Thermal Units (“MMBtu”) for natural gas and in barrels (“Bbls”) for oil.

 

     Remaining
Volume
     Weighted Average NYMEX Contract Price per Unit      Fair Value  

Period

      Swap      Sold Put      Floor      Ceiling     

Crude Oil

                 

Fixed Price Swap

                 

Jan – Dec 2016

     604,000       $ 65.70         —           —           —         $ 14,486   

Collar

                 

Jan – Dec 2016

     44,744         —           —         $ 78.85       $ 95.00         1,674   

Jan – Dec 2017

     3,528         —           —           78.85         95.00         120   

Three-Way Collar

                 

Jan – Dec 2016

     785,000         —         $ 41.81         56.81         71.00         8,864   

Jan – Dec 2017

     853,000         —           45.00         60.00         71.00         7,514   
  

 

 

                

 

 

 

Total crude oil (Bbls)

     2,290,272                     32,658   
  

 

 

                

 

 

 

Natural Gas

                 

Fixed Price Swap

                 

Jan – Dec 2016

     35,380,000       $ 3.49         —           —           —         $ 34,475   

Collar

                 

Jan – Dec 2016

     1,347,929         —           —         $ 4.12       $ 4.75         2,210   

Jan – Dec 2017

     20,567,539         —           —           3.01         3.62         7,284   
  

 

 

                

 

 

 

Total natural gas (MMbtu)

     57,295,468                     43,969   
  

 

 

                

 

 

 

Total unrealized derivative contracts

                  $ 76,627   
                 

 

 

 

We are exposed to credit loss in the event of nonperformance by our derivative counterparties; however, we do not currently anticipate that the counterparties will be unable to fulfill their contractual obligations. Additional collateral is not required by us due to the derivative counterparties’ collateral rights as a lender under our Credit Facility, and we do not require collateral from our derivative counterparties.

 

F-15


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

 

9. Fair Value Measurements

We classify financial assets and liabilities that are measured and reported at fair value on a recurring basis using a hierarchy based on the inputs used in measuring fair value. GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

We classify the inputs used to measure fair value into the following hierarchy:

Level 1: Quoted market prices in active markets for identical assets or liabilities.

Level 2: Quoted market prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active or other than quoted prices that are observable and can be corroborated by observable market data.

Level 3: Unobservable inputs that reflect management’s best estimates and assumptions of what market participants would use in measuring the fair value of an asset or liability.

Recurring Fair Value Measurements

The following tables summarize the location and fair value of our open commodity derivative contracts in our balance sheet at December 31, 2015 and 2014. All items included are reported at fair value using market inputs including quoted forward commodity prices, discount rates, and volatility factors (Level 2 inputs).

 

     Derivative Assets  
     Gross Fair Value      Offset in Balance
Sheet
     Balance Sheet Location  
           Current      Noncurrent  

December 31, 2015

   $ 76,627       $ —         $ 61,709       $ 14,918   

December 31, 2014

     51,893         (290      41,255         10,348   
     Derivative Liabilities  
     Gross Fair Value      Offset in Balance
Sheet
     Balance Sheet Location  
           Current      Noncurrent  

December 31, 2015

   $ —         $ —         $ —         $ —     

December 31, 2014

     (290      290         —           —     

The tables above exclude realized derivative contracts of $5.2 million and $1.5 million for which cash had not been received at December 31, 2015 and 2014, respectively.

Changes in the fair value of our commodity derivative contracts are recognized currently in earnings and were as follows for the years ended December 31, 2015, 2014 and 2013:

 

    

Location in
Statement of Operations

   Year Ended December 31,  
        2015      2014      2013  

Derivative gain:

           

Realized gain (loss)

  

Gain (loss) on derivative contracts, net

   $ 62,015       $ 1,445       $ (719

Unrealized gain (loss)

  

Gain (loss) on derivative contracts, net

     25,025         52,061         (458
     

 

 

    

 

 

    

 

 

 

Gain (loss) on derivative contracts, net

      $ 87,040       $ 53,506       $ (1,177
     

 

 

    

 

 

    

 

 

 

Nonrecurring Fair Value Measurements

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis (e.g., oil and natural gas properties) and are subject to fair value adjustments under certain circumstances. The inputs used to determine such fair value are primarily based upon internally developed cash flow models, as well as market-based valuations as discussed in Note 2 and are classified within Level 3.

 

F-16


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Other Fair Value Measurements

The carrying value of cash, accounts receivable, accounts payable, accrued liabilities and royalties and revenue payable approximate their fair values due to the short-term maturities of these instruments. Our current and long-term debt obligations under the Credit Facility also approximate fair value since the associated variable rates of interest are market based.

 

10. Members’ Equity

Our Limited Liability Company Agreement (the “LLC Agreement”) provides for the issuance of three classes of membership interests: a Capital Interest; a Management Incentive Interest; and a Key Employee Interest. Each member’s relative rights, privileges, preferences and obligations are represented by such membership interest. Members owning Capital Interests have voting rights and other interest owners do not. Capital Interest owners are obligated to make Capital Contributions to us, while Management Incentive Interest and Key Employee Interest owners have no such obligation. To the extent we make distributions to our members, such distributions will be made in accordance with a certain order of priority and in amounts that are based upon each membership interest as specified by the LLC Agreement.

Management Incentive Units

We have an Incentive Pool Plan (the “Plan”), whereby we may grant up to 100,000 Management Incentive Units (“MIUs”) to certain key employees as an additional form of compensation. Each MIU entitles the holder to share, in accordance with the LLC Agreement, in the allocations and distributions of any potential net proceeds received from a Vesting Event (as defined by the Plan). The table below presents the activity and weighted average grant date fair value related to our MIUs during the years ended December 31, 2015 and 2014:

 

     Number of Units      Weighted
Average Grant
Date Fair Value
 

Outstanding, January 1, 2013

     67,500       $ —     

Granted

     23,450         46.57   

Vested

     (9,878      —     

Forfeited

     (2,000      —     

Expired

     —           —     
  

 

 

    

 

 

 

Outstanding, January 1, 2014

     79,072       $ 13.81   

Granted

     2,330         497.72   

Vested

     (13,328      81.95   

Forfeited

     (100      —     

Expired

     —           —     
  

 

 

    

 

 

 

Outstanding, December 31, 2014

     67,974         33.13   

Granted

     456         584.63   

Vested

     (13,677      164.83   

Forfeited

     —           —     

Expired

     —           —     
  

 

 

    

 

 

 

Outstanding, December 31, 2015

     54,753       $ 46.03   
  

 

 

    

 

 

 

MIUs generally vest in equal fifteen percent increments on each of the first five anniversaries from the date of grant, with any remaining unvested MIUs vesting on the date of a Vesting Event.

Based on the characteristics of the Plan, we concluded that MIUs are considered equity-classified awards and determined the compensation expense associated with these awards based on their grant date fair value. We calculate grant date fair value based on our total estimated value as of the grant date, which requires several estimates and assumptions including: (i) the value of our oil and natural gas assets; (ii) future oil and natural gas market prices; (iii) the success of our development plan; (iv) future well performance; (v) estimated capital expenditures; and (vi) the potential date, if any, on which a Vesting Event will occur.

 

F-17


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

 

As of December 31, 2015, we have not recorded any compensation expense related to MIUs. Because the MIUs vest upon the occurrence of a performance condition, which is not probable to occur and is out of our control, no compensation expense will be recognized until the occurrence of a Vesting Event. At December 31, 2015, unrecognized compensation expense associated with MIUs was $2.5 million.

 

11. Related Party Transactions

Transactions with Vitruvian Exploration II, LLC

We are majority owned by Vitruvian Exploration II Holdings, LLC (“VEX II Holdings”), which is majority owned by Vitruvian Exploration II, LLC (“VEX II”). VEX II and VEX II Holdings are affiliates of Quantum. We routinely pay VEX II for certain operating and G&A expenses, consisting primarily of salaries and benefits, incurred on our behalf, and have made advances of potential management incentive unit distributions to VEX II Holdings.

During the years ended December 31, 2015, 2014 and 2013, VEX II paid $13.4 million, $14.4 million and $11.0 million, respectively, of costs and expenses on our behalf. As of December 31, 2015 and 2014, our receivable from VEX II was $1.0 million and $0.4 million, respectively.

Formation of and Transactions with Vitruvian Exploration III, LLC

Vitruvian Exploration III, LLC (“VEX III”), a Delaware limited liability company, was formed on December 18, 2015 by certain members of our management team and affiliates of Quantum to engage in the acquisition, development and production of unconventional resource plays across North America.

During the year ended December 31, 2015 we allocated $0.2 million of costs and expenses to VEX III, consisting primarily of salaries, benefits and rent expense. As of December 31, 2015, our receivable from VEX III was $0.2 million.

Transactions with Quantum

In February and March 2015, we borrowed a total of $30.0 million from Quantum. All amounts were repaid prior to December 31, 2015.

Transactions with Woodford Express, LLC (“WEX”)

Woodford Express, LLC, a midstream company with natural gas assets in Oklahoma, was formed by affiliates of Quantum, and is partially owned by certain members of our management team. We have an acreage dedication agreement with WEX, whereby WEX has the right to gather and process the natural gas produced from our leases located in Grady, Stephens and Garvin counties in Oklahoma. During the year ended December 31, 2015 and 2014, we paid $12.9 million and $2.1 million, respectively, to WEX for gathering, transportation and processing fees. Additionally, during the years ended December 31, 2015 and 2014, we received payments from WEX of $18.1 million and $11.7 million, respectively, for the sale of oil, natural gas and NGLs. No such transactions occurred with WEX during the year ended December 31, 2013.

 

12. Commitments and Contingencies

Commitments

We have various commitments related to office space, office equipment and drilling rigs utilized in our exploration and development operations. Minimum future lease payments due under non-cancelable operating leases with initial or remaining terms in excess of one year at December 31, 2015 are as follows:

 

     Rent      Office
Equipment
     Total  

2016

   $ 894       $ 40       $ 934   

2017

     909         3         912   

2018

     833         —           833   

2019

     843         —           843   

2020

     214         —           214   

Thereafter

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Total

   $ 3,693       $ 43       $ 3,736   
  

 

 

    

 

 

    

 

 

 

 

F-18


VITRUVIAN II WOODFORD, LLC

NOTES TO FINANCIAL STATEMENTS (Continued)

 

Operating Leases

We lease office space in Lindsay, Oklahoma and in The Woodlands, Texas under the terms of non-cancelable leases expiring in 2017 and 2020, respectively. We also lease certain office equipment.

Total rental expense for the years ended December 31, 2015, 2014 and 2013 was $1.3 million, $1.2 million and $1.1 million, respectively.

Delivery Commitments

In addition to the commitments above we are party to various natural gas and NGL agreements which include certain minimum volume delivery commitments. Our NGL volume commitments range from 2,000 bbls to 12,000 bbls per day over the term of the contract, which extends through 2025. Our natural gas volume commitments are 90,000 MMcfe/day in 2016, 80,000 MMcfe/day from 2017 through 2020 and 30,000 MMcfe/ day from 2021 through 2025. The table below presents the aggregate amount of payments we expect to make under these various contracts:

 

     Payments Due by Period for the Year Ending December 31,  
     2016      2017      2018      2019      2020      Thereafter      Total  
     (In thousands)  

Delivery commitments

   $ 20.4       $ 26.1       $ 28.4       $ 28.4       $ 29.4       $ 118.2       $ 250.9   

To the extent we do not deliver the minimum contractual volumes due, we will be required to pay the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a transportation fee.

We made deficiency payments of $1.2 million related to our NGL commitments during the year ended December 31, 2015. We do not expect to incur any additional volumetric shortfall payments during the remaining contract terms of these agreements.

Performance Bonds

We have performance bonds required by various agencies as collateral against potential damage caused by our development activities. Aggregate amounts associated with our performance bonds were $2.1 million at December 31, 2015.

Contingencies

From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of business.

We are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.

 

13. Subsequent Events

As of February 24, 2016, the date that the financial statements were issued, there have been no events subsequent to December 31, 2015 that would require additional adjustments to or disclosure in our financial statements.

 

F-19


VITRUVIAN II WOODFORD, LLC

Supplemental Oil, Natural Gas and NGL Disclosures (Unaudited)

Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves

All of our reserve information related to oil, natural gas and NGLs was compiled based on estimates prepared and reviewed by our engineers, each of whom we believe have the appropriate expertise and qualifications. The reserves estimation is part of our internal controls process subject to management’s annual review and approval. The reserve estimates as of December 31, 2015 were audited by Netherland, Sewell & Associates, Inc., our independent reserve engineers. All of the subject reserves are located in the continental United States.

Many assumptions and judgmental decisions are required to estimate reserves. Quantities reported are considered reasonable but are subject to future revisions, some of which may be substantial, as additional information becomes available. Such additional information may be gained as the result of reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other factors.

Regulations define proved oil, natural gas and NGL reserves as those quantities of oil, natural gas NGLs that, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether the estimate is a deterministic estimate or probabilistic estimate. Proved developed oil, natural gas and NGL reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well or through installed extraction equipment and infrastructure operational at the time of the reserves estimates if the extraction is by means not involving a well.

Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For oil volumes as of December 31, 2015, the average West Texas Intermediate spot price of $50.28 per barrel was adjusted for quality and transportation fees. For gas volumes as of December 31, 2015, the average Henry Hub spot price of $2.63 per MMBtu was similarly adjusted for gathering, transportation fees and distance from market. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties as of December 31, 2015 and 2014 are provided in the table below:

 

     2015      2014      2013  

Oil (per Bbl)

   $ 45.43       $ 89.23       $ 93.44   

Natural gas (per Mcf)

     2.58         4.62         4.06   

NGLs (per Bbl)

     13.76         31.90         33.10   

The following table sets forth our net proved oil, natural gas and NGL reserves at December 31, 2015, 2014 and 2013, and the changes in net proved oil, natural gas and NGL reserves during such years:

 

     Natural gas
(MMcf)
     Oil
(MBbl)
     NGL
(MBbl)
     Total
(MMcfe)(1)
 

Proved reserve quantities January 1, 2013

     33,990         1,029         1,821         51,090   

Extensions and discoveries

     33,011         890         2,085         50,861   

Production

     (4,066      (122      (228      (6,166

Revisions of previous estimates

     2,894         (494      (804      (4,894
  

 

 

    

 

 

    

 

 

    

 

 

 

Proved reserve quantities December 31, 2013

     65,829         1,303         2,874         90,891   

Extensions and discoveries

     108,589         3,096         7,385         171,475   

Production

     (8,707      (257      (549      (13,543

Revisions of previous estimates

     25,518         1,143         1,704         42,600   
  

 

 

    

 

 

    

 

 

    

 

 

 

Proved reserve quantities December 31, 2014

     191,229         5,285         11,414         291,423   

Extensions and discoveries

     497,990         17,133         28,773         773,426   

Production

     (21,327      (933      (1,297      (34,707

Revisions of previous estimates

     (19,213      (991      (1,445      (33,829
  

 

 

    

 

 

    

 

 

    

 

 

 

 

F-20


VITRUVIAN II WOODFORD, LLC

Supplemental Oil, Natural Gas and NGL Disclosures (Unaudited) (Continued)

 

     Natural gas
(MMcf)
     Oil
(MBbl)
     NGL
(MBbl)
     Total
(MMcfe)(1)
 

Proved reserve quantities December 31, 2015

     648,679         20,494         37,445         996,313   

Proved developed reserve quantities:

           

December 31, 2013

     36,288         901         1,935         53,304   

December 31, 2014

     70,448         2,098         4,309         108,890   

December 31, 2015

     167,361         5,219         9,310         254,535   

Proved undeveloped reserve quantities:

           

December 31, 2013

     29,541         402         939         37,587   

December 31, 2014

     120,781         3,187         7,105         182,533   

December 31, 2015

     481,318         15,275         28,135         741,778   

Total proved:

           

December 31, 2013

     65,829         1,303         2,874         90,891   

December 31, 2014

     191,229         5,285         11,414         291,423   

December 31, 2015

     648,679         20,494         37,445         996,313   

 

(1) May not sum or recalculate due to rounding.

The changes in proved reserves during 2015, 2014 and 2013 are comprised of the following items:

Revision of previous estimates . The downward revision of previous estimates of 33,829 MMcfe during 2015 is attributable to decreased commodity prices, which decreased the useful lives of the wells, decreasing the ultimate reserves recovered. The upward revision of previous estimates of 42,600 MMcfe during 2014 is primarily attributable to well performance exceeding previous estimates. The downward revision of previous estimates of 4,894 during 2013 is attributable to technical adjustments.

Extensions and discoveries . Extensions and discoveries of 773,426 MMcfe, 171,475 MMcfe and 50,861 MMcfe during 2015, 2014 and 2013, respectively, are comprised of extensions and discoveries as a result of continuous drilling in the SCOOP play.

Since June 2013 when we began operation of our first drilling rig, we increased to five rigs during 2014 and maintained a level of at least four drilling rigs throughout 2015. During this time, our operated horizontal producing wells increased from two wells as of December 31, 2013 to 35 wells as of December 31, 2015 driving a corresponding growth in proved reserves.

Standardized Measure

The standardized measure of discounted future net cash flows relating to proved oil, natural gas and NGL reserves as of the years ended December 31, 2015, 2014 and 2013, are shown in the table below. Since we are not a taxpaying entity for federal income tax purposes, we did not provide for any future income tax expense in our calculation.

 

     2015      2014      2013  

Future cash inflows

   $ 3,280,608       $ 1,796,635       $ 483,893   

Future production costs

     (1,281,335      (483,549      (129,673

Future development costs

     (737,545      (241,783      (65,375

Future income tax expenses

     —           —           —     
  

 

 

    

 

 

    

 

 

 

Future net cash flows

     1,261,728         1,071,303         288,845   

10% annual discount for estimated timing of cash flows

     (812,530      (609,218      (153,789
  

 

 

    

 

 

    

 

 

 

Standardized measure of discounted future net cash flows

   $ 449,198       $ 462,085       $ 135,056   
  

 

 

    

 

 

    

 

 

 

 

F-21


VITRUVIAN II WOODFORD, LLC

Supplemental Oil, Natural Gas and NGL Disclosures (Unaudited) (Continued)

 

Changes in Standardized Measure

The following are the principal sources of change in the standardized measure of discounted future net cash flows for the years shown:

 

     2015     2014     2013  

Standardized measure January 1,

   $ 462,085      $ 135,056      $ 74,859   

Sale of oil and natural gas produced, net of production costs

     (78,041     (60,407     (23,952

Changes in prices, net of production costs

     (338,361     14,763        (4,090

Extensions, discoveries and enhanced production

     375,251        290,032        66,384   

Change in estimated future development and abandonment costs

     71,109        (34,317     (5,814

Development costs incurred, previously estimated

     8,992        9,960        361   

Revision of quantity estimates

     (25,485     84,061        (7,311

Accretion of discount

     46,209        13,506        7,486   

Changes in timing of estimated cash flows and other

     (72,561     9,431        27,133   
  

 

 

   

 

 

   

 

 

 

Standardized measure December 31,

   $ 449,198      $ 462,085      $ 135,056   
  

 

 

   

 

 

   

 

 

 

Per Unit Realized Price and Costs

The following table presents per unit realized price and costs of our oil, natural gas and NGLs for the years ended December 31, 2015, 2014 and 2013:

 

     2015      2014      2013  

Average unit realized price excluding the effects of hedging:

        

Oil (per Bbl)

   $ 42.85       $ 89.76       $ 95.32   

Natural gas (per Mmcf)

     2.52         4.37         3.55   

NGLs (per Bbl)

     13.64         31.40         35.85   
  

 

 

    

 

 

    

 

 

 

Net equivalent thousand cubic feet of gas (6:1)

   $ 3.21       $ 5.79       $ 5.55   

Average unit production costs:

        

Net equivalent thousand cubic feet of gas (6:1)

   $ 0.96       $ 1.33       $ 1.67   

 

F-22


VITRUVIAN II WOODFORD, LLC

UNAUDITED BALANCE SHEET

(In thousands)

 

     September 30,
2016
    December 31,
2015
 

ASSETS

    

Current assets:

    

Cash and cash equivalents

   $ 1,985      $ 2,509   

Accounts receivable:

    

Oil and gas

     28,122        16,246   

Affiliates

     2,219        1,177   
  

 

 

   

 

 

 

Total accounts receivable

     30,341        17,423   

Derivative contracts

     16,105        66,951   

Prepaid and other current assets

     10,397        4,784   
  

 

 

   

 

 

 

Total current assets

     58,828        91,667   

Property and equipment, at cost:

    

Oil and natural gas properties (full cost method):

    

Proved

     855,808        691,464   

Unproved

     342,487        373,597   

Other property and equipment

     13,849        13,434   
  

 

 

   

 

 

 

Total property and equipment

     1,212,144        1,078,495   

Less: accumulated depreciation, depletion and amortization

     (478,992     (243,343
  

 

 

   

 

 

 

Net property and equipment

     733,152        835,152   

Deferred financing costs

     3,191        2,602   

Derivative contracts

     1,046        14,918   

Other assets

     28        28   
  

 

 

   

 

 

 

Total assets

   $ 796,245      $ 944,367   
  

 

 

   

 

 

 

LIABILITIES AND MEMBERS’ EQUITY

    

Current liabilities:

    

Accounts payable

   $ 8,462      $ 8,761   

Accrued liabilities

     22,973        37,897   

Royalties and revenue payable

     13,013        7,960   

Derivative contracts

     68        —     

Current maturities of long-term debt

     —          31,000   
  

 

 

   

 

 

 

Total current liabilities

     44,516        85,618   

Long-term debt

     321,500        306,653   

Derivative contracts

     1,058        —     

Asset retirement obligations

     6,535        6,184   
  

 

 

   

 

 

 

Total liabilities

     373,609        398,455   

Commitments and contingencies (Note 8)

    

Members’ equity

     422,636        545,912   
  

 

 

   

 

 

 

Total liabilities and members’ equity

   $ 796,245      $ 944,367   
  

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

F-23


VITRUVIAN II WOODFORD, LLC

UNAUDITED STATEMENT OF OPERATIONS

(In thousands)

 

     Nine Months Ended
September 30,
 
     2016     2015  

Revenues:

    

Oil

   $ 35,273      $ 27,672   

Natural gas

     63,383        37,666   

Natural gas liquids

     18,241        12,119   
  

 

 

   

 

 

 

Total revenues

     116,897        77,457   
  

 

 

   

 

 

 

Operating expenses:

    

Lease operating

     4,676        5,772   

Gathering, transportation and processing

     29,481        15,215   

Production and other taxes

     1,951        1,296   

Depreciation, depletion and amortization

     47,605        33,354   

Impairment of oil and natural gas properties

     188,318        —     

General and administrative

     9,592        5,151   
  

 

 

   

 

 

 

Total operating expenses

     281,623        60,788   
  

 

 

   

 

 

 

Operating income (loss)

     (164,726     16,669   

Other income (expense):

    

Interest expense

     (13,252     (7,987

Interest capitalized

     13,252        7,987   

Gain (loss) on derivative contracts, net

     (13,433     57,294   

Loss on sale of assets

     (87     —     
  

 

 

   

 

 

 

Total other income (expense)

     (13,520     57,294   
  

 

 

   

 

 

 

Income (loss) before taxes

     (178,246     73,963   

Income tax benefit (expense)

     (30     3   
  

 

 

   

 

 

 

Net income (loss)

   $ (178,276   $ 73,966   
  

 

 

   

 

 

 

The accompanying notes are an integral part of these financial statements.

 

F-24


VITRUVIAN II WOODFORD, LLC

UNAUDITED STATEMENT OF CHANGES IN MEMBERS’ EQUITY

(In thousands)

 

Balance at December 31, 2015

   $ 545,912   

Net loss

     (178,276

Member contributions

     55,000   
  

 

 

 

Balance at September 30, 2016

   $ 422,636   
  

 

 

 

The accompanying notes are an integral part of these financial statements.

 

F-25


VITRUVIAN II WOODFORD, LLC

UNAUDITED STATEMENT OF CASH FLOWS

(In thousands)

 

     Nine Months Ended
September 30,
 
     2016     2015  

Cash flows from operating activities:

    

Net income (loss)

   $ (178,276   $ 73,966   

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

    

Depreciation, depletion and amortization

     47,605        33,354   

Impairment of oil and natural gas properties

     188,318        —     

Loss on sale of assets

     87        —     

(Gain) loss on derivative contracts, net

     13,433        (57,294

Cash receipts on derivative contract settlements, net

     49,103        36,773   

Allowance for doubtful accounts

     4,365        —     

Amortization of deferred financing costs

     1,270        1,104   

Changes in operating assets and liabilities:

    

Accounts receivable—oil and gas

     (16,241     (8,368

Accounts receivable—affiliates

     (1,042     (597

Prepaid and other current assets

     1,318        (2,650

Accounts payable

     (299     8,264   

Accrued liabilities

     4,791        302   

Royalties and revenue payable

     5,053        1,489   

Other liabilities

     (34     (41
  

 

 

   

 

 

 

Net cash provided by operating activities

     119,451        86,302   
  

 

 

   

 

 

 

Cash flows from investing activities:

    

Investments in oil and natural gas properties

     (153,305     (241,033

Investments in other property and equipment

     (675     (275

Change in restricted cash

     (3,000     —     

Proceeds from the sale of assets

     17        150   
  

 

 

   

 

 

 

Net cash used in investing activities

     (156,963     (241,158
  

 

 

   

 

 

 

Cash flows from financing activities:

    

Proceeds from borrowings under Credit Facility

     20,000        152,000   

Repayments of borrowings under Credit Facility

     (136,153     —     

Issuance of long-term debt

     100,000        —     

Debt issuance costs

     (1,859     (2,513

Member contributions

     55,000        —     
  

 

 

   

 

 

 

Net cash provided by financing activities

     36,988        149,487   
  

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     (524     (5,369

Cash and cash equivalents, beginning of period

     2,509        7,310   
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 1,985      $ 1,941   
  

 

 

   

 

 

 

Non-cash investing and financing activities—at period end:

    

Capital expenditures included in accrued liabilities

   $ 12,709      $ 23,895   

The accompanying notes are an integral part of these financial statements.

 

F-26


VITRUVIAN II WOODFORD, LLC

NOTES TO UNAUDITED FINANCIAL STATEMENTS

(Except per unit amounts, or as noted within the context of each footnote disclosure, the dollar amounts presented in the tabular data within these footnote disclosures are stated in thousands of dollars.)

References to “we,” “us” and “our” mean Vitruvian II Woodford, LLC (“Woodford”).

 

1. Organization, Description of Operations and Basis of Presentation

Organization

We were formed as a Delaware limited liability company on November 14, 2012 by members of our senior management team and affiliates of Quantum Energy Partners (“Quantum”), a private equity investment firm engaged in the acquisition and development of oil and natural gas properties.

Description of Operations

We are an independent energy company engaged in the acquisition, exploration, development and production of crude oil, natural gas and natural gas liquids (“NGLs”). We operate and have non-operating interests in producing wells within the Woodford and Springer shale formations in the South Central Oklahoma Oil Province, or SCOOP, resource play.

Basis of Presentation

The accompanying unaudited financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim reporting and, in the opinion of management, reflect all adjustments, including those of a normal recurring nature, necessary to fairly state the results of the interim periods. Actual results may differ from the estimates, judgments and assumptions used in the preparation of our financial statements.

These unaudited financial statements and notes should be read in conjunction with the audited financial statements and notes thereto as of and for the year ended December 31, 2015.

Impairment of Oil and Gas Properties

Under the full cost method of accounting, we are required to perform a quarterly ceiling test, which establishes a limit on the book value of oil and natural gas properties. The capitalized costs of proved oil and natural gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes, may not exceed this “ceiling.” The ceiling limitation is equal to the sum of (i) the present value of estimated future net revenues from the projected production of proved oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations accrued on the balance sheet, calculated using the average oil and natural gas sales price as of the first trading day of each month over the preceding twelve months (such prices are held constant throughout the life of the properties) and a discount factor of 10%; (ii) the cost of unproved and unevaluated properties excluded from the costs being amortized; (iii) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; and (iv) related income tax effects. If capitalized costs exceed this ceiling, the excess is charged as impairment expense and any write downs are not recoverable or reversible in future periods.

During the nine months ended September 30, 2016, we recorded an impairment to the carrying value of our oil and natural gas properties of $188.3 million. The lower ceiling values resulted primarily from decreases in the trailing twelve-month average prices for oil and natural gas, which significantly reduced proved reserves values. No impairment was recorded during the nine months ended September 30, 2015.

 

2. Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by various accounting standard-setting bodies.

 

F-27


VITRUVIAN II WOODFORD, LLC

NOTES TO UNAUDITED FINANCIAL STATEMENTS (Continued)

 

In February 2016, the FASB issued ASU 2016-02, Leases. This new standard introduces a new lease model that requires the recognition of right-of-use assets and lease liabilities on the balance sheet and the disclosure of key information about leasing arrangements. The new guidance will be effective for annual periods beginning after December 15, 2018, and interim periods thereafter. Upon adoption of this standard, a modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are currently assessing the potential impact of this new standard on our financial statements and related disclosures.

In April 2015, the FASB issued ASU 2015-03 which simplifies the presentation of debt issuance costs. This ASU requires companies to present debt issuance costs as a direct deduction from the carrying value of that debt liability for non-revolver type debt. ASU 2015-03 does not impact the recognition and measurement guidance for debt issuance costs. Additionally, in August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest: Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (ASU 2015-15). These ASUs are effective for annual reporting periods beginning after December 15, 2015 and early adoption is permitted. Accordingly, we will adopt this ASU on December 31, 2016. Companies are required to use a retrospective approach, and we currently believe there will not be a material impact on our financial statement disclosures.

In August 2014, the FASB issued ASU 2014-15 which provides guidance regarding disclosures of uncertainties about an entity’s ability to continue as a going concern. The guidance applies prospectively to all entities, requiring management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern and disclose certain information when substantial doubt exists. We currently believe there will not be a material impact on our financial statements when we adopt this guidance for the annual period ending December 31, 2016.

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers, ASU 2014-09. In April and May 2016, the FASB issued additional guidance under ASU 2016-12, addressed implementation issues and provided technical corrections. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings. The guidance is effective for interim and annual periods beginning on or after December 15, 2017. We are currently evaluating the impact of this guidance on our financial statements.

 

3. Oil and Natural Gas Properties

Capitalized Costs

The following table summarizes the capitalized costs of our oil and natural gas properties:

 

     September 30,
2016
     December 31,
2015
 

Oil and natural gas properties:

     

Proved

   $ 855,808       $ 691,464   

Unproved, excluded from amortization

     342,487         373,597   
  

 

 

    

 

 

 

Total oil and natural gas properties

     1,198,295         1,065,061   

Less: accumulated DD&A

     (477,369      (242,266
  

 

 

    

 

 

 

Net oil and natural gas properties

   $ 720,926       $ 822,795   
  

 

 

    

 

 

 

Proved oil and natural gas properties at September 30, 2016 and December 31, 2015 include $5.6 million and $5.5 million, respectively, related to capitalized plugging, abandonment and site restoration costs.

 

4. Long Term Debt

We have a senior secured revolving credit agreement (the “Credit Facility”) with Wells Fargo Bank, N.A. (“Wells Fargo”) as administrative agent and other lenders. During 2015, we amended this agreement to provide

 

F-28


VITRUVIAN II WOODFORD, LLC

NOTES TO UNAUDITED FINANCIAL STATEMENTS (Continued)

 

funding up to $650.0 million under two tranches: (i) Tranche A, which matures December 27, 2017, is subject to a borrowing base and is secured by a first lien on substantially all of our assets and (ii) Tranche B, which matured upon closing of a second lien term loan in June 2016, was supported by unfunded capital commitments of our equity sponsors. At September 30, 2016, we had a total of $221.5 million of principal outstanding under Tranche A. At December 31, 2015, we had a total of $337.7 million of principal outstanding under Tranche A and Tranche B, $31.0 million of which was classified under current maturity of long-term debt on our balance sheet.

Borrowing Base

The amount we may borrow under Tranche A is limited by a borrowing base based on our oil and natural gas properties, proved reserves, total indebtedness and other factors consistent with customary lending criteria. The borrowing base is re-determined quarterly through April 1, 2016 and at least semi-annually thereafter. As of September 30, 2016, the borrowing base for Tranche A was $255.0 million. On June 17, 2016, in conjunction with the closing of our Second Lien Term Loan, the borrowing base for Tranche B was reduced to zero. The borrowing bases for Tranche A and Tranche B were $295.0 million and $75.0 million, respectively, at December 31, 2015.

Interest

Interest on borrowings is calculated using the adjusted base rate (“ABR”) or the London Interbank Offering Rate (“LIBOR”), plus an applicable margin. The applicable margin ranges from 1.0% to 1.75% for ABR loans and from 2.0% to 2.75% for LIBOR loans, depending on the percentage of the total borrowing base utilization level. In addition to interest, we pay various fees, including a commitment fee equal to 0.50% per annum on the unutilized commitment, which is included within interest expense on our statement of operations. The weighted average interest rate on loan amounts outstanding during the nine months ended September 30, 2016 was 4.1%.

Covenants

The Credit Facility contains certain covenants that restrict the payment of cash dividends, borrowings other than from the Credit Facility, sales of assets, loans to others, investments, merger activity, commodity swap agreements, liens and other transactions without the prior consent of the lenders. We are subject to various financial covenants calculated as of the last day of each fiscal quarter, including a minimum current ratio, a maximum leverage ratio and ratios related to the amounts borrowed under Tranche B. The Credit Facility also contains representations, warranties, indemnifications and affirmative and negative covenants, including events of default relating to nonpayment of principal, interest or fees, inaccuracy of representations or warranties in any material respect when made or when deemed made, violation of covenants, bankruptcy and insolvency events, certain unsatisfied judgments and a change of control. If an event of default occurs and we are unable to cure such default as allowed by the Credit Facility, the lenders will be able to accelerate the maturity of the Credit Facility and exercise other rights and remedies.

Second Lien Term Loan

On June 17, 2016, we entered into a second lien term loan agreement with Wells Fargo Energy Capital, Inc., as administrative agent, and a syndicate of lenders in the form of a $100.0 million term loan facility which is due on June 27, 2018. The debt governed by this agreement is effectively subordinated to the prior payment in full of the debt under the Credit Facility discussed above.

Pursuant to the second lien term loan, interest on borrowings is calculated using the alternate base rate plus a margin of 8.00% or LIBOR plus a margin of 9.00%. The alternate base rate is defined as the higher of (a) the prime rate established by the administrative agent, (b) the federal funds rate in effect plus 0.50% and (c) the daily three-month LIBOR plus 1.00%. The weighted average interest rate on loan amounts outstanding during the nine months ended September 30, 2016 was 10.0%.

Letters of Credit

From time to time, we may request the issuance of letters of credit for our own account. Letters of credit are subject to a fee of 25 basis points and accrue interest at a rate equal to the margin associated with LIBOR borrowings. At September 30, 2016 and December 31, 2015, we had a letter of credit outstanding of $2.3 million and $5.3 million, respectively, which reduces the amount available to borrow under the Credit Facility.

 

F-29


VITRUVIAN II WOODFORD, LLC

NOTES TO UNAUDITED FINANCIAL STATEMENTS (Continued)

 

5. Financial Instruments

In the normal course of business, we are exposed to certain risks including changes in the prices of oil, natural gas and NGLs which may impact the cash flows associated with the sale of our future oil and natural gas production. We enter into derivative contracts with lenders under our Credit Facility that consist of either a single derivative instrument or a combination of instruments to manage our exposure to these risks. As of September 30, 2016, our commodity derivative instruments consisted of fixed price swaps, costless collars and three-way collars, which are described below:

Fixed Price Swaps : Under a swap contract, we will receive payment if the settlement price is less than the fixed price and would be required to make a payment to the counterparty is the settlement price is greater than the fixed price.

Costless Collars : A collar consists of a sold call option (ceiling) and a purchased put option (floor) and allows us to benefit from increases in commodity prices up to the ceiling price of the contract and protects us from decreases in commodity prices below the floor price. At settlement, the counterparty is required to make a payment to us if the settlement price is below the floor price, while we are required to make a payment to the counterparty if the settlement price is above the ceiling price. If the settlement price is between the floor price and ceiling price, no payments are due from either party.

Three-Way Collars : Three-way collars consist of a standard costless collar contract described above plus a put option sold by us with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the settlement price is below the sold put option price. By combining the standard costless collar contract with the additional sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard costless collar and the additional sold put price if the settlement price is equal to or less than the additional sold put price. If the settlement price is greater than the additional sold put price, the result is the same as it would have been with a standard costless collar only.

The table below presents our open commodity derivative contracts at September 30, 2016, none of which were designated as hedging instruments. Volumes are presented in million British Thermal Units (“MMBtu”) for natural gas and in barrels (“Bbls”) for oil.

 

Period

   Remaining
Volume
     Weighted Average NYMEX Contract Price per Unit      Fair Value  
      Swap      Sold Put      Floor      Ceiling     

Crude Oil

                 

Fixed Price Swap

                 

Oct – Dec 2016

     172,000       $ 65.70         —           —           —         $ 2,867   

Collar

                 

Oct – Dec 2016

     10,701         —           —         $ 78.85       $ 95.00         319   

Jan – Dec 2017

     3,528         —           —           78.85         95.00         101   

Three-Way Collar

                 

Oct – Dec 2016

     216,000         —         $ 41.62         56.62         71.22         1,626   

Jan – Dec 2017

     853,000         —           45.00         60.00         71.10         5,833   
  

 

 

                

 

 

 

Total crude oil (Bbls)

     1,255,229                   $ 10,746   
  

 

 

                

 

 

 

Natural Gas

                 

Fixed Price Swap

                 

Oct – Dec 2016

     10,985,000       $ 3.44         —           —           —         $ 4,825   

Jan – Dec 2017

     10,800,000         2.82                  (2,939

Jan – Dec 2018

     14,600,000         2.86                  (782

Collar

                 

Oct – Dec 2016

     325,158         —           —         $ 4.12       $ 4.75         366   

Jan – Dec 2017

     29,567,539         —           —           2.97         3.46         2,037   

Jan – Dec 2018

     4,950,000         —           —           3.05         3.47         (160
  

 

 

                

 

 

 

Total natural gas (MMbtu)

     71,227,697                   $ 3,347   
  

 

 

                

 

 

 

Total unrealized derivative contracts

                  $ 14,093   
                 

 

 

 

 

F-30


VITRUVIAN II WOODFORD, LLC

NOTES TO UNAUDITED FINANCIAL STATEMENTS (Continued)

 

We are exposed to credit loss in the event of nonperformance by our derivative counterparties; however, we do not currently anticipate that the counterparties will be unable to fulfill their contractual obligations. Additional collateral is not required by us due to the derivative counterparties’ collateral rights as a lender under our Credit Facility, and we do not require collateral from our derivative counterparties.

 

6. Fair Value Measurements

We classify financial assets and liabilities that are measured and reported at fair value on a recurring basis using a hierarchy based on the inputs used in measuring fair value. GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price).

We classify the inputs used to measure fair value into the following hierarchy:

Level 1: Quoted market prices in active markets for identical assets or liabilities.

Level 2: Quoted market prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets and liabilities in markets that are not active or other than quoted prices that are observable and can be corroborated by observable market data.

Level 3: Unobservable inputs that reflect management’s best estimates and assumptions of what market participants would use in measuring the fair value of an asset or liability.

Recurring Fair Value Measurements

The following tables summarize the location and fair value of our open commodity derivative contracts in our balance sheet at September 30, 2016 and December 31, 2015. All items included are reported at fair value using market inputs including quoted forward commodity prices, discount rates, and volatility factors (Level 2 inputs).

 

     Derivative Assets  
     Gross Fair Value      Offset in Balance
Sheet
     Balance Sheet Location  
           Current      Noncurrent  

September 30, 2016

   $ 18,425       $ (3,206    $ 14,173       $ 1,046   

December 31, 2015

     76,627         —           61,709         14,918   
     Derivative Liabilities  
     Gross Fair Value      Offset in Balance
Sheet
     Balance Sheet Location  
           Current      Noncurrent  

September 30, 2016

   $ (4,332    $ 3,206       $ 68       $ 1,058   

December 31, 2015

     —           —           —           —     

The tables above exclude realized derivative contracts of $1.9 million and $5.2 million for which cash had not been received at September 30, 2016 and December 31, 2015, respectively.

Changes in the fair value of our commodity derivative contracts are recognized currently in earnings and were as follows for the nine months ended September 30, 2016 and 2015:

 

F-31


VITRUVIAN II WOODFORD, LLC

NOTES TO UNAUDITED FINANCIAL STATEMENTS (Continued)

 

          Nine Months Ended
September 30,
 
    

Location in Statement of Operations

   2016     2015  

Derivative gain:

       

Realized gain

  

Gain (loss) on derivative contracts, net

   $ 49,101      $ 36,773   

Unrealized gain (loss)

  

Gain (loss) on derivative contracts, net

     (62,534     20,521   
     

 

 

   

 

 

 

Gain (loss) on derivative contracts, net

      $ (13,433   $ 57,294   
     

 

 

   

 

 

 

Nonrecurring Fair Value Measurements

Certain nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis (e.g., oil and natural gas properties) and are subject to fair value adjustments under certain circumstances. The inputs used to determine such fair value are primarily based upon internally developed cash flow models, as well as market-based valuations as discussed in Note 1 and are classified within Level 3.

Other Fair Value Measurements

The carrying value of cash, accounts receivable, accounts payable, accrued liabilities and royalties and revenue payable approximate their fair values due to the short-term maturities of these instruments. Our current and long-term debt obligations under the Credit Facility also approximate fair value since the associated variable rates of interest are market based.

 

7. Related Party Transactions

Transactions with Vitruvian Exploration II, LLC

We are majority owned by Vitruvian Exploration II Holdings, LLC (“VEX II Holdings”), which is majority owned by Vitruvian Exploration II, LLC (“VEX II”). VEX II and VEX II Holdings are affiliates of Quantum. We routinely pay VEX II for certain operating and G&A expenses, consisting primarily of salaries and benefits, incurred on our behalf, and have made advances of potential management incentive unit distributions to VEX II Holdings.

During the nine months ended September 30, 2016 and 2015, VEX II paid $9.2 million and $10.7 million, respectively, of costs and expenses on our behalf. As of September 30, 2016 and December 31, 2015, our receivable from VEX II was $1.4 million and $1.0 million, respectively.

Formation of and Transactions with Vitruvian Exploration III, LLC

Vitruvian Exploration III, LLC (“VEX III”), a Delaware limited liability company, was formed on December 18, 2015 by certain members of our management team and affiliates of Quantum to engage in the acquisition, development and production of unconventional resource plays across North America.

During the nine months ended September 30, 2016, we allocated $2.3 million of costs and expenses to VEX III, consisting primarily of salaries, benefits and rent expense. No such costs were allocated during the nine months ended September 30, 2015. As of September 30, 2016 and December 31, 2015, our receivable from VEX III was $0.8 million and $0.2 million, respectively.

Transactions with Quantum

In February and March 2015, we borrowed a total of $30.0 million from Quantum. All amounts were repaid prior to December 31, 2015.

Transactions with Woodford Express, LLC (“WEX”)

Woodford Express, LLC, a midstream company with natural gas assets in Oklahoma, was formed by affiliates of Quantum, and is partially owned by certain members of our management team. We have an acreage dedication agreement with WEX, whereby WEX has the right to gather and process the natural gas produced from our leases

 

F-32


VITRUVIAN II WOODFORD, LLC

NOTES TO UNAUDITED FINANCIAL STATEMENTS (Continued)

 

located in Grady, Stephens, and Garvin counties in Oklahoma. During the nine months ended September 30, 2016 and 2015, we paid $20.1 million and $8.1 million, respectively, to WEX for gathering, transportation and processing fees. Additionally, during the nine months ended September 30, 2016 and 2015, we received payments from WEX of $1.8 million and $13.5 million, respectively, for the sale of oil, natural gas and NGLs.

 

8. Commitments and Contingencies

Commitments

We have various commitments related to office space, office equipment and drilling rigs utilized in our exploration and development operations. There have been no material changes to our commitments since year end December 31, 2015.

Contingencies

From time to time, we may be a plaintiff or defendant in a pending or threatened legal proceeding arising in the normal course of business. We are currently unaware of any proceedings that, in the opinion of management, will individually or in the aggregate have a material adverse effect on our financial position, results of operations or cash flows.

 

9. Subsequent Events

Except for those disclosed below, there have been no events subsequent to September 30, 2016 that would require additional adjustments to or disclosure in our financial statements.

On November 7, 2016, we amended our credit facility. The amendment (i) increased the applicable margin ranges to 1.25% to 2.25% for ABR loans and to 2.25% to 3.25% for LIBOR loans and (ii) increased our borrowing base to $272.0 million.

 

F-33

Exhibit 99.5

SUMMARY UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL INFORMATION

The following unaudited pro forma consolidated financial information is presented to illustrate the effect of Gulfport’s (or our) (1) purchase of oil and gas assets from Vitruvian for cash and shares of our common stock to be issued to Vitruvian in the Pending Acquisition, (2) offering of 29,000,000 shares of our common stock and (3) offering of $600.0 million aggregate principal amount of senior notes (the “notes”) on our historical financial position and operating results. The unaudited pro forma balance sheet as of September 30, 2016 is based on our historical financial statements as of September 30, 2016 after giving effect to the transactions as if they had occurred on September 30, 2016. The unaudited pro forma statements of operations for our nine months ended September 30, 2016 and the fiscal year ended December 31, 2015 are based on the historical financial statements for such periods after giving effect to the transactions as if they had occurred on January 1, 2015. The unaudited pro forma financial information should be read in conjunction with our historical consolidated financial statements and notes thereto included in our reports filed with the SEC under the Securities Exchange Act of 1934, as amended.

The preparation of the unaudited pro forma consolidated financial information is based on financial statements prepared in accordance with accounting principles generally accepted in the United States of America. These principles require the use of estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Actual results could differ from those estimates.

The unaudited pro forma consolidated financial information is provided for illustrative purposes only and does not purport to represent what our actual results of operations or our financial position would have been had the transactions occurred on the respective dates assumed, nor is it indicative of our future operating results or financial position. The pro forma adjustments reflected in the accompanying unaudited pro forma consolidated financial information reflect estimates and assumptions that our management believes to be reasonable. The preliminary purchase price allocation of approximately $1.9 billion is allocated to oil and gas properties, of which $1.4 billion is non-amortizing, and includes an asset retirement obligation of $11.8 million.

 

1


GULFPORT ENERGY CORPORATION

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

At September 30, 2016

 

    As
Reported
    Vitruvian
Historical
    Equity
Offering
Adjustments
    Senior Note
Offering
Adjustments
    Vitruvian
Acquisition
Adjustments
    Pro Forma
as
Adjusted
 
    (in thousands)        

Assets

           

Current assets:

           

Cash and cash equivalents

  $ 364,276      $ 1,985      $ 777,030 (1)    $ 590,750 (4)    $ (1,351,985 )(6)    $ 382,056   

Accounts receivable—oil and gas

    127,788        28,122        —          —          (28,122 )(7)      127,788   

Accounts receivable—related parties

    96        2,219        —          —          (2,219 )(7)      96   

Prepaid expenses and other current assets

    10,740        10,397        —          —          (10,397 )(7)      10,740   

Short-term derivative instruments

    39,363        16,105        —          —          (16,105 )(7)      39,363   

Deferred tax asset

    38        —          —          —          —          38   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total current assets

    542,301        58,828        777,030        590,750        (1,408,828     560,081   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Property and equipment:

           

Oil and natural gas properties, full-cost accounting, $1,723,821, $342,487 and $3,111,321 excluded from amortization as reported, Vitruvian Historical and pro forma as adjusted, respectively

    5,816,458        1,198,295        —          —          663,538 (8),(9)      7,678,291   

Other property and equipment

    54,460        13,849        —          —          (13,849 )(7)      54,460   

Accumulated depletion, depreciation, amortization and impairment

    (3,613,662     (478,992     —          —          478,992 (8)      (3,613,662
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Property and equipment, net

    2,257,256        733,152        —          —          1,128,681        4,119,089   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other assets

           

Equity investments

    251,309        —          —          —          —          251,309   

Deferred financing costs

    —          3,191        —          —          (3,191 )(7)       —     

Long-term derivative instruments

    15,262        1,046        —          —          (1,046 )(7)       15,262   

Deferred tax asset

    4,203        —          —          —          —          4,203   

Other assets

    5,512        28        —          —          (28 )(7)      5,512   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other assets

    276,286        4,265        —          —          (4,265     276,286   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

  $ 3,075,843      $ 796,245      $ 777,030      $ 590,750      $ (284,412   $ 4,955,456   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Liabilities and Stockholders’ Equity

           

Current liabilities:

           

Accounts payable and accrued liabilities

  $ 304,341      $ 44,448      $ —        $ —        $ (44,448 )(10)    $ 304,341   

Asset retirement obligation—current

    75        —          —          —          —          75   

Short-term derivative instruments

    37,220        68        —          —          (68 )(10)      37,220   

Current maturities of long-term debt

    220        —          —          —          —          220   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total current liabilities

    341,856        44,516        —          —          (44,516     341,856   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Long-term derivative instrument

    14,907        1,058        —          —          (1,058 )(10)      14,907   

Asset retirement obligation—long-term

    32,910        6,535        —          —          5,298 (9)      44,743   

Long-term debt, net of current maturities

    961,050        321,500        —          590,750 (5)      (321,500 )(10)      1,551,800 (14) 
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities

    1,350,723        373,609        —          590,750        (361,776     1,953,306   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Commitments and contingencies

           

Preferred stock, $.01 par value; 5,000,000 authorized, 30,000 authorized as redeemable 12% cumulative preferred stock, Series A; 0 issued and outstanding

    —          —          —          —          —          —     

Stockholders’ equity:

           

Common stock—$.01 par value, 200,000,000 authorized, 125,453,533 and 173,282,109 issued and outstanding as reported and pro forma as adjusted, respectively

    1,253        —          290 (2)      —          188 (11)      1,731   

Paid-in capital

    3,245,393        —          776,740 (3)      —          499,812 (12)      4,521,945   

Accumulated other comprehensive loss

    (50,816     —          —          —          —          (50,816

Retained (deficit) earnings

    (1,470,710     422,636        —          —          (422,636 )(13)      (1,470,710
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total stockholders’ equity

    1,725,120        422,636        777,030        —          77,364        3,002,150   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total liabilities and stockholders’ equity

  $ 3,075,843      $ 796,245      $ 777,030      $ 590,750      $ (284,412   $ 4,955,456   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

2


 

Notes:

(1) To adjust cash for the estimated receipt of proceeds from the issuance of our common shares, net of estimated offering expenses.
(2) To adjust common stock for the issuance of our common shares in our equity offering discussed in this Current Report.
(3) To adjust paid-in capital for the issuance of our common shares in our equity offering discussed in this Current Report.
(4) To adjust cash for the estimated receipt of proceeds from the issuance of notes in the concurrent notes offering, net of estimated issuance costs.
(5) To adjust long-term debt, net of current maturities, for the issuance of notes in the concurrent notes offering, net of deferred issuance costs.
(6) To adjust cash for the consideration paid to Vitruvian for the acquisition of oil and gas assets and to adjust for assets not acquired in the acquisition.
(7) To adjust for assets not acquired.
(8) To adjust for the purchase of oil and gas properties acquired based on preliminary estimates of allocated fair value of purchase price.
(9) To adjust for the non-current portion of asset retirement obligation related to assets acquired from Vitruvian.
(10) To adjust for liabilities not assumed.
(11) To adjust for the common shares issued to Vitruvian for consideration paid for the purchase of oil and gas assets.
(12) To adjust paid-in capital for the common shares issued to Vitruvian for consideration paid for the purchase of oil and gas assets.
(13) To adjust for the impact of the acquisition to our retained deficit based on our preliminary purchase price allocation.
(14) Excludes the impact of the issuance of $650.0 million of our 6.000% Senior Notes due 2024 and related repurchase or redemption of $600.0 million of our 7.750% Senior Notes due 2020 in October 2016 with the net proceeds thereof and cash on hand.

 

3


GULFPORT ENERGY CORPORATION

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

YEAR ENDED DECEMBER 31, 2015

 

    Gulfport
Historical
    Vitruvian
Historical
    Equity
Offering
Adjustments
    Senior Note
Offering
Adjustments
    Vitruvian
Acquisition
Adjustments
    Pro Forma  
    (in thousands, except per share data)  

Revenues:

           

Gas, oil and natural gas liquids sales, net of derivative instruments

  $ 708,990      $ 111,339      $ —        $ —        $ 87,040 (2)    $ 907,369   

Other income

    485        —          —          —          —          485   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    709,475        111,339        —          —          87,040        907,854   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

           

Lease operating expenses

    69,475        7,182        —          —          —          76,657   

Production taxes

    14,740        1,810        —          —          —          16,550   

Midstream gathering and processing

    138,590        24,306        —          —          —          162,896   

Depreciation, depletion, and amortization

    337,694        49,497        —          —          52,650 (3)      439,841   

Impairment of oil and gas properties

    1,440,418        140,165        —          —          —          1,580,583   

General and administrative

    41,967        6,824        —          —          (6,824 )(4)      41,967   

Accretion expense

    820        —          —          —          293 (5)      1,113   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    2,043,704        229,784        —          —          46,119        2,319,607   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

(LOSS) INCOME FROM OPERATIONS:

    (1,334,229     (118,445     —          —          40,921        (1,411,753
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

OTHER (INCOME) EXPENSE:

           

Interest expense

    51,221        —          —          35,656 (1)      —          86,877   

Interest income

    (643     —          —          —          —          (643

Insurance proceeds

    (10,015     —          —          —          —          (10,015

Gain on derivative instruments, net

    —          (87,040     —          —          87,040 (2)      —     

Loss from equity method investments

    106,093        —          —          —          —          106,093   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    146,656        (87,040     —          35,656        87,040        182,312   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

LOSS BEFORE INCOME TAXES

    (1,480,885     (31,405     —          (35,656     (46,119     (1,594,065

INCOME TAX (BENEFIT) EXPENSE

    (256,001     7        —          —          77 (6)      (255,917
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

NET LOSS

  $ (1,224,884   $ (31,412   $ —        $ (35,656   $ (46,196   $ (1,338,148
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

NET LOSS PER COMMON SHARE:

           

Basic

  $ (12.27           $ (9.06
 

 

 

           

 

 

 

Diluted

  $ (12.27           $ (9.06
 

 

 

           

 

 

 

Weighted average common shares outstanding—Basic

    99,792,401          29,000,000          18,828,576        147,620,977   

Weighted average common shares outstanding—Diluted

    99,792,401          29,000,000          18,828,576        147,620,977   

 

Notes:

(1) To adjust interest expense for issuance of notes and amortization of estimated deferred issuance costs.
(2) To reclassify derivative activity as an offset to gas, oil and natural gas liquids sales consistent with the Company’s historical financial statements.
(3) To adjust historical depletion expense associated with the oil and gas properties acquired.
(4) Excludes general and administrative expenses as only oil and gas assets were acquired.
(5) To adjust historical accretion expense associated with the oil and gas properties acquired.
(6) To adjust historical income tax expense for the oil and gas properties acquired.

 

4


GULFPORT ENERGY CORPORATION

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2016

 

    Gulfport
Historical
    Vitruvian
Historical
    Equity
Offering
Adjustments
    Senior Note
Offering
Adjustments
    Vitruvian
Acquisition
Adjustments
    Pro Forma  
    (in thousands, except per share data)  

Revenues:

           

Gas, oil and natural gas liquids sales, net of derivative instruments

  $ 322,494      $ 116,897      $ —        $ —        $ (13,433 )(2)    $ 425,958   

Other income

    3        —          —          —          —          3   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    322,497        116,897        —          —          (13,433     425,961   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

           

Lease operating expenses

    48,789        4,676        —          —          —          53,465   

Production taxes

    9,492        1,951        —          —          —          11,443   

Midstream gathering and processing

    122,476        29,481        —          —          —          151,957   

Depreciation, depletion, and amortization

    183,414        47,605        —          —          69,186 (3)      300,205   

Impairment of oil and gas properties

    601,806        188,318        —          —          —          790,124   

General and administrative

    32,941        9,592        —          —          (9,592 )(4)      32,941   

Accretion expense

    777        —          —          —          237 (5)      1,014   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    999,695        281,623        —          —          59,831        1,341,149   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

LOSS FROM OPERATIONS:

    (677,198     (164,726     —          —          (73,264     (915,188
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

OTHER (INCOME) EXPENSE:

           

Interest expense

    44,892        —          —          26,742 (1)      —          71,634   

Interest income

    (822     —          —          —          —          (822

Insurance proceeds

    (3,750     —          —          —          —          (3,750

Loss on derivative instruments, net

    —          13,433        —          —          (13,433 )(2)      —     

Loss on sale of assets

    —          87        —          —          (87 )(6)      —     

Loss from equity method investments

    25,576        —          —          —          —          25,576   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    65,896        13,520        —          26,742        (13,520     92,638   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

LOSS BEFORE INCOME TAXES

    (743,094     (178,246     —          (26,742     (59,744     (1,007,826

INCOME TAX (BENEFIT) EXPENSE

    (3,755     30        —          —          504 (7)      (3,221
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

NET LOSS

  $ (739,339     (178,276   $ —        $ (26,742   $ (60,248   $ (1,004,605
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

NET LOSS PER COMMON SHARE:

           

Basic

  $ (6.12           $ (5.96
 

 

 

           

 

 

 

Diluted

  $ (6.12           $ (5.96
 

 

 

           

 

 

 

Weighted average common shares outstanding—Basic

    120,771,046          29,000,000          18,828,576        168,599,622   

Weighted average common shares outstanding—Diluted

    120,771,046          29,000,000          18,828,576        168,599,622   

 

Notes :

(1) To adjust interest expense for issuance of notes and amortization of estimated deferred issuance costs.
(2) To reclassify derivative activity as an offset to gas, oil and natural gas liquids sales, consistent with the Company’s historical financial statements.
(3) To adjust historical depletion expense associated with the oil and gas properties acquired.
(4) Excludes general and administrative expenses as only oil and gas assets were acquired.
(5) To adjust historical accretion expense associated with the oil and gas properties acquired.
(6) Excludes loss on sale of assets not included in acquisition.
(7) To adjust historical income tax expense for the oil and gas properties acquired.

 

5

Exhibit 99.6

 

LOGO

ESTIMATES
of
RESERVES AND FUTURE REVENUE
to the
VITRUVIAN EXPLORATION II, LLC INTEREST
in
CERTAIN OIL AND GAS PROPERTIES
located in
OKLAHOMA
as of
DECEMBER 31, 2015
Prepared in accordance with
U.S. SECURITIES AND EXCHANGE COMMISSION REGULATIONS
NSAI
NETHERLAND, SEWELL
& ASSOCIATES, INC.
WORLDWIDE PETROLEUM
CONSULTANTS
ENGINEERING GEOLOGY
GEOPHYSICS PETROPHYSICS


     C HAIRMAN  & CEO

LOGO

  E XECUTIVE C OMMITTEE   

C.H. ( SCOTT ) R EES  III

  R OBERT C. B ARG    M IKE K. N ORTON   

P RESIDENT  & COO

  P. S COTT F ROST    D AN P AUL S MITH   

D ANNY D. S IMMONS

WORLDWIDE PETROLEUM CONSULTANTS

  J OHN G. H ATTNER    J OSEPH  J. S PELLMAN   

E XECUTIVE VP

ENGINEERING • GEOLOGY • GEOPHYSICS • PETROPHYSICS   J. C ARTER  H ENSON , J R .    D ANIEL  T. W ALKER    G. L ANCE B INDER

 

February 3, 2016

Mr. Richard F. Lane

Vitruvian Exploration II, LLC

4 Waterway Square Place, Suite 400

The Woodlands, Texas 77380

Dear Mr. Lane:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2015, to the Vitruvian Exploration II, LLC (Vitruvian) interest in certain oil and gas properties located in Oklahoma, as listed in the accompanying tabulations. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Vitruvian. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter.

We estimate the net reserves and future net revenue to the Vitruvian interest in these properties, as of December 31, 2015, to be:

 

     Net Reserves      Future Net Revenue (M$)  

Category

   Oil
(MBBL)
     NGL
(MBBL)
     Gas
(MMCF)
     Total      Present Worth
at 10%
 

Proved Developed Producing

     4,240.9         9,420.3         157,685.6         448,535.9         293,075.2   

Proved Undeveloped

     10,703.0         28,020.0         456,627.9         666,048.7         136,308.1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     14,943.9         37,440.3         614,313.4         1,114,584.6         429,383.3   

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved developed producing and proved undeveloped reserves. Our study indicates that there are no proved developed non-producing reserves for these properties at this time. No study was made to determine whether probable or possible reserves might be established for these properties. Estimates of proved undeveloped reserves have been included for certain locations that generate positive future net revenue but have negative present worth discounted at 10 percent based on the constant prices and costs discussed in subsequent paragraphs of this letter. These locations have been included based on the operators’ declared intent to drill these wells, as evidenced by Vitruvian’s internal budget, reserves estimates, and price forecast. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

As shown in the Table of Contents, this report includes summary projections of reserves and revenue by reserves category. Also included are reserves and economics data for each reserves category; these data include a summary projection of reserves and revenue along with one-line summaries of basic data, reserves, and economics by lease.

 

 

2100 R OSS A VENUE , S UITE 2200 • D ALLAS , T EXAS 75201-2737 • P H : 214-969-5401 • F AX : 214-969-5411

  nsai@nsai-petro.com
1301 M C K INNEY S TREET , S UITE 3200 • H OUSTON , T EXAS 77010-3034 • P H : 713-654-4950 • F AX : 713-654-4951   netherlandsewell.com


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Gross revenue shown in this report is Vitruvian’s share of the gross (100 percent) revenue from the properties prior to any deductions. As requested, revenue attributable to fuel and percent of proceeds gas and NGL volumes are shown herein as “other” revenue; however, these volumes and revenues are not included in our net reserves or future net revenue estimates. Future net revenue is after deductions for Vitruvian’s share of production taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2015. For oil and NGL volumes, the average West Texas Intermediate posted price of $46.79 per barrel is adjusted by lease for quality and market differentials. For gas volumes, the average Henry Hub spot price of $2.587 per MMBTU is adjusted by lease for energy content, market differentials, and plant fees. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $45.44 per barrel of oil, $14.65 per barrel of NGL, and $2.536 per MCF of gas.

Operating costs used in this report are based on operating expense records of Vitruvian. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Vitruvian are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Vitruvian and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for new development wells and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Vitruvian interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Vitruvian receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Vitruvian, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.


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For the purposes of this report, we used technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Vitruvian, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

 

      Sincerely,
      NETHERLAND, SEWELL & ASSOCIATES, INC.
      Texas Registered Engineering Firm F-2699
      By:   /s/ C.H. (Scott) Rees III
        C.H. (Scott) Rees III, P.E.
        Chairman and Chief Executive Officer
By:   /s/ Richard B. Talley, Jr.     By:   /s/ David E. Nice
  Richard B. Talley, Jr., P.E. 102425       David E. Nice, P.G. 346
  Senior Vice President       Vice President
Date Signed:   February 3, 2016     Date Signed:   February 3, 2016

WKB:ALA

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir . Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

 

  (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

 

  (ii) Same environment of deposition;

 

  (iii) Similar geological structure; and

 

  (iv) Same drive mechanism.

Instruction to paragraph (a)(2) : Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen . Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate . Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate . The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves . Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

  (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

  (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

 

  (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

 

  (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

 

Definitions - Page 1 of 6


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

  (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

 

  (iv) Provide improved recovery systems.

(8) Development project . A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well . A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible . The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

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

(12) Exploration costs . Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

 

  (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

 

  (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

 

  (iii) Dry hole contributions and bottom hole contributions.

 

  (iv) Costs of drilling and equipping exploratory wells.

 

  (v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well . An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well . An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities .

 

  (i) Oil and gas producing activities include:

 

  (A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

 

  (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

 

  (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

 

  (1) Lifting the oil and gas to the surface; and

 

  (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

 

  (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

Instruction 1 to paragraph (a)(16)(i) : The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

 

  a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

 

  b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

 

  (ii) Oil and gas producing activities do not include:

 

  (A) Transporting, refining, or marketing oil and gas;

 

  (B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

 

  (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

 

  (D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 

  (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

 

  (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

 

  (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

  (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

 

  (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

 

  (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 

  (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

  (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

 

  (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

 

  (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs .

 

  (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

 

  (A) Costs of labor to operate the wells and related equipment and facilities.

 

  (B) Repairs and maintenance.

 

  (C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

 

  (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

 

  (E) Severance taxes.

 

  (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

  (i) The area of the reservoir considered as proved includes:

 

  (A) The area identified by drilling and limited by fluid contacts, if any, and

 

  (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

  (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

  (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

  (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

  (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

  (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26) : Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

 

  a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

 

  b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

 

  a. Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

 

  b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

 

  c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

 

  d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

 

Definitions - Page 5 of 6


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

  e . Discount. This amount shall be derived from using a discount rate of 10  percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

 

  f . Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

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

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

  (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

  (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

 

    The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

 

    The company’s historical record at completing development of comparable long-term projects;

 

    The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

 

    The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

 

    The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

 

  (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

 

Definitions - Page 6 of 6

Exhibit 99.7

 

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ESTIMATES
of
RESERVES AND FUTURE REVENUE
to the
VITRUVIAN EXPLORATION II, LLC INTEREST
in
CERTAIN OIL AND GAS PROPERTIES
located in
OKLAHOMA
as of
DECEMBER 31, 2014
REVISED
BASED ON CONSTANT PRICE AND COST PARAMETERS
in accordance with
U.S. SECURITIES AND EXCHANGE COMMISSION REGULATIONS
NSAI
NETHERLAND, SEWELL & ASSOCIATES, INC.
WORLDWIDE PETROLEUM CONSULTANTS
ENGINEERING GEOLOGY
GEOPHYSICS PETROPHYSICS


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WORLDWIDE PETROLEUM CONSULTANTS

ENGINEERING GEOLOGY GEOPHYSICS PETROPHYSICS

 

 

C HAIRMAN  & CEO

C.H. (S COTT ) R EES  III

P RESIDENT  & COO

D ANNY D. S IMMONS

E XECUTIVE VP

G. L ANCE B INDER

 

  

  E XECUTIVE  C OMMITTEE

P. S COTT F ROST

J. C ARTER  H ENSON , J R .

D AN P AUL S MITH

J OSEPH J. S PELLMAN

March 10, 2015

Mr. Richard F. Lane

Vitruvian Exploration II, LLC

4 Waterway Square Place, Suite 400

The Woodlands, Texas 77380

Dear Mr. Lane:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2014, to the Vitruvian Exploration II, LLC (Vitruvian) interest in certain oil and gas properties located in Oklahoma, as listed in the accompanying tabulations. This is a revision of our report dated January 23, 2015. Capital costs and estimated gas price adjustments, gas plant processing fees, transportation fees, and lease operating expenses have been updated based on additional information provided by Vitruvian. With the exception of these changes, we completed our evaluation on or about January 23, 2015. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Vitruvian. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter.

We estimate the net reserves and future net revenue to the Vitruvian interest in these properties, as of December 31, 2014, to be:

 

     Net Reserves      Future Net Revenue (M$)  

Category

   Oil
(MBBL)
     NGL
(MBBL)
     Gas
(MMCF)
     Total      Present Worth
at 10%
 

Proved Developed Producing

     1,880.4         4,538.7         63,373.4         435,972.3         235,571.4   

Proved Undeveloped

     1,892.0         5,546.2         90,390.6         364,575.3         124,673.4   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     3,772.4         10,084.8         153,764.0         800,547.6         360,244.7   

 

Totals may not add because of rounding.

              

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved developed producing and proved undeveloped reserves. Our study indicates that there are no proved developed non-producing reserves for these properties at this time. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

As shown in the Table of Contents, this report includes summary projections of reserves and revenue by reserves category. Also included are reserves and economics data for each reserves category; these data include a summary projection of reserves and revenue along with one-line summaries of basic data, reserves, and economics by lease.

 

 

2100 R OSS A VENUE , S UITE 2200 • D ALLAS , T EXAS 75201-2737 • P H : 214-969-5401 • F AX : 214-969-5411

  nsai@nsai-petro.com
1301 M C K INNEY S TREET , S UITE 3200 • H OUSTON , T EXAS 77010-3034 • P H : 713-654-4950 • F AX : 713-654-4951   netherlandsewell.com


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Gross revenue shown in this report is Vitruvian’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Vitruvian’s share of production taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2014. For oil and NGL volumes, the average West Texas Intermediate posted price of $91.48 per barrel is adjusted by lease for quality and market differentials. For gas volumes, the average Henry Hub spot price of $4.350 per MMBTU is adjusted by lease for energy content, market differentials, and plant fees. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $92.68 per barrel of oil, $31.79 per barrel of NGL, and $4.375 per MCF of gas.

Operating costs used in this report are based on operating expense records of Vitruvian. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Vitruvian are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Vitruvian and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for new development wells and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Vitruvian interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Vitruvian receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Vitruvian, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.


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For the purposes of this report, we used technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Vitruvian, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons primarily responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

 

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:   /s/ C.H. (Scott) Rees III
  C.H. (Scott) Rees III, P.E.
  Chairman and Chief Executive Officer
By:   /s/ Richard B. Talley, Jr.
  Richard B. Talley, Jr., P.E. 102425
  Vice President
Date Signed: March 10, 2015

WKB:ALA

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

 

  (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

 

  (ii) Same environment of deposition;

 

  (iii) Similar geological structure; and

 

  (iv) Same drive mechanism.

Instruction to paragraph (a)(2) : Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen . Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate . Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate . The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves . Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

  (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

  (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

 

  (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

 

  (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

 

Definitions - Page 1 of 6


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

  (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

 

  (iv) Provide improved recovery systems.

(8) Development project . A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well . A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible . The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

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

(12) Exploration costs . Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

 

  (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

 

  (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

 

  (iii) Dry hole contributions and bottom hole contributions.

 

  (iv) Costs of drilling and equipping exploratory wells.

 

  (v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well . An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well . An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities .

 

  (i) Oil and gas producing activities include:

 

  (A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

 

  (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

 

  (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

 

  (1) Lifting the oil and gas to the surface; and

 

  (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

 

  (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

 

Definitions - Page 2 of 6


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

Instruction 1 to paragraph (a)(16)(i) : The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

 

  a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

 

  b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

 

  (ii) Oil and gas producing activities do not include:

 

  (A) Transporting, refining, or marketing oil and gas;

 

  (B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

 

  (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

 

  (D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 

  (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

 

  (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

 

  (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

  (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

 

  (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

 

  (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 

  (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 

Definitions - Page 3 of 6


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

  (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

 

  (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

 

  (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs .

 

  (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

 

  (A) Costs of labor to operate the wells and related equipment and facilities.

 

  (B) Repairs and maintenance.

 

  (C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

 

  (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

 

  (E) Severance taxes.

 

  (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

  (i) The area of the reservoir considered as proved includes:

 

  (A) The area identified by drilling and limited by fluid contacts, if any, and

 

  (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

  (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

  (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

  (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

  (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

  (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

Definitions - Page 4 of 6


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26) : Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

 

  a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

 

  b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

 

  a. Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

 

  b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

 

  c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

 

  d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

 

Definitions - Page 5 of 6


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

  e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

 

  f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

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

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

  (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

  (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

 

    The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

 

    The company’s historical record at completing development of comparable long-term projects;

 

    The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

 

    The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

 

    The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

 

  (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

 

Definitions - Page 6 of 6

Exhibit 99.8

 

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ESTIMATES
of
RESERVES AND FUTURE REVENUE
to the
VITRUVIAN EXPLORATION II, LLC INTEREST
in
CERTAIN OIL AND GAS PROPERTIES
located in
OKLAHOMA
as of
DECEMBER 31, 2013
BASED ON CONSTANT PRICE AND COST PARAMETERS
in accordance with
U.S. SECURITIES AND EXCHANGE COMMISSION REGULATIONS
NSAI
NETHERLAND, SEWELL
& ASSOCIATES, INC.
WORLDWIDE PETROLEUM
CONSULTANTS
ENGINEERING GEOLOGY
GEOPHYSICS PETROPHYSICS


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WORLDWIDE PETROLEUM CONSULTANTS

ENGINEERING GEOLOGY GEOPHYSICS PETROPHYSICS

 

 

C HAIRMAN  & CEO

C.H. (S COTT ) R EES  III

P RESIDENT  & COO

D ANNY D. S IMMONS

E XECUTIVE VP

G. L ANCE B INDER

 

  

E XECUTIVE  C OMMITTEE

 

P. S COTT F ROST - D ALLAS

  J. C ARTER  H ENSON , J R . - H OUSTON

D AN P AUL S MITH - D ALLAS

J OSEPH J. S PELLMAN - D ALLAS

T HOMAS J. T ELLA II - D ALLAS

February 3, 2014

Mr. Richard F. Lane

Vitruvian Exploration II, LLC

4 Waterway Square Place, Suite 400

The Woodlands, Texas 77380

Dear Mr. Lane:

In accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2013, to the Vitruvian Exploration II, LLC (Vitruvian) interest in certain oil and gas properties located in Oklahoma, as listed in the accompanying tabulations. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves estimated in this report constitute all of the proved reserves owned by Vitruvian. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter.

We estimate the net reserves and future net revenue to the Vitruvian interest in these properties, as of December 31, 2013, to be:

 

     Net Reserves      Future Net Revenue (M$)  

Category

   Oil
(MBBL)
     NGL
(MBBL)
     Gas
(MMCF)
     Total      Present Worth
at 10%
 

Proved Developed Producing

     900.6         1,934.6         36,288.0         206,740.3         112,494.1   

Proved Developed Non-Producing (1)

     0.0         0.0         0.0         0.0         0.0   

Proved Undeveloped

     364.0         919.6         23,361.2         81,372.7         22,142.6   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     1,264.6         2,854.2         59,649.1         288,113.0         134,636.6   

Totals may not add because of rounding.

 

(1)   There are no proved developed non-producing reserves at the price and cost parameters used in this report.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The estimates shown in this report are for proved reserves. No study was made to determine whether probable or possible reserves might be established for these properties. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

As shown in the Table of Contents, this report includes summary projections of reserves and revenue by reserves category. Also included are reserves and economics data for each reserves category; these data include a summary projection of reserves and revenue along with one-line summaries of basic data, reserves, and economics by lease.

 

 

4500 T HANKSGIVING T OWER • 1601 E LM S TREET • D ALLAS , T EXAS 75201-4754 • P H : 214-969-5401 • F AX : 214-969-5411   nsai@nsai-petro.com
1221 L AMAR S TREET , S UITE 1200 • H OUSTON , T EXAS 77010-3072 • P H : 713-654-4950 • F AX : 713-654-4951   netherlandsewell.com


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Gross revenue shown in this report is Vitruvian’s share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for Vitruvian’s share of production taxes, capital costs, and operating expenses but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of the properties.

Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2013. For oil and NGL volumes, the average West Texas Intermediate posted price of $93.42 per barrel is adjusted by lease for quality and regional price differentials. For gas volumes, the average Henry Hub spot price of $3.670 per MMBTU is adjusted by lease for energy content, regional price differentials, and plant fees. When applicable, gas prices have been adjusted to include the value for natural gas liquids. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production production over the remaining lives of the properties are $93.62 per barrel of oil, $34.68 per barrel of NGL, and $3.811 per MCF of gas.

Operating costs used in this report are based on operating expense records of Vitruvian. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Headquarters general and administrative overhead expenses of Vitruvian are included to the extent that they are covered under joint operating agreements for the operated properties. Operating costs are not escalated for inflation.

Capital costs used in this report were provided by Vitruvian and are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Capital costs are not escalated for inflation. As requested, our estimates do not include any salvage value for the lease and well equipment or the cost of abandoning the properties.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.

We have made no investigation of potential volume and value imbalances resulting from overdelivery or underdelivery to the Vitruvian interest. Therefore, our estimates of reserves and future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on Vitruvian receiving its net revenue interest share of estimated future gross production.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be commercially recoverable; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.


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For the purposes of this report, we used technical and economic data including, but not limited to, well test data, production data, historical price and cost information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

The data used in our estimates were obtained from Vitruvian, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the titles to the properties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

 

Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
By:   /s/ C.H. (Scott) Rees III
  C.H. (Scott) Rees III, P.E.
  Chairman and Chief Executive Officer
By:   /s/ Richard B. Talley, Jr.
  Richard B. Talley, Jr., P.E. 102425
  Vice President
Date Signed: February 3, 2014

WKB:ALA

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas, and (3) the SEC’s Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir . Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

 

  (i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

 

  (ii) Same environment of deposition;

 

  (iii) Similar geological structure; and

 

  (iv) Same drive mechanism.

Instruction to paragraph (a)(2) : Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen . Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate . Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate . The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves . Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

 

  (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

 

  (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves – Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves – Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

 

  (i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

 

  (ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

 

Definitions - Page 1 of 6


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

  (iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

 

  (iv) Provide improved recovery systems.

(8) Development project . A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

(9) Development well . A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

(10) Economically producible . The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

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

(12) Exploration costs . Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

 

  (i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or “G&G” costs.

 

  (ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

 

  (iii) Dry hole contributions and bottom hole contributions.

 

  (iv) Costs of drilling and equipping exploratory wells.

 

  (v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well . An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well . An extension well is a well drilled to extend the limits of a known reservoir.

(15) Field . An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities .

 

  (i) Oil and gas producing activities include:

 

  (A) The search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations;

 

  (B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

 

  (C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

 

  (1) Lifting the oil and gas to the surface; and

 

  (2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

 

  (D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

 

Definitions - Page 2 of 6


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

Instruction 1 to paragraph (a)(16)(i) : The oil and gas production function shall be regarded as ending at a “terminal point”, which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

 

  a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

 

  b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

 

  (ii) Oil and gas producing activities do not include:

 

  (A) Transporting, refining, or marketing oil and gas;

 

  (B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

 

  (C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

 

  (D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

 

  (i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

 

  (ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

 

  (iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

 

  (iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

 

  (v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

 

  (vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

 

  (i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

 

Definitions - Page 3 of 6


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

  (ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

 

  (iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

 

  (iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs .

 

  (i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

 

  (A) Costs of labor to operate the wells and related equipment and facilities.

 

  (B) Repairs and maintenance.

 

  (C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

 

  (D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

 

  (E) Severance taxes.

 

  (ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

  (i) The area of the reservoir considered as proved includes:

 

  (A) The area identified by drilling and limited by fluid contacts, if any, and

 

  (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

 

  (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

 

  (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

 

  (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

 

  (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

 

  (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

 

  (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

 

Definitions - Page 4 of 6


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26) : Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity’s interests in both of the following shall be disclosed as of the end of the year:

 

  a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

 

  b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

 

  a. Future cash inflows. These shall be computed by applying prices used in estimating the entity’s proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

 

  b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

 

  c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity’s proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity’s proved oil and gas reserves.

 

  d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

 

Definitions - Page 5 of 6


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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

 

  e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

 

  f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

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

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as “exploratory type” if not drilled in a known area or “development type” if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

 

  (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

 

  (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC’s Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects — such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

 

    The company’s level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

 

    The company’s historical record at completing development of comparable long-term projects;

 

    The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

 

    The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

 

    The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

 

  (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

 

Definitions - Page 6 of 6

Exhibit 99.9

 

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WORLDWIDE PETROLEUM CONSULTANTS

     C HAIRMAN  & CEO
  E XECUTIVE C OMMITTEE   

  C.H. (S COTT ) R EES  III

  R OBERT C. B ARG   M IKE K. N ORTON   

P RESIDENT  & COO

  P. S COTT F ROST   D AN P AUL S MITH   

D ANNY D. S IMMONS

  J OHN G. H ATTNER       J OSEPH  J. S PELLMAN   

E XECUTIVE VP

ENGINEERING • GEOLOGY • GEOPHYSICS • PETROPHYSICS   J. C ARTER  H ENSON , J R .   D ANIEL  T. W ALKER    G. L ANCE B INDER

 

 

November 11, 2016

Mr. Richard F. Lane

Vitruvian II Woodford, LLC

4 Waterway Square Place, Suite 400

The Woodlands, Texas 77380

Dear Mr. Lane:

In accordance with your request, we have audited the estimates prepared by Vitruvian II Woodford, LLC (Vitruvian), as of September 30, 2016, of the proved reserves and future revenue to the Vitruvian interest in certain oil and gas properties located in Oklahoma. It is our understanding that the proved reserves estimated herein constitute all of the proved reserves owned by Vitruvian. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with the definitions and regulations of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. We completed our audit on or about the date of this letter. This report has been prepared for Vitruvian’s use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth Vitruvian’s estimates of the net reserves and future net revenue, as of September 30, 2016, for the audited properties:

 

     Net Reserves      Future Net Revenue (M$)  

Category

   Oil
(MBBL)
     NGL
(MBBL)
     Gas
(MMCF)
     Total      Present Worth
at 10%
 

Proved Developed Producing

     6,000.85         11,251.00         218,853.72         502,030.41         302,112.30   

Proved Developed Non-Producing

     14.61         168.48         3,193.05         3,250.51         2,209.07   

Proved Undeveloped

     14,913.61         27,295.21         564,416.08         621,520.03         73,521.20   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Proved

     20,929.07         38,714.69         786,462.85         1,126,800.95         377,842.56   

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on a lease-by-lease basis, some of the estimates of Vitruvian are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. (NSAI). However, in our opinion the estimates shown herein of Vitruvian’s reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by Vitruvian in preparing the September 30, 2016, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Vitruvian.

 

 

2100 R OSS A VENUE , S UITE 2200 • D ALLAS , T EXAS 75201 • P H : 214-969-5401 • F AX : 214-969-5411

  info@nsai-petro.com
1301 M CKINNEY S TREET , S UITE 3200 • H OUSTON , T EXAS 77010 • P H : 713-654-4950 • F AX : 713-654-4951   netherlandsewell.com


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The estimates shown herein are for proved reserves. Vitruvian’s estimates do not include probable or possible reserves that may exist for these properties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

Prices used by Vitruvian are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period October 2015 through September 2016. For oil and NGL volumes, the average West Texas Intermediate spot price of $41.68 per barrel is adjusted by lease for quality and market differentials. For gas volumes, the average Henry Hub spot price of $2.283 per MMBTU is adjusted by lease for energy content, market differentials, and plant fees. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $36.83 per barrel of oil, $13.68 per barrel of NGL, and $2.28 per MCF of gas.

Operating costs used by Vitruvian are based on historical operating expense records. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-production costs. Headquarters general and administrative overhead expenses of Vitruvian are included to the extent that they are covered under joint operating agreements for the operated properties. Capital costs used by Vitruvian are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Abandonment costs used are Vitruvian’s estimates of the costs to abandon the wells and production facilities, net of any salvage value. Operating costs, capital, and abandonment costs are not escalated for inflation.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of Vitruvian and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Vitruvian, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of major properties making up approximately 62 percent of the total proved reserves and accounting for approximately 92 percent of the present worth for those reserves. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Vitruvian with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our audit did not include a review of Vitruvian’s overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis and analogy, that we considered to be appropriate and necessary to establish the conclusions set forth


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herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

Supporting data documenting this audit, along with data provided by Vitruvian, are on file in our office. The technical persons primarily responsible for conducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Richard B. Talley, Jr., a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2004 and has over 5 years of prior industry experience. Mike K. Norton, a Licensed Professional Geoscientist, has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

 

    Sincerely,
    NETHERLAND, SEWELL & ASSOCIATES, INC.
    Texas Registered Engineering Firm F-2699
    By:   /s/ C.H. (Scott) Rees III
      C.H. (Scott) Rees III, P.E.
      Chairman and Chief Executive Officer
By:   /s/ Richard B. Talley, Jr   By:   /s/ Mike K. Norton
  Richard B. Talley, Jr., P.E. 102425     Mike K. Norton, P.G. 441
  Senior Vice President     Senior Vice President
Date Signed: November 11, 2016   Date Signed: November 11, 2016

WKB:ALA

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.