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UNITED STATES

SECURITIES AND EXCHANGE COMMISSIONWASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

☒☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2017

or

☐☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-36006

Jones Energy, Inc.(Exact name of registrant as specified in its charter)

Delaware 1311 80-0907968(State or other Jurisdiction of (Primary Standard Industrial (IRS EmployerIncorporation or Organization) Classification Code Number) Identification Number)

807 Las Cimas Parkway, Suite 350 Austin, Texas 78746

(512) 328-2953 (Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)

Robert J. Brooks807 Las Cimas Parkway, Suite 350

Austin, Texas 78746 (512) 328-2953

(Address, including zip code, and telephone number, including area code, of Agent for service)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 duringthe preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for thepast 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to besubmitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrantwas required to submit and post such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerginggrowth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 ofthe Exchange Act. (Check one):

Large accelerated filer ☐ Accelerated filer ☒

Non-accelerated filer ☐ Smaller reporting company ☐(Do not check if a smaller reporting company)

Emerging growth company ☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new orrevised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☒ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

On July 28, 2017, the Registrant had 72,754,205 shares of Class A common stock outstanding and 23,718,779 shares of Class B common stock outstanding.

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JONES ENERGY, INC.TABLE OF CONTENTS

PART 1—FINANCIAL INFORMATION 1 Item 1. Financial Statements 1 Unaudited Consolidated Financial Statements 1 Balance Sheets 1 Statements of Operations 2 Statement of Changes in Stockholders’ Equity 3 Statements of Cash Flows 4 Notes to the Consolidated Financial Statements 5 Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 40 Item 3. Quantitative and Qualitative Disclosures About Market Risk 50 Item 4. Controls and Procedures 52

PART II—OTHER INFORMATION 53 Item 1. Legal Proceedings 53 Item 1A. Risk Factors 53 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 53 Item 3. Defaults upon Senior Securities 53 Item 4. Mine Safety Disclosures 53 Item 5. Other Information 53 Item 6. Exhibits 53

SIGNATURES 54

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E ofthe Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this report that addressactivities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this report specificallyinclude the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, ourexpectations regarding our ability to drill the recently acquired acreage in the Merge, our potential decrease in capital spending ifprofitability or cash flows are lower than anticipated, our ability to mitigate commodity price risk through our hedging program, ourability to maintain compliance with our debt covenants, JEH’s obligations to pay cash distributions, expectations regarding litigation,our belief that we will be able to identify and prioritize projects with the greatest expected returns, and our ability to successfullyexecute our 2017 development plan. These statements are based on certain assumptions made by the Company based onmanagement’s experience and perception of historical trends, current conditions, anticipated future developments and other factorsbelieved to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyondthe control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include, but are not limited to, changes in prices for oil, natural gas liquids, and natural gas prices, weather,including its impact on oil and natural gas demand and weather-related delays on operations, the amount, nature and timing of plannedcapital expenditures, availability and method of funding acquisitions, uncertainties in estimating proved reserves and forecastingproduction results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capitalmarkets generally, as well as our ability to access them, customers’ elections to reject ethane and include it as part of the natural gasstream, ability to fund our 2017 capital expenditure budget, the proximity to and capacity of transportation facilities, and uncertaintiesregarding environmental regulations or litigation and other legal or regulatory developments affecting the Company’s business andother important factors that could cause actual results to differ materially from those projected as described in the Company’s reportsfiled with the SEC. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes noobligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise,except as required by applicable law.

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PART 1—FINANCIAL INFORMATIO NItem 1. Financial Statement s

Jones Energy, Inc.Consolidated Balance Sheet s (Unaudited)

June 30, December 31, (in thousands of dollars) 2017 2016 Assets Current assets Cash $ 6,254 $ 34,642 Accounts receivable, net Oil and gas sales 24,557 26,568 Joint interest owners 9,032 5,267 Other 7,205 6,061

Commodity derivative assets 39,823 24,100 Other current assets 11,381 2,684 Assets held for sale 3,455 —

Total current assets 101,707 99,322 Assets held for sale, net 64,200 — Oil and gas properties, net, at cost under the successful efforts method 1,545,991 1,743,588 Other property, plant and equipment, net 2,812 2,996 Commodity derivative assets 5,914 34,744 Other assets 5,395 6,050

Total assets $ 1,726,019 $ 1,886,700 Liabilities and Stockholders' Equity Current liabilities Trade accounts payable $ 56,053 $ 36,527 Oil and gas sales payable 22,301 28,339 Accrued liabilities 19,571 25,707 Commodity derivative liabilities 3,036 14,650 Other current liabilities 8,099 2,584 Liabilities related to assets held for sale 7,472 —

Total current liabilities 116,532 107,807 Liabilities related to assets held for sale 1,143 — Long-term debt 728,163 724,009 Deferred revenue 6,106 7,049 Commodity derivative liabilities 123 1,209 Asset retirement obligations 19,061 19,458 Liability under tax receivable agreement 11,807 43,045 Other liabilities 902 792 Deferred tax liabilities 2,911 2,905

Total liabilities 886,748 906,274 Commitments and contingencies (Note 14) Mezzanine equity Series A preferred stock, $0.001 par value; 1,840,000 shares issued and outstanding at June 30, 2017 and December 31, 2016 89,288 88,975

Stockholders' equity Class A common stock, $0.001 par value; 66,671,659 shares issued and 66,649,057 shares outstanding at June 30, 2017 and57,048,076 shares issued and 57,025,474 shares outstanding at December 31, 2016

67 57

Class B common stock, $0.001 par value; 29,823,927 shares issued and outstanding at June 30, 2017 and 29,832,098 shares issuedand outstanding at December 31, 2016

30 30

Treasury stock, at cost: 22,602 shares at June 30, 2017 and December 31, 2016 (358) (358) Additional paid-in-capital 477,390 447,137 Retained (deficit) / earnings (121,477) (8,652)

Stockholders' equity 355,652 438,214 Non-controlling interest 394,331 453,237 Total stockholders’ equity 749,983 891,451

Total liabilities and stockholders' equity $ 1,726,019 $ 1,886,700

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

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Jones Energy, Inc.Consolidated Statements of Operation s (Unaudited)

Three months ended June 30, Six months ended June 30, (in thousands of dollars except per share data) 2017 2016 2017 2016 Operating revenues Oil and gas sales $ 48,114 $ 28,398 $ 88,791 $ 53,478 Other revenues 512 746 1,068 1,524 Total operating revenues 48,626 29,144 89,859 55,002 Operating costs and expenses Lease operating 9,425 7,545 18,231 16,162 Production and ad valorem taxes 2,790 1,727 1,884 3,328 Exploration 6,725 77 9,669 239 Depletion, depreciation and amortization 45,336 38,137 80,990 79,899 Impairment of oil and gas properties 161,886 — 161,886 — Accretion of ARO liability 266 297 467 590 General and administrative 8,633 8,126 16,674 15,630 Total operating expenses 235,061 55,909 289,801 115,848 Operating income (loss) (186,435) (26,765) (199,942) (60,846) Other income (expense) Interest expense (12,677) (12,807) (25,564) (27,605) Gain on debt extinguishment — 8,878 — 99,530 Net gain (loss) on commodity derivatives 21,527 (40,002) 43,847 (22,783) Other income (expense) 29,834 (338) 30,414 (113) Other income (expense), net 38,684 (44,269) 48,697 49,029 Income (loss) before income tax (147,751) (71,034) (151,245) (11,817) Income tax provision (benefit) (2,419) (12,388) (2,398) (1,685) Net income (loss) (145,332) (58,646) (148,847) (10,132) Net income (loss) attributable to non-controlling interests (56,093) (35,401) (58,221) (5,798) Net income (loss) attributable to controlling interests $ (89,239) $ (23,245) $ (90,626) $ (4,334) Dividends and accretion on preferred stock (1,966) — (3,993) — Net income (loss) attributable to common shareholders $ (91,205) $ (23,245) $ (94,619) $ (4,334) Earnings (loss) per share (1) : Basic - Net income (loss) attributable to common shareholders $ (1.39) $ (0.69) $ (1.48) $ (0.13) Diluted - Net income (loss) attributable to common shareholders $ (1.39) $ (0.69) $ (1.48) $ (0.13) Weighted average Class A shares outstanding (1) : Basic 65,681 33,598 63,948 33,410 Diluted 65,681 33,598 63,948 33,410

(1) All share and earnings per share information presented has been recast to retrospectively adjust for the effects of the 0.087423 per share SpecialStock Dividend, as defined in Note 11, “Stockholders’ and Mezzanine equity”, distributed on March 31, 2017.


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Jones Energy, Inc.Statement of Changes in Stockholders’ Equit y (Unaudited)

Common Stock Treasury Stock Additional Retained Total Class A Class B Class A Paid-in- (Deficit)/

Non-controlling Stockholders'

(amounts in thousands) Shares Value Shares Value Shares Value Capital Earnings Interest Equity Balance at December 31, 2016 57,025 $ 57 29,832 $ 30 23 $ (358) $ 447,137 $ (8,652) $ 453,237 $ 891,451 Cumulative effect of adoption of ASU2016-09 — — — — — — 706 (706) — — Stock-compensation expense 756 1 — — — — 3,273 — — 3,274 Cash tax distribution — — — — — — — — (562) (562) Sale of common stock 3,716 4 — — — — 8,348 — — 8,352 Stock dividends on common stock 5,000 5 — — — — 17,495 (17,500) — — Exchange of Class B shares for Class Ashares 8 — (8) — — — 118 — (123) (5) Dividends and accretion on preferredstock 144 — — — — — 313 (3,993) — (3,680) Net income (loss) — — — — — — — (90,626) (58,221) (148,847) Balance at June 30, 2017 66,649 $ 67 29,824 $ 30 23 $ (358) $ 477,390 $ (121,477) $ 394,331 $ 749,983


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Jones Energy, Inc.Consolidated Statements of Cash Flow s (Unaudited)

Six months ended June 30, (in thousands of dollars) 2017 2016 Cash flows from operating activities Net income (loss) $ (148,847) $ (10,132) Adjustments to reconcile net income (loss) to net cash provided by operating activities Depletion, depreciation, and amortization 80,990 79,899 Exploration (dry hole and lease abandonment) 6,880 27 Impairment of oil and gas properties 161,886 — Accretion of ARO liability 467 590 Amortization of debt issuance costs 1,953 2,107 Stock compensation expense 3,736 3,084 Deferred and other non-cash compensation expense 180 401 Amortization of deferred revenue (942) (1,241) (Gain) loss on commodity derivatives (43,847) 22,783 (Gain) loss on sales of assets 119 1 (Gain) on debt extinguishment — (99,530) Deferred income tax provision 6 (3,291) Change in liability under tax receivable agreement (30,599) (162) Other - net 1,307 1,111 Changes in operating assets and liabilities Accounts receivable (4,188) 11,353 Other assets (12,590) (482) Accrued interest expense (1,301) (4,201) Accounts payable and accrued liabilities 6,268 3,683 Net cash provided by operations 21,478 6,000

Cash flows from investing activities Additions to oil and gas properties (107,250) (27,592) Net adjustments to purchase price of properties acquired 2,391 — Proceeds from sales of assets 2,730 5 Acquisition of other property, plant and equipment (436) 12 Current period settlements of matured derivative contracts 45,738 77,622

Net cash (used in) / provided by investing (56,827) 50,047 Cash flows from financing activities Proceeds from issuance of long-term debt 75,000 75,000 Repayment of long-term debt (72,000) — Purchase of senior notes — (84,589) Payment of cash dividends on preferred stock (3,367) — Net distributions paid to JEH unitholders (562) (10,109) Net payments for share based compensation (462) — Proceeds from sale of common stock 8,352 1,056

Net cash provided by / (used in) financing 6,961 (18,642) Net increase (decrease) in cash (28,388) 37,405

Cash Beginning of period 34,642 21,893 End of period $ 6,254 $ 59,298 Supplemental disclosure of cash flow information Cash paid for interest $ 24,064 $ 29,700 Change in accrued additions to oil and gas properties 13,155 1,980 Asset retirement obligations incurred, including changes in estimate 395 160


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Jones Energy, Inc.Notes to the Consolidated Financial Statement s (Unaudited) 1. Organization and Description of Business

Organization Jones Energy, Inc. (the “Company”) was formed in March 2013 as a Delaware corporation to become a publicly-traded entityand the holding company of Jones Energy Holdings, LLC (“JEH”). As the sole managing member of JEH, the Company isresponsible for all operational, management and administrative decisions relating to JEH’s business and consolidates thefinancial results of JEH and its subsidiaries. JEH was formed as a Delaware limited liability company on December 16, 2009 through investments made by the Jonesfamily, certain members of management and through private equity funds managed by Metalmark Capital, among others. JEHacts as a holding company of operating subsidiaries that own and operate assets that are used in the exploration, development,production and acquisition of oil and natural gas properties. The Company’s certificate of incorporation authorizes two classes of common stock, Class A common stock and Class Bcommon stock. The Class B common stock is held by the remaining owners of JEH prior to the initial public offering (“IPO”)of the Company (collectively, the “Class B shareholders”) and can be exchanged (together with a corresponding number ofcommon units representing membership interests in JEH (“JEH Units”)) for shares of Class A common stock on a one-for-onebasis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similartransactions. The Class B common stock has no economic rights but entitles its holders to one vote on all matters to be votedon by the Company’s stockholders generally. As of June 30, 2017, the Company held 66,649,057 JEH Units and all of thepreferred units representing membership interests in JEH, and the remaining 29,823,927 JEH Units are held by the Class Bshareholders. The Class B shareholders have no voting rights with respect to their economic interest in JEH, resulting in theCompany reporting this ownership interest as a non-controlling interest. The Company’s certificate of incorporation also authorizes the Board of Directors of the Company to establish one or moreseries of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorizedshares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares ofpreferred stock are subject to authorization by the Board of Directors of the Company and may differ from those of any and allother series at any time outstanding. On August 25, 2016, the Company issued 1,840,000 shares of its 8.0% Series A Perpetual Convertible Preferred Stock, parvalue $0.001 per share (the “Series A preferred stock”), pursuant to a registered public offering at $50 per share. See Note 11,“Stockholders’ and Mezzanine equity”. Description of Business The Company is engaged in the exploration, development, production and acquisition of oil and natural gas properties in themid-continent United States, spanning areas of Texas and Oklahoma. The Company’s assets are located within the EasternAnadarko basin, targeting the liquids rich Woodford shale and Meramec formations in the Merge area of the STACK/SCOOP,and the Western Anadarko basin, targeting the liquids rich Cleveland, Granite Wash, Tonkawa and Marmaton formations, andare owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas.

2. Significant Accounting Policies

Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with accounting principles generallyaccepted in the United States of America (“GAAP”) and in accordance with the rules and regulations of the Securities andExchange Commission. All significant intercompany transactions and balances have been eliminated in consolidation. TheCompany’s financial position as of December 31, 2016 and the

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financial statements reported for June 30, 2017 and 2016 and each of the six-month periods then ended include the Companyand all of its subsidiaries. Certain prior period amounts have been reclassified to conform to the current presentation. The accompanying unaudited condensed consolidated financial statements for the periods ending June 30, 2017 and 2016 havebeen prepared in accordance with GAAP for interim financial information and in accordance with the rules and regulations ofthe Securities and Exchange Commission. Certain information relating to the Company’s organization and footnote disclosuresnormally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted inthis Quarterly Report. The Company believes the disclosures made are adequate to make the information presented notmisleading. The unaudited condensed consolidated financial statements contained in this report include all normal andrecurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position,results of operations and cash flows for the interim periods presented herein. It is recommended that these unaudited condensedconsolidated financial statements should be read in conjunction with our most recent audited consolidated financial statementsincluded in Jones Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2016. Use of Estimates There have been no significant changes in our use of estimates since those reported in Jones Energy, Inc.’s Annual Report onForm 10-K for the year ended December 31, 2016. Production taxes During the first quarter of 2017, the Company's application for High-Cost Gas Incentive refunds in Texas was approved forqualified wells on which taxes were initially paid between October 2012 and September 2016. The Company received a netproduction tax refund of $3.3 million, which was recorded as a reduction in Production and ad valorem taxes on theCompany’s Consolidated Statement of Operations. No further refunds were received during the three months ended June 30,2017. Recent Accounting Pronouncements Adopted in the current year-to-date period: In March 2016, the FASB issued ASU 2016-09, “Compensation—Stock Compensation” (Topic 718). This amendment isintended to simplify the accounting for share-based payment awards to employees, specifically in regard to (1) the income taxconsequences, (2) classification of awards as either equity or liabilities, and (3) classification on the statement of cash flows.The amendments are effective for interim and annual reporting periods beginning after December 15, 2016. Therefore, theCompany has adopted ASU 2016-09 effective as of January 1, 2017. Upon adoption of ASU 2016-09, the Company elected tochange its accounting policy to account for forfeitures as they occur. The change was applied on a modified retrospective basiswith a cumulative effect adjustment to retained earnings for forfeitures of $0.7 million as of January 1, 2017. As a result of thevaluation allowance against the Company’s deferred tax assets, there was no net adjustment to retained earnings for the changein accounting for unrecognized windfall tax benefits. In May 2017, the FASB issued ASU 2017-09, “Scope of Modification Accounting” as it relates to “Compensation—StockCompensation” (Topic 718). This amendment clarifies when changes to the terms or conditions of a share-based paymentaward must be accounted for as modifications. The new guidance is expected to reduce diversity in practice and result in fewerchanges to the terms of an award being accounted for as modifications. Under ASU 2017-09, an entity will not applymodification accounting to a share-based payment award if the award’s fair value, vesting conditions and classification as anequity or liability instrument are the same immediately before and after the change. The amendments are effective for interimand annual reporting periods beginning after December 15, 2017. Early adoption is permitted and the Company chose to earlyadopt ASU 2017-09 beginning April 1, 2017. The change was applied prospectively to awards modified on or after theadoption date. Adoption did not have a material impact on the financial position, cash flows or results of operations.

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To be adopted in a future period: In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which creates a new topic in theAccounting Standards Codification (“ASC”), topic 606, “Revenue from Contracts with Customers.” This ASU sets forth afive-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognizerevenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receivein exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing anduncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, whichdeferred the effective date of ASU 2014-09 by one year. The amendments are now effective for interim and annual reportingperiods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis. Early adoptionis permitted. The Company is in the process of comparing our current revenue recognition policies to the new requirements foreach of our revenue categories based upon review of our current contracts by product category and homogenous groupings.Our evaluation is not yet complete, and we have not concluded on the overall impacts of adopting the new requirements. TheCompany will continue to further evaluate the effect that the adoption of Update 2014-09 and Update 2015-14 will have on ourfinancial statements and our anticipated method of adoption. We anticipate adoption of Update 2014-09 and Update 2015-14effective as of January 1, 2018. In February 2016, the FASB issued ASU 2016-02, “Leases” (Topic 842). This amendment requires, among other things, thatlessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a leaseliability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) aright-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the leaseterm. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after,the beginning of the earliest comparative period presented in the financial statements. The amendments are effective forinterim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts ofthe amendments to our financial statements and accounting practices for leases. We anticipate adoption of ASU 2016-02effective as of January 1, 2019.

3. Acquisitions and Divestitures

During the six months ended June 30, 2017 and the year ended December 31, 2016, the Company entered into several purchaseand sale agreements, as described below. Merge Acquisition On September 22, 2016, JEH acquired oil and gas properties located in the Merge area of the STACK/SCOOP (the “Merge”)play in Central Oklahoma (the “Merge Acquisition”) from SCOOP Energy Company, LLC for cash consideration of $134.4million, net of the final working capital settlement of $2.4 million received in the first quarter of 2017. The oil and gasproperties acquired in the Merge Acquisition, on a closed and funded basis, principally consist of 16,975 undeveloped net acresin Canadian, Grady and McClain Counties, Oklahoma. This transaction has been accounted for as an asset acquisition. TheCompany used proceeds from our equity offerings to fund a portion of the purchase. See Note 11, “Stockholders’ andMezzanine equity”.

Anadarko Acquisition On August 25, 2016, JEH acquired producing and undeveloped oil and gas assets in the Western Anadarko basin (the“Anadarko Acquisition”) for final consideration of $25.9 million. This transaction was accounted for as a businesscombination. The Company allocated $32.3 million to “Oil and gas properties,” with $3.0 million allocated to “Unproved”properties, $17.0 million allocated to “Proved” properties, and $12.3 million allocated to “Wells and equipment and relatedfacilities”, based on the respective fair values of the assets acquired. Additionally, the Company allocated $6.4 million to ourARO liability associated with those proved properties. As of June 30, 2017, the measurement-period has closed. The AnadarkoAcquisition did not result in a significant impact to revenues or net income and as such, pro forma financial information is notincluded. The Company funded the Anadarko Acquisition with cash on hand.

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The assets acquired in the Anadarko Acquisition included interests in 174 wells, 59% of which were operated by the company,and approximately 25,000 net acres in Lipscomb and Ochiltree Counties in the Texas Panhandle. As of the closing date, theacquired acreage was producing approximately 900 barrels of oil equivalent per day. Arkoma Divestiture On August 1, 2017, JEH closed its previously announced agreement to sell its Arkoma Basin properties (the “Arkoma Assets”)for a purchase price of $65.0 million, subject to customary adjustments (the “Arkoma Divestiture”). JEH may also receive upto $2.5 million in contingent payments based on natural gas prices. No amounts have been recorded related to this contingentpayment as of June 30, 2017. The Company received a deposit of $4.9 million associated with the pending sale which has beenincluded in Other current liabilities on the Company’s Consolidated Balance Sheet as of June 30, 2017. See Note 15,“Subsequent Events - Arkoma Divestiture”. Assets held for sale As of June 30, 2017, the Arkoma Assets and related liabilities (the “Held for sale assets”) were classified as held for sale due tothe pending Arkoma Divestiture. Upon the classification change occurring on June 30, 2017, the Company ceased recordingdepletion on the Held for sale assets. Based on the Company’s anticipated sales price, the Company has recognized animpairment charge of $161.9 million at June 30, 2017 which has been included in Impairment of oil and gas properties on theCompany’s Consolidated Statement of Operations.

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The following table presents balance sheet data related to the Held for sale assets:

June 30, (in thousands of dollars) 2017 Assets:

Accounts receivable, net Oil and gas sales $ 3,250 Joint interest owners 102 Other 14 Other current assets 4 Leasehold improvements 27 Other 68 Less: Accumulated depreciation and amortization (10) Other property, plant and equipment, net 85

Total current assets held for sale 3,455

Mineral interests in properties Unproved 12,204 Proved 216,570 Wells and equipment and related facilities 179,925 Less: Accumulated depletion and impairment (344,499) Oil and gas properties, net 64,200

Total assets held for sale, net $ 67,655

Liabilities:

Trade accounts payable $ 379 Oil and gas sales payable, 6,015 Accrued liabilities 1,078 Total current liabilities related to assets held for sale 7,472

Asset retirement obligations 1,143 Total liabilities related to assets held for sale $ 8,615

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4. Properties, Plant and Equipment Oil and Gas Properties The Company accounts for its oil and natural gas exploration and production activities under the successful efforts method ofaccounting. Oil and gas properties consisted of the following at June 30, 2017 and December 31, 2016:

June 30, December 31, (in thousands of dollars) 2017 2016 Mineral interests in properties

Unproved $ 180,018 $ 213,153 Proved 879,149 1,054,683

Wells and equipment and related facilities 1,311,087 1,395,291 2,370,254 2,663,127 Less: Accumulated depletion and impairment (824,263) (919,539)

Net oil and gas properties $ 1,545,991 $ 1,743,588

There were no exploratory wells drilled during the six months ended June 30, 2017 or 2016. As such, no associated costs werecapitalized and no exploratory wells resulted in exploration expense during either period. The Company capitalizes interest on expenditures for significant exploration and development projects that last more than sixmonths while activities are in progress to bring the assets to their intended use. During the six months ended June 30, 2017, theCompany capitalized $0.2 million associated with such in progress projects. The Company did not capitalize any interestduring the six months ended June 30, 2016 as no projects lasted more than six months. Costs incurred to maintain wells andrelated equipment are charged to expense as incurred. Depletion of oil and gas properties amounted to $45.1 million and $80.5 million for the three and six months ended June 30,2017, respectively, and $37.8 million and $79.3 million for the three and six months ended June 30, 2016, respectively. The Company continues to monitor its proved and unproved properties for impairment. No impairments of proved or unprovedproperties were recorded as a result of our standard impairment assessment during the six months ended June 30, 2017 or2016. However, as noted in Note 3, “Acquisitions and Divestitures - Assets held for sale,” the Company has recognized animpairment charge of $161.9 million at June 30, 2017 based on the anticipated sales price of our Held for sale assets. Other Property, Plant and Equipment Other property, plant and equipment consisted of the following at June 30, 2017 and December 31, 2016:

June 30, December 31, (in thousands of dollars) 2017 2016 Leasehold improvements $ 1,186 $ 1,213 Furniture, fixtures, computers and software 4,378 4,170 Vehicles 1,768 1,677 Aircraft 910 910 Other 215 284 8,457 8,254 Less: Accumulated depreciation and amortization (5,645) (5,258)

Net other property, plant and equipment $ 2,812 $ 2,996

Depreciation and amortization of other property, plant and equipment amounted to $0.2 million and $0.5 million for the threeand six months ended June 30, 2017, respectively, and $0.3 million and $0.6 million for the three and six months ended June30, 2016, respectively.

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5. Long-Term Debt Long-term debt consisted of the following at June 30, 2017 and December 31, 2016:

(in thousands of dollars) June 30, 2017 December 31, 2016 Revolver $ 181,000 $ 178,000 2022 Notes 409,148 409,148 2023 Notes 150,000 150,000 Total principal amount 740,148 737,148

Less: unamortized discount (5,735) (6,240) Less: debt issuance costs, net (6,250) (6,899)

Total carrying amount $ 728,163 $ 724,009 Senior Unsecured Notes On April 1, 2014, JEH and Jones Energy Finance Corp., JEH’s wholly owned subsidiary formed for the sole purpose of co-issuing certain of JEH’s debt (collectively, the “Issuers”), sold $500.0 million in aggregate principal amount of the Issuers’6.75% senior notes due 2022 (the “2022 Notes”). The Company used the net proceeds from the issuance of the 2022 Notes torepay all outstanding borrowings under the Term Loan (as defined below) ($160.0 million), a portion of the outstandingborrowings under the Revolver (as defined below) ($308.0 million) and for working capital and general corporate purposes.The Company subsequently terminated the Term Loan in accordance with its terms. The 2022 Notes bear interest at a rate of6.75% per year, payable semi-annually on April 1 and October 1 of each year beginning October 1, 2014. The 2022 Noteswere registered in March 2015.

On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of 9.25% senior notes due 2023 (the“2023 Notes”) in a private placement to affiliates of GSO Capital Partners LP and Magnetar Capital LLC. The 2023 Noteswere issued at a discounted price equal to 94.59% of the principal amount. The Company used the $236.5 million net proceedsfrom the issuance of the 2023 Notes to repay outstanding borrowings under the Revolver and for working capital and generalcorporate purposes. The 2023 Notes bear interest at a rate of 9.25% per year, payable semi-annually on March 15 andSeptember 15 of each year beginning September 15, 2015. The 2023 Notes were registered in February 2016.

During 2016, the Company purchased an aggregate principal amount of $190.9 million of its senior unsecured notes throughseveral open market and privately negotiated purchases. The Company purchased $90.9 million principal amount of its 2022Notes for $38.1 million, and $100.0 million principal amount of its 2023 Notes for $46.5 million, in each case excludingaccrued interest and including any associated fees. The Company used cash on hand and borrowings from its Revolver to fundthe note purchases. In conjunction with the extinguishment of this debt, JEH recognized cancellation of debt income of $99.5million for the twelve months ended December 31, 2016, on a pre-tax basis. This income is recorded in Gain on debtextinguishment on the Company’s Consolidated Statement of Operations. Of the Company’s total repurchases, $20.3 millionprincipal amount of its 2022 Notes were not cancelled and are available for future reissuance, subject to applicable securitieslaws. The 2022 Notes and 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of its significantsubsidiaries. The 2022 Notes and 2023 Notes will be senior in right of payment to any future subordinated indebtedness of theIssuers. The Company may redeem the 2022 Notes at any time on or after April 1, 2017 and the 2023 Notes at any time on or afterMarch 15, 2018 at a declining redemption price set forth in the respective indentures, plus accrued and unpaid interest. The indentures governing the 2022 Notes and 2023 Notes are substantially identical and contain covenants that, among otherthings, limit the ability of the Company to incur additional indebtedness or issue certain preferred stock, pay dividends oncapital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or otherpayments from the Company’s restricted subsidiaries to the Company, consolidate, merge or transfer all of the Company’sassets, engage in transactions with affiliates or create unrestricted subsidiaries. If at any time when the 2022 Notes or 2023Notes are rated investment grade and no

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default or event of default (as defined in the indenture) has occurred and is continuing, many of the foregoing covenantspertaining to the 2022 Notes or 2023 Notes, as applicable, will be suspended. If the ratings on the 2022 Notes or 2023 Notes,as applicable, were to decline subsequently to below investment grade, the suspended covenants would be reinstated. As of June 30, 2017, the Company was in compliance with the indentures governing the 2022 Notes and 2023 Notes. Other Long-Term Debt

The Company entered into two credit agreements dated December 31, 2009, with Wells Fargo Bank N.A, the Senior SecuredRevolving Credit Facility (the “Revolver”) and the Second Lien Term Loan (the “Term Loan”). On April 1, 2014, the TermLoan was repaid in full and terminated in connection with the issuance of the 2022 Notes. On November 6, 2014, the Companyamended the Revolver to, among other things, extend the maturity date of the Revolver to November 6, 2019. The Company’soil and gas properties are pledged as collateral to secure its obligations under the Revolver. On August 1, 2016, the Company entered into an amendment to the Revolver to, among other things (i) require that theCompany's deposit accounts and securities accounts (subject to certain exclusions) become subject to control agreements, (ii)restrict the Company from borrowing or receiving Letters of Credit under the Revolver if the Company has, or, after givingeffect to such borrowing or issuance of Letter of Credit, will have, a Consolidated Cash Balance (as defined in the Revolver) inexcess of $30.0 million (in each case giving effect to the anticipated use of proceeds thereof) and (iii) set the borrowing baseunder the Revolver at $425.0 million. The borrowing base was reaffirmed at this level during the most recent semi-annualborrowing base re-determination effective May 15, 2017. On August 1, 2017, upon closing of the Arkoma Divestiture, theCompany’s borrowing base was reduced to $375.0 million. See Note 15, “Subsequent Events”. The terms of the Revolver require the Company to make periodic payments of interest on the loans outstanding thereunder,with all outstanding principal and interest under the Revolver due on the maturity date. The Revolver is subject to a borrowingbase, which limits the amount of borrowings which may be drawn thereunder. The borrowing base will be re-determined bythe lenders at least semi-annually on or about April 1 and October 1 of each year, with such re-determination based primarilyon reserve reports using lender commodity price expectations at such time. Any reduction in the borrowing base will reduceour liquidity, and, if the reduction results in the outstanding amount under our revolving credit facility exceeding theborrowing base, we will be required to repay the deficiency within a short period of time. Interest on the Revolver is calculated, at the Company’s option, at either (a) the London Interbank Offered (“LIBO”) rate forthe applicable interest period plus a margin of 1.50% to 2.50% based on the level of borrowing base utilization at such time or(b) the greatest of the federal funds rate plus 0.50%, the one month adjusted LIBO rate plus 1.00%, or the prime rateannounced by Wells Fargo Bank, N.A. in effect on such day, in each case plus a margin of 0.50% to 1.50% based on the levelof borrowing base utilization at such time. For the three and six months ended June 30, 2017, the average interest rates underthe Revolver were 2.84% and 2.72%, respectively, on average outstanding balances of $194.6 million and $194.9 million,respectively. For the three and six months ended June 30, 2016, the average interest rates under the Revolver were 2.25% and2.43%, respectively, on average outstanding balances of $185.0 million and $164.0 million, respectively. Total interest and commitment fees under the Revolver were $1.6 million and $3.1 million for the three and six months endedJune 30, 2017, respectively, and $1.3 million and $2.6 million for the three and six months ended June 30, 2016, respectively. Jones Energy, Inc. and its consolidated subsidiaries are subject to certain covenants under the Revolver, including therequirement to maintain the following financial ratios:

· a total leverage ratio, consisting of consolidated debt to EBITDAX, of not greater than 4.0 to 1.00x as of the last dayof any fiscal quarter; and

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· a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, toconsolidated current liabilities, of not less than 1.00 to 1.00x as of the last day of any fiscal quarter.

As of June 30, 2017, our total leverage ratio was 3.84x and our current ratio was 2.70x, as calculated based on the requirementsin our covenants. We were in compliance with all terms of our Revolver at June 30, 2017, and we expect to maintaincompliance throughout the next twelve-month period. However, factors including those outside of our control, such ascommodity price declines, may prevent us from maintaining compliance with these covenants, at future measurement dates in2017 and beyond. In the event it were to become necessary, we believe we have the ability to take actions that would preventus from failing to comply with our covenants, such as hedge restructuring or seeking a waiver of such covenants. If an event ofdefault exists under the Revolver, the lenders would be able to accelerate the obligations outstanding under the Revolver andexercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change ofcontrol, as defined in the Revolver.

6. Derivative Instruments and Hedging Activities The Company uses derivative instruments to mitigate volatility in commodity prices. While the use of these instruments limitsthe downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. Dependingon changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increaseor decrease our hedging positions. The following tables summarize our hedging positions as of June 30, 2017: Hedging Positions

June 30, 2017 Weighted Final Low High Average Expiration Oil swaps Exercise price $ 44.60 $ 85.60 $ 56.75 December 2020 Offset exercise price $ 42.00 $ 47.65 $ 46.43 Net barrels per month 20,000 181,000 76,762 Natural gas swaps Exercise price $ 2.76 $ 4.57 $ 3.18 December 2020 Offset exercise price $ 2.80 $ 2.92 $ 2.81 Net mmbtu per month 300,000 1,890,000 1,093,095 Natural gas liquids swaps Exercise price $ 18.06 $ 72.52 $ 28.61 December 2018 Barrels per month 130,000 145,000 140,000 Oil collars Puts (floors) $ 45.00 $ 50.00 $ 48.52 September 2019 Calls (ceilings) $ 56.60 $ 61.00 $ 59.64 Net barrels per month 65,000 73,000 67,500 Natural gas collars Puts (floors) $ 2.55 $ 2.55 $ 2.55 December 2019 Calls (ceilings) $ 3.08 $ 3.41 $ 3.19 Net barrels per month 950,000 1,050,000 990,833

The Company recognized net gains on derivative instruments of $21.5 million and $43.8 million for the three and six monthsended June 30, 2017, respectively. The Company recognized net losses on derivative instruments of $40.0 million and $22.8million for the three and six months ended June 30, 2016, respectively. The Company routinely enters into oil and natural gas swap contracts as seller, thus resulting in a fixed price. During 2016 and2017, the Company realized certain mark-to-market gains associated with oil and natural gas hedges the Company had in placefor years 2018 and 2019. The gains were effectively realized by purchasing, as opposed to selling, oil and natural gas swapcontracts for the equal volume that was associated with the initial hedge transaction. Therefore, as prices fluctuate, the loss (orgain) on any single contract in 2018 and 2019 will be offset by an equal gain (or loss). This essentially leaves the underlyingproduction open to fluctuations in market prices. Based on the original contract terms of these purchased swaps, the gainswould be recognized as the hedge contracts mature in 2018 and 2019. See further discussion below. Information related tothese purchased oil and natural gas swap contracts is presented in the table above as the “offset exercise price”, and thevolumes in the table above are presented “net” of such purchased oil and natural gas swap contracts. During the three and six months ended June 30, 2017, the Company unwound a portion of its realized 2018 and 2019 hedgesresulting in approximately $8.1 million and $28.0 million, respectively, of recognized gains which

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have been included in Net gain (loss) on commodity derivatives on the Company’s Consolidated Statement of Operations.

Offsetting Assets and Liabilities As of June 30, 2017, the counterparties to our commodity derivative contracts consisted of six financial institutions. All of ourcounterparties or their affiliates are also lenders under the Revolver. We are not generally required to post additional collateralunder our derivative agreements. Our derivative agreements contain set-off provisions that state that in the event of default or early termination, any obligationowed by the defaulting party may be offset against any obligation owed to the defaulting party. The following table presents information about our commodity derivative contracts that are netted on our ConsolidatedBalance Sheet as of June 30, 2017 and December 31, 2016:

Net Amounts Gross of Assets / Gross Amounts Gross Amounts Amounts Liabilities Not of Recognized Offset in the Presented in Offset in the Assets / Balance the Balance Balance (in thousands of dollars) Liabilities Sheet Sheet Sheet Net Amount June 30, 2017

Commodity derivativecontracts Assets $ 58,023 $ (12,286) $ 45,737 $ — $ 45,737 Liabilities (15,445) 12,286 (3,159) — (3,159)

December 31, 2016 Commodity derivativecontracts Assets $ 79,649 $ (20,805) $ 58,844 $ — $ 58,844 Liabilities (36,664) 20,805 (15,859) — (15,859)

7. Fair Value Measurement

Fair Value of Financial Instruments The Company determines fair value amounts using available market information and appropriate valuation methodologies. Fairvalue is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transactionbetween market participants at the measurement date. Considerable judgment is required in interpreting market data to developthe estimates of fair value. The use of different market assumptions and/or estimation methods may have a material effect onthe estimated fair value amounts. The Company enters into a variety of derivative financial instruments, which may include over-the-counter instruments, suchas natural gas, crude oil, and natural gas liquid contracts. The Company utilizes valuation techniques that maximize the use ofobservable inputs, where available. If listed market prices or quotes are not published, fair value is determined based upon amarket quote, adjusted by other market-based or independently sourced market data, such as trading volume, historicalcommodity volatility, and counterparty-specific considerations. These adjustments may include amounts to reflect counterpartycredit quality, the time value of money, and the liquidity of the market. Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fairvalue as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have lowdefault rates and equal credit quality. Therefore, an adjustment may be necessary to reflect the quality of a specificcounterparty to determine the fair value of the instrument. The Company currently has all derivative positions placed and heldby members of its lending group, which have high credit quality.

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Liquidity valuation adjustments are necessary when the Company is not able to observe a recent market price for financialinstruments that trade in less active markets. Exchange traded contracts are valued at market value without making anyadditional valuation adjustments; therefore, no liquidity reserve is applied. Valuation Hierarchy Fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon thetransparency of inputs to the valuation of an asset or liability as of the measurement date. A financial instrument’scategorization within the hierarchy is based upon the input that requires the highest degree of judgment in the determination ofthe instrument’s fair value. The three levels are defined as follows: Level 1 Pricing inputs are based on published prices in active markets for identical assets or liabilities as of the reporting date. Level 2 Pricing inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable

for the asset or liability, either directly or indirectly, as of the reporting date. Contracts that are not traded on arecognized exchange or are tied to pricing transactions for which forward curve pricing is readily available areclassified as Level 2 instruments. These include natural gas, crude oil and some natural gas liquids price swaps andnatural gas basis swaps.

Level 3 Pricing inputs include significant inputs that are generally unobservable from objective sources. The Company

classifies natural gas liquid swaps and basis swaps for which future pricing is not readily available as Level 3. TheCompany obtains estimates from independent third parties for its open positions and subjects those to the creditadjustment criteria described above.

The financial instruments carried at fair value as of June 30, 2017 and December 31, 2016, by consolidated balance sheetcaption and by valuation hierarchy, as described above are as follows:

(in thousands of dollars) June 30, 2017 Fair Value Measurements Using

Commodity Price Hedges (Level 1) (Level 2)

(Level 3)

Total Current assets $ — $ 39,823 $ — $ 39,823 Long-term assets — 3,567 2,347 5,914 Current liabilities — 2,702 334 3,036 Long-term liabilities (1) — (137) 260 123

(in thousands of dollars) December 31, 2016 Fair Value Measurements Using Commodity Price Hedges (Level 1) (Level 2) (Level 3) Total Current assets $ — $ 24,100 $ — $ 24,100 Long-term assets (2) — 36,384 (1,640) 34,744 Current liabilities — 13,636 1,014 14,650 Long-term liabilities — 892 317 1,209

(1) Level 2 long-term liabilities are negative as a result of the netting of our commodity derivatives reflected on ourConsolidated Balance Sheet as of June 30, 2017. Our agreements include set-off provisions, as noted in Note 6,“Derivative Instruments and Hedging Activities - Offsetting Assets and Liabilities”.

(2) Level 3 long-term assets are negative as a result of the netting of our commodity derivatives reflected on our ConsolidatedBalance Sheet as of December 31, 2016. Our agreements include set-off provisions, as noted in Note 6, “DerivativeInstruments and Hedging Activities - Offsetting Assets and Liabilities”.

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The following table represents quantitative information about Level 3 inputs used in the fair value measurement of theCompany’s commodity derivative contracts as of June 30, 2017:

Quantitative Information About Level 3 Fair Value Measurements Fair Value Unobservable Commodity Price Hedges (000’s) Valuation Technique Input Range Natural gas liquidswaps

$ (252) Use a discounted cash flowapproach using inputsincluding forward pricestatements fromcounterparties

Natural gas liquidfutures

$22.89 - $23.94per barrel

Crude oil collars

$ 2,766 Use a discounted optionmodel approach usinginputs includinginterpolated volatilities forcertain settlement monthswhere market volatilityquotes were unavailablefor the option strike price

Market volatilityquotes at the

option strike forcertain settlementmonths in 2019

$45.00 - $61.00per barrel

Natural gas collars

$ (761) Use a discounted optionmodel approach usinginputs includinginterpolated volatilities forcertain settlement monthswhere market volatilityquotes were unavailablefor the option strike price

Market volatilityquotes at the

option strike forcertain settlementmonths in 2019

$2.55 - $3.41per barrel

Significant increases/decreases in natural gas liquid prices in isolation would result in a significantly lower/higher fair valuemeasurement. The following table presents the changes in the Level 3 financial instruments for the six months ended June 30,2017. Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported inother income (expense). New contracts entered into during the year are generally entered into at no cost with changes in fairvalue from the date of agreement representing the entire fair value of the instrument. Transfers between levels are evaluated atthe end of the reporting period. The following table summarizes the Company’s commodity derivative contract activity involving Level 3 instruments duringthe six months ended June 30, 2017:

(in thousands of dollars) Balance at December 31, 2016, net $ (2,971)

Purchases 131 Settlements 716 Transfers to Level 2 — Transfers to Level 3 — Changes in fair value 3,877

Balance at June 30, 2017, net $ 1,753

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Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidatedfinancial statements:

June 30, 2017 December 31, 2016 Principal Principal

(in thousands of dollars) Amount Fair Value Amount Fair Value Debt: Revolver $ 181,000 $ 181,000 $ 178,000 $ 178,000 2022 Notes 409,148 289,206 409,148 393,150 2023 Notes 150,000 111,590 150,000 153,375

The Revolver (as defined in Note 5) is categorized as Level 3 in the valuation hierarchy as the debt is not publicly traded andno observable market exists to determine the fair value; however, the carrying value of the Revolver approximates fair value,as it is subject to short-term floating interest rates that approximate the rates available to the Company for those periods. The fair value of the 2022 Notes (as defined in Note 5) is based on pricing that is readily available in the public market.Accordingly, the 2022 Notes are classified as Level 1 in the valuation hierarchy as the pricing is based on quoted market pricesfor the debt securities and is actively traded. The fair value of the 2023 Notes (as defined in Note 5) is based on indicative pricing that is available in the public market.Accordingly, the 2023 Notes are classified as Level 2 in the valuation hierarchy as the pricing is based on quoted market pricesfor the debt securities but is not actively traded. As a result of the Arkoma Divestiture that was pending as of June 30, 2017, the Company recognized an impairment charge of$161.9 million at June 30, 2017. This impairment was recorded for excess net book value over anticipated sales proceeds lesscosts to sell. Fair values of assets held for sale were determined based upon the anticipated sales proceeds less costs to sell,which resulted in a Level 2 classification. See Note 3, “Acquisitions and Divestitures” for further details regarding the“Arkoma Divestiture” and the related “Assets held for sale”.

8. Asset Retirement Obligations A summary of the Company’s Asset Retirement Obligations (“ARO”) for the six months ended June 30, 2017 is as follows:

(in thousands of dollars) Balance at December 31, 2016 $ 20,058 Liabilities incurred 563 Accretion of ARO liability 467 Liabilities settled due to sale of related properties (60) Liabilities settled due to plugging and abandonment (56) Liabilities related to assets held for sale (1,143) Change in estimate (168) Total ARO balance at June 30, 2017 19,661 Less: Current portion of ARO (600) Total long-term ARO at June 30, 2017 $ 19,061

9. Stock-based Compensation

Management Unit Awards

Effective January 1, 2010, JEH implemented a management incentive plan that provided indirect awards of membershipinterests in JEH to members of senior management (“Management Units”). These awards had various vesting schedules, and aportion of the Management Units vested in a lump sum at the IPO date. In

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connection with the IPO, both the vested and unvested Management Units were converted into the right to receive JEH Unitsand shares of Class B common stock. The JEH Units (together with a corresponding number of shares of Class B commonstock) will become exchangeable under this plan into a like number of shares of Class A common stock upon vesting orforfeiture. No new Management Units have been awarded since the IPO and no new JEH Units or shares of Class B commonstock are created upon a vesting event. Grants listed below reflect the transfer of JEH Units that occurred upon forfeiture.

The following table summarizes information related to the vesting of Management Units as of June 30, 2017:

Weighted Average Grant Date Fair Value JEH Units per Share Unvested at December 31, 2016 90,762 $ 15.00 Granted — 15.00 Forfeited — 15.00 Vested (43,377) 15.00 Unvested at June 30, 2017 47,385 $ 15.00

Stock compensation expense associated with the Management Units was $0.2 million and $0.4 million for the three and sixmonths ended June 30, 2017, respectively, and $0.2 million and $0.8 million for the three and six months ended June 30, 2016,respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. 2013 Omnibus Incentive Plan Under the Amended and Restated Jones Energy, Inc. 2013 Omnibus Incentive Plan (the “LTIP”), established in conjunctionwith the Company’s IPO and restated on May 4, 2016 following approval by the Company’s stockholders, the Company hasreserved a total of 8,010,102 shares of Class A common stock for non-employee director, consultant, and employee stock-based compensation awards, as adjusted for the effects of the Special Stock Dividend and the preferred stock dividend paid inshares, as described in Note 11 “Stockholders’ and Mezzanine equity”. The Company granted (i) performance share unit and restricted stock unit awards to certain officers and employees and (ii)restricted shares of Class A common stock to the Company’s non-employee directors under the LTIP during 2014, 2015, 2016and 2017. During 2016 and 2017, the Company also granted performance unit awards to certain members of the seniormanagement team under the LTIP. All share and earnings per share information presented for awards made under the LTIP has been recast to retrospectivelyadjust for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 11, “Stockholders’ and Mezzanineequity”, distributed on March 31, 2017.

Restricted Stock Unit Awards The Company has outstanding restricted stock unit awards granted to certain officers and employees of the Company under theLTIP. The fair value of the restricted stock unit awards is based on the value of the Company’s Class A common stock on thedate of grant and is expensed on a straight-line basis over the applicable vesting period, which is typically three years.

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The following table summarizes information related to the total number of units awarded to officers and employees as of June30, 2017:

Restricted Weighted Average Stock Unit Grant Date Fair Value Awards per Share Unvested at December 31, 2016 1,359,142 $ 5.60 Adjustment (1) 6,830 — Granted 2,333,368 2.34 Forfeited (163,211) 3.23 Vested (577,729) 6.68 Unvested at June 30, 2017 2,958,400 $ 2.93

(1) Increase of 0.002195 units for each unvested restricted stock unit awards at the time of the Company’s May 15, 2017preferred stock dividend for the portion of such dividend paid in shares of the Company’s Class A common stock, asdescribed in Note 11 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards. Thisincrease is in addition to the adjustment for the effects of the Special Stock Dividend previously disclosed in our QuarterlyReport on Form 10-Q for the quarter ended March 31, 2017.

Stock compensation expense associated with the employee restricted stock unit awards was $1.0 million and $2.0 million forthe three and six months ended June 30, 2017, respectively, and $0.9 million and $1.0 million for the three and six monthsended June 30, 2016, respectively, and is included in general and administrative expenses on the Company’s ConsolidatedStatement of Operations. Performance Share Unit Awards The Company has outstanding performance share unit awards granted to certain members of the senior management team ofthe Company under the LTIP. Prior to the second quarter of 2016, the performance share unit awards were described in theCompany’s filings as performance unit awards. During the second quarter of 2016, the Company created a new class of equityaward, described below as a performance unit award, that is settled in cash rather than shares of the Company’s Class Acommon stock. As a result, references to performance unit awards in the Company’s filings prior to the second quarter of 2016refer to this description of performance share unit awards. Upon the completion of the applicable three-year performance period, each recipient may vest in a number of performanceshare units. The percent of awarded performance share units in which each recipient vests at such time, if any, will range from0% to 200% based on the Company’s total shareholder return relative to an industry peer group over the applicable three-yearperformance period. Each vested performance share unit is exchangeable for one share of the Company’s Class A commonstock. The grant date fair value of the performance share units was determined using a Monte Carlo simulation model, whichresults in an estimated percentage of performance share units earned. The fair value of the performance share units is expensedon a straight-line basis over the applicable three-year performance period. The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the performance share unit awards granted during the six months ended June 30, 2017:

2017 Performance Share Unit Awards Forecast period (years) 2.71 Risk-free interest rate 1.34 % Jones stock price volatility 78.93 %

For the performance share units granted during the six months ended June 30, 2017, the Monte Carlo simulationmodel resulted in approximately 29% of performance share units expected to be earned.

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The following table summarizes information related to the total number of performance share units awarded to the seniormanagement team as of June 30, 2017:

Performance Weighted Average Share Unit Grant Date Fair Value Awards per Share Unvested at December 31, 2016 942,073 $ 6.25 Adjustment (1) 4,067 — Granted 519,562 2.24 Forfeited (23,552) 9.42 Vested — — Unvested at June 30, 2017 1,442,150 $ 4.74

(1) Increase of 0.002195 units for each unvested performance share unit award at the time of the Company’s May 15, 2017preferred stock dividend for the portion of such dividend paid in shares of the Company’s Class A common stock, asdescribed in Note 11 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards. Thisincrease is in addition to the adjustment for the effects of the Special Stock Dividend previously disclosed in our QuarterlyReport on Form 10-Q for the quarter ended March 31, 2017.

Stock compensation expense associated with the performance share unit awards was $0.5 million and $1.0 million for the threeand six months ended June 30, 2017, respectively, and $0.6 million and $1.0 million for the three and six months ended June30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement ofOperations. Performance Unit Awards The value of awarded performance units in which each recipient vests at such time, if any, will range from $0.00 to $200.00per performance unit based on the Company’s total shareholder return relative to an industry peer group over the applicablethree-year performance period. For accounting purposes, the performance units are treated as a liability award with the liabilitybeing re-measured at the end of each reporting period. Therefore, the expense associated with these awards is subject tovolatility until the payout is finally determined at the end of the performance period. The value of the performance units wasdetermined using a Monte Carlo simulation model, as of the grant date, which resulted in an estimated final value upon vestingof $0.4 and $1.3 million for awards made during 2017 and 2016, respectively. The fair value measured as of June 30, 2017 was$0.8 million. The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the performance unit awards granted during the six months ended June 30, 2017:

2017 Performance Unit Awards Forecast period (years) 2.71 Risk-free interest rate 1.34 % Jones stock price volatility 78.93 %

For the performance units granted during the six months ended June 30, 2017, the Monte Carlo simulationmodel resulted in an expected payout of $28.25 per performance unit as of the grant date. Stock compensation expense associated with the performance unit awards was an offset to expense of less than $0.1 million forthe three and six months ended June 30, 2017, respectively, as a result of the decrease in market value of the outstandingawards and less than $0.1 million for the three and six months ended June 30, 2016, and is included in general andadministrative expenses on the Company’s Consolidated Statement of Operations. As of June 30, 2017, $0.5 million ofunrecognized compensation expense related to the performance unit awards,

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subject to re-measurement and adjustment for the change in estimated final value as of the end of each reporting period, isexpected to be recognized over the remaining weighted average service period of 1.9 years. Restricted Stock Awards The Company has outstanding restricted stock awards granted to the non-employee members of the Board of Directors of theCompany under the LTIP. The restricted stock will vest upon the director serving as a director of the Company for a one-yearservice period in accordance with the terms of the award. The fair value of the awards was based on the price of theCompany’s Class A common stock on the date of grant.

The following table summarizes information related to the total value of the awards to the Board of Directors as of June 30,2017:

Weighted Average Restricted Grant Date Fair Value

Stock Awards per Share

Unvested at December 31, 2016 152,050 $ 3.68 Granted 180,000 2.25 Forfeited — — Vested (152,050) 3.68 Unvested at June 30, 2017 180,000 $ 2.25

Stock compensation expense associated with awards to the members of the Board of Directors was $0.1 million and $0.3million for the three and six months ended June 30, 2017, respectively, and $0.2 million and $0.3 million for the three and sixmonths ended June 30, 2016, respectively, and is included in general and administrative expenses on the Company’sConsolidated Statement of Operations.

10. Income Taxes

The Company records federal and state income tax liabilities associated with its status as a corporation. The Companyrecognizes a tax liability on its share of pre-tax book income, exclusive of the non-controlling interest. JEH is not subject toincome tax at the federal level and only recognizes Texas franchise tax expense. The Company’s effective tax rate was 1.6% and 1.6% for the three and six months ended June 30, 2017, respectively, and17.4% and 14.3% for the three and six months ended June 30, 2016, respectively. The effective tax rate reduction is primarilydue to the effect of the valuation allowance recorded against the Company’s deferred tax assets. The effective rate differs fromthe statutory rate of 35% due to net income allocated to the non-controlling interest, percentage depletion, state income taxes,the valuation allowance recorded against deferred tax assets, and other permanent differences between book and taxaccounting. The Company’s income tax provision was a benefit of $2.4 million for the three and six months ended June 30, 2017,respectively, and a benefit of $12.4 million and $1.7 million for the three and six months ended June 30, 2016, respectively. The following table summarizes information related to the allocation of the income tax provision between the controlling andnon-controlling interests:

Three Months Ended June 30, Six Months Ended June 30, (in thousands of dollars) 2017 2016 2017 2016 Jones Energy, Inc. $ (2,414) $ (12,215) $ (2,400) $ (1,646) Non-controlling interest (5) (173) 2 (39) Income tax provision (benefit) $ (2,419) $ (12,388) $ (2,398) $ (1,685)

The Company had deferred tax assets for its federal and state net operating loss carry forwards at June 30, 2017 recorded in itsdeferred taxes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likelythan not that some portion or all of the deferred tax assets will not be realized. As of June 30, 2017, we have a valuationallowance of $51.8 million as a result of management’s assessment of the realizability of federal and state deferred tax assets.Management believes that there will be sufficient future

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taxable income based on the reversal of temporary differences to enable utilization of substantially all other tax carryforwards. Tax Receivable Agreement In connection with the IPO, the Company entered into a Tax Receivable Agreement (the “TRA”) which obligates the Companyto make payments to certain current and former owners equal to 85% of the applicable cash savings that the Company realizesas a result of tax attributes arising from exchanges of JEH Units and shares of the Company’s Class B common stock held bythose owners for shares of the Company’s Class A common stock. The Company will retain the benefit of the remaining 15%of these tax savings. At the time of an exchange, the company records a liability to reflect the future payments under the TRA. The actual amount and timing of payments to be made under the TRA will depend upon a number of factors, including theamount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers, and theportion of the Company’s payments under the TRA constituting imputed interest. In the event that the Company records avaluation allowance against its deferred tax assets associated with an exchange, the TRA liability will also be reduced as thepayment of the TRA liability is dependent on the realizability of the deferred tax assets. As of June 30, 2017 and December 31,2016, the amount of the TRA liability was reduced by $33.2 million and $2.7 million, respectively, as a result of the valuationallowance recorded against the Company’s deferred tax assets. To the extent the Company does not realize all of the taxbenefits in future years or in the event of a change in future tax rates, this liability may change. As of June 30, 2017 and December 31, 2016, the Company had recorded a TRA liability of $12.4 million and $43.0 million,respectively, for the estimated payments that will be made to the Class B shareholders who have exchanged shares, afteradjusting for the TRA liability reduction, along with corresponding deferred tax assets, net of valuation allowance, of $14.5million, and $50.6 million, respectively, as a result of the increase in tax basis generated arising from such exchanges. As of June 30, 2017, the Company had not made any significant payments under the TRA to Class B shareholders who haveexchanged JEH Units and Class B common stock for Class A common stock. The Company anticipates making a payment ofapproximately $0.6 million under the TRA with respect to cash savings that the Company will realize on its 2016 tax returns asa result of tax attributes arising from prior exchanges, to be paid in the first quarter of 2018. Cash Tax Distributions The holders of JEH Units, including the Company, incur U.S. federal, state and local income taxes on their share of anytaxable income of JEH. Under the terms of its operating agreement, JEH is generally required to make quarterly pro-rata cashtax distributions to its unitholders (including us) based on income allocated to its unitholders through the end of each relevantquarter, as adjusted to take into account good faith projections by the Company of taxable income or loss for the remainder ofthe calendar year, to the extent JEH has cash available for such distributions and subject to certain other restrictions. A Special Committee of the Board of Directors comprised solely of directors who do not have a direct or indirect interest insuch distribution approved, and JEH made, aggregate cash tax distributions during the three and six months ended June 30,2017 of $0.0 million and $1.7 million, respectively. Distributions during the year were made pro-rata to all members of JEH,and included a $1.1 million payment to the Company and a $0.6 million payment to JEH unitholders other than the Company.During the three and six months ended June 30, 2016 the Company made aggregate cash tax distributions of $20.0 million toits unitholders towards its total 2016 projected tax distribution obligation. The distributions were made pro-rata to all membersof JEH, and included a $9.9 million payment to the Company, and a $10.1 million payment to JEH unitholders other than theCompany. All tax distributions were paid as a result of JEH’s 2016 taxable income.

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11. Stockholders’ and Mezzanine equity Stockholders’ equity is comprised of two classes of common stock, Class A common stock and Class B common stock. TheClass B common stock is held by the owners of JEH prior to the Company’s IPO and can be exchanged (together with acorresponding number of units representing membership interests in JEH Units) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and othersimilar transactions. The Class B common stock has no economic rights but entitles its holders to one vote on all matters to bevoted on by the Company’s stockholders generally. The Company has classified the Series A preferred stock as mezzanine equity based upon the terms and conditions that containvarious redemption and conversion features. For a description of these features, please see below under “—Offering of 8.0%Series A Perpetual Convertible Preferred Stock.” Equity Distribution Agreement On May 24, 2016, the Company and JEH entered into an Equity Distribution Agreement (“Equity Distribution Agreement”)with Citigroup Global Markets Inc. and Wells Fargo Securities, LLC (each, a “Manager” and collectively, the “Managers”).Pursuant to the terms of the Equity Distribution Agreement, the Company may sell from time to time through the Managers, asthe Company’s sales agents, the Company’s Class A common stock having an aggregate offering price of up to $73.0 million(the “Class A Shares”). Under the terms of the Equity Distribution Agreement, the Company may also sell Class A Sharesfrom time to time to any Manager as principal for its own account at a price to be agreed upon at the time of sale. Any sale ofClass A Shares to a Manager as principal would be pursuant to the terms of a separate terms agreement between the Companyand such Manager. Sales of the Class A Shares, if any, will be made by means of ordinary brokers’ transactions, to or througha market maker or directly on or through an electronic communication network, a “dark pool” or any similar market venue, oras otherwise agreed by the Company and one or more of the Managers. During the three and six months ended June 30, 2017, the Company sold approximately 2.5 million and 3.7 million Class AShares, respectively, under the Equity Distribution Agreement for net proceeds of approximately $5.6 million ($5.8 milliongross proceeds, net of approximately $0.2 million in commissions and professional services expenses) and $8.4 million ($8.7million gross proceeds, net of approximately $0.3 million in commissions and professional services expenses), respectively.The Company used the net proceeds for general corporate purposes. As of June 30, 2017, approximately $62.2 million inaggregate offering proceeds remained available to be issued and sold under the Equity Distribution Agreement. Offering of Class A Common Stock On August 26, 2016, the Company issued 21,000,000 shares of Class A common stock pursuant to an underwritten publicoffering, and on September 12, 2016 the Company issued an additional 3,150,000 shares of Class A common stock inconnection with the exercise of the underwriters’ over-allotment option. The total net proceeds (after underwriters’ discountsand commissions, but before estimated expenses) of the offering, including the exercise of the over-allotment option, was$64.0 million. Offering of 8.0% Series A Perpetual Convertible Preferred Stock On August 26, 2016, the Company issued 1,840,000 shares of Series A preferred stock pursuant to an underwritten publicoffering for total net proceeds (after underwriters’ discounts and commissions but before expenses) of $88.3 million. Holders of Series A preferred stock are entitled to receive, when as and if declared by the Company’s Board of Directors,cumulative dividends at the rate of 8.0% per annum (the “dividend rate”) per share on the $50.00 liquidation preference pershare of the Series A Preferred Stock, payable quarterly in arrears on February 15, May 15, August 15 and November 15 ofeach year, beginning on November 15, 2016. Dividends may be paid in cash or, subject to certain limitations, in Class Acommon stock, or a combination thereof.

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Under the terms of the Series A preferred stock, the Company’s ability to declare or pay dividends or make distributions on, orpurchase, redeem or otherwise acquire for consideration, shares of the Company’s Class A common stock, or any junior stockor parity stock currently outstanding or issued in the future, will be subject to certain restrictions in the event that the Companydoes not pay in full or declare and set aside for payment in full all accrued and unpaid dividends on the Series A preferredstock (including certain unpaid excess cash payment amounts excused from payment as a dividend due to restrictions in creditfacilities or other indebtedness or legal requirements (“Unpaid Excess Cash Payment Amounts”)). Each share of Series A preferred stock has a liquidation preference of $50.00 per share and is convertible, at the holder’soption at any time, into approximately 17.0683 shares of Class A common stock after adjusting the conversion ratio for theeffects of the Special Stock Dividend, as defined in Note 11, “Stockholders’ and Mezzanine equity”, (which is equivalent to aconversion price of approximately $2.93 per share after adjusting for the effects of the Special Stock Dividend), subject tospecified further adjustments and limitations as set forth in the certificate of designations for the Series A preferred stock.Based on the adjusted conversion rate and the full exercise of the Preferred Stock Underwriters’ over-allotment option,approximately 31.4 million shares of Class A common stock would be issuable upon conversion of all the Series A preferredstock. On or after August 15, 2021, the Company may, at its option, give notice of its election to cause all outstanding shares ofSeries A preferred stock to be automatically converted into shares of Class A common stock at the conversion rate, if theclosing sale price of the Class A common stock equals or exceeds 175% of the conversion price for at least 20 trading days in aperiod of 30 consecutive trading days. On August 15, 2024 (the “designated redemption date”), each holder of Series A preferred stock may require us to redeem anyor all Series A preferred stock held by such holder outstanding on the designated redemption date at a redemption price equalto a liquidation preference of $50.00 per share plus all accrued dividends on the shares up to but excluding the designatedredemption date that have not been paid plus any Unpaid Excess Cash Payment Amounts (the “redemption price”). At ouroption, the redemption price may be paid in cash or, subject to certain limitations, in Class A common stock, or a combinationthereof. Except as required by law or the Company’s certificate of incorporation, which includes the certificate of designations for theSeries A preferred stock, the holders of Series A preferred stock have no voting rights (other than with respect to certainmatters regarding the Series A preferred stock or when dividends payable on the Series A preferred stock have not been paidfor an aggregate of six quarterly dividend periods, or more, whether or not consecutive, as provided in the certificate ofdesignations for the Series A preferred stock). The Series A preferred stock is classified as mezzanine equity on the Company’s Consolidated Balance Sheet and is not listedon a national stock exchange. A summary of the Company’s Mezzanine equity for the six months ended June 30, 2017 is as follows:

(in thousands of dollars) Mezzanine equity at December 31, 2016 $ 88,975 Dividends on preferred stock, net — Accretion on preferred stock 313 Mezzanine equity at June 30, 2017 $ 89,288

Preferred Stock Dividends On January 19, 2017, the Company’s Board of Directors declared a quarterly cash dividend per share equal to 8.0% based onthe liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock. Thisdividend is for the period beginning on the last payment date of November 15, 2016 through February 14, 2017 and was paidin cash on February 15, 2017 to shareholders of record as of February 1, 2017. On April 17, 2017, the Company’s Board of Directors declared a quarterly dividend per share equal to 8.0% based on theliquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock. On May15, 2017, the dividend was paid in a combination of cash and the Company’s Class A

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common stock, with the cash component equal to $0.83 per share and the stock component equal to $0.17 per share. The priceper share of the Class A common stock used to determine the number of shares issued was equal to 95% of the averagevolume-weighted average price per share for each day during the five-consecutive day trading period ending immediately priorto the payment date. This dividend was for the period beginning on the last payment date of February 15, 2017 through May14, 2017 to shareholders of record as of May 1, 2017. Special Stock Dividend On March 31, 2017, the Company paid a stock dividend (the “Special Stock Dividend”) of 0.087423 shares of the Class Acommon stock to holders of record as of March 15, 2017. From time-to-time, JEH makes cash distributions to the holders ofJEH Units to cover tax obligations that may occur as a result of any net taxable income of JEH allocable to holders of JEHUnits. As a holder of JEH Units, the Company has received such cash distributions from JEH in excess of the amount requiredto satisfy the Company’s associated tax obligations. As a result, the Company used the excess cash of approximately $17.5million in the aggregate to acquire newly-issued JEH Units from JEH. The Special Stock Dividend was distributed in order to equalize the number of shares of Class A common stock outstanding tothe number of JEH Units held by the Company, and the aggregate number of shares of Class A common stock issued in theSpecial Stock Dividend equaled the number of additional JEH Units the Company purchased from JEH. The Companypurchased 4,999,927 JEH Units at a price of $3.50 per share, which is the volume weighted average price per share of theClass A common stock for the five trading days ended February 28, 2017. Immaterial cash payments were made in lieu offractional shares. The comparative earnings per share information has been recast to retrospectively adjust for the effects of theSpecial Stock Dividend.

12. Earnings per Share

Basic earnings per share (“EPS”) is computed by dividing net income (loss) attributable to controlling interests by theweighted average number of shares of Class A common stock outstanding during the period. Shares of Class B common stockare not included in the calculation of earnings per share because they are not participating securities and have no economicinterest in the Company. Diluted earnings per share takes into account the potential dilutive effect of shares that could beissued by the Company in conjunction with the Series A preferred stock and from stock awards that have been granted todirectors and employees. Awards of non-vested shares are considered outstanding as of the respective grant dates for purposesof computing diluted EPS even though the award is contingent upon vesting. For the three and six months ending June 30,2017, 2,958,400 restricted stock units, 1,442,150 performance share units, and 31,405,672 shares from the convertible Class Apreferred stock, were excluded from the calculation as they would have had an anti-dilutive effect.

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The following is a calculation of the basic and diluted weighted-average number of shares of Class A common stockoutstanding and EPS for the three and six months ended June 30, 2017:

Three Months Ended

June 30, Six Months Ended

June 30, (in thousands, except per share data) 2017 2016 2017 2016 Income (numerator):

Net income (loss) attributable to controllinginterests $ (89,239) $ (23,245) $ (90,626) $ (4,334) Less: Dividends and accretion on preferredstock (1,966) — (3,993) — Net income (loss) attributable to commonshareholder $ (91,205) $ (23,245) $ (94,619) $ (4,334)

Weighted-average shares (denominator): (1) Weighted-average number of shares of Class Acommon stock - basic 65,681 33,598 63,948 33,410 Weighted-average number of shares of Class Acommon stock - diluted 65,681 33,598 63,948 33,410

Earnings (loss) per share: (1) Basic - Net income (loss) attributable tocommon shareholders $ (1.39) $ (0.69) $ (1.48) $ (0.13) Diluted - Net income (loss) attributable tocommon shareholders $ (1.39) $ (0.69) $ (1.48) $ (0.13)

(1) All share and earnings per share information presented has been recast to retrospectively adjust for the effects of the0.087423 per share Special Stock Dividend, as defined in Note 11, “Stockholders’ and Mezzanine equity”, distributedon March 31, 2017.

13. Related Parties Related Party Transactions Transactions with Our Executive Officers, Directors and 5% Stockholders Monarch Natural Gas Holdings, LLC Natural Gas Sale and Purchase Agreement On May 7, 2013, the Company entered into a natural gas sale and purchase agreement with Monarch Natural Gas, LLC,(“Monarch”), under which Monarch has the first right to gather the natural gas the Company produces from dedicatedproperties, process the NGLs from this natural gas production and market the processed natural gas and extracted NGLs.Under the Monarch agreement, the Company is paid a specified percentage of the value of the NGLs extracted and sold byMonarch, based on a set liquids recovery percentage, and the amount received from the sale of the residue gas, after deductinga fixed volume for fuel, lost and unaccounted-for gas. The Company produced approximately 1.4 MMBoe of natural gas andNGLs for the year ended December 31, 2014, from the properties that became subject to the Monarch agreement. During theyear ended December 31, 2014, the Company recognized $37.0 million of revenue associated with the aforementioned naturalgas and NGL production. Effective May 1, 2015, the rights to gather natural gas under the sale and purchase agreementtransferred from Monarch to Enable Midstream Partners LP, (“Enable”), an unaffiliated third-party. Prior to closing of thetransfer of these rights, the Company produced approximately 1.0 MMBoe of natural gas and NGLs for the year endedDecember 31, 2015 from the properties that became subject to the Monarch agreement for which the Company recognized$10.6 million of revenue. The revenue, for all years mentioned, is recorded in Oil and gas sales on the Company’sConsolidated Statement of Operations. The initial term of the agreement, which remains unchanged by the transfer to Enable,runs for 10 years from the effective date of September 1, 2013. At the time the Company entered into the 2013 Monarch agreement, Metalmark Capital owned approximately 81% of theoutstanding equity interests of Monarch. In addition, Metalmark Capital beneficially owns in excess of five percent of theCompany’s outstanding equity interests and two of our former directors, Howard I. Hoffen

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and Gregory D. Myers, are managing directors of Metalmark Capital and were directors at the time the Company entered intothe 2013 Monarch agreement. In connection with the Company’s entering into the 2013 Monarch agreement, Monarch issued to JEH equity interests inMonarch, having an estimated fair value of $15.0 million, in return for marketing services to be provided throughout the termof the agreement. The Company recorded this amount as deferred revenue which is being amortized on an estimated units-of-production basis commencing in September 2013, the first month of product sales to Monarch. The Company amortized $0.5million and $0.9 million, respectively, of the deferred revenue balance during the three and six months ended June 30, 2017,and $0.6 million and $1.2 million, respectively, of the deferred revenue balance during the three and six months ended June 30,2016. This revenue is recorded in Other revenues on the Company’s Consolidated Statement of Operations. Following the issuance of $15.0 million Monarch equity interests to JEH, JEH assigned $2.4 million of the equity interests toJonny Jones, the Company’s chief executive officer and chairman of the Board of Directors, and reserved $2.6 million of theequity interests for future distribution through an incentive plan to certain of the Company’s officers, including MikeMcConnell, Robert Brooks and Eric Niccum. The remaining $10.0 million of Monarch equity interests was distributed tocertain of the Class B shareholders, which included, among others, Metalmark Capital, the Jones family entities, and certain ofthe Company’s officers and directors, including Jonny Jones, Mike McConnell and Eric Niccum. As of June 30, 2017, equityinterests in Monarch of $0.7 million are included in Other assets on the Company’s Consolidated Balance Sheet. During the sixmonths ended June 30, 2017, no equity interests were distributed to management under the incentive plan. The Companyrecognized expense of $0.1 million and $0.2 million during the three and six months ended June 30, 2017, respectively, inconnection with the incentive plan. In September 2014, the Company signed a 10-year oil gathering and transportation agreement with Monarch Oil Pipeline LLC,pursuant to which Monarch Oil Pipeline LLC built, at its expense, a new oil gathering system and connected the gatheringsystem to dedicated Company leases in Texas. At the time the Company entered into the agreement, Metalmark Capital ownedthe majority of the outstanding equity interests of Monarch Oil Pipeline LLC and/or its parent. The system began serviceduring the fourth quarter of 2015 and provides connectivity to both a regional refinery market as well as the Cushing markethub. The Company incurred gathering fees, which were paid to Monarch Oil Pipeline LLC, of $0.6 million and $1.3 millionfor the three and six months ended June 30, 2017, respectively, associated with the approximately 0.3 MMBoe and 0.6MMBoe, respectively, of oil production transported under the agreement. These costs are recorded as an offset to Oil and gassales in the Company’s Consolidated Statement of Operations. The aforementioned production was recognized as Oil and gassales on the Company’s Consolidated Statement of Operations at the time it was sold to the purchasers, who are unaffiliatedthird parties, after passing through the gathering and transportation system. The audit committee of the Board of Directorsreviewed and approved the terms of the agreement with Monarch Oil Pipeline LLC. Purchases of Senior Unsecured Notes On February 29, 2016, JEH and Jones Energy Finance Corp. purchased $50.0 million principal amount of their outstanding2023 Notes from investment funds managed by Magnetar Capital and its affiliates, which investment funds collectively thenowned more than 5% of a class of voting securities of the Company, for approximately $23.3 million excluding accruedinterest and including any associated fees. On the same day, JEH and Jones Energy Finance Corp. purchased an additional$50.0 million principal amount of their outstanding 2023 Notes from investment funds managed by Blackstone GroupManagement L.L.C. and its affiliates, which investment funds collectively then owned more than 5% of a class of votingsecurities of the Company, for approximately $23.3 million excluding accrued interest and including any associated fees. Inconjunction with the extinguishment of this $100.0 million principal amount of debt, JEH recognized cancellation of debtincome of $48.3 million on a pre-tax basis. This income is recorded in Gain on debt extinguishment on the Company’sConsolidated Statement of Operations.

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Issuance of Class A Shares In connection with the August 2016 issuance of Class A common stock pursuant to an underwritten public offering asdescribed above under “Item 11. Stockholders’ and Mezzanine equity—Offering of Class A Common Stock,” affiliates of JVLAdvisors, L.L.C. (“JVL”), who then owned more than 5% of a class of voting securities of the Company, purchased 9,025,270shares of Class A common stock, prior to adjustment for the effects of the 0.087423 per share Special Stock Dividend, asdefined in Note 11, “Stockholders’ and Mezzanine equity”, in the offering, for gross proceeds to the Company of $25.0million, before underwriting discounts and commissions of $1.1 million. Following its purchase in the offering, JVL owned in excess of 15% of our outstanding voting stock. As a result, the Companyentered into a letter agreement with JVL (the “JVL Letter Agreement”) in connection with the offering. The JVL LetterAgreement approved, pursuant to Section 203 of the Delaware General Corporation Law (“Section 203”), the purchase ofshares of Class A common stock in the offering by JVL. This approval resulted in JVL not being subject to the restrictions on“business combinations” contained in Section 203. In consideration of such approval, JVL agreed that, among other things:

· it will not acquire any material assets of the Company;· it will not become the owner of more than 19.9% of the Company’s outstanding voting stock (other than as a result of

actions taken solely by the Company) without the prior approval of the Company’s independent directors who are notaffiliated with JVL; and

· it will not engage in any “business combination” (as defined in the JVL Letter Agreement). On May 3, 2017, the Company amended and restated its registration rights agreement dated August 29, 2013 (as amended andrestated, the “Restated Registration Rights Agreement”) to add JVL as a party in order to facilitate an orderly distribution ofJVL’s shares of Class A common stock in the future, a copy of which was filed on the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 3, 2017. Issuance of Series A Preferred Stock In connection with the August 2016 issuance of Series A preferred stock pursuant to an underwritten public offering asdescribed above under “Item 11. Stockholders’ and Mezzanine equity—Offering of 8.0% Series A Perpetual ConvertiblePreferred Stock,” affiliates of Metalmark, who then owned more than 5% of a class of voting securities of the Company andhad two representatives on our Board of Directors, purchased 200,000 shares of Series A preferred stock in the offering, forgross proceeds to the Company of $10.0 million, before underwriting discounts and commissions of $400,000. Amended and Restated Registration Rights and Stockholders Agreement On May 2, 2017, we entered into an Amended and Restated Registration Rights and Stockholders Agreement (the “RestatedAgreement”) with certain entities affiliated with the Jones family (the “Jones Family Entities”), Metalmark and JVL. The Restated Agreement amends and restates in its entirety that certain Registration Rights and Stockholders Agreement, datedJuly 29, 2013 (the “Original Agreement”), by and among the Company, Metalmark and the Jones Family Entities, to, amongother things, provide JVL with certain rights, in addition to those rights granted to Metalmark and the Jones Family Entities inthe Original Agreement, to require the Company to register the sale of any number of JVL’s shares of Class A common stock.JVL shall have the right to cause no more than one such required or “demand” registration, which shall be requested by amajority in interest of the JVL holders who hold certain equity securities of the Company or securities convertible orexchangeable into equity securities of the Company. The Company is not obligated to affect any demand registration in whichthe anticipated aggregate offering price included in such offering is equal to or less than $50,000,000 ($25,000,000 where theregistration is on a Form S-3). Furthermore, if, at any time, the Company proposes to register an offering of Class A commonstock (subject to certain exceptions) for the Company’s own account, then it must give prompt notice to Metalmark, JVL andthe Jones Family Entities to allow them to include a specified number of their shares in that registration statement. Theseregistration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the numberof shares to be included in a registration and the Company’s right to

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delay or withdraw a registration statement under certain circumstances. The Company will generally be obligated to pay allregistration expenses in connection with the registration obligations, regardless of whether a registration statement is filed orbecomes effective. The Restated Agreement also includes customary provisions dealing with indemnification, contribution andallocation of expenses.

14. Commitments and Contingencies

Litigation The Company is subject to legal proceedings and claims that arise in the ordinary course of its business. When applicable, werecord accruals for contingencies when it is probable that a liability will be incurred and the amount of loss can be reasonablyestimated. While the outcome of lawsuits and other proceedings against us cannot be predicted with certainty, in the opinion ofmanagement, individually or in the aggregate, no such lawsuits are expected to have a material effect on our financial position,results of operations, or liquidity. In an action filed on June 12, 2015 in the 31 District Court of Hemphill County, Texas, DonnaKimFlowersandMitchellKirkFlowersv.JonesEnergy,LLCf/k/aJonesEnergyLimited,LLCf/k/aJonesEnergy,Ltd.(Case No. 7225), the Companywas sued by Donna Kim Flowers and Mitchell Kirk Flowers (the “plaintiffs”). The plaintiffs own surface rights to propertylocated in Hemphill County, Texas. The mineral rights are leased to third parties, and the Company is the operator of the Oiland Gas Mineral Lease. On May 28, 2010, the plaintiffs and the Company entered into a Surface Use Agreement concerningthe Company’s operations on the property, which require the Company to minimize disruption and damage to the plaintiffs’surface rights. The plaintiffs allege that the Company is in breach of such contract, and seek monetary damages. In June 2016,the Company presented a settlement offer to the plaintiffs. As a result of this settlement offer, the Company accrued $1.5million related to its estimated obligation under this settlement offer. This accrual was included in accrued liabilities on theCompany’s Consolidated Balance Sheet as of December 31, 2016, and the charge was recorded as general and administrativeexpense on the Company’s Consolidated Statement of Operations during the three months ended June 30, 2016. In June 2017,the Company presented a revised settlement offer to the plaintiffs and the plaintiff accepted. The settlement was paid in cashduring June 2017. Upon settlement, the Company recognized an additional charge of $1.4 million which was recorded asgeneral and administrative expense on the Company’s Consolidated Statement of Operations during the three months endedJune 30, 2017.

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15. Subsequent Events Preferred Stock Dividend Declared On July 13, 2017, the Company’s Board of Directors declared a quarterly dividend per share equal to 8.0% based on theliquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock, to bepaid entirely in shares of Class A common stock (the “August Preferred Dividend”). The price per share of the Class Acommon stock used to determine the number of shares issued will equal to 95% of the average volume-weighted average priceper share for each day during the 5-consecutive day trading period ending immediately prior to the payment date. The AugustPreferred Dividend will be paid on August 15, 2017 for the period beginning on the last payment date of May 15, 2017 throughAugust 14, 2017 to shareholders of record as of August 1, 2017. Arkoma Divestiture On August 1, 2017, JEH closed the previously announced Arkoma Divestiture for a purchase price of $65.0 million, subject tocustomary adjustments. Upon closing, the Company’s borrowing base on the Revolver was reduced to $375.0 million. Class B to Class A Share Exchanges On July 7, 2017, certain Class B shareholders exchanged an aggregate of 6,105,148 shares of Class B common stock (togetherwith a corresponding number of JEH Units) for shares of Class A common stock on a one-for-one basis (the “JulyExchanges”). As of June 30, 2017 and December 31, 2016, the Company had recorded a TRA liability of $12.4 million and$43.0 million, respectively, for the estimated payments that will be made to Class B shareholders who have exchanged sharesof Class B common stock, after adjusting for the TRA liability reduction as a result of the increase in tax basis arising fromsuch exchanges. After the July Exchanges, the gross TRA liability increased by approximately $18.7 million. The increase inTRA liability will be offset entirely as a result of the valuation allowance recorded against the deferred asset generated in theexchange that would lead to payment of such TRA liability.

16. Subsidiary Guarantors

The 2022 Notes and the 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of JEH’s currentsubsidiaries (except Jones Energy Finance Corp. and two immaterial subsidiaries) and certain future subsidiaries, including anyfuture subsidiaries that guarantee any indebtedness under the Revolver. Each subsidiary guarantor is 100% owned by JEH, andall guarantees are full and unconditional, subject to customary exceptions pursuant to the indentures governing our 2022 Notesand 2023 Notes, as discussed below, and joint and several with all other subsidiary guarantees and the parent guarantee. Anysubsidiaries of JEH other than the subsidiary guarantors and Jones Energy Finance Corp. are immaterial. As of December 31, 2016, the 2022 Notes and the 2023 Notes were guaranteed on a senior unsecured basis by the Companyand by all of its significant subsidiaries, other than Nosley SCOOP, LLC and Nosley Acquisition, LLC. These subsidiarieshave since become guarantors during the first quarter of 2017 and are therefore presented accordingly in the accompanyingcondensed consolidated guarantor financial information. Guarantees of the 2022 Notes and 2023 Notes will be released under certain circumstances, including (i) in connection withany sale or other disposition of (a) all or substantially all of the properties or assets of a guarantor (including by way of mergeror consolidation) or (b) all of the capital stock of such guarantor, in each case, to a person that is not the Company or arestricted subsidiary of the Company, (ii) if the Company designates any restricted subsidiary that is a guarantor as anunrestricted subsidiary, (iii) upon legal defeasance, covenant defeasance or satisfaction and discharge of the applicableindenture, or (iv) at such time as such guarantor ceases to guarantee any other indebtedness of the Company or any otherguarantor. The Company is a holding company whose sole material asset is an equity interest in JEH. The Company is the sole managingmember of JEH and is responsible for all operational, management and administrative decisions related to JEH’s business. Inaccordance with JEH’s limited liability company agreement, the Company may not be removed as the sole managing memberof JEH.

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As of June 30, 2017, the Company held 66,649,057 JEH Units and all of the preferred units representing membership interestsin JEH, and the remaining 29,823,927 JEH Units are held by the Class B shareholders. The Class B shareholders have novoting rights with respect to their economic interest in JEH. The Company has two classes of common stock, Class A common stock, which was sold to investors in the IPO, and Class Bcommon stock, and one series of preferred stock, Series A preferred stock. Pursuant to the Company’s certificate ofincorporation, each share of Class A common stock is entitled to one vote per share, and the shares of Class A common stockare entitled to 100% of the economic interests in the Company. Each share of Class B common stock has no economic rights inthe Company, but entitles its holder to one vote on all matters to be voted on by the Company’s stockholders generally. Exceptas required by law or the Company’s certificate of incorporation, which includes the certificate of designations for the Series Apreferred stock, the holders of Series A preferred stock have no voting rights (other than with respect to certain mattersregarding the Series A preferred stock or when dividends payable on the Series A preferred stock have not been paid for anaggregate of six quarterly dividend periods, or more, whether or not consecutive, as provided in the certificate of designationsfor the Series A preferred stock). In connection with a reorganization that occurred immediately prior to the IPO, each Existing Owner was issued a number ofshares of Class B common stock that was equal to the number of JEH Units that such Class B shareholders held. Holders of theCompany’s Class A common stock and Class B common stock generally vote together as a single class on all matterspresented to the Company’s stockholders for their vote or approval. Accordingly, the Class B shareholders collectively have anumber of votes in the Company equal to the aggregate number of JEH Units that they hold. The Class B shareholders have the right, pursuant to the terms of an exchange agreement by and among the Company, JEH andeach of the Class B shareholders (the “Exchange Agreement”), to exchange their JEH Units (together with a correspondingnumber of shares of Class B common stock) for shares of Class A common stock on a one-for-one basis, subject to customaryconversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. As a result, theCompany expects that over time the Company will have an increasing economic interest in JEH as Class B common stock andJEH Units are exchanged for Class A common stock. Moreover, any transfers of JEH Units outside of the ExchangeAgreement (other than permitted transfers to affiliates) must be approved by the Company. The Company intends to retain fullvoting and management control over JEH. During the preparation of the condensed consolidating financial information of Jones Energy, Inc. and Subsidiaries as of andfor the three and six months period ended June 30, 2017, it was determined that the Issuer Investment in subsidiaries and therelated Eliminations at December 31, 2016 as filed in the Company’s 2016 Form 10-K were improperly calculated andunderstated by $453.2 million. Additionally, it was determined that the Guarantor Subsidiaries Intercompany payable balancesand the related Eliminations and the Issuer Intercompany receivable and the related Eliminations at December 31, 2016 as filedin the Company’s 2016 Form 10-K were improperly calculated and overstated by $453.2 million and $80.0 million,respectively. In addition, it was determined that the Issuer Equity interest in income (loss) and the related Eliminations for thethree and six months period ended June 30, 2016 as filed in the Company’s second quarter 2016 Form 10-Q were improperlycalculated and understated by $35.7 million and $5.8 million, respectively. Lastly, it was determined that the IssuerAdjustments to reconcile net income (loss) to net cash provided by operating activities and the related Eliminations for the sixmonths period ended June 30, 2016 as filed in the Company’s second quarter 2016 Form 10-Q was improperly calculated andoverstated by $5.8 million. The errors, which the Company has determined are not material to this disclosure, had no impact on the total assets of theParent or the Guarantor Subsidiaries and are eliminated upon consolidation, and therefore have no impact on the Company’sconsolidated financial condition, results of operations or cash flows. The Company has revised the Condensed Consolidating Balance Sheets for the Issuer, Guarantor Subsidiaries andEliminations as of December 31, 2016, the Condensed Consolidating Income Statements for the Issuer and Eliminations for thethree and six months period ended June 30, 2016 and the Condensed Consolidating Statement of Cash Flows for the sixmonths ended June 30, 2016 to correct for these errors.

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Jones Energy, Inc.Condensed Consolidating Balance Sheet

June 30, 2017

Guarantor Non-Guarantor (in thousands of dollars) JEI (Parent) Issuers Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets

Cash $ 3,254 $ 781 $ 2,199 $ 20 $ — $ 6,254 Accounts receivable, net Oil and gas sales — — 24,557 — — 24,557 Joint interest owners — — 9,032 — — 9,032 Other — 3,943 3,262 — — 7,205

Commodity derivative assets — 39,823 — — — 39,823 Other current assets 2,746 311 8,324 — — 11,381 Assets held for sale — — 3,455 — — 3,455 Intercompany receivable 18,567 1,204,759 — — (1,223,326) —

Total current assets 24,567 1,249,617 50,829 20 (1,223,326) 101,707 Assets held for sale, net — — 64,200 — — 64,200 Oil and gas properties, net, at cost under thesuccessful efforts method — — 1,545,991 — — 1,545,991 Other property, plant and equipment, net — — 2,239 573 — 2,812 Commodity derivative assets — 5,914 — — — 5,914 Other assets — 4,467 928 — — 5,395 Investment in subsidiaries 432,964 394,331 — — (827,295) —

Total assets $ 457,531 $ 1,654,329 $ 1,664,187 $ 593 $ (2,050,621) $ 1,726,019 Liabilities and Stockholders’ Equity Current liabilities

Trade accounts payable $ 27 $ 62 $ 55,964 $ — $ — $ 56,053 Oil and gas sales payable — — 22,301 — — 22,301 Accrued liabilities 33 11,418 8,120 — — 19,571 Commodity derivative liabilities — 3,036 — — — 3,036 Other current liabilities 639 1,985 5,475 — — 8,099 Liabilities related to assets held for sale — — 7,472 — — 7,472 Intercompany payable — — 1,220,390 2,936 (1,223,326) —

Total current liabilities 699 16,501 1,319,722 2,936 (1,223,326) 116,532 Liabilities related to assets held for sale — — 1,143 — — 1,143 Long-term debt — 728,163 — — — 728,163 Deferred revenue — 6,106 — — — 6,106 Commodity derivative liabilities — 123 — — — 123 Asset retirement obligations — — 19,061 — — 19,061 Liability under tax receivable agreement 11,807 — — — — 11,807 Other liabilities — 236 666 — — 902 Deferred tax liabilities 85 2,826 — — — 2,911

Total liabilities 12,591 753,955 1,340,592 2,936 (1,223,326) 886,748 Mezzanine equity

Series A preferred stock, $0.001 par value;1,840,000 shares issued and outstanding atJune 30, 2017 89,288 — — — — 89,288

Stockholders’/ members' equity (deficit) Members' equity — 900,374 323,595 (2,343) (1,221,626) —

Class A common stock, $0.001 par value;66,671,659 shares issued and 66,649,057 sharesoutstanding at June 30, 2017 67 — — — — 67 Class B common stock, $0.001 par value;29,823,927 shares issued and outstanding atJune 30, 2017 30 — — — — 30

Treasury stock, at cost: 22,602 shares atJune 30, 2017 (358) — — — — (358)

Additional paid-in-capital 477,390 — — — — 477,390 Retained earnings (deficit) (121,477) — — — — (121,477)

Stockholders' equity (deficit) 355,652 900,374 323,595 (2,343) (1,221,626) 355,652 Non-controlling interest — — — — 394,331 394,331

Total stockholders’ equity 355,652 900,374 323,595 (2,343) (827,295) 749,983 Total liabilities and stockholders’ equity $ 457,531 $ 1,654,329 $ 1,664,187 $ 593 $ (2,050,621) $ 1,726,019

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Jones Energy, Inc.Condensed Consolidating Balance Sheet

December 31, 2016

Guarantor Non-Guarantor (in thousands of dollars) JEI (Parent) Issuers Subsidiaries Subsidiaries Eliminations Consolidated Assets Current assets

Cash $ 27,164 $ 1,975 $ 5,483 $ 20 $ — $ 34,642 Accounts receivable, net Oil and gas sales — — 26,568 — — 26,568 Joint interest owners — — 5,267 — — 5,267 Other — 5,434 627 — — 6,061

Commodity derivative assets — 24,100 — — — 24,100 Other current assets — 422 2,262 — — 2,684 Intercompany receivable 15,666 1,100,834 — — (1,116,500) —

Total current assets 42,830 1,132,765 40,207 20 (1,116,500) 99,322 Oil and gas properties, net, at cost under thesuccessful efforts method — — 1,743,588 — — 1,743,588 Other property, plant and equipment, net — — 2,378 618 — 2,996 Commodity derivative assets — 34,744 — — — 34,744 Other assets — 5,265 785 — — 6,050 Investment in subsidiaries 531,363 453,237 — — (984,600) —

Total assets $ 574,193 $ 1,626,011 $ 1,786,958 $ 638 $ (2,101,100) $ 1,886,700 Liabilities and Stockholders’ Equity Current liabilities

Trade accounts payable $ — $ 13 $ 36,514 $ — $ — $ 36,527 Oil and gas sales payable — — 28,339 — — 28,339 Accrued liabilities 3,874 11,227 10,597 9 — 25,707 Commodity derivative liabilities — 14,650 — — — 14,650 Other current liabilities — 1,984 600 — — 2,584 Intercompany payable — — 1,113,704 2,796 (1,116,500) —

Total current liabilities 3,874 27,874 1,189,754 2,805 (1,116,500) 107,807 Long-term debt — 724,009 — — — 724,009 Deferred revenue — 7,049 — — — 7,049 Commodity derivative liabilities — 1,209 — — — 1,209 Asset retirement obligations — — 19,458 — — 19,458 Liability under tax receivable agreement 43,045 — — — — 43,045 Other liabilities — 269 523 — — 792 Deferred tax liabilities 85 2,820 — — — 2,905

Total liabilities 47,004 763,230 1,209,735 2,805 (1,116,500) 906,274 Mezzanine equity

Series A preferred stock, $0.001 par value;1,840,000 shares issued and outstanding atDecember 31, 2016 88,975 — — — — 88,975

Stockholders’/ members' equity (deficit) Members' equity — 862,781 577,223 (2,167) (1,437,837) —

Class A common stock, $0.001 par value;57,048,076 shares issued and 57,025,474shares outstanding at December 31, 2016 57 — — — — 57 Class B common stock, $0.001 par value;29,832,098 shares issued and outstandingat December 31, 2016 30 — — — — 30

Treasury stock, at cost: 22,602 shares atDecember 31, 2016 (358) — — — — (358)

Additional paid-in-capital 447,137 — — — — 447,137 Retained earnings (deficit) (8,652) — — — — (8,652)

Stockholders' equity (deficit) 438,214 862,781 577,223 (2,167) (1,437,837) 438,214 Non-controlling interest — — — — 453,237 453,237

Total stockholders’ equity 438,214 862,781 577,223 (2,167) (984,600) 891,451 Total liabilities and stockholders’equity $ 574,193 $ 1,626,011 $ 1,786,958 $ 638 $ (2,101,100) $ 1,886,700

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Jones Energy, Inc.Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2017

Guarantor Non-

Guarantor (in thousands of dollars)

JEI (Parent) Issuers Subsidiaries Subsidiaries Eliminations Consolidated

Operatingrevenues Oil and gas sales $ — $ — $ 48,114 $ — $ — $ 48,114 Other revenues — 485 27 — — 512 Total operatingrevenues — 485 48,141 — — 48,626 Operating costsand expenses Lease operating — — 9,425 — — 9,425 Production and advalorem taxes — — 2,790 — — 2,790 Exploration — — 6,725 — — 6,725 Depletion,depreciation andamortization — — 45,313 23 — 45,336 Impairment of oiland gas properties — — 161,886 — — 161,886 Accretion of AROliability — — 266 — — 266 General andadministrative — 2,920 5,626 87 — 8,633 Total operatingexpenses — 2,920 232,031 110 — 235,061 Operating income(loss) — (2,435) (183,890) (110) — (186,435) Other income(expense) Interest expense — (12,941) 264 — — (12,677) Net gain (loss) oncommodityderivatives — 21,527 — — — 21,527 Other income(expense) 29,913 (24) (55) — — 29,834 Other income(expense), net 29,913 8,562 209 — — 38,684 Income (loss)before income tax 29,913 6,127 (183,681) (110) — (147,751) Equity interest inincome (loss) (121,557) (56,107) — — 177,664 — Income taxprovision (benefit) (2,405) (14) — — — (2,419) Net income (loss) (89,239) (49,966) (183,681) (110) 177,664 (145,332) Net income (loss)attributable tonon-controllinginterests — — — — (56,093) (56,093) Net income (loss)attributable tocontrollinginterests $ (89,239) $ (49,966) $ (183,681) $ (110) $ 233,757 $ (89,239) Dividends andaccretion onpreferred stock (1,966) — — — — (1,966) Net income (loss)attributable tocommonshareholders $ (91,205) $ (49,966) $ (183,681) $ (110) $ 233,757 $ (91,205)

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Six Months Ended June 30, 2017

Guarantor Non-

Guarantor (in thousands of dollars) JEI (Parent) Issuers Subsidiaries Subsidiaries Eliminations Consolidated Operating revenues Oil and gas sales $ — $ — $ 88,791 $ — $ — $ 88,791 Other revenues — 942 126 — — 1,068 Total operatingrevenues — 942 88,917 — — 89,859 Operating costs andexpenses Lease operating — — 18,231 — — 18,231 Production and advalorem taxes — — 1,884 — — 1,884 Exploration — — 9,669 — — 9,669 Depletion,depreciation andamortization — — 80,945 45 — 80,990 Impairment of oil andgas properties — — 161,886 — — 161,886 Accretion of AROliability — — 467 — — 467 General andadministrative — 5,913 10,630 131 — 16,674 Total operatingexpenses — 5,913 283,712 176 — 289,801 Operating income(loss) — (4,971) (194,795) (176) — (199,942) Other income(expense) Interest expense — (25,755) 191 — — (25,564) Net gain (loss) oncommodityderivatives — 43,847 — — — 43,847 Other income(expense) 30,581 (48) (119) — — 30,414 Other income(expense), net 30,581 18,044 72 — — 48,697 Income (loss) beforeincome tax 30,581 13,073 (194,723) (176) — (151,245) Equity interest inincome (loss) (123,611) (58,215) — — 181,826 — Income tax provision(benefit) (2,404) 6 — — — (2,398) Net income (loss) (90,626) (45,148) (194,723) (176) 181,826 (148,847) Net income (loss)attributable to non-controlling interests — — — — (58,221) (58,221) Net income (loss)attributable tocontrolling interests $ (90,626) $ (45,148) $ (194,723) $ (176) $ 240,047 $ (90,626) Dividends andaccretion on preferredstock (3,993) — — — — (3,993) Net income (loss)attributable tocommonshareholders $ (94,619) $ (45,148) $ (194,723) $ (176) $ 240,047 $ (94,619)

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Three Months Ended June 30, 2016

Guarantor Non-

Guarantor (in thousands of dollars) JEI (Parent) Issuers Subsidiaries Subsidiaries Eliminations Consolidated Operating revenues Oil and gas sales $ — $ — $ 28,398 $ — $ — $ 28,398 Other revenues — 596 150 — — 746 Total operatingrevenues — 596 28,548 — — 29,144 Operating costs andexpenses Lease operating — — 7,545 — — 7,545 Production and advalorem taxes — — 1,727 — — 1,727 Exploration — — 77 — — 77 Depletion,depreciation andamortization — — 38,118 19 — 38,137 Accretion of AROliability — — 297 — — 297 General andadministrative — 3,293 4,806 27 — 8,126 Total operatingexpenses — 3,293 52,570 46 — 55,909 Operating income(loss) — (2,697) (24,022) (46) — (26,765) Other income(expense) Interest expense — (12,727) (80) — — (12,807) Gain on debtextinguishment — 8,878 — — — 8,878 Net gain (loss) oncommodityderivatives — (40,002) — — — (40,002) Other income(expense) (267) (73) 2 — — (338) Other income(expense), net (267) (43,924) (78) — — (44,269) Income (loss) beforeincome tax (267) (46,621) (24,100) (46) — (71,034) Equity interest inincome (loss) (35,100) (35,667) — — 70,767 — Income tax provision(benefit) (12,122) (266) — — — (12,388) Net income (loss) (23,245) (82,022) (24,100) (46) 70,767 (58,646) Net income (loss)attributable to non-controlling interests — — — — (35,401) (35,401) Net income (loss)attributable tocontrolling interests $ (23,245) $ (82,022) $ (24,100) $ (46) $ 106,168 $ (23,245)

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Guarantor Non-

Guarantor (in thousands of dollars) JEI (Parent) Issuers Subsidiaries Subsidiaries Eliminations Consolidated Operating revenues Oil and gas sales $ — $ — $ 53,478 $ — $ — $ 53,478 Other revenues — 1,241 283 — — 1,524 Total operatingrevenues — 1,241 53,761 — — 55,002 Operating costs andexpenses Lease operating — — 16,162 — — 16,162 Production and advalorem taxes — — 3,328 — — 3,328 Exploration — — 239 — — 239 Depletion,depreciation andamortization — — 79,857 42 — 79,899 Accretion of AROliability — — 590 — — 590 General andadministrative — 6,171 9,407 52 — 15,630 Total operatingexpenses — 6,171 109,583 94 — 115,848 Operating income(loss) — (4,930) (55,822) (94) — (60,846) Other income(expense) Interest expense — (27,766) 161 — — (27,605) Gain on debtextinguishment — 99,530 — — — 99,530 Net gain (loss) oncommodityderivatives — (22,783) — — — (22,783) Other income(expense) 162 (274) (1) — — (113) Other income(expense), net 162 48,707 160 — — 49,029 Income (loss) beforeincome tax 162 43,777 (55,662) (94) — (11,817) Equity interest inincome (loss) (6,132) (5,847) — — 11,979 — Income tax provision(benefit) (1,636) (49) — — — (1,685) Net income (loss) (4,334) 37,979 (55,662) (94) 11,979 (10,132) Net income (loss)attributable to non-controlling interests — — — — (5,798) (5,798) Net income (loss)attributable tocontrolling interests $ (4,334) $ 37,979 $ (55,662) $ (94) $ 17,777 $ (4,334)

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Jones Energy, Inc.Condensed Consolidating Statement of Cash Flows


Guarantor Non-Guarantor

(in thousands of dollars) JEI

(Parent) Issuers Subsidiaries Subsidiaries Eliminations Consolidated Cash flows from operating activities Net income (loss) $ (90,626) $ (45,148) $ (194,723) $ (176) $ 181,826 $ (148,847) Adjustments to reconcile net income (loss)to net cash provided by operating activities 60,656 (2,685) 294,004 176 (181,826) 170,325

Net cash (used in) / provided byoperations (29,970) (47,833) 99,281 — — 21,478

Cash flows from investing activities Additions to oil and gas properties — — (107,250) — — (107,250) Net adjustments to purchase price ofproperties acquired — — 2,391 — — 2,391 Proceeds from sales of assets — — 2,730 — — 2,730 Acquisition of other property, plant andequipment — — (436) — — (436) Current period settlements of maturedderivative contracts — 45,738 — — — 45,738

Net cash (used in) / provided byinvesting — 45,738 (102,565) — — (56,827)

Cash flows from financing activities Proceeds from issuance of long-term debt — 75,000 — — — 75,000 Repayment of long-term debt — (72,000) — — — (72,000) Payment of cash dividends on preferredstock (3,367) — — — — (3,367) Net distributions paid to JEH unitholders 1,075 (1,637) — — — (562) Net payments for share based compensation — (462) — — — (462) Proceeds from sale of common stock 8,352 — — — — 8,352

Net cash (used in) / provided byfinancing 6,060 901 — — — 6,961 Net increase (decrease) in cash (23,910) (1,194) (3,284) — — (28,388)

Cash Beginning of period 27,164 1,975 5,483 20 — 34,642 End of period $ 3,254 $ 781 $ 2,199 $ 20 $ — $ 6,254

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Jones Energy, Inc.Condensed Consolidating Statement of Cash Flows


Guarantor Non-Guarantor

(in thousands of dollars) JEI

(Parent) Issuers Subsidiaries Subsidiaries Eliminations Consolidated Cash flows from operating activities Net income (loss) $ (4,334) $ 37,979 $ (55,662) $ (94) $ 11,979 $ (10,132) Adjustments to reconcile net income (loss)to net cash provided by operating activities 3,278 (86,767) 111,506 94 (11,979) 16,132

Net cash (used in) / provided byoperations (1,056) (48,788) 55,844 — — 6,000

Cash flows from investing activities Additions to oil and gas properties — — (27,592) — — (27,592) Proceeds from sales of assets — — 5 — — 5 Acquisition of other property, plant andequipment — — 12 — — 12 Current period settlements of maturedderivative contracts — 77,622 — — — 77,622

Net cash (used in) / provided byinvesting — 77,622 (27,575) — — 50,047

Cash flows from financing activities Proceeds from issuance of long-term debt — 75,000 — — — 75,000 Purchase of senior notes — (84,589) — — — (84,589) Net distributions paid to JEH unitholders 9,910 (20,019) — — — (10,109) Proceeds from sale of common stock 1,056 — — — — 1,056

Net cash (used in) / provided byfinancing 10,966 (29,608) — — — (18,642) Net increase (decrease) in cash 9,910 (774) 28,269 — — 37,405

Cash — Beginning of period 100 12,448 9,325 20 — 21,893 End of period $ 10,010 $ 11,674 $ 37,594 $ 20 $ — $ 59,298

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Item 2. Management’s Discussion and Analysi s of Financial Condition and Results of Operations Thefollowingdiscussionandanalysisofourfinancialconditionandresultsofoperationsshouldbereadinconjunctionwiththe“Management’sDiscussionandAnalysisofFinancialConditionandResultsofOperations”sectionandauditedconsolidatedfinancialstatementsandrelatednotestheretoincludedinourAnnualReportonForm10-KfortheyearendedDecember31,2016,filedonMarch10,2017withtheSecuritiesandExchangeCommission,andwiththeunauditedconsolidatedfinancialstatementsandrelatednotestheretopresentedinthisQuarterlyReportandinourquarterlyreportforthequarterendedMarch31,2017,filedonMay5,2017withtheSecuritiesandExchangeCommission.UnlessindicatedotherwiseinthisQuarterlyReportorthecontextrequiresotherwise,allreferencesto“JonesEnergy,”the“Company,”“ourcompany,”“we,”“our”and“us”refertoJonesEnergy,Inc.anditssubsidiaries,includingJonesEnergyHoldings,LLC(“JEH”).JonesEnergy,Inc.(“JONE”)isaholdingcompanywhosesolematerialassetisanequityinterestinJEH. Overview We are an independent oil and gas company engaged in the exploration, development, production and acquisition of oil and naturalgas properties in the mid-continent United States, spanning areas of Texas and Oklahoma. Our Chairman and CEO, Jonny Jones,founded our predecessor company in 1988 in continuation of his family’s long history in the oil and gas business, which dates back tothe 1920’s. We have grown rapidly by leveraging our focus on low cost drilling and completion methods and our horizontal drillingexpertise to develop our inventory and execute several strategic acquisitions. We have accumulated extensive knowledge andexperience in developing the Anadarko basin, having concentrated our operations in the Anadarko basin for over 25 years. We havedrilled over 880 total wells as operator, including approximately 705 horizontal wells, since our formation and delivered compellingrates of return over various commodity price cycles. Our operations are focused on horizontal drilling and completions within twodistinct areas in the Texas Panhandle and Oklahoma:

· the Eastern Anadarko Basin—targeting the liquids rich Woodford shale and Meramec formations in the Merge area of theSTACK/SCOOP (the “Merge”); and

· the Western Anadarko Basin—targeting the liquids rich Cleveland, Granite Wash, Tonkawa and Marmaton formations.

We seek to optimize returns through a disciplined emphasis on controlling costs and promoting operational efficiencies, and we arerecognized as one of the lowest cost drilling and completion operators in the Cleveland shale formation. We believe that our low-costdrilling expertise will apply directly to our new drilling in the Merge area, which is located approximately 150 miles to the east of ourCleveland play. Second Quarter and Year-to-Date 2017 Highlights:

· Reducing 2017 Capex budget to $250.0 million from $275.0 million, raising midpoint of 2017 production guidance net ofArkoma Basin divestiture.

· Average daily net production for second quarter 2017 of 23.8 Mboe/d.

· Dropped one core Cleveland rig late July. The plan is to drop second core Cleveland rig in September 2017.

· Second Meramec well GARRETT achieves 672 Bbls/d and 2,242 Mcf/d, with rates still increasing.

· Sold Arkoma Basin properties for $65.0 million, deal closing is credit accretive.

· Net loss for the second quarter of 2017 of $145.3 million, which includes a $161.9 million impairment charge related to the

Arkoma sale, non-GAAP adjusted net income of $5.7 million, or $0.12 per share and EBITDAX of $48.3 million.

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Updated Capital Expenditures Outlook We have revised our full year 2017 budget for capital expenditures to be $250.0 million versus the initial budget of $275.0 million.The updated budget reflects reduced activity in the Cleveland, realized and projected cost inflation, increased costs related to fracdesigns in the Merge, increased costs related to long lateral drilling, and less than anticipated non-op spending from the initial budget.The Company continues to have a high degree of flexibility in its program and could take further action if conditions merit

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Results of Operations

The following table sets forth selected financial data of Jones Energy, Inc. for the periods indicated.

(in thousands of dollars except for Three Months Ended June 30, Six Months Ended June 30, production, sales price and average cost data) 2017 2016 Change 2017 2016 Change Revenues: Oil $ 23,312 $ 16,108 $ 7,204 $ 41,579 $ 29,422 $ 12,157 Natural gas 12,767 5,115 7,652 24,194 11,657 12,537 NGLs 12,035 7,175 4,860 23,018 12,399 10,619 Total oil and gas 48,114 28,398 19,716 88,791 53,478 35,313

Other 512 746 (234) 1,068 1,524 (456) Total operating revenues 48,626 29,144 19,482 89,859 55,002 34,857

Costs and expenses: Lease operating 9,425 7,545 1,880 18,231 16,162 2,069 Production and ad valorem taxes 2,790 1,727 1,063 1,884 3,328 (1,444) Exploration 6,725 77 6,648 9,669 239 9,430 Depletion, depreciation and amortization 45,336 38,137 7,199 80,990 79,899 1,091 Impairment of oil and gas properties 161,886 — 161,886 161,886 — 161,886 Accretion of ARO liability 266 297 (31) 467 590 (123) General and administrative 8,633 8,126 507 16,674 15,630 1,044

Total costs and expenses 235,061 55,909 179,152 289,801 115,848 173,953 Operating income (loss) (186,435) (26,765) (159,670) (199,942) (60,846) (139,096)

Other income (expenses): Interest expense (12,677) (12,807) 130 (25,564) (27,605) 2,041 Gain on debt extinguishment — 8,878 (8,878) — 99,530 (99,530) Net gain (loss) on commodity derivatives 21,527 (40,002) 61,529 43,847 (22,783) 66,630 Other income/(expense) 29,834 (338) 30,172 30,414 (113) 30,527

Total other income (expense) 38,684 (44,269) 82,953 48,697 49,029 (332) Income (loss) before income tax (147,751) (71,034) (76,717) (151,245) (11,817) (139,428)

Income tax provision (benefit) (2,419) (12,388) 9,969 (2,398) (1,685) (713) Net income (loss) (145,332) (58,646) (86,686) (148,847) (10,132) (138,715) Net income (loss) attributable to non-controllinginterests (56,093) (35,401) (20,692) (58,221) (5,798) (52,423) Net income (loss) attributable to controlling interests $ (89,239) $ (23,245) $ (65,994) $ (90,626) $ (4,334) $ (86,292) Dividends and accretion on preferred stock (1,966) — (1,966) (3,993) — (3,993) Net income (loss) attributable to commonshareholders $ (91,205) $ (23,245) $ (67,960) $ (94,619) $ (4,334) $ (90,285) Net production volumes:

Oil (MBbls) 525 396 129 910 875 35 Natural gas (MMcf) 5,836 4,608 1,228 10,491 9,528 963 NGLs (MBbls) 668 529 139 1,206 1,084 122 Total (MBoe) 2,166 1,693 473 3,865 3,547 318 Average net (Boe/d) 23,802 18,604 5,198 21,354 19,489 1,865

Average sales price, unhedged: Oil (per Bbl), unhedged $ 44.40 $ 40.68 $ 3.72 $ 45.69 $ 33.63 $ 12.06 Natural gas (per Mcf), unhedged 2.19 1.11 1.08 2.31 1.22 1.09 NGLs (per Bbl), unhedged 18.02 13.56 4.46 19.09 11.44 7.65 Combined (per Boe), unhedged 22.21 16.77 5.44 22.97 15.08 7.89

Average sales price, hedged: Oil (per Bbl), hedged $ 61.30 $ 87.87 $ (26.57) $ 82.47 $ 85.77 $ (3.30) Natural gas (per Mcf), hedged 4.04 3.40 0.64 3.84 3.54 0.30 NGLs (per Bbl), hedged 15.36 17.64 (2.28) 14.65 17.33 (2.68) Combined (per Boe), hedged 30.49 35.33 (4.84) 34.42 35.96 (1.54)

Average costs (per BOE): Lease operating $ 4.35 $ 4.46 $ (0.11) $ 4.72 $ 4.56 $ 0.16 Production and ad valorem taxes 1.29 1.02 0.27 0.49 0.94 (0.45) Depletion, depreciation and amortization 20.93 22.53 (1.60) 20.95 22.53 (1.58) General and administrative 3.99 4.80 (0.81) 4.31 4.41 (0.10)

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Non-GAAP financial measures EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidatedfinancial statements, such as industry analysts, investors, lenders and rating agencies. We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, explorationexpense, gains and losses from derivatives less the current period settlements of matured derivative contracts and the other itemsdescribed below. EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles,or GAAP. Management believes EBITDAX is useful because it allows them to more effectively evaluate our operating performanceand compare the results of our operations from period to period and against our peers without regard to our financing methods orcapital structure. We exclude the items listed above from net income in arriving at EBITDAX because these amounts can varysubstantially from company to company within our industry depending upon accounting methods and book values of assets, capitalstructures and the method by which the assets were acquired. EBITDAX has limitations as an analytical tool and should not beconsidered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of ourliquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financialperformance, such as a company’s cost of capital and tax structure, as well as the historical costs of depreciable assets. Ourpresentation of EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurringitems. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. The following table sets forth a reconciliation of net income (loss) as determined in accordance with GAAP to EBITDAX for theperiods indicated:

Three Months Ended


June 30, (in thousands of dollars) 2017 2016 2017 2016 Reconciliation of EBITDAX to net income Net income (loss) $ (145,332) $ (58,646) $ (148,847) $ (10,132) Interest expense 12,677 12,807 25,564 27,605 Exploration expense 6,725 77 9,669 239 Income taxes (2,419) (12,388) (2,398) (1,685) Depreciation and depletion 45,336 38,137 80,990 79,899 Impairment of oil and natural gas properties 161,886 — 161,886 — Accretion of ARO liability 266 297 467 590 Change in TRA liability (29,931) 267 (30,599) (162) Other non-cash charges 1,266 1,645 1,307 1,111 Stock compensation expense 1,764 1,899 3,736 3,084 Deferred and other non-cash compensation expense 44 133 180 401 Net (gain) loss on derivative contracts (21,527) 40,002 (43,847) 22,783 Current period settlements of matured derivative contracts 17,921 31,410 44,253 74,081 Amortization of deferred revenue (484) (596) (942) (1,241) (Gain) loss on sale of assets 55 (3) 119 1 (Gain) on debt extinguishment — (8,878) — (99,530) Financing expenses and other loan fees 24 73 48 273 EBITDAX $ 48,271 $ 46,236 $ 101,586 $ 97,317

Adjusted Net Income and Adjusted Earnings per Share are supplemental non-GAAP financial measures that are used by managementand external users of the Company’s consolidated financial statements. We define Adjusted Net Income as net income excluding theimpact of certain non-cash items including gains or losses on commodity derivative instruments not yet settled, impairment of oil andgas properties, non-cash compensation expense, and the other items described below. We define Adjusted Earnings per Share asearnings per share plus that portion of the components of adjusted net income allocated to the controlling interests divided byweighted average shares outstanding. We believe adjusted net income and adjusted earnings per share are useful to investors becausethey provide readers with a more meaningful measure of our profitability before recording certain items for which the timing oramount cannot be reasonably determined. However, these measures are provided in addition to, not as an alternative for, and shouldbe read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP. Our

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computations of adjusted net income and adjusted earnings per share may not be comparable to other similarly titled measures of othercompanies. The following tables provide a reconciliation of net income (loss) as determined in accordance with GAAP to adjusted net income forthe periods indicated:

Three Months Ended


June 30, (in thousands except per share data) 2017 2016 2017 2016 Net income (loss) $ (145,332) $ (58,646) $ (148,847) $ (10,132)

Net (gain) loss on derivative contracts (21,527) 40,002 (43,847) 22,783 Current period settlements of matured derivative contracts 17,921 31,410 44,253 74,081 Impairment of oil and gas properties 161,886 — 161,886 — Exploration 6,725 77 9,669 239 Non-cash stock compensation expense 1,764 1,899 3,736 3,084 Deferred and other non-cash compensation expense 44 133 180 401 (Gain) on debt extinguishment — (8,878) — (99,530) Financing expenses — — — — Change in TRA liability (29,931) 267 (30,599) (162) Tax impact of adjusting items (1) (34,141) (11,390) (36,017) (331) Change in valuation allowance 48,261 (597) 49,173 392

Adjusted net income (loss) 5,670 (5,723) 9,587 (9,175) Adjusted net income (loss) attributable to non-controlling interests (3,991) (2,948) (3,018) (5,566) Adjusted net income (loss) attributable to controlling interests 9,661 (2,775) 12,605 (3,609) Dividends and accretion on preferred stock (1,966) — (3,993) — Adjusted net income (loss) attributable to common shareholders $ 7,695 $ (2,775) $ 8,612 $ (3,609) Earnings per share (basic and diluted): (2) $ (1.39) $ (0.69) $ (1.48) $ (0.13)

Net (gain) loss on derivative contracts (0.23) 0.59 (0.46) 0.34 Current period settlements of matured derivative contracts 0.19 0.46 0.46 1.10 Impairment of oil and gas properties 1.70 — 1.75 — Exploration 0.07 0.03 0.10 0.05 Non-cash stock compensation expense 0.02 — 0.04 0.01 Deferred and other non-cash compensation expense — (0.13) — (1.46) (Gain) on debt extinguishment — — — — Financing expenses — — — — Change in TRA liability (0.46) 0.01 (0.48) — Tax impact of adjusting items (1) (0.51) (0.33) (0.56) (0.01) Change in valuation allowance 0.73 (0.02) 0.77 0.01

Adjusted earnings per share (basic and diluted) $ 0.12 $ (0.08) $ 0.14 $ (0.09) Weighted average Class A shares outstanding: (2)

Basic 65,681 33,598 63,948 33,410 Diluted 65,681 33,598 63,948 33,410

Effective tax rate on net income (loss) attributable to controlling interests 40.3 % 36.8 % 40.0 % 36.8 %

(1) In arriving at adjusted net income, the tax impact of the adjustments to net income is determined by applying the appropriate taxrate to each adjustment and then allocating the tax impact between the controlling and non-controlling interests.

(2) All share and earnings per share information presented has been recast to retrospectively adjust for the effects of the 0.087423per share Special Stock Dividend, as defined in Note 11, “Stockholders’ and Mezzanine equity”, distributed on March 31, 2017.

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Results of Operations - Three months ended June 30, 2017 as compared to the three months ended June 30, 2016 Operating revenues Oilandgassales.Oil and gas sales increased $ 19.7 million, or 69.4%, to $48.1 million for the three months ended June 30, 2017, ascompared to $28.4 million for the three months ended June 30, 2016. The increase was attributable to the increase in productionvolumes ($10.9 million) and the increase in commodity prices ($8.8 million). The increase in production volumes was driven by theyear-over-year increase in producing wells due to continued drilling activity. The average realized oil price, excluding the effects ofcommodity derivative instruments, increased from $40.68 per Bbl for the three months ended June 30, 2016 to $44.40 per Bbl for thethree months ended June 30, 2017, or 9.1%. The average realized natural gas price, excluding the effects of commodity derivativeinstruments, increased from $1.11 per Mcf for the three months ended June 30, 2016 to $2.19 per Mcf for the three months ended June30, 2017, or 97.3%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments,increased from $13.56 per Bbl for the three months ended June 30, 2016 to $18.02 per Bbl for the three months ended June 30, 2017,or 32.9%. Average daily production increased 27.9% to 23,802 Boe per day for the three months ended June 30, 2017 as compared to18,604 Boe per day for the three months ended June 30, 2016. Costs and expenses Leaseoperating.Lease operating expenses increased by $1.9 million, or 25.3%, to $9.4 million for the three months ended June 30,2017, as compared to $7.5 million for the three months ended June 30, 2016. The increase in lease operating expenses is primarilyattributable to the increase in number of producing wells. On a per unit basis, lease operating expenses decreased $0.11 per Boe, or2.5%, from $4.46 per Boe in the three months ended June 30, 2016 to $4.35 per Boe in the three months ended June 30, 2017. Productionandadvaloremtaxes.Production and ad valorem taxes increased by $1.1 million, or 64.7%, to $2.8 million for the threemonths ended June 30, 2017, as compared to $1.7 million for the three months ended June 30, 2016. Production taxes increased $0.9million, from $1.4 million for the three months ended June 30, 2016 to $2.3 million for the three months ended June 30, 2017. Theincrease was attributable to the increase in production volumes. Production tax rates vary between states, products, and productionlevels; therefore, the overall blended rate is impacted by numerous factors and the mix of producing wells at any given time. Further,estimated ad valorem taxes increased $0.2 million, from $0.3 million for the three months ended June 30, 2016 to $0.5 million for thethree months ended June 30, 2017. The average effective rate excluding the impact of ad valorem taxes remained constant at 4.8% forthe three months ended June 30, 2016 and 2017. Exploration.Exploration expense increased from $0.1 million for the three months ended June 30, 2016 to $6.7 million for the threemonths ended June 30, 2017. The Company recognized charges for lease abandonment of $5.2 million relating to certain leases thatthe Company decided during the second quarter of 2017 not to develop. Spending during 2017 primarily related to geological data andseismic processing associated with unproved acreage. No exploratory wells resulted in exploration expense during the second quarterof either year. Depreciation,depletionandamortization.Depreciation, depletion and amortization increased by $7.2 million, or 18.9%, to $45.3million for the three months ended June 30, 2017, as compared to $38.1 million for the three months ended June 30, 2016. Theincrease was primarily the result of capital spending related to our drilling program. On a per unit basis, depletion expense decreased$1.60 per Boe or 7.1% from $22.53 per Boe for the three months ended June 30, 2016 as compared to $20.93 per Boe for the threemonths ended June 30, 2017. The decrease was primarily the result of lower production and capital spending throughout 2016, drivenby a temporary suspension of the drilling program late in 2015 and continuing into early 2016. Impairmentofoilandgasproperties.As of June 30, 2017, the Company’s Arkoma Basin oil and gas property assets and relatedliabilities were classified as held for sale due to the pending Arkoma Divestiture. Based on the Company’s anticipated sales price, animpairment charge of $161.9 million was recognized at June 30, 2017 due to the loss on disposal. No impairment charges wererecognized during the three months ended June 30, 2016. Generalandadministrative.General and administrative expenses increased by $0.5 million, or 6.2%, to $8.6 million for the threemonths ended June 30, 2017, as compared to $8.1 million for the three months ended June 30, 2016. The increase was driven by alitigation settlement for which the Company recognized an additional charge of $1.4 million

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during the three months ended June 30, 2017, offset by reductions in other costs. Non-cash compensation expense decreased $0.2million, from $2.0 million for the three months ended June 30, 2016 to $1.8 million for the three months ended June 30, 2017. On aper unit basis, general and administrative expenses, excluding all non-cash items, decreased from $2.63 per Boe for the three monthsended June 30, 2016 to $2.57 per Boe for the three months ended June 30, 2017. Interestexpense.Interest expense decreased by $0.1 million, or 0.8%, to $12.7 million for three months ended June 30, 2017, ascompared to $12.8 million for the three months ended June 30, 2016. The decrease was driven by a reduction in the outstandingbalance of the 2022 Notes and the 2023 Notes as a result of our 2016 debt extinguishments. During the three months ended June 30,2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.84%, 6.75%and 9.25%, respectively. Average outstanding balances for the three months ended June 30, 2017 were $194.6 million, $409.1 millionand $150.0 million under the Revolver, the 2022 Notes and the 2023 Notes, respectively. Netgain(loss)oncommodityderivatives.The net gain (loss) on commodity derivatives was a net gain of $21.5 million for the threemonths ended June 30, 2017, as compared to a net loss of $40.0 million for the three months ended June 30, 2016. The gain wasprimarily driven by lower average crude oil and natural gas prices ($48.10 per barrel and $3.08 per Mcf, respectively) for the threemonths ended June 30, 2017, as compared to the crude oil and natural gas prices as of March 31, 2017 ($50.54 per barrel and$3.13 per Mcf, respectively). Additionally, the Company unwound a portion of its realized 2018 hedges resulting in gains ofapproximately $8.1 million for the three months ended June 30, 2017. See Note 6, “Derivative Instruments and Hedging Activities,”for further details. Otherincome(expense).Other income (expense) for the three months ended June 30, 2017 was a net income of $29.8 million, ascompared to a net expense of $0.3 million for the three months ended June 30, 2016. Other income (expense) during the six monthsended June 30, 2017 primarily related to an increase in the TRA valuation allowance which resulted in income of $29.9 million. Incometaxes.The provision for federal and state income taxes for the three months ended June 30, 2017 was a benefit of $2.4 millionresulting in a 1.6% effective tax rate as a percentage of our pre-tax book income for the quarter as compared to a benefit of $12.4million resulting in a 17.4% effective tax rate as a percentage of our pre-tax book income for the three months ended June 30, 2016.Our effective tax rate is based on the statutory rate applicable to the U.S. and the blended rate of the states in which we conductbusiness and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest. The effective taxrate reduction is primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets. See Note10, “Income Taxes,” for further details. Results of Operations - Six months ended June 30, 2017 as compared to the six months ended June 30, 2016 Operating revenues Oilandgassales.Oil and gas sales increased $35.3 million, or 66.0%, to $88.8 million for the six months ended June 30, 2017, ascompared to $53.5 million for the six months ended June 30, 2016. The increase was attributable to the increase in commodity prices($29.2 million) and the increase in production volumes ($6.1 million). The increase in production volumes was driven by the year-over-year increase in producing wells due to continued drilling activity. The average realized oil price, excluding the effects ofcommodity derivative instruments, increased from $33.63 per Bbl for the six months ended June 30, 2016 to $45.69 per Bbl for the sixmonths ended June 30, 2017, or 35.9%. The average realized natural gas price, excluding the effects of commodity derivativeinstruments, increased from $1.22 per Mcf for the six months ended June 30, 2016 to $2.31 per Mcf for the six months ended June 30,2017, or 89.3%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increasedfrom $11.44 per Bbl for the six months ended June 30, 2016 to $19.09 per Bbl for the six months ended June 30, 2017, or 66.9%.Average daily production increased 9.6% to 21,354 Boe per day for the six months ended June 30, 2017 as compared to 19,489 Boeper day for the six months ended June 30, 2016. Costs and expenses Leaseoperating.Lease operating expenses increased by $2.0 million, or 12.3%, to $18.2 million for the six months ended June 30,2017, as compared to $16.2 million for the six months ended June 30, 2016. The increase in lease operating expenses is primarilyattributable to the increase in number of producing wells. On a per unit basis, lease

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operating expenses increased $0.16 per Boe, or 3.5%, from $4.56 per Boe in the six months ended June 30, 2016 to $4.72 per Boe inthe six months ended June 30, 2017. Productionandadvaloremtaxes.Production and ad valorem taxes decreased by $1.4 million, or 42.4%, to $1.9 million for the sixmonths ended June 30, 2017, as compared to $3.3 million for the six months ended June 30, 2016. During the first quarter of 2017, theCompany's application for High-Cost Gas Incentive refunds in Texas was approved for qualified wells on which taxes were initiallypaid between October 2012 and September 2016. The Company received a net production tax refund of $3.3 million during the sixmonths ended June 30, 2017, which was recorded as a reduction in Production and ad valorem taxes on the Company’s ConsolidatedStatement of Operations. Production taxes, excluding the impact of this refund, increased from $2.5 million for the six months endedJune 30, 2016 to $4.1 million for the six months ended June 30, 2017. The increase was attributable to the increase in productionvolumes. Production tax rates vary between states, products, and production levels; therefore, the overall blended rate is impacted bynumerous factors and the mix of producing wells at any given time. Further, estimated ad valorem taxes increased $0.3 million from$0.7 million for the six months ended June 30, 2016 to $1.0 million for the six months ended June 30, 2017. The average effective rateexcluding the impact of ad valorem taxes decreased from 4.8% for the six months ended June 30, 2016 to 1.0% for the six monthsended June 30, 2017. Exploration.Exploration expense increased from $0.2 million for the six months ended June 30, 2016 to $9.7 million for the sixmonths ended June 30, 2017. The Company recognized charges for lease abandonment of $6.9 million relating to certain leases thatthe Company decided during 2017 not to develop. Spending during 2017 primarily related to geological data and seismic processingassociated with unproved acreage. No exploratory wells resulted in exploration expense during the six months ended June 30 of eitheryear. Depreciation,depletionandamortization.Depreciation, depletion and amortization increased by $1.1 million, or 1.4%, to $81.0million for the six months ended June 30, 2017, as compared to $79.9 million for the six months ended June 30, 2016. The increasewas primarily the result of capital spending related to our drilling program. On a per unit basis, depletion expense decreased $1.58 perBoe or 7.0% from $22.53 per Boe for the six months ended June 30, 2016 as compared to $20.95 per Boe for the six months endedJune 30, 2017. The decrease was primarily the result of lower production and capital spending throughout 2016, driven by atemporary suspension of the drilling program late in 2015 and continuing into early 2016. Impairmentofoilandgasproperties.As of June 30, 2017, the Company’s Arkoma Basin oil and gas property assets and relatedliabilities were classified as held for sale due to the pending Arkoma Divestiture. Based on the Company’s anticipated sales price, animpairment charge of $161.9 million was recognized at June 30, 2017 due to the loss on disposal. No impairment charges wererecognized during the six months ended June 30, 2016. Generalandadministrative.General and administrative expenses increased by $1.1 million, or 7.1%, to $16.7 million for the sixmonths ended June 30, 2017, as compared to $15.6 million for the six months ended June 30, 2016. The increase was driven by alitigation settlement for which the Company recognized an additional charge of $1.4 million during the six months ended June 30,2017, offset by reductions in other costs. Non-cash compensation expense increased $0.4 million, from $3.5 million for the six monthsended June 30, 2016 to $3.9 million for the six months ended June 30, 2017. On a per unit basis, general and administrative expenses,excluding all non-cash items, decreased from $3.11 per Boe for the six months ended June 30, 2016 to $2.96 per Boe for the sixmonths ended June 30, 2017. Interestexpense.Interest expense decreased by $2.0 million, or 7.2%, to $25.6 million for six months ended June 30, 2017, ascompared to $27.6 million for the six months ended June 30, 2016. The decrease was driven by a reduction in the outstanding balanceof the 2022 Notes and the 2023 Notes as a result of our 2016 debt extinguishments. During the six months ended June 30, 2017,borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.72%, 6.75% and9.25%, respectively. Average outstanding balances for the six months ended June 30, 2017 were $194.9 million, $409.1 million and$150.0 million under the Revolver, the 2022 Notes and the 2023 Notes, respectively. Netgain(loss)oncommodityderivatives.The net gain (loss) on commodity derivatives was a net gain of $43.8 million for the sixmonths ended June 30, 2017, as compared to a net loss of $22.8 million for the six months ended June 30, 2016. The gain wasprimarily driven by lower average crude oil and natural gas prices ($49.85 per barrel and $3.05 per Mcf, respectively) for the sixmonths ended June 30, 2017, as compared to the crude oil and natural gas prices as of December 31, 2016 ($53.75 per barrel and$3.71 per Mcf, respectively). Additionally, the Company unwound a portion

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of its realized 2018 and 2019 hedges resulting in gains of approximately $28.0 million for the six months ended June 30, 2017. SeeNote 6, “Derivative Instruments and Hedging Activities,” for further details. Otherincome(expense).Other income (expense) for the six months ended June 30, 2017 was a net income of $30.4 million, ascompared to a net expense of $0.1 million for the six months ended June 30, 2016. Other income (expense) during the six monthsended June 30, 2017 primarily related to an increase in the TRA valuation allowance which resulted in income of $30.6 million. Incometaxes.The provision for federal and state income taxes for the six months ended June 30, 2017 was a benefit of $2.4 millionresulting in a 1.6% effective tax rate as a percentage of our pre-tax book income for the quarter as compared to a benefit of $1.7million resulting in a 14.3% effective tax rate as a percentage of our pre-tax book income for the six months ended June 30, 2016. Oureffective tax rate is based on the statutory rate applicable to the U.S. and the blended rate of the states in which we conduct businessand is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest. The effective tax ratereduction is primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets. See Note 10,“Income Taxes,” for further details. Liquidity and Capital Resources Historically, our primary sources of liquidity have been private and public sales of our debt and equity, borrowings under bank creditfacilities and cash flows from operations. Our primary use of capital has been for the exploration, development and acquisition of oiland gas properties. As we pursue reserves and production growth, we continually consider which capital resources, including equityand debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidityrequirements. Our ability to grow proved reserves and production will be highly dependent on the capital resources available to us.We strive to maintain financial flexibility in order to maintain substantial borrowing capacity under our Revolver (as defined below),facilitate drilling on our undeveloped acreage positions and permit us to selectively expand our acreage positions. Depending on theprofitability, timing and concentration of the development of our non-proved locations, we may be required to generate or raisesignificant amounts of capital to develop all of our potential drilling locations should we endeavor to do so. In the event ourprofitability or cash flows are materially less than anticipated and other sources of capital we historically have utilized are notavailable on acceptable terms, we may curtail our capital spending. Our balance sheet at June 30, 2017 reflects a negative workingcapital balance. We have historically and in the future expect to maintain a negative working capital balance, and we use our Revolverto help manage our working capital. Availability under the Revolver is subject to a borrowing base, as well as financial covenants. Our borrowing base at June 30, 2017was $425.0 million of which $181.0 million was utilized leaving an unused capacity of $244.0 million. On August 1, 2017, uponclosing of the Arkoma Divestiture, the Company’s borrowing base was reduced to $375.0 million. The borrowing base will be re-determined at least semi-annually on or about April 1 and October 1 of each year, with such re-determination based primarily onreserve reports using lender commodity price expectations at such time. Any reduction in the borrowing base will reduce our liquidity,and, if the reduction results in the outstanding amount under our Revolver exceeding the borrowing base, we will be required to repaythe deficiency within a short period of time. The financial covenants may further constrain our ability to borrow under our Revolver. The Revolver also contains a covenant which restricts the ability of Jones Energy, Inc. to (i) hold any assets, (ii) incur, create, assume,or suffer to exist any debt or any other liability or obligation, (iii) create, make or enter into any investment or (iv) engage in any otheractivity or operation other than, among other exceptions described therein, its ownership of equity interests in JEH and the activities ofa passive holding company and assets and operations incidental thereto (including the maintenance of cash and reserves for thepayment of operational costs and expenses). Jones Energy, Inc. and its consolidated subsidiaries are also subject to certain covenants under the Revolver, including therequirement to maintain the following financial ratios:

· a total leverage ratio, consisting of consolidated debt to EBITDAX, of not greater than 4.00 to 1.00 as of the last day of anyfiscal quarter; and

· a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to

consolidated current liabilities, of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

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As of June 30, 2017, our total leverage ratio was 3.84x and our current ratio was 2.70x, as calculated based on the requirements in ourcovenants. We were in compliance with all terms of our Revolver at June 30, 2017, and we expect to maintain compliance throughoutthe next twelve-month period. However, factors including those outside of our control, such as commodity price declines, may preventus from maintaining compliance with these covenants, at future measurement dates in 2017 and beyond. In the event it were tobecome necessary, we believe we have the ability to take actions that would prevent us from failing to comply with our covenants,such as hedge restructuring or seeking a waiver of such covenants. If an event of default exists under the Revolver, the lenders wouldbe able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver containscustomary events of default, including the occurrence of a change of control, as defined in the Revolver. The Company routinely enters into oil and natural gas swap contracts as seller, thus resulting in a fixed price. During 2016 and 2017,the Company realized certain mark-to-market gains associated with oil and natural gas hedges the Company had in place for years2018 and 2019. The gains were effectively realized by purchasing, as opposed to selling, oil and natural gas swap contracts for theequal volume that was associated with the initial hedge transaction. During the three and six months ended June 30, 2017, theCompany unwound a portion of its realized 2018 and 2019 hedges resulting in approximately $8.1 million and $28.0 million,respectively, of recognized gains which have been included in Net gain (loss) on commodity derivatives on the Company’sConsolidated Statement of Operations. The estimated mark-to-market value of the Company’s remaining realized gains as a result ofthese offsetting hedges were approximately $15.1 million relating to the year ended December 31, 2018, incorporating NYMEX strippricing as of July 28, 2017, but excluding adjustments for credit risk. The amount, timing and allocation of capital expenditures are largely discretionary and within management’s control. If oil and gasprices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we may choose to defer aportion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses ofliquidity and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cashflow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. Wecontinuously monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities,changes in prices, availability of financing, drilling and completion costs, industry conditions, the availability of rigs, contractualobligations, internally generated cash flow and other factors both within and outside our control. The following table summarizes our cash flows for the six months ended June 30, 2017 and 2016:

Six Months Ended

June 30, (in thousands of dollars) 2017 2016 Net cash provided by operating activities $ 21,478 $ 6,000 Net cash (used in) / provided by investing activities (56,827) 50,047 Net cash provided by / (used in) financing activities 6,961 (18,642) Net increase (decrease) in cash $ (28,388) $ 37,405 Cash flow provided by operating activities Net cash provided by operating activities was $21.5 million during the six months ended June 30, 2017 as compared to $6.0 millionduring the six months ended June 30, 2016. The increase in operating cash flows was primarily due to the $35.3 million increase in oiland gas revenues for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016, primarily driven by theincrease in commodity prices. Cash flow (used in) / provided by investing activities Net cash used in investing activities was $56.8 million during the six months ended June 30, 2017 as compared to net cash providedby investing activities of $50.0 million during the six months ended June 30, 2016. The decrease in investing cash flow was primarilydriven by increased capital spending, following the temporary suspension of the drilling program late in 2015 and continuing intoearly 2016.

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Cash flow provided by / (used in) financing activities

Net cash provided by financing activities was $7.0 million during the six months ended June 30, 2017 as compared to net cash used infinancing activities of $18.6 million during the six months ended June 30, 2016. The increase in financing cash flows was primarilydue to a reduction of $12.6 million in cash used toward reducing outstanding borrowings. During the six months ended June 30, 2017,the Company made repayments of $72.0 million toward borrowings under the Revolver, as compared to cash of $84.6 million used topurchase an aggregate principal amount of $190.9 million of our senior unsecured notes during the six months ended June 30, 2016.Also contributing to the increase in cash flows was a reduction of $9.5 million in cash tax distributions, from $10.1 million during thesix months ended June 30, 2016 to $0.6 million during the six months ended June 30, 2017. Additionally, there was an increase inproceeds from the sale of Class A common stock of $7.2 million, from $1.1 million during the six months ended June 30, 2016 to $8.4million during the six months ended June 30, 2017. These increases in cash flow were partially offset by the payment of dividends onSeries A preferred stock of $3.4 million during the six months ended June 30, 2017. Contractual Obligations The holders of JEH Units, including us, incur U.S. federal, state and local income taxes on their share of any taxable income of JEH.Under the terms of its operating agreement, JEH is generally required to make quarterly pro-rata cash tax distributions to itsunitholders (including us) based on income allocated to its unitholders through the end of each relevant quarter, as adjusted to takeinto account good faith projections by the Company of taxable income or loss for the remainder of the calendar year, to the extent JEHhas cash available for such distributions and subject to certain other restrictions. This tax distribution is computed based on theestimate of net taxable income of JEH allocated to each holder of JEH Units multiplied by the highest marginal effective rate offederal, state and local income tax applicable to an individual resident in New York, New York, without regard for the federal benefitof the deduction for any state taxes. During 2016, JEH generated taxable income, resulting in the payment of cash tax distributions to JEH unitholders. As a result ofJEH’s 2016 taxable income (all of which is passed-through and taxed to us and JEH’s other unitholders), during the first quarter of2017, we made further income tax payments to federal and state taxing authorities of $4.1 million and JEH made further taxdistributions to JEH unitholders (other than us) of $0.6 million. Based on information available as of this filing, we do not anticipate that we will be required to make any additional tax payments orthat JEH will make any additional tax distributions during the remainder of 2017. Estimating the tax distributions required under theoperating agreement is imprecise by nature, highly uncertain, and dependent upon a variety of factors. There have been no other material changes in our contractual obligations as reported in our Annual Report on Form 10-K for the yearended December 31, 2016. Off-Balance Sheet Arrangements We do not have any off-balance sheet arrangements. Critical Accounting Policies and Estimates There have been no changes to our critical accounting policies and estimates from those set forth in our Annual Report on Form 10-Kfor the year ended December 31, 2016. Item 3. Quantitative and Qualitative Disclosure s about Market Risk The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market riskcontained in our Annual Report on Form 10-K for the year ended December 31, 2016, as well as with the unaudited consolidatedfinancial statements and notes included in this Quarterly Report. We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. Wemay enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculativepurposes. We do not designate these or future derivative instruments as hedges for

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accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings. Potential Impairment of Oil and Gas Properties Oil and natural gas prices are inherently volatile and have decreased significantly since 2014. Depressed commodity prices havecontinued into 2017 and historically low commodity prices may exist for an extended period. Taking into consideration the businessenvironment in which we operate, we continually review our held for use oil and gas properties for indicators of potential impairmenton an undiscounted basis. While no such indicators were present at June 30, 2017, assets held for sale related to the ArkomaDivestiture were written down to the estimated selling price resulting in an impairment charge of $161.9 million. Our revenues and net income are sensitive to crude oil, NGL and natural gas prices which have been and are expected to continue tobe highly volatile. The recent volatility in crude oil and natural gas prices increases the uncertainty as to the impact of commodityprices on our estimated proved reserves. Although we are unable to predict future commodity prices, a prolonged period of depressedcommodity prices may have a significant impact on the volumetric quantities of our proved reserves. The impact of commodity priceson our estimated proved reserves can be illustrated as follows: if the prices used for our December 31, 2016 Reserve Report had beenreplaced with the unweighted arithmetic average of the first-day-of-the-month prices for the applicable commodity for the trailingtwelve-month period ended June 30, 2017 (without regard to our commodity derivative positions and without assuming any change indevelopment plans, costs, or other variables), then estimated proved reserves volumes as of December 31, 2016 would have increasedby approximately 3.1%. The use of this pricing example is for illustration purposes only, and does not indicate management’s view onfuture commodity prices, costs or other variables, or represent a forecast or estimate of the actual amount by which our provedreserves may fluctuate when a full assessment of our reserves is completed as of December 31, 2017. Periodic revisions to the estimated reserves and related future cash flows may be necessary as a result of a number of factors,including changes in oil and natural gas prices, reservoir performance, new drilling and completion, purchases, sales and terminationsof leases, drilling and operating cost changes, technological advances, new geological or geophysical data or other economic factors.All of these factors are inherently estimates and are inter dependent. While each variable carries its own degree of uncertainty, somefactors, such as oil and natural gas prices, have historically been highly volatile and may be highly volatile in the future. This highdegree of volatility causes a high degree of uncertainty associated with the estimation of reserve quantities and estimated future cashflows. Therefore, future results are highly uncertain and subject to potentially significant revisions. Accordingly, reserve estimates aregenerally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing offuture reserve revisions, as such revisions could be negatively impacted by:

· Declines in commodity prices or actual realized prices below those assumed for future years; · Increases in service costs; · Increases in future global or regional production or decreases in demand; · Increases in operating costs; · Reductions in availability of drilling, completion, or other equipment.

If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment ofassets that may be material. Any future impairments are difficult to predict, and although it is not reasonably practicable to quantifythe impact of any future impairments at this time, such impairments may be significant. Commodity price risk and hedges Our principal market risk exposure is to oil, natural gas and NGL prices, which are inherently volatile. As such, future earnings aresubject to change due to fluctuations in such prices. Realized prices are primarily driven by the prevailing prices for oil and regionalspot prices for natural gas and NGLs. We have used, and expect to continue to use, oil, natural

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gas and NGL derivative contracts to reduce our risk of price fluctuations of these commodities. Pursuant to our risk managementpolicy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. Thefair value of our oil, natural gas and NGL derivative contracts at June 30, 2017 was a net asset of $42.6 million. Counterparty risk Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. We evaluate the credit standing ofour counterparties, but do not require them to post collateral. The majority of our derivative contracts currently in place are withlenders under our Revolver, who have investment grade ratings. Interest rate risk We are subject to market risk exposure related to changes in interest rates on our variable rate indebtedness. The terms of the seniorsecured revolving credit facility provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plusmargins ranging from 0.50% to 2.50% depending on the base rate used and the amount of the loan outstanding in relation to theborrowing base. The base rate margins under the terminated term loan were 6.0% to 7.0% depending on the base rate used and theamount of the loan outstanding. The terms of our senior notes provide for a fixed interest rate through their respective maturity dates.During the three months ended June 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at aweighted average rate of 2.84%, 6.75% and 9.25%, respectively. During the six months ended June 30, 2017, borrowings under theRevolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.72%, 6.75% and 9.25%, respectively. Item 4. Controls and Procedure s Changes in Internal Control over Financial Reporting There have been no changes in internal control over financial reporting during the quarter ended June 30, 2017 that have materiallyaffected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. Evaluation of Disclosure Controls and Procedures As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of ourmanagement, including our principal executive officer and principal financial officer, the effectiveness of the design and operation ofour disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of theperiod covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that theinformation required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to ourmanagement, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisionsregarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules andforms of the SEC. Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectivenessof the design and operation of our disclosure controls and procedures. Based on that evaluation, our principal executive officer andprincipal financial officer concluded that as of June 30, 2017, the end of the period covered by this report, our disclosure controls andprocedures are effective at a reasonable assurance level. Management’s Assessment of Internal Control over Financial Reporting The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring every public company that files reports withthe SEC to include a management report on such company’s internal control over financial reporting in its annual report. Pursuant tothe Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), our independent registered public accounting firm will not berequired to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-OxleyAct of 2002 for up to five years or through such earlier date that we are no longer an “emerging growth company” as defined in theJOBS Act. Our Annual Report on Form 10-K for the year ended December 31, 2016 included a report of management’s assessmentregarding internal control over financial reporting.

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PART II—OTHER INFORMATIO N Item 1. Legal Proceeding s For a discussion of legal proceedings, see Note 14 “Commitments and Contingencies,” in the Notes to Consolidated FinancialStatements for further discussion appearing in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated in this itemby reference. Item 1A. Risk Factor s Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings, including ourAnnual Report on Form 10-K for the year ended December 31, 2016, could have a material impact on our business, financial positionor results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial mayalso impair our business operations. For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our Annual Report onForm 10-K for the year ended December 31, 2016. There have been no material changes in our risk factors from those described inour Annual Report for the year ended December 31, 2016. Item 2. Unregistered Sales of Equity Securitie s and Use of Proceeds None. Item 3. Defaults Upon Senior Securitie s None. Item 4. Mine Safety Disclosure s Not applicable. Item 5. Other Informatio n Not applicable. Item 6. Exhibit s Exhibit No. Description2.1*

Purchase and Sale Agreement, dated June 22, 2017, between Jones Energy Holdings, LLC and the purchaser partythereto.

4.1

Amended and Restated Registration Rights and Stockholders Agreement, dated May 2, 2017, among Jones Energy,Inc., Jones Energy Holdings, LLC and the other parties thereto (incorporated by reference to the Quarterly Report onForm 10-Q filed with the Securities and Exchange Commission on May 5, 2017).

31.1* Rule 13a-14(a)/15d-14(a) Certification of Jonny Jones (Principal Executive Officer).31.2* Rule 13a-14(a)/15d-14(a) Certification of Robert J. Brooks (Principal Financial Officer).32.1** Section 1350 Certification of Jonny Jones (Principal Executive Officer).32.2** Section 1350 Certification of Robert J. Brooks (Principal Financial Officer).101.INS* XBRL Instance Document.101.SCH* XBRL Taxonomy Extension Schema Document.101.CAL* XBRL Taxonomy Extension Calculation Linkbase Document.101.DEF* XBRL Taxonomy Extension Definition Linkbase Document.101.LAB* XBRL Taxonomy Extension Label Linkbase Document.101.PRE* XBRL Taxonomy Extension Presentation Linkbase Document.

* - filed herewith** - furnished herewith

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SIGNATURE S

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

Jones Energy, Inc.(registrant)

Date: August 7, 2017 By: /s/ Robert J. BrooksName: Robert J. BrooksTitle: Chief Financial Officer (Principal Financial Officer)

SignaturePagetoForm10-Q(Q22017)

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Execution Version

PURCHASE AND SALE AGREEMENT

BETWEEN

JONES ENERGY HOLDINGS, LLC,

AS SELLER

AND

FOUNDATION ENERGY FUND VI-A, LP,

AS PURCHASER

Executed on June 22, 2017

TABLE OF CONTENTS

PageARTICLE 1 PURCHASE AND SALE 1

Section 1.1 Purchase and Sale. 1Section 1.2 Assets. 1Section 1.3 Excluded Assets. 3Section 1.4 Effective Time; Proration of Costs and Revenues. 5Section 1.5 Delivery and Maintenance of Records and Retained Records. 6

ARTICLE 2 PURCHASE PRICE 7Section 2.1 Purchase Price. 7Section 2.2 Adjustments to Purchase Price. 7Section 2.3 Allocation of Purchase Price. 9Section 2.4 Deposit. 9

ARTICLE 3 TITLE MATTERS 10Section 3.1 Seller’s Title. 10Section 3.2 Certain Definitions. 10Section 3.3 Definition of Permitted Encumbrances. 12Section 3.4 Notice of Title Defects Defect Adjustments. 14Section 3.5 Consents to Assignment and Preferential Rights to Purchase. 18Section 3.6 Casualty or Condemnation Loss. 20Section 3.7 Limitations on Applicability. 21

ARTICLE 4 ENVIRONMENTAL MATTERS 21Section 4.1 Assessment. 21Section 4.2 NORM. 22Section 4.3 Notice of Violations of Environmental Laws. 22Section 4.4 Remedies for Violations of Environmental Laws. 23Section 4.5 Limitations. 25

ARTICLE 5 REPRESENTATIONS AND WARRANTIES OF SELLER 25Section 5.1 Disclaimers. 25Section 5.2 Existence and Qualification. 27Section 5.3 Power. 28Section 5.4 Authorization and Enforceability. 28Section 5.5 No Conflicts. 28Section 5.6 Liability for Brokers’ Fees. 28Section 5.7 Litigation. 28Section 5.8 Taxes and Assessments. 29Section 5.9 Outstanding Capital Commitments. 29Section 5.10 Compliance with Laws. 29Section 5.11 Contracts. 29Section 5.12 Payments for Production. 30Section 5.13 Governmental Authorizations. 30

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TABLE OF CONTENTS(continued)

Page

Section 5.14 Consents and Preferential Purchase Rights. 30Section 5.15 Environmental Laws. 30Section 5.16 Bankruptcy. 31Section 5.17 Imbalances. 31Section 5.18 Oil and Gas Operations. 31Section 5.19 Non-Consent Operations. 31Section 5.20 Sufficiency of Assets. 31

ARTICLE 6 REPRESENTATIONS AND WARRANTIES OF PURCHASER 31Section 6.1 Existence and Qualification. 31Section 6.2 Power. 32Section 6.3 Authorization and Enforceability. 32Section 6.4 No Conflicts. 32Section 6.5 Liability for Brokers’ Fees. 32Section 6.6 Litigation. 32Section 6.7 Financing. 33Section 6.8 Independent Investigation. 33Section 6.9 Bankruptcy. 34Section 6.10 Qualification. 34Section 6.11 Consents. 34

ARTICLE 7 COVENANTS OF THE PARTIES 34Section 7.1 Access. 34Section 7.2 Government Reviews. 35Section 7.3 Notification of Breaches. 35Section 7.4 Operatorship. 35Section 7.5 Operation of Business. 36Section 7.6 Indemnity Regarding Access. 37Section 7.7 Other Preferential Rights. 37Section 7.8 Tax Matters. 38Section 7.9 Special Warranty of Title. 40Section 7.10 Suspended Proceeds. 41Section 7.11 Further Assurances. 41Section 7.12 Contingent Payment. 41

ARTICLE 8 CONDITIONS TO CLOSING 43Section 8.1 Conditions of Seller to Closing. 43Section 8.2 Conditions of Purchaser to Closing. 44

ARTICLE 9 CLOSING 45Section 9.1 Time and Place of Closing. 45Section 9.2 Obligations of Seller at Closing. 45Section 9.3 Obligations of Purchaser at Closing. 46

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TABLE OF CONTENTS(continued)

Page

Section 9.4 Closing Payment and Post-Closing Purchase Price Adjustments. 46ARTICLE 10 TERMINATION 48

Section 10.1 Termination. 48Section 10.2 Effect of Termination. 48Section 10.3 Distribution of Deposit Upon Termination. 48

ARTICLE 11 POST-CLOSING OBLIGATIONS; INDEMNIFICATION; LIMITATIONS;DISCLAIMERS AND WAIVERS

50

Section 11.1 Receipts. 50Section 11.2 Assumption and Indemnification. 50Section 11.3 Indemnification Actions. 53Section 11.4 Limitation on Actions. 54Section 11.5 Recording. 56Section 11.6 Waivers. 56Section 11.7 Insurance. 56Section 11.8 Tax Treatment of Indemnification Payments. 57

ARTICLE 12 MISCELLANEOUS 57Section 12.1 Counterparts. 57Section 12.2 Notice. 57Section 12.3 Sales or Use Tax, Recording Fees, and Similar Taxes and Fees. 58Section 12.4 Expenses. 58Section 12.5 Change of Name. 59Section 12.6 Replacement of Bonds and Guarantees. 59Section 12.7 Governing Law and Venue. 60Section 12.8 Jurisdiction; Waiver of Jury Trial. 60Section 12.9 Captions. 60Section 12.10 Waivers. 60Section 12.11 Assignment. 61Section 12.12 Entire Agreement. 61Section 12.13 Amendment. 61Section 12.14 No Third-Party Beneficiaries. 61Section 12.15 Public Announcements. 61Section 12.16 Invalid Provisions. 62Section 12.17 References. 62Section 12.18 Construction. 62Section 12.19 Limitation on Damages. 62

ARTICLE 13 DEFINITIONS 63

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EXHIBITS AND SCHEDULES

Exhibit A LeasesExhibit A-1 PropertiesExhibit A-2 Excluded EquipmentExhibit B ConveyanceExhibit C Persons with Knowledge Schedule 1.2(d) ContractsSchedule 1.2(e) Surface ContractsSchedule 1.3(h) Excluded PermitsSchedule 2.3 Allocated ValueSchedule 3.3(n) Other Permitted EncumbrancesSchedule 5.7 LitigationSchedule 5.8 Taxes and AssessmentsSchedule 5.9 Outstanding Capital CommitmentsSchedule 5.10 Compliance With LawsSchedule 5.11(a) DefaultsSchedule 5.11(b) Certain ContractsSchedule 5.12 Payments For ProductionSchedule 5.13 Governmental AuthorizationsSchedule 5.14 Preferential Rights & Consents to AssignSchedule 5.15 Environmental LawsSchedule 5.17 ImbalancesSchedule 7.5 Operation of BusinessSchedule 9.4(c) Seller’s Wiring InstructionsSchedule 12.6(a) Governmental BondsSchedule 12.6(b) Guarantees

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PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (the “ Agreement ”), is executed on June 22, 2017, by andbetween Jones Energy Holdings, LLC, a Delaware limited liability company ( “Seller ”) and FoundationEnergy Fund VI-A, LP, a Delaware limited partnership (“ Purchaser ”). Seller and Purchaser may eachbe referred to herein as a “ Party ” and collectively as the “ Parties ”.

RECITALS:

A. Seller desires to sell to Purchaser and Purchaser desires to purchase from Seller theAssets, in the manner and upon the terms and conditions hereafter set forth.

NOW, THEREFORE, in consideration of the premises and of the mutual promises,representations, warranties, covenants, conditions and agreements contained herein, and for othervaluable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties,intending to be legally bound by the terms hereof, agree as follows:

ARTICLE 1

PURCHASE AND SALE

Section 1.1 Purchase and Sale .

At the Closing, and upon the terms and subject to the conditions of this Agreement, Seller agreesto sell and convey to Purchaser and Purchaser agrees to purchase, accept and pay for the Assets andassume the Assumed Obligations. Capitalized terms used herein shall have the respective meaningsascribed to them in this Agreement as such terms are identified and/or defined in Article 13 hereof.

Section 1.2 Assets .

As used herein, the term “ Assets ” means, subject to the terms and conditions of this Agreement,all of Seller’s right, title, interest and estate, real or personal, recorded or unrecorded, movable orimmovable, tangible or intangible, in and to the following, excluding, however, the Excluded Assets:

(a) All of the oil and gas leases, oil, gas and mineral leases, subleases and otherleaseholds, carried interests, mineral fee interests, overriding royalty interests, reversionary rights,farmout rights, options, and other properties and interests described on Exhibit A, subject to suchdepth limitations and other restrictions and limitations as may be set forth on Exhibit A or in theinstruments that constitute (or are assignments or conveyances in the chain of title to) theforegoing properties and interests (collectively, the “ Leases ”), together with, subject to suchlimitations and restrictions, each and every kind and character of right, title, claim, and interestthat Seller has in and to the Leases, the lands covered by the Leases or the lands pooled, unitized,communitized or consolidated therewith (such lands covered by the Leases or pooled, unitized,communitized or consolidated therewith being hereinafter referred to as the “ Lands ”);

(b) All oil, gas, water, CO2 or injection wells located on or within the geographical

boundaries of the Lands, whether producing, shut-in, plugged or abandoned, and including thewells shown on Exhibit A-1 attached hereto (whether or not located on the Lands) (the “ Wells”);

(c) Any pools or units which include any portion of the Lands or all or a part of anyLeases or any Wells, including those pools or units referred to on Exhibit A-1 (the “ Units ”, suchUnits together with the Leases, Lands and Wells, or in cases when there is no Unit, the Leasestogether with the Lands and Wells, being hereinafter referred to collectively as the “ Properties ”and individually as a “ Property ”), and including all interest of Seller in Hydrocarbonproduction from any such Unit, whether such Unit Hydrocarbon production comes from Wellslocated on or off of a Lease, and all tenements, hereditaments and appurtenances belonging to theLeases and Units;

(d) All contracts, agreements and instruments by which the Properties are bound, orthat relate to or are otherwise applicable to the Properties, but in each case only to the extentapplicable to the Properties and not other properties of Seller not included in the Assets, includingoperating agreements, unitization, pooling and communitization agreements, declarations andorders, joint venture agreements, farmin and farmout agreements, water rights agreements,exploration agreements, area of mutual interest agreements, participation agreements, exchangeagreements, transportation or gathering agreements, agreements for the sale and purchase ofHydrocarbons and processing agreements, and further including those agreements andinstruments identified on Schedule 1.2(d) (hereinafter collectively referred to as the “ Contracts”), providedthat “Contracts” shall exclude (i) any master service agreements, (ii) any contracts,agreements and instruments to the extent transfer is (A) restricted by their respective terms orthird-party agreement and the necessary consents to transfer are not obtained pursuant to Section3.5, or (B) subject to payment of a fee or other consideration under any license agreement orother agreement with a Person other than an Affiliate of Seller, and for which no consent totransfer has been received or for which Purchaser has not agreed in writing to pay the fee or otherconsideration, as applicable and (iii) the instruments constituting the Leases, Surface Contractsand the assignments or conveyances in Seller’s chain of title to the Leases;

(e) All easements, permits, licenses, servitudes, rights-of-way, surface leases andother surface rights appurtenant to, and used or held for use primarily in connection with, theProperties, including those identified on Schedule 1.2(e) (hereinafter collectively referred to asthe “ Surface Contracts ”), provided that “Surface Contracts” shall exclude any permits andother appurtenances to the extent transfer is (i) restricted by their respective terms or third-partyagreement and the necessary consents to transfer are not obtained pursuant to Section 3.5, or (ii)subject to payment of a fee or other consideration under any license agreement or otheragreement with a Person other than an Affiliate of Seller, and for which no consent to transfer hasbeen received or for which Purchaser has not agreed in writing to pay the fee or otherconsideration, as applicable;

(f) All equipment, machinery, fixtures and other tangible personal property andimprovements located on the Properties and used or held for use primarily in connection

2

with the operation of the Properties, including any wells, tanks, boilers, buildings, fixtures,injection facilities, saltwater disposal facilities, compression facilities, pumping units and engines,flow lines, pipelines, gathering systems, gas and oil treating facilities, machinery, power lines,telephone and telegraph lines, roads, and other appurtenances, improvements and facilities, butexcluding the items expressly identified on Exhibit A-2 (subject to such exclusions, the “Equipment ”);

(g) All Hydrocarbons produced from or attributable to the Properties from and afterthe Effective Time and all inventories of Hydrocarbons produced from or attributable to theProperties that are in storage in tanks or pipelines on the Effective Time;

(h) All Imbalances; and

(i) Copies of all of the following items, subject to Section 1.5, all lease files, landfiles, well files, gas and oil sales contract files, gas processing files, division order files, abstracts,title opinions, land surveys, logs, maps, engineering data and reports, files, all Geological Data,and all other books, records, data, files, maps and accounting records to the extent related to theAssets, or used or held for use primarily in connection with the maintenance or operation thereof,but excluding (i) any books, records, data, files, maps and accounting records to the extentdisclosure or transfer is restricted by third-party agreement or applicable Law and the necessaryconsents to transfer are not obtained pursuant to Section 3.5, or subjected to payment of a fee orother consideration by any license agreement or other agreement with a Person other than anAffiliate of Seller, or by applicable Law, and for which no consent to transfer has been receivedor for which Purchaser has not agreed in writing to pay the fee or other consideration, asapplicable; (ii) computer software; (iii) all legal records and legal files of Seller, work product ofSeller’s legal counsel and records protected by attorney-client privilege, but excluding in eachcase Leases, Contracts, Surface Contracts and title opinions; (iv) records relating to the offer,negotiation or consummation of the sale of the Assets or any interest in the Properties; and (v)Seller’s reserve studies, estimates and evaluations, and engineering studies and economic studies(such copies, collectively, and subject to such exclusions, the “ Records ”).

Section 1.3 Excluded Assets .

Notwithstanding the foregoing, the Assets shall not include, and there is excepted, reserved andexcluded from the purchase and sale contemplated hereby (collectively, the “ Excluded Assets ”):

(a) (i) All corporate, partnership, limited liability company, financial, tax and legalrecords of Seller that relate to Seller’s business generally (whether or not relating to the Assets),(ii) all books, records and files that relate to the Excluded Assets, (iii) those records retained bySeller pursuant to Section 1.2(i), and (iv) copies of any other records retained by Seller pursuantto Section 1.5;

(b) The items expressly identified on Exhibit A-2;

3

(c) All claims for refunds of, or rights to receive funds from any Governmental Body

or loss carry forwards with respect to (i) Taxes attributable to the Assets for any taxable period,or portion thereof, ending at or prior to the Effective Time or to Seller’s businesses generally, (ii)income or franchise Taxes of Seller, or (iii) any Taxes attributable to the Excluded Assets;

(d) All rights to any other costs or expenses borne by Seller or Seller’s predecessorsin interest and title attributable to periods prior to the Effective Time;

(e) All rights relating to existing claims and causes of action (including insuranceclaims, whether or not asserted, under policies of insurance or claims to the proceeds ofinsurance) that may be asserted against a third Person, including those described in Schedule 5.7hereto, except to the extent such rights and claims and causes of action arise from or by theirterms cover obligations or liabilities expressly assumed by Purchaser hereunder;

(f) All rights of Seller under Contracts attributable to periods before the EffectiveTime insofar as such rights relate to Seller Indemnity Obligations or other liabilities of Sellerretained under this Agreement;

(g) Rights to initiate and conduct joint interest audits or other audits of Property Costsincurred before the Effective Time, and to receive costs and revenues in connection with suchaudits, in each case to the extent Seller is responsible for such Property Costs under thisAgreement;

(h) Seller’s area-wide bonds, permits and licenses or other permits, licenses orauthorizations used in the conduct of Seller’s business generally as reflected in Schedule 1.3(h);

(i) All trade credits, account receivables, note receivables, take-or-pay amountsreceivable, and other receivables attributable to the Assets (excluding Hydrocarbon inventoriessubject to Section 1.2(g) for which Seller receives an upward adjustment to the Purchase Price)with respect to any period of time prior to the Effective Time, as determined in accordance withGAAP;

(j) Trademarks, patents and trade names;

(k) Bonds, letters of credit and guarantees retained by Seller pursuant to Section 12.6;

(l) All tools, pulling machines, warehouse stock, equipment or material temporarilylocated on the Properties and not presently required for the operation of the Properties ascurrently operated;

(m) All hedges, futures, swaps and other derivatives, including rights relating thereto,affecting the Assets;

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(n) All offices and office leases, and computers, phones, office supplies, furniture and

related personal effects located off the Properties or only temporarily located on the Properties;

(o) Assets retained by Seller or excluded from the Assets at Closing pursuant toSections 3.4(d)(ii), 3.5, 4.4(b) or 7.7, subject to the terms of such Sections;

(p) All leased personal property (including leased vehicles); and

(q) the Contingent Payment.

Section 1.4 Effective Time; Proration of Costs and Revenues .

(a) Possession of the Assets shall be transferred from Seller to Purchaser at theClosing, but certain financial benefits and obligations of the Assets shall be transferred effectiveas of 7:00 A.M., local time, where the respective Assets are located, on June 1, 2017 (the “Effective Time ”), as further set forth in this Agreement.

(b) Except to the extent accounted for in the adjustments to the Purchase Price madeunder Section 2.2, (i) Purchaser shall be entitled to all production from or attributable to theProperties at and after the Effective Time (and all products and proceeds attributable thereto), andto all other income, proceeds, receipts and credits earned with respect to the Assets at or after theEffective Time, and (ii) Seller shall be entitled to all production from or attributable to theProperties prior to the Effective Time (and all products and proceeds attributable thereto), and toall other income, proceeds, receipts and credits earned with respect to the Assets prior to theEffective Time. The terms “earned” and “incurred”, as used in this Agreement, shall beinterpreted in accordance with GAAP and Council of Petroleum Accountants Society (“ COPAS”) standards, as implemented by Seller in the ordinary course of business consistent with pastpractice. For purposes of allocating production (and accounts receivable with respect thereto),under this Section 1.4(b), (i) liquid Hydrocarbons shall be deemed to be “from or attributable to”the Leases, Units and Wells when, after production from the Leases, Units and Wells, saidproduction passes through connecting pipelines/flowlines to storage facilities, whether or notowned by Seller, located off the Leases, Units and Wells, or if there are no storage facilities,when they pass through the LACT meter or similar meter at the entry point into the pipelinesthrough which they are transported from such lands and (ii) gaseous Hydrocarbons shall bedeemed to be “from or attributable to” the Leases, Units and Wells when they pass through thedelivery point sales meters or similar meters at the entry point into the pipelines through whichthey are transported from such lands. Seller shall utilize reasonable interpolative procedures toarrive at an allocation of production when exact meter readings or gauging and strapping data isnot available.

(c) As used herein, “ Property Costs ” means (i) all costs attributable to theownership, development, operation or maintenance of the Assets (including costs of insurance),lease bonus payments, renewals, extensions or amendments, and ad valorem, property, excise,sales, use, severance, production and similar Taxes (including any interest, fine, penalty oradditions to Tax imposed by a Governmental Body in connection

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with such Taxes) based upon or measured by the ownership or operation of the Assets or theproduction of Hydrocarbons therefrom, but excluding any other Taxes, (ii) capital expendituresincurred in the ownership, development, operation and maintenance of the Assets in the ordinarycourse of business, (iii) where applicable, such costs and capital expenditures charged inaccordance with the relevant operating agreement, unit agreement, pooling agreement, pre-pooling agreement, pooling order or similar instrument, or if none, charged to the Assets on thesame basis as charged on the date of this Agreement, and (iv) overhead costs charged to theAssets by unaffiliated third parties under the relevant operating agreement, unit agreement,pooling agreement, pre-pooling agreement, pooling order or similar instrument, or if none,charged to the Assets by unaffiliated third parties on the same basis as charged on the date of thisAgreement; provided that “Property Costs” shall exclude, without limitation, liabilities, losses,costs, and expenses attributable to (A) claims, investigations, administrative proceedings orlitigation directly or indirectly arising out of or resulting from actual or claimed personal injury ordeath, property damage or violation of any Law (including private rights or causes of actionunder any Law), (B) title claims (including claims that the Leases have terminated), (C)obligations to plug wells, dismantle facilities, close pits and restore the surface or seabed aroundsuch wells, facilities and pits, (D) obligations to cure, address or remediate any contamination ofgroundwater, surface water, soil or Equipment under applicable Environmental Laws, (E)obligations to furnish make-up gas according to the terms of applicable gas sales, gathering ortransportation contracts, (F) gas balancing obligations and similar obligations arising fromImbalances and (G) obligations to pay working interests, royalties, overriding royalties or otherinterests held in suspense, all of which are addressed in Section 11.2 or elsewhere in thisAgreement. Subject to the other provisions herein, Seller shall bear and be responsible for allProperty Costs incurred or arising prior to the Effective Time and Purchaser shall bear and beresponsible for all Property Costs incurred or arising at and after the Effective Time. For thepurposes of calculating the adjustments to the Purchase Price under Section 2.2 or implementingthe terms of Section 7.8 or Article 11, (1) right-of-way fees, insurance premiums and PropertyCosts (excluding Taxes which are addressed in clauses (2), (3), and (4) of this sentence) delayrentals, lease bonuses, minimum royalties, option payments, lease extension payments and shut-inroyalties) that are paid periodically shall be prorated based on the number of days in theapplicable period falling before, or at and after, the Effective Time, (2) ad valorem, property,severance, production or similar Taxes which are based on the quantity of or the value ofproduction of Hydrocarbons shall be apportioned between Seller and Purchaser based on thenumber of units or value of production actually produced, as applicable, before, and after, theEffective Time, (3) other ad valorem, property, severance, production or similar Taxes shall beprorated based on the number of days in the applicable period falling before, or at and after, theEffective Time, and (4) all other Taxes shall be apportioned based on an interim closing of thebooks of Seller as of the Effective Time.

Section 1.5 Delivery and Maintenance of Records and Retained Records .

(a) Seller, at Purchaser’s cost, shall use reasonable efforts to deliver the Records inSeller’s possession or control (FOB Seller’s office), to Purchaser within thirty (30) daysfollowing Closing. Seller may retain original Records and/or copies of any Records.

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(b) Purchaser, for a period of four (4) years following the Closing, will (i) retain the

Records, (ii) provide Seller, its Affiliates, and its and their officers, employees andrepresentatives with access to the Records during normal business hours for review and copyingat Seller’s expense and (iii) provide Seller, its Affiliates, and its and their officers, employees andlegal counsel with access, during normal business hours, to materials received or produced afterClosing relating to any claim for indemnification made under Section 11.2 of this Agreement(excluding, however, attorney work product and attorney-client communications protected byprivilege and prepared with respect to any such claim being brought by Purchaser andinformation subject to an applicable confidentiality restriction in favor of third parties) for reviewand copying at Seller’s expense.

ARTICLE 2

PURCHASE PRICE

Section 2.1 Purchase Price .

The purchase price for the Assets (the “ Purchase Price ”) shall be Sixty Five Million Dollars($65,000,000.00), and shall be adjusted as provided in Section 2.2 (the “ Adjusted Purchase Price ”).

Section 2.2 Adjustments to Purchase Price .

The Purchase Price for the Assets shall be adjusted as follows with all such amounts beingdetermined in accordance with GAAP and COPAS standards (with such adjustments being made so as tonot give duplicative effect):

(a) Reduced by the aggregate amount of the following proceeds received and retainedby Seller between the Effective Time and the Closing Date (with the period between the EffectiveTime and the Closing Date referred to as the “ Adjustment Period ”): proceeds from the sale ofHydrocarbons (net of any royalties, overriding royalties or other burdens on or payable out ofproduction, gathering, processing and transportation costs and any production, severance, sales,use or excise Taxes not reimbursed to Seller by the purchaser of production) produced from orattributable to the Properties during the Adjustment Period;

(b) Reduced in accordance with Section 3.5, by an amount equal to the AllocatedValue of those Properties (i) with respect to which preferential purchase rights have beenexercised prior to Closing or (ii) that cannot be transferred due to unsatisfied and unwaivedrequirements for consent to the assignments contemplated hereby;

(c) Reduced in accordance with Section 7.7 by an amount equal to the AllocatedValue of those Properties that are subject to a suit, action or proceeding prior to Closing seekingto restrain, enjoin or otherwise prohibit the consummation of the transactions contemplatedhereby in connection with a claim to enforce preferential rights;

(d) (i) Subject to Section 3.4(i), reduced by the applicable Title Defect Amount as aresult of Title Defects for which the Title Defect Amount has been finally determined

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or agreed pursuant to Section 3.4 (or, for purposes of the Closing Payment, pursuant to Seller’sgood faith estimate), and reduced by the Allocated Value of any Defect Property retained bySeller pursuant to Section 3.4(d)(ii), and (ii) increased by the applicable Title Benefit Amount asa result of Title Benefits for which the Title Benefit Amount has been finally determined oragreed pursuant to Section 3.4;

(e) Reduced by the Allocated Values of any Properties excluded by Seller pursuant toSection 3.6;

(f) Reduced by (i) subject to Section 4.4, any amount agreed upon by Purchaser andSeller pursuant to Section 4.4(a) regarding the reasonable estimate of the cost of curingEnvironmental Liabilities for any affected Property not retained by Seller, and (ii) the AllocatedValue of any Property retained by Seller pursuant to Section 4.4(b);

(g) Increased by the amount equal to the value of all of Seller’s inventories ofHydrocarbons produced from or attributable to the Properties that are in storage above the loadline or pipeline connection, as applicable, as of the Effective Time (which value shall becomputed using the applicable contract price at the Effective Time), less any applicable severanceTaxes, royalties and similar burdens; provided, however , that the adjustment contemplated bythis paragraph shall be only made to the extent that Seller does not receive and retain theproceeds, or portion thereof, attributable to the sale of such Hydrocarbons;

(h) Increased by the amount of all Property Costs and other costs attributable to theownership, development, operation and maintenance of the Assets that are paid by Seller andincurred on or after the Effective Time (or with respect to any period on or after the EffectiveTime), except any Property Costs and other such costs already deducted in the determination ofproceeds in Section 2.2(a);

(i) Decreased by the proceeds from the sale of surplus and inventoried Equipmentfrom the Properties after the Effective Time, to the extent such proceeds are attributable toSeller’s interest;

(j) Increased by an overhead charge of $35,000 per month (pro-rated for any partialmonths as applicable) for the period of time beginning at the Effective Time and ending on theClosing Date (it being understood that no other Seller overhead charge will be charged to theAssets after the Effective Time); and

(k) Decreased in accordance with Section 7.10, as applicable.

The adjustment described in Section 2.2(a) shall serve to satisfy, up to the amount of theadjustment, Purchaser’s entitlement under Section 1.4 to Hydrocarbon production from or attributable tothe Properties during the Adjustment Period, and to the value of other income, proceeds, receipts andcredits earned with respect to the Assets during the Adjustment Period, and Purchaser shall not have anyseparate rights to receive any production or income, proceeds, receipts and credits with respect to whichan adjustment has been made.

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Section 2.3 Allocation of Purchase Price .

(a) For Title Defect purposes, concurrent with the execution of this Agreement,Purchaser and Seller have agreed upon an allocation of the unadjusted Purchase Price amongeach of the Wells and PLSS Sections. Such allocation of value is attached to this Agreement asSchedule 2.3. The “ Allocated Value ” for any Well and PLSS Section equals the portion of theunadjusted Purchase Price allocated to such Well and PLSS Section on Schedule 2.3, increased ordecreased as described in Section 2.2.

(b) For federal income tax purposes, Purchaser and Seller shall use commerciallyreasonable efforts to agree on an allocation of the Purchase Price within thirty (30) days after thedetermination of the Adjusted Purchase Price. In this respect, the allocation of value reflected inSchedule 2.3 for the unadjusted Purchase Price is to be modified by the Parties to take intoaccount the adjustments made which determine the Adjusted Purchase Price. Seller andPurchaser agree (a) that the agreed allocation shall be used by Seller and Purchaser as the basisfor reporting asset values and other items for purposes of all federal, state, and local Tax Returns,including Internal Revenue Service Form 8594 and (b) that, except as required by applicableLaw, neither they nor their Affiliates will take positions inconsistent with the agreed allocation inany Tax Returns, in notices to Governmental Bodies, in audit or other proceedings with respect toTaxes, in notices to preferential purchase right holders, or in other documents or notices relatingto the transactions contemplated by this Agreement without the consent of the other Party. EachParty shall promptly notify the other Party in writing upon receipt of notice of any pending orthreatened Tax audit or assessment challenging the agreed allocation, and neither party shallagree to any proposed adjustment to the agreed allocation by any Governmental Body withoutfirst giving to the other party prior written notice. However, nothing contained herein shallprevent either party from settling any proposed deficiency or adjustment by any GovernmentalBody based upon or arising out of the agreed allocation, and neither party shall be required tolitigate any proposed deficiency or adjustment by any Governmental Body challenging suchagreed allocation.

Section 2.4 Deposit .

Concurrently with the execution of this Agreement, Purchaser has paid to Seller an earnest moneydeposit in an amount equal to seven and a half percent (7.5%) of the Purchase Price, which is FourMillion Eight Hundred Seventy Five Thousand Dollars ($4,875,000.00) (the “ Deposit ”). If Closingoccurs, at Closing, the Deposit will be credited against the Purchase Price. If Closing does not occur, theDeposit shall be distributed in accordance with ‎ Section 10.3.

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ARTICLE 3

TITLE MATTERS

Section 3.1 Seller’s Title .

(a) This Article 3 and the Special Warranty in the Conveyance (subject to Section7.9) shall, to the fullest extent permitted by applicable Law, be the exclusive right and remedy ofPurchaser with respect to title to the Assets.

(b) The conveyance of the Assets to be delivered by Seller to Purchaser shall besubstantially in the form of Exhibit B (the “ Conveyance ”).

Section 3.2 Certain Definitions .

(a) As used in this Agreement, the term “ Defensible Title ” means that title of Sellerthat:

(i) Entitles Seller to receive a share of the Hydrocarbons produced, saved andmarketed from such Property (after satisfaction of all royalties, overriding royalties,nonparticipating royalties, net profits interests or other similar burdens on or measured byproduction of Hydrocarbons) (a “ Net Revenue Interest ”), of not less than the “netrevenue interest” share shown in Schedule 2.3 for such Well, except for decreases inconnection with those operations permitted under Section 7.5 in which Seller may afterthe Effective Time be a non-consenting party, decreases resulting from the election toratify or the establishment or amendment of pools or units on or after the Effective Time,decreases required to allow other working interest owners to make up pastunderproduction or pipelines to make up past under deliveries, and decreases resultingfrom reversionary interests, carried interests, horizontal or vertical severances or othermatters or changes in interest stated in Schedule 2.3;

(ii) Obligates Seller to bear a percentage of the costs and expenses for themaintenance and development of, and operations relating to any Well not greater than the“working interest” shown in Schedule 2.3 without increase, (a “ Working Interest ”)except increases resulting from matters stated in Schedule 2.3, increases resulting fromcontribution requirements with respect to defaulting parties under applicable operating,unit, pooling, pre-pooling or similar agreements and increases that are accompanied by atleast a proportionate increase in Seller’s Net Revenue Interest; and

(iii) Is free and clear of liens and encumbrances on title that affect orencumber a Property;

(iv) with respect to a PLSS Section, entitles Seller to the Net Acres in suchPLSS Section set forth on Schedule 2.3 for such PLSS Section; and

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in each case excluding, subject to and determined without regard to matters constituting

Permitted Encumbrances.

(b) As used in this Agreement, the term “ Title Benefit ” shall mean any right,circumstance or condition that operates to (i) increase the Net Revenue Interest of Seller in anyWell shown on Schedule 2.3, without causing a greater than proportionate increase in Seller’sWorking Interest above that shown in Schedule 2.3 or (ii) increase the number of Net Acres ofSeller in any PLSS Section above that set forth on Schedule 2.3.

(c) As used in this Agreement, the term “ Title Defect ” shall mean any lien,encumbrance, obligation or defect that causes Seller’s title to any PLSS Sections or Wells shownon Schedule 2.3 to be less than Defensible Title; provided that“Title Defect” shall exclude thefollowing:

(i) defects based solely on a lack of information in Seller’s files or referencesto a document if such document is not in Seller’s files;

(ii) defects arising out of lack of corporate or other entity authorization unlessPurchaser provides affirmative evidence that the action was not authorized and results inanother Person’s superior claim of title to the relevant Asset;

(iii) defects in the chain of title consisting of the failure to recite marital statusin a document or omissions of successions of heirship or estate proceedings, or any othermatter which could be legally cured and not considered an encumbrance or defect underthe Title Examination Standards adopted as of the Effective Time by the Oklahoma BarAssociation, unless, in each case, Purchaser provides affirmative evidence that suchfailure or omission could reasonably be expected to result in another Person’s superiorclaim of title to the relevant Asset;

(iv) defects that have been cured by applicable Laws of limitation orprescription;

(v) defects arising out of a lack of survey, unless a survey is expresslyrequired by applicable Laws; and

(vi) defects based on a gap in Seller’s chain of title in the applicable countyrecords, unless such gap is affirmatively shown to exist in such records by an abstract oftitle, title opinion or landman’s title chain which documents shall be included in a TitleDefect Notice;

(vii) defects based upon the failure to record any state or federal Leases or anyassignments of interests in such Leases in the Assets in any applicable county records;

(viii) any encumbrance or loss of title resulting from Seller’s conduct ofbusiness in compliance with this Agreement;

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(ix) encumbrances created under deeds of trust, mortgages and similar

instruments by the lessor under a Lease covering the lessor’s surface and mineral interestsin the land covered thereby that would customarily be accepted in taking or purchasingsuch Leases and for which the lessee would not customarily seek a subordination of suchencumbrance to the oil and gas leasehold estate prior to conducting drilling activities onthe Lease;

(x) encumbrances created under deeds of trust, mortgages and similarinstruments by the grantor under a right-of-way that would customarily be accepted intaking or purchasing such rights-of-way; and

(xi) defects disclosed herein (including on any Schedule or Exhibit).

Section 3.3 Definition of Permitted Encumbrances .

As used herein, the term “ Permitted Encumbrances ” means any or all of the following:

(a) Royalties, nonparticipating royalty interests, net profits interests and anyoverriding royalties, reversionary interests and other burdens to the extent that they do not,individually or in the aggregate, reduce Seller’s Net Revenue Interest or Net Acres below thatshown in Schedule 2.3 or increase Seller’s Working Interest above that shown in Schedule 2.3without a corresponding increase in the Net Revenue Interest;

(b) All leases, unit agreements, pooling agreements, pre-pooling agreements,operating agreements, production sales contracts, division orders and other contracts, agreementsand instruments applicable to the Assets, to the extent that they do not, individually or in theaggregate: (i) reduce Seller’s Net Revenue Interest or Net Acres below that shown in Schedule2.3 or increase Seller’s Working Interest above that shown in Schedule 2.3 without acorresponding increase in the Net Revenue Interest and (ii) materially interfere with theownership and operation of the Assets as currently owned and operated;

(c) Subject to compliance with Sections 3.5 and 7.7, third-party consents andpreferential rights to purchase the Assets applicable to this or a future transaction involving theAssets;

(d) Third-party consent requirements and similar restrictions with respect to whichwaivers or consents are obtained by Seller from the appropriate Persons prior to the Closing Dateor the appropriate time period for asserting the right has expired or which need not be satisfiedprior to a transfer;

(e) Liens for Taxes or assessments not yet delinquent or, if delinquent, beingcontested in good faith by appropriate actions;

(f) Materialman’s, mechanic’s, repairman’s, employee’s, contractor’s, operator’s andother similar liens or charges arising in the ordinary course of business for amounts not yetdelinquent (including any amounts being withheld as provided by Law), or if delinquent, beingcontested in good faith by appropriate actions;

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(g) All rights to consent, required notices to, filings with, or other actions by

Governmental Bodies in connection with the sale or conveyance of the Assets if they are notrequired prior to the sale or conveyance or are of a type customarily obtained after Closing;

(h) Rights of reassignment arising upon final intention to abandon or release all orany part of the Assets;

(i) Easements, rights-of-way, servitudes, permits, surface leases and other rights inrespect of surface operations to the extent that they do not, individually or in the aggregate:materially interfere with the ownership and operation of the Assets as currently owned andoperated as of the Effective Time;

(j) Calls on Hydrocarbon production under existing any Contracts identified inSchedule 1.2(d);

(k) All rights reserved to or vested in any Governmental Body to control or regulateany of the Assets in any manner and all obligations and duties under all applicable Laws, rulesand orders of any such Governmental Body or under any franchise, grant, license or permit issuedby any such Governmental Body;

(l) Any encumbrance on or affecting the Assets which is expressly assumed, bondedor paid by Purchaser at or prior to Closing or which is discharged by Seller at or prior to Closing;

(m) Any matters shown on Schedule 2.3;

(n) Any matters shown on Schedule 5.7 or Schedule 3.3(n);

(o) Imbalances associated with the Assets;

(p) In the case of any well on an undeveloped location or other operation that has notbeen commenced as of the Closing Date, any permits, easements, rights of way, unit designationsor production or drilling units not yet obtained, formed or created;

(q) Lack of rights, access or transportation as to any rights of way for gathering ortransportation pipelines or facilities that do not constitute any of the Assets;

(r) Any liens, charges, encumbrances, defects or irregularities (i) which affect aProperty from which Hydrocarbons have been and are being produced (or to which production ofHydrocarbons is allocable) for the last ten (10) years and for which no claim related to title hasbeen made in writing by any Person during such ten (10) year period, (ii) which would beaccepted by a reasonably prudent purchaser engaged in the business of owning and operating oiland gas properties or (iii) which do not, individually or in the aggregate, materially detract fromthe value of or materially interfere with the ownership and operation of the Assets subject theretoor affected thereby (as currently owned and operated), and do not reduce Seller’s Net RevenueInterest or Net Acres below that shown

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in Schedule 2.3, or increase Seller’s Working Interest above that shown in Schedule 2.3 without acorresponding increase in the Net Revenue Interest;

(s) Such Title Defects or other defects as Purchaser has waived in writing; and

(t) Liens to be released at Closing.

Section 3.4 Notice of Title Defects Defect Adjustments .

(a) To assert a Title Defect, Purchaser must deliver claim notices to Seller (each a “Title Defect Notice ”) on or before 5:00 p.m., Central Daylight Savings Time on July 21, 2017(the “ Title Claim Date ”), except as otherwise provided under Sections 3.5 or 3.6. Each TitleDefect Notice shall be in writing and shall include (i) a description of the alleged Title Defect(s),(ii) the Wells and PLSS Sections affected by the Title Defect (each a “ Defect Property ”), (iii)the Allocated Values of each Defect Property, (iv) supporting documents reasonably necessaryfor Seller (as well as any title attorney or examiner hired by Seller) to verify the existence of thealleged Title Defect(s) and (v) the amount by which Purchaser reasonably believes the AllocatedValues of each Defect Property are reduced by the alleged Title Defect(s) and the computationsand information upon which Purchaser’s belief is based. Purchaser shall be deemed to havewaived for all purposes hereunder all Title Defects that were not included in a Title Defect Noticedelivered to Seller on or before the Title Claim Date. To give Seller an opportunity to commencereviewing and curing alleged Title Defects, Purchaser agrees to provide Seller, on or before theend of each calendar week prior to the Title Claim Date, written notices of all Title Defectsdiscovered by Purchaser during the preceding calendar week, which notice may be preliminary innature and supplemented prior to the Title Claim Date. Purchaser shall also promptly furnishSeller with written notice of any Title Benefit that is discovered by any of Purchaser’srepresentatives, title attorneys, landmen or other title examiners while conducting Purchaser’s duediligence with respect to the Assets prior to the Title Claim Date.

(b) Seller shall have the right, but not the obligation, to deliver to Purchaser withrespect to each Title Benefit a written notice (a “ Title Benefit Notice ”) asserting such TitleBenefit on or before the Title Claim Date. Each Title Benefit Notice shall include (i) adescription of the Title Benefit(s), (ii) the Wells and PLSS Sections affected by the Title Benefit(each a “ Title Benefit Property ”), (iii) the Allocated Values of the Title Benefit Property, (iv)supporting documents reasonably necessary for Purchaser (as well as any title attorney orexaminer hired by Purchaser) to verify the existence of the alleged Title Benefit(s) and (v) theamount by which Seller reasonably believes the Allocated Values of those Wells and PLSSSections are increased by the Title Benefit, and the computations and information upon whichSeller’s belief is based. Seller shall be deemed to have waived for all purposes hereunder all TitleBenefits that were not included in a Title Benefit Notice delivered to Purchaser on or before theTitle Claim Date.

(c) Seller shall have the right, but not the obligation, upon delivering written notice toPurchaser, to attempt, at Seller’s sole cost, to cure or remove any Title Defects of which it hasbeen advised by Purchaser on or before the expiration of sixty (60) successive

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days from and after the Title Claim Date (the “ Cure Period ”), unless the Parties otherwiseagree. If Seller has provided notice at or prior to the Closing Date of Seller’s intent to attempt tocure a Title Defect within the Cure Period, there shall be no reduction to the Purchase Price withrespect to the Title Defect for purposes of Closing. If at the end of the Cure Period Seller andPurchaser agree that the Title Defect is not cured, or, in the absence of agreement of the Sellerand Purchaser, the Title Arbitrator determines that such Title Defect is not cured at the end of theCure Period, then in either case Seller shall elect one of the options set forth in Section 3.4(d)(i)or, with Purchaser’s consent, Section 3.4(d)(ii)(B) for such Title Defect, in which event thePurchase Price adjustment required in connection with the selected option under this Article 3shall be made in the final statement of the Adjusted Purchase Price pursuant to Section9.4(b). No action of Seller in electing or attempting to cure a Title Defect shall constitute awaiver of Seller’s right to dispute the existence, nature or value of, or cost to cure, the TitleDefect.

(d) In the event that (I) any Title Defect asserted by Purchaser in accordance withSection 3.4(a) is not waived by Purchaser and (II) Seller has not provided notice to Purchaser ator prior to the Closing Date of Seller’s intent to attempt to cure the given Title Defect, or Sellerhas provided such notice but the Title Defect is not cured before the expiration of the CurePeriod, then Seller shall elect to:

(i) reduce the Purchase Price by the Title Defect Amount determinedpursuant to Section 3.4(f) or 3.4(h); or

(ii) with the consent of Purchaser, (A) at Closing, retain the Property that isassociated with such Title Defect, in which event the Purchase Price shall be reduced byan amount equal to the Allocated Value of such Property or (B) promptly after expirationof the Cure Period have Purchaser reconvey the Property that is associated with such TitleDefect to Seller, in which event the Purchase Price shall be reduced by an amount equal tothe Allocated Value of such Property, adjusted as provided in Section 2.2; or

(iii) if applicable, terminate this Agreement pursuant to Article 10.

(e) In the event that any Title Benefit asserted by Seller in accordance with Section3.4(b) is not waived by Seller, then:

(i) to the extent Purchaser and Seller agree on the Title Benefit Amount ascalculated pursuant to Section 3.4(g), the Purchase Price shall be increased by suchamount; and

(ii) to the extent there is no agreement under Section 3.4(e)(i) on or before theClosing Date, the disagreement between Seller and Purchaser regarding the Title BenefitProperty or the Title Benefit Amount, as applicable, shall be submitted to arbitration inaccordance with Section 3.4(h).

(f) The “ Title Defect Amount ” resulting from a Title Defect shall be determined asfollows:

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(i) if Purchaser and Seller agree on the Title Defect Amount, then that

amount shall be the Title Defect Amount;

(ii) if the Title Defect is a lien, encumbrance or other charge which isundisputed and liquidated in amount, then the Title Defect Amount shall be the amountnecessary to be paid to remove the Title Defect from the Defect Property;

(iii) if the Title Defect represents a discrepancy between (A) the Net RevenueInterest for any Defect Property and (B) the Net Revenue Interest stated on Schedule 2.3,then the Title Defect Amount shall be the product of the Allocated Value of such DefectProperty multiplied by a fraction, the numerator of which is the actual amount of thedecrease in Net Revenue Interest from that stated on Schedule 2.3 and the denominator ofwhich is the Net Revenue Interest stated on Schedule 2.3; provided,however, that if theTitle Defect does not affect the Defect Property throughout its entire life, the Title DefectAmount shall be reduced to take into account the applicable time period only;

(iv) if the Title Defect represents an obligation, encumbrance, burden orcharge upon or other defect in title to the Defect Property of a type not described inSection 3.4(f)(i), Section 3.4(f)(ii) or Section 3.4(f)(iii), then the Title Defect Amountshall be determined by taking into account the Allocated Value of the Defect Property, theportion of the Defect Property affected by the Title Defect, the legal effect of the TitleDefect, the potential economic effect of the Title Defect over the life of the DefectProperty, the values placed upon the Title Defect by Purchaser and Seller and such otherfactors as are necessary to make a proper evaluation;

(v) if the Title Defect represents (A) a discrepancy between (1) the NetRevenue Interest for any Defect Property and (2) the Net Revenue Interest stated onSchedule 2.3, and (B) an obligation, encumbrance, burden or charge upon or other defectin title to the Defect Property, then the Title Defect Amount shall be determined byapplying both of Section 3.4(f)(iii) and Section 3.4(f)(iv) to such Title Defect, withoutduplication;

(vi) if the Title Defect is based on the Seller owning fewer Net Acres in aPLSS Section than those shown on Schedule 2.3, then the Title Defect Amount for suchPLSS Section shall be calculated by multiplying the Allocated Value set forth onSchedule 2.3, by a fraction, the numerator of which is an amount equal to the number ofNet Acres shown for such PLSS Section on Schedule 2.3, less the actual Net Acresactually owned for such PLSS Section, and the denominator of which is the Net Acresshown for such PLSS Section on Schedule 2.3; and

(vii) notwithstanding anything to the contrary in this Article 3, the aggregateTitle Defect Amounts attributable to the effects of all Title Defects upon any DefectProperty shall not exceed the Allocated Value of such Defect Property.

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(g) The “ Title Benefit Amount ” resulting from a Title Benefit (i) the result of an

increase in the Net Revenue Interest in a Title Benefit Property from that stated on Schedule 2.3shall be the product of the Allocated Value of the Title Benefit Property multiplied by a fraction,the numerator of which is the actual amount of the increase in Net Revenue Interest from thatstated on Schedule 2.3 and the denominator of which is the Net Revenue Interest stated onSchedule 2.3; provided, however , that if the Title Benefit does not affect the applicable TitleBenefit Property throughout its entire life, the Title Benefit Amount shall be reduced to take intoaccount the applicable time period only and (ii) the result of the Net Acres in a Title BenefitProperty being greater than that stated on Schedule 2.3 shall be the product of the AllocatedValue of the Title Benefit Property set forth on Schedule 2.3 and a fraction, the numerator ofwhich is the actual Net Acres actually owned for such PLSS Section less an amount equal to thenumber of Net Acres shown for such PLSS Section on Schedule 2.3, and the denominator ofwhich is the Net Acres shown for such PLSS Section on Schedule 2.3.

(h) With respect to Title Defect Notices and Title Benefit Notices provided andreceived on or before the Title Claim Date, Seller and Purchaser shall attempt to agree on all TitleDefects, Title Benefits, Title Defect Amounts and Title Benefit Amounts on or before the daybefore the Closing Date, subject to Seller and Purchaser’s rights under Sections 3.4(d)(ii). IfSeller and Purchaser are unable to agree by that date, then subject to Section 3.4(c) and Seller andPurchaser’s rights under Sections 3.4(d)(ii), Seller’s good faith estimate shall be used forpurposes of calculating the Closing Payment pursuant to Section 9.4(a), and the Title Defects,Title Benefits, Title Defect Amounts and Title Benefit Amounts in dispute shall be exclusivelyand finally resolved by arbitration pursuant to this Section 3.4(h). Likewise, if Seller hasprovided notice at or prior to the Closing Date of Seller’s intent to attempt to cure a Title Defectand by the end of the Cure Period, Seller and Purchaser have been unable to agree upon whethersuch Title Defect has been cured, or Seller has failed to cure any Title Defects which Sellerprovided notice that Seller would attempt to cure and Seller and Purchaser have been unable toagree on the Title Defect Amounts for such Title Defects, then the cure and/or Title DefectAmounts and Title Benefit Amounts in dispute shall be exclusively and finally resolved byarbitration pursuant to this Section 3.4(h), subject to Seller and Purchaser’s rights under Section3.4(d)(ii). There shall be a single arbitrator, who shall be a title attorney with at least ten (10)years’ experience in oil and gas titles in the State of Oklahoma as selected by mutual agreementof Purchaser and Seller within fifteen (15) days after the end of the Cure Period (or such othertime as mutually agreed) and absent such agreement on the selection of the arbitrator, thearbitrator shall be selected by the Oklahoma City, Oklahoma office of the American ArbitrationAssociation; provided, however , that in any case such attorney shall not have worked as anemployee of or outside counsel for either Seller or Purchaser or any of their Affiliates during the5-year period preceding the applicable arbitration or have any financial interest in the applicabledispute (such attorney, the “ Title Arbitrator ”). The arbitration proceeding shall be held inHouston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules ofthe American Arbitration Association, to the extent such rules do not conflict with the terms ofthis Section. The Title Arbitrator’s determination shall be made within twenty (20) days aftersubmission of the matters in dispute and shall be final and binding upon both Parties, withoutright of appeal. In making his determination, the Title Arbitrator shall be bound by the rules set

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forth in Section 3.4(a), Section 3.4(b), Section 3.4(c), Section 3.4(d), Section 3.4(e), Section3.4(f), Section 3.4(g) and Section 3.4(i) and may consider such other matters as in the opinion ofthe Title Arbitrator are necessary or helpful to make a proper determination. Additionally, theTitle Arbitrator may consult with and engage disinterested third Persons to advise the arbitrator,including petroleum engineers. The Title Arbitrator shall act as an expert for the limited purposeof determining the specific disputed Title Defects, Title Benefits, Title Defect Amounts and TitleBenefit Amounts submitted by either Party and may not award damages, interest or penalties toeither Party with respect to any matter. Each Party shall bear its own legal fees and other costs ofpresenting its case and shall bear one-half of the costs and expenses of the Title Arbitrator.

(i) Notwithstanding anything herein to the contrary, (y) in no event shall there be anyadjustments to the Purchase Price or other remedies provided by Seller for any Title Defectsrelating to a Defect Property unless the aggregate Title Defect Amount for the Title Defectsrelating to a particular Defect Property exceed the sum of Fifty Thousand Dollars ($50,000.00)(the “ Property Defect Threshold ”); and (z) in no event shall there be any adjustments to thePurchase Price or other remedies provided by Seller for Title Defects unless the sum of (i) theaggregate amount of all Title Defect Amounts for Title Defects covered by Section 3.4(d)(i) thatsatisfy the Property Defect Threshold, plus (ii) the aggregate amount of all EnvironmentalLiabilities covered by Section 4.4(a) that satisfy the Property Defect Threshold (that is, theaggregate Environmental Liabilities relating to a Property exceed the sum of Fifty ThousandDollars ($50,000.00)), exceeds a deductible in an amount equal to two percent (2%) of thePurchase Price (the “ Defect Deductible ”), after which point Purchaser shall be entitled toadjustments to the Purchase Price or other available remedies under this Article 3 with respect toall Title Defects satisfying the Property Defect Threshold in excess of the Defect Deductible,subject to Seller’s elections under Section 3.4(d). The provisions of this Section 3.4(i) shall notapply to Title Defects relating to consent to assignment and preferential rights to purchase whichshall be handled or treated under Section 3.5. The Allocated Value of any Property retained bySeller in accordance with Section 3.4(d)(ii) may not be used in meeting the Defect Deductible.

(j) Seller shall convey the Assets to Purchaser at Closing free and clear of (i) anymortgages, deeds of trust, or other encumbrances created by Seller, or Affiliates of Seller, tosecure money borrowed or other form of financing, and (ii) any mechanic liens of record, to theextent relating to pre-Effective Time claims, asserted against any part of portion of the Assetsarising from operations having been conducted by Seller or an Affiliate of Seller. Any notice byPurchaser to Seller regarding the existence of any such liens or encumbrances need not be by theTitle Claim Date. The costs to Seller to remove such lien is not part of the Defect Deductible.

Section 3.5 Consents to Assignment and Preferential Rights to Purchase .

Seller shall use commercially reasonable efforts to promptly prepare and send (i) notices to thethird party holders (excluding Governmental Bodies, which are addressed elsewhere in this Agreement)of any required consents to assignment of any Assets to request such consents and (ii) notices to theholders of any applicable preferential rights to purchase any Asset requesting waivers of suchpreferential rights to purchase, in each case that would be triggered by the purchase and

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sale contemplated by this Agreement, and of which Seller has knowledge. The consideration payableunder this Agreement for any particular Assets for purposes of preferential purchase right notices shall bethe Allocated Value for such Assets (proportionately reduced if an Asset is only partiallyaffected). Seller shall use commercially reasonable efforts to cause such consents and waivers ofpreferential rights to purchase (or the exercise thereof) to be obtained and delivered prior toClosing. Purchaser shall cooperate with Seller in seeking to obtain such consents to assignment andwaivers of preferential rights. Notwithstanding anything contained herein to the contrary, Seller shallhave no liability for failure to either send such notices or obtain such consents or waivers.

(a) Consents . Seller shall notify Purchaser in writing on or before the Title ClaimDate of all required third-party consents to the assignment of the Assets to Purchaser which havenot been obtained and the Assets to which they pertain. In no event shall there be included in theConveyances at Closing any Asset subject to an unsatisfied consent requirement that would betriggered by the purchase and sale contemplated by this Agreement and provides that transfer ofthe Asset without consent will result in a termination or other material impairment of any existingrights in relation to such Asset (such consent, a “ Required Consent ”). In cases where the Assetsubject to such a Required Consent is a Contract and Purchaser is assigned the Properties towhich the Contract relates, but the Contract is not transferred to Purchaser due to the unwaivedconsent requirement, Seller shall continue after Closing to use commercially reasonable efforts toobtain such consent so that Seller’s right, title and interest in such Contract can be transferred toPurchaser upon receipt of such consent. In cases where the Asset subject to such a RequiredConsent is a Property and the third-party consent to the sale and transfer of the Property is notobtained prior to the Closing Date, Purchaser may elect to treat the unsatisfied Required Consentas a Title Defect by giving Seller notice thereof in accordance with Section 3.4(a), except thatsuch notice must be given at least three (3) days prior to the Closing Date; provided,however,the Allocated Value for such Property may not be used in meeting the Defect Deductible, andSeller may elect to cure such unsatisfied consent under Section 3.4(c), in which event theprovisions of Section 3.4(c) shall apply (provided the affected Asset shall be excluded from theAssets for purposes of Closing until the Required Consent is waived or satisfied (unless otherwiseagreed by Seller and Purchaser)). In cases where an Asset is subject to a third-party consentrequirement that is not a Required Consent, the Asset shall be included in the Assets at Closing(unless excluded pursuant to the other provisions of this Agreement) and Purchaser shall beresponsible after Closing for satisfying such consent requirement at its sole cost, risk andexpense, to the extent the applicable consent was not obtained or waived on or prior to Closing. Ifan unsatisfied Required Consent with respect to which a Purchase Price adjustment is made underSection 3.4 is subsequently satisfied prior to the date of the final adjustment to the Purchase Priceunder Section 9.4(b), Seller shall receive an additional upward adjustment to the Purchase Pricein the final adjustments made under Section 9.4(b) equal to the amount of the previous reductionin the Purchase Price on account of such Required Consent and the provisions of this Section 3.5shall no longer apply except for the assignment made under the next sentence. Within five (5)Business Days of the date on which the final statement of the Adjusted Purchase Price is finallydetermined, whether by agreement between Seller and Purchaser or the determination of anIndependent Expert under Section 9.4(b) (or both), Seller shall assign to Purchaser using the formattached as

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Exhibit B, to the extent previously unassigned, each Property subject to a Required Consent thatwas subsequently satisfied prior to the date of the final adjustment of the Purchase Price underSection 9.4(b).

(b) Exercised Preferential Rights to Purchase . If any preferential right to purchaseany Property that would be triggered by the purchase and sale contemplated by this Agreement isexercised prior to Closing, the Property transferred to a third Person as a result of the exercise ofsuch preferential right shall be treated as if it was subject to a Title Defect resulting in thecomplete loss of title and the Purchase Price shall be reduced under Section 2.2(b) by theAllocated Value for such Property (proportionately reduced if the preferential right affects only aportion of such Property), without application of the Defect Deductible. Seller shall retain theconsideration paid by the third party pursuant to the exercise of such preferential right; provided,however, the adjustment made under this Section 3.5(b) for such Property may not be used inmeeting the Defect Deductible. If, on or before ninety (90) days following the Closing Date, suchholder of such preferential right fails to consummate the purchase of the Property (or portionthereof) covered by such preferential right then (A) Seller shall so notify Purchaser on or beforeone hundred (100) days following the Closing Date, and (B) Purchaser shall purchase, on orbefore five (5) Business Days following receipt of such notice, such Property (or portion thereof)that was so excluded from the Properties to be assigned to Purchaser at Closing, under the termsof this Agreement and for a price equal to the amount by which the Purchase Price was reduced atClosing with respect to such excluded Property (or portion thereof), subject to adjustmentsapplicable to such Property under Section 2.2 above, and (C) Seller shall assign to Purchaser theProperty (or portion thereof) so excluded at Closing pursuant to an instrument in substantially thesame form as the Conveyance. If any preferential right to purchase any Asset is not exercised anddoes not expire prior to Closing, then the terms of Section 7.7 shall apply to such right.

Section 3.6 Casualty or Condemnation Loss .

Subject to the provisions of Sections 8.1(e) and 8.2(e), if, after the date of this Agreement butprior to the Closing Date, any portion of the Assets is destroyed by fire or other casualty or is taken incondemnation or under right of eminent domain, and the loss as a result of such individual casualty ortaking exceeds One Hundred Thousand Dollars ($100,000.00), Seller shall elect by written notice toPurchaser prior to Closing either (i) to cause the Assets affected by any casualty to be repaired orrestored prior to Closing to at least its condition prior to such casualty, at Seller’s sole cost (without anadjustment to the Purchase Price pursuant to Section 2.2 or otherwise), as promptly as reasonablypracticable (which work may extend thirty (30) days after the Closing Date), or (ii) unless such casualtyor taking is waived by Purchaser, to exclude the affected Property or Properties from the Assets andreduce the Purchase Price by the Allocated Value thereof; provided,however, that any adjustment to thePurchase Price pursuant to this Section 3.6 may not be used in meeting the Defect Deductible. In eachcase, Seller shall retain all of the aforementioned rights to insurance and other claims against thirdPersons with respect to the casualty or taking except to the extent the Parties otherwise agree in writing.

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Section 3.7 Limitations on Applicability .

The rights of Purchaser under Section 3.1(a) and Section 3.4(a) shall terminate as of the TitleClaim Date and be of no further force and effect thereafter, providedthere shall be no termination ofPurchaser’s or Seller’s rights under Section 3.4 with respect to any bona fide Title Defect properlyreported in a Title Defect Notice or bona fide Title Benefit properly reported in a Title Benefit Notice onor before the Title Claim Date. Except as provided in this Article 3 and for the Special Warranty in theConveyance (subject to Section 7.9), Purchaser releases, remises and forever discharges the SellerIndemnitees from any and all suits, legal or administrative proceedings, claims, demands, damages,losses, costs, liabilities, interest or causes of action whatsoever, in Law or in equity, known or unknown,which Purchaser might now or subsequently may have, based on, relating to or arising out of, any TitleDefect or other deficiency in or encumbrance on title to any Asset.

ARTICLE 4

ENVIRONMENTAL MATTERS

Section 4.1 Assessment .

From and after the date hereof and up to and including the Closing Date (or upon the earliertermination of this Agreement) but subject to the limitations set forth herein and in Section 7.1,Purchaser may, at its option, cause, or cause to be conducted by a reputable environmental consulting orengineering firm approved in advance in writing by Seller (the “ Environmental Consultant ”) anenvironmental assessment of all or any portion of the Assets and/or visual inspections, record reviews,and interviews relating to the Properties, including their condition and their compliance withEnvironmental Laws (the “ Assessment ”). In connection with the foregoing, Seller hereby consents to[_____] ,should such Person become Purchaser’s Environmental Consultant. The Assessment shall beconducted at the sole risk, cost and expense of Purchaser, and all of Purchaser’s and the EnvironmentalConsultant’s activity conducted under this Section 4.1 and Section 7.1 shall be subject to the indemnityprovisions of Section 7.6. Purchaser’s right of access shall not entitle Purchaser or the EnvironmentalConsultant to operate equipment or conduct testing or sampling of soil, groundwater or other materials(including any testing or sampling for hazardous substances, Hydrocarbons or NORM). Seller has theright to be present during any activities conducted on the Assets as part of the Assessment. Purchasershall give Seller reasonable prior written notice before gaining physical access to the Assets. Purchasershall coordinate the Assessment with Seller to minimize any inconvenience to or interruption of theconduct of business by Seller. Purchaser shall abide by Seller’s, and any third party operator’s, safetyrules, regulations and operating policies while conducting its due diligence evaluation of the Assetsincluding the Assessment. Purchaser shall promptly provide, but not later than the Environmental ClaimDate, copies of all reports, results, and other documentation and data prepared or compiled by Purchaserand/or any of its representatives or agents in connection with the Assessment (excluding alldocumentation subject to the attorney-client privilege). Upon completion of the Assessment, Purchasershall at its sole cost and expense and without any cost or expense to Seller or any of its Affiliates(i) repair all damages done to any Assets in connection the Assessment (including due diligenceconducted by Purchaser’s environmental consulting or engineering firm), (ii) if applicable, restore theAssets to the approximate same condition as, or

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better condition than, they were prior to commencement of the Assessment, and (iii) remove allequipment, tools and other property brought onto the Assets in connection with the Assessment. Anydisturbance to the Assets (including the leasehold associated therewith) resulting from the Assessmentwill be promptly corrected by Purchaser at Purchaser’s sole cost and expense. Seller shall not be deemedby its receipt of said documents or otherwise to have made any representation or warranty, expressed,implied or statutory, as to the condition of the Assets or the accuracy of said documents or theinformation contained therein. During all periods that Purchaser or any of its representatives orcontractors are on the Assets, Purchaser shall maintain, at its sole expense and with reputable insurers,such insurance as is reasonably sufficient to support Purchaser’s indemnity obligations under Section 7.6specifically naming Seller as an insured party. All information (including all reports, results anddocumentation containing such information) acquired by Purchaser, its agents or representatives, or theEnvironmental Consultant, in conducting the Assessment under this Section shall be subject to theConfidentiality Agreement.

Section 4.2 NORM .

Purchaser acknowledges the following:

(a) The Assets have been used for exploration, development, and production of oiland gas and that there may be petroleum, produced water, wastes, or other materials located on orunder the Properties or associated with the Assets.

(b) Equipment and sites included in the Assets may contain asbestos, hazardoussubstances, or NORM.

(c) NORM may affix or attach itself to the inside of wells, materials, and equipmentas scale, or in other forms.

(d) The wells, materials, and equipment located on the Properties or included in theAssets may contain NORM and other wastes or hazardous substances.

(e) NORM containing material and other wastes or hazardous substances may havecome in contact with the soil.

(f) Special procedures may be required for the remediation, removal, transportation,or disposal of soil, wastes, asbestos, hazardous substances, and NORM from the Assets.

Section 4.3 Notice of Violations of Environmental Laws .

Purchaser shall deliver any claim notices to Seller in writing (an “ Environmental Defect Notice”), on or before 5:00 p.m., Central Daylight Savings Time on July 21, 2017 (the “ Environmental ClaimDate ”), of each individual environmental matter disclosed by the Assessment that Purchaser reasonablybelieves in good faith may constitute or result in (including with notice or solely with the passage oftime) Environmental Liabilities which, utilizing the Lowest Cost Response to address the matter, satisfythe Property Defect Threshold, including in the Environmental Defect Notice (i) a reasonably detaileddescription of the specific matter that is an alleged violation of Environmental Laws, including (A) thewritten conclusion of Purchaser or

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Purchaser’s Environmental Consultant that Environmental Liabilities exist, which conclusion shall bereasonably substantiated by the factual data gathered in Purchaser’s Assessment and (B) a separatespecific citation of the provisions of Environmental Laws alleged to be violated and the related facts thatsubstantiate such violation; (ii) the Wells or associated Assets affected; (iii) a detailed estimate of theLowest Cost Response to cure or eliminate the alleged matter in question; (iv) supporting documentsreasonably necessary for Seller (as well as any consultant, inspector or expert hired by Seller to verifythe existence of the facts alleged in the Environmental Defect Notice); and (v) information reflecting thesatisfaction of the Property Defect Threshold. The failure of an Environmental Defect Notice to containthe information required by item nos. (i) through (iv) of the prior sentence on or prior to theEnvironmental Claim Date shall render such notice ineffective. Purchaser shall furnish Seller, on orbefore the end of each calendar week prior to the Environmental Claim Date, Environmental DefectNotices with respect to any Environmental Liability that any of Purchaser’s or any of its Affiliate’semployees, representatives, attorney or other environmental personnel or contractors, including theEnvironmental Consultant, discover or become aware of during the preceding calendar week, whichnotice may be preliminary in nature and supplemented prior to the Environmental Claim Date.

Section 4.4 Remedies for Violations of Environmental Laws .

If Seller confirms to its reasonable satisfaction that any individual matter described in anEnvironmental Defect Notice delivered pursuant to Section 4.3 may constitute or result in EnvironmentalLiabilities for which, when utilizing the Lowest Cost Response to address such matters, exceeds theProperty Defect Threshold, then Seller shall elect to:

(a) reduce the Purchase Price by an amount agreed upon in writing by Purchaser andSeller as being a reasonable estimate of the cost of curing the matter described in suchEnvironmental Defect Notice; or

(b) with the consent of Purchaser, retain the Property that is associated with suchEnvironmental Defect Notice and affected by such matter, in which event the Purchase Price shallbe reduced by an amount equal to the Allocated Value of such Property; provided,however, thatif the Environmental Liabilities affecting a Property exceed the Allocated Value of the Property,Seller may elect to retain the Property in accordance with this Section 4.4(b) without the consentof Purchaser; or

(c) perform or cause to be performed prior to Closing, at the sole cost and expense ofSeller, such operations as may be necessary to bring such affected Property into compliance withthe applicable Environmental Law disclosed in such Environmental Defect Notice; or

(d) enter into an agreement with Purchaser whereby Seller will as soon as reasonablypracticable after Closing, at the sole cost and expense of Seller, perform or cause to be performedsuch operations as may be necessary to bring such affected Property into compliance with theapplicable Environmental Law disclosed in such Environmental Defect Notice; or

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(e) if applicable, terminate this Agreement pursuant to Article 10.

In the event that (i) Seller elects to proceed under Section 4.4(a) and Purchaser and Seller havefailed to agree by Closing on the reduction to the Purchase Price (which agreement Seller and Purchasershall use good faith efforts to reach) or (ii) Purchaser and Seller cannot otherwise agree on the existence,extent or amount of Environmental Liabilities alleged in an Environmental Defect Notice before Closing,Seller shall then proceed with respect to such matter under any of Sections 4.4(b), (c), (d), or (e) orsubmit such dispute to arbitration pursuant to this Section 4.4. In the event that Seller elects to proceedunder Section 4.4(d) and Purchaser and Seller have failed to agree by Closing on the terms of theagreement contemplated thereby (which agreement Seller and Purchaser shall use good faith efforts toreach), Seller shall then proceed with respect to such matter under any of Sections 4.4(b), (c), or (e) orsubmit such dispute to arbitration pursuant to this ‎Section 4.4.

For all matters submitted to arbitration pursuant to this Section 4.4, there shall be a singlearbitrator, who shall be an environmental consultant with at least ten (10) years’ relevant experience asselected by mutual agreement of Purchaser and Seller within fifteen (15) days of an election by Seller tosubmit such dispute to arbitration. Absent such agreement on the selection of the arbitrator, the arbitratorshall be selected by the Houston, Texas office of the American Arbitration Association (the “Environmental Arbitrator ”). The arbitration proceeding shall be held in Houston, Texas and shall beconducted in accordance with the Commercial Arbitration Rules of the American ArbitrationAssociation, to the extent such rules do not conflict with the terms of this Section. The EnvironmentalArbitrator’s determination shall be made within twenty (20) days after submission of the matters indispute and shall be final and binding upon both parties, without right of appeal. In making hisdetermination, the Environmental Arbitrator shall be bound by the rules set forth in this Article 4 andmay consider such other matters as in the opinion of the Environmental Arbitrator are necessary orhelpful to make a proper determination. In connection with the determination of a matter submitted tothe Environmental Arbitrator Purchaser may not assert any violation of Environmental Law that is notspecified by Purchaser in the applicable Environmental Claim Notice. The Environmental Arbitratorshall act as an expert for the limited purpose of determining the specific disputed Environmental Liabilityor the Lowest Cost Response for such Environmental Liability submitted by Seller and may not awarddamages, interest or penalties to either Party with respect to any matter nor may it award Purchaser agreater amount with respect to the applicable Environmental Liability than the Lowest Cost Response setforth by Purchaser in the applicable Environmental Claim Notice. Seller and Purchaser shall each bearits own legal fees and other costs of presenting its case. Each Party shall bear one-half of the costs andexpenses of the Environmental Arbitrator. If the validity of any Environmental Liability or the LowestCost Response attributable thereto, is not determined prior to Closing by the Environmental Arbitratorpursuant to this Section 4.4, all affected Properties shall be conveyed to Purchaser at Closing and thepurchase price paid by Purchaser at Closing shall not be reduced by virtue of such dispute and upon finalresolution of such dispute the Lowest Cost Response for such Environmental Liability as determined bythe Environmental Arbitrator shall, subject to the terms of this this Section 4.4, be promptly refunded bySeller to Purchaser.

Notwithstanding anything herein to the contrary, (i) in no event shall there be any adjustments tothe Purchase Price or other remedies provided by Seller for Environmental Liabilities for which, whenutilizing the Lowest Cost Response to address same do not satisfy the

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Property Defect Threshold; and (ii) in no event shall there be any adjustments to the Purchase Price orother remedies provided by Seller for Environmental Liabilities unless and until the sum of (i) theaggregate amount of all Title Defect Amounts for Title Defects covered by Section 3.4(d)(i) that satisfythe Property Defect Threshold, plus (ii) the aggregate amount of all Environmental Liabilities covered bySection 4.4(a) that satisfy the Property Defect Threshold, exceeds the Defect Deductible, after whichpoint Purchaser shall be entitled to adjustments to the Purchase Price or other available remedies underthis Section 4.4 with respect to Environmental Liabilities in excess of such Defect Deductible, subject toSeller’s elections under this Section 4.4 and the last sentence of this Section 4.4. The Allocated Value ofany Property (or affected portion thereof) retained by Seller in accordance with Section 4.4(b) may notbe used in meeting the Defect Deductible.

Section 4.5 Limitations .

Notwithstanding anything to the contrary in this Agreement, except for the indemnity providedunder Section 11.2(c) as it relates to breaches of the representation in Section 5.15, this Article 4 isintended to be the sole and exclusive remedy that Purchaser Indemnitees shall have against SellerIndemnitees with respect to any matter or circumstance relating to Environmental Laws, the release ofmaterials into the environment or protection of the environment or health. Except to the limited extentnecessary to enforce the terms of this Article 4 and the indemnity provided under Section 11.2(c) as itrelates to breaches of the representation in Section 5.15, Purchaser (on behalf of itself, each of the otherPurchaser Indemnitees and their respective insurers and successors in interest) hereby releases anddischarges any and all claims and remedies at Law or in equity, known or unknown, whether nowexisting or arising in the future, contingent or otherwise, against the Seller Indemnitees with respect toany matter or circumstance relating to Environmental Laws, Environmental Liabilities, the release orthreatened release of materials into the environment or protection of the environment, natural resources,threatened or endangered species, or health EVEN IF SUCH CLAIMS OR DAMAGES ARECAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE (WHETHER SOLE, JOINT ORCONCURRENT, EXCLUDING WILLFUL MISCONDUCT), STRICT LIABILITY OR OTHERLEGAL FAULT OF SELLER INDEMNITEES . Except as expressly provided in Section 5.15,Purchaser acknowledges that Seller has not made and will not make any representation or warrantyregarding any matter or circumstance relating to Environmental Laws, Environmental Liabilities, therelease or threatened release of materials into the environment or protection of the environment, naturalresources, threatened or endangered species, or health, and that nothing in Article 5 or otherwise shall beconstrued as such a representation or warranty.

ARTICLE 5

REPRESENTATIONS AND WARRANTIES OF SELLER

Section 5.1 Disclaimers .

(a) EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN ARTICLE5 OF THIS AGREEMENT OR IN THE CERTIFICATE OF SELLER TO BE DELIVEREDPURSUANT TO SECTION 9.2(F), OR FOR THE SPECIAL WARRANTY IN THECONVEYANCE ( SUBJECT TO SECTION 7.9 ) , WITH RESPECT TO THE ASSETS ANDTHE TRANSACTIONS CONTEMPLATED HEREBY (i) SELLER

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MAKES NO REPRESENTATIONS OR WARRANTIES, STATUTORY, EXPRESS ORIMPLIED, AND (ii) PURCHASER HAS NOT RELIED UPON, AND SELLER EXPRESSLYDISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR, ANY REPRESENTATION,WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLYOR IN WRITING) TO PURCHASER OR ANY OF ITS AFFILIATES, OR ITS OR THEIREMPLOYEES, AGENTS, OFFICERS, DIRECTORS, MEMBERS, MANAGERS, EQUITYOWNERS, CONSULTANTS, REPRESENTATIVES OR ADVISORS (INCLUDING ANYOPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEENPROVIDED TO PURCHASER BY ANY EMPLOYEE, AGENT, OFFICER, DIRECTOR,MEMBER, MANAGER, EQUITY OWNER, CONSULTANT, REPRESENTATIVE ORADVISOR OF SELLER OR ANY OF ITS AFFILIATES).

(b) EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN ARTICLE5 OR IN THE CERTIFICATE OF SELLER TO BE DELIVERED PURSUANT TO SECTION9.2(F) , OR FOR THE SPECIAL WARRANTY IN THE CONVEYANCE ( SUBJECT TOSECTION 7.9 ) , WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLEREXPRESSLY DISCLAIMS, AND PURCHASER ACKNOWLEDGES AND AGREES THATIT HAS NOT RELIED UPON, ANY REPRESENTATION OR WARRANTY, STATUTORY,EXPRESS OR IMPLIED, AS TO (i) TITLE TO ANY OF THE ASSETS, (ii) THE CONTENTS,CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, OR ANY REPORTOF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL ORSEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (iii) THEQUANTITY, QUALITY OR RECOVERABILITY OF PETROLEUM SUBSTANCES IN ORFROM THE ASSETS, (iv) ANY ESTIMATES OF THE VALUE OF THE ASSETS ORFUTURE REVENUES GENERATED BY THE ASSETS, (v) THE PRODUCTION OFPETROLEUM SUBSTANCES FROM THE ASSETS, (vi) ANY ESTIMATES OFOPERATING COSTS AND CAPITAL REQUIREMENTS FOR ANY WELL, OPERATION,OR PROJECT, (vii) THE MAINTENANCE, REPAIR, CONDITION, QUALITY,SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (viii) THE CONTENT,CHARACTER OR NATURE OF ANY DESCRIPTIVE MEMORANDUM, REPORTS,BROCHURES, CHARTS OR STATEMENTS PREPARED BY THIRD PARTIES, (ix) ANYOTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLEOR COMMUNICATED TO PURCHASER OR ITS AFFILIATES, OR ITS OR THEIREMPLOYEES, AGENTS, OFFICERS, DIRECTORS, MEMBERS, MANAGERS, EQUITYOWNERS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTIONWITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANYDISCUSSION OR PRESENTATION RELATING THERETO, AND FURTHER DISCLAIMSANY REPRESENTATION OR WARRANTY, STATUTORY, EXPRESS OR IMPLIED, OFMERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TOMODELS OR SAMPLES OF MATERIALS OF ANY EQUIPMENT, IT BEING EXPRESSLYUNDERSTOOD AND AGREED BY THE PARTIES THAT PURCHASER HAS INSPECTED,OR WAIVED PURCHASER’S RIGHT TO INSPECT, THE ASSETS FOR ALL PURPOSESAND SATISFIED ITSELF AS TO THEIR PHYSICAL AND ENVIRONMENTAL

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CONDITION, BOTH SURFACE AND SUBSURFACE, INCLUDING BUT NOT LIMITED TOCONDITIONS SPECIFICALLY RELATED TO THE PRESENCE, RELEASE OR DISPOSALOF HAZARDOUS SUBSTANCES, SOLID WASTES OR NORM, AND THAT PURCHASERSHALL BE DEEMED TO BE OBTAINING THE ASSETS, INCLUDING THE EQUIPMENT,IN ITS PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHEREIS” WITH ALL FAULTS AND DEFECTS, AND THAT PURCHASER HAS MADE ORCAUSED TO BE MADE SUCH INSPECTIONS AS PURCHASER DEEMS APPROPRIATE,OR (ix) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT ORTRADEMARK INFRINGEMENT.

(c) Any representation “to the knowledge of Seller” or “to Seller’s knowledge” islimited to matters within the actual knowledge of the persons set forth on Exhibit C. Exhibit Cfurther identifies all offices or employment positions of said persons with the Seller, or Affiliatesof Seller, and the periods of time such offices and employment positions were held. “Actualknowledge” for purposes of this Agreement means information actually personally known.

(d) Inclusion of a matter on a Schedule to a representation or warranty whichaddresses matters having a Material Adverse Effect shall not be deemed an indication that suchmatter does, or may, have a Material Adverse Effect. Matters may be disclosed on a Schedule tothis Agreement for purposes of information only. Matters disclosed in each Schedule shallqualify the representation and warranty in which such Schedule is referenced and any otherrepresentation and warranty to which the matters disclosed reasonably relate.

(e) From time to time prior to the Closing Date, Seller may supplement or amend theSchedules hereto, to correct any matter that would otherwise constitute a breach of anyrepresentation or warranty of Seller contained herein (each a “ Schedule Supplement ”), andeach such Schedule Supplement shall be deemed to be incorporated into and supplement andamend the Schedules as of the Closing Date; provided, however, that any such ScheduleSupplement shall be disregarded for purposes of, and shall not affect Purchaser’s conditions toClosing set forth in Section 8.2, Purchaser’s Assumed Obligations, and Purchaser’s indemnitiesin Section 11.2(b).

(f) Subject to the foregoing provisions of this Section 5.1, and the other terms andconditions of this Agreement, Seller, as to its individual interest only, represents and warrants toPurchaser the matters set out in Sections 5.2 through Section 5.16 as of the date of thisAgreement.

Section 5.2 Existence and Qualification .

Seller is duly organized, validly existing and in good standing under the Laws of the state of itsformation and is duly qualified to do business in the jurisdictions where the Assets are located, exceptwhere the failure to so qualify would not have a Material Adverse Effect.

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Section 5.3 Power .

Seller has the requisite power to enter into and perform this Agreement and consummate thetransactions contemplated by this Agreement.

Section 5.4 Authorization and Enforceability .

The execution, delivery and performance of this Agreement, and the performance of thetransactions contemplated hereby, have been duly and validly authorized by all necessary action on thepart of Seller. This Agreement has been duly executed and delivered by Seller (and all documentsrequired hereunder to be executed and delivered by Seller at Closing will be duly executed and deliveredby Seller) and this Agreement constitutes, and at the Closing such documents will constitute, the validand binding obligations of Seller, enforceable in accordance with their terms except as suchenforceability may be limited by applicable bankruptcy or other similar Laws affecting the rights andremedies of creditors generally as well as to general principles of equity (regardless of whether suchenforceability is considered in a proceeding in equity or at Law).

Section 5.5 No Conflicts .

The execution, delivery and performance of this Agreement by Seller, and the transactionscontemplated by this Agreement, will not (i) violate any provision of the governing documents of Seller,(ii) result in a material default (with due notice or lapse of time or both) or the creation of any lien orencumbrance, or give rise to any right of termination, cancellation or acceleration under any of the terms,conditions or provisions of any promissory note, bond, mortgage, indenture, loan or similar financinginstrument to which Seller is a party and which affects the Assets, (iii) violate any judgment, order,ruling, or decree applicable to Seller as a party in interest or (iv) violate any Laws applicable to Seller orany of the Assets (except for rights to consent by, required notices to, and filings with or other actions byGovernmental Bodies where the same are not required prior to the assignment of oil and gas interests),except any matters described in clauses (ii), (iii) or (iv) above which would not have, individually or inthe aggregate, a Material Adverse Effect.

Section 5.6 Liability for Brokers’ Fees .

Purchaser shall not directly or indirectly have any responsibility, liability or expense, as a resultof undertakings or agreements of Seller, for brokerage fees, finder’s fees, agent’s commissions or othersimilar forms of compensation in connection with this Agreement or any agreement or transactioncontemplated hereby.

Section 5.7 Litigation .

Except as disclosed on Schedule 5.7, there are no actions, suits or proceedings pending for whichSeller has received written notice, or to Seller’s knowledge threatened in writing, before anyGovernmental Body or arbitrator to which the Assets are subject except for any such actions, suits orproceedings which would not have, individually or in the aggregate, a Material Adverse Effect.

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Section 5.8 Taxes and Assessments .

Except as set forth on Schedule 5.8, Seller warrants and represents (a) all material reports,returns, statements (including estimated reports, returns or statements), and other similar filings withrespect to Taxes (the “ Tax Returns ”) relating to the ownership or operation of the Assets required to befiled by Seller have been timely filed (taking into account all applicable extensions) with the appropriateGovernmental Body in all jurisdictions in which such Tax Returns are required to be filed; (b) such TaxReturns are true and correct in all material respects, and all material Taxes reported and due on such TaxReturns have been paid; (c) there is not currently in effect any extension or waiver of any statute oflimitations regarding the assessment or collection of any Tax with respect to the Assets, which period hasnot yet expired; (d) there are no administrative proceedings or lawsuits pending with respect to theAssets by any taxing authority for which Seller has received written notice; and (e) none of the Assets isheld in an arrangement that is treated as a partnership for Tax purposes.

Notwithstanding anything in this Agreement to the contrary, this Section 5.8 contains theexclusive representations and warranties with respect to Tax matters, and no other Section in this Article5 shall apply to Tax matters.

Section 5.9 Outstanding Capital Commitments .

As of the date of this Agreement, there is no individual outstanding authority for expenditurewhich is binding on the Assets, the value of which Seller reasonably anticipates exceeds Fifty ThousandDollars ($50,000.00) chargeable to Seller’s interests participating in the operation covered by suchauthority for expenditure after the Effective Time, other than those shown on Schedule 5.9 hereto.

Section 5.10 Compliance with Laws .

Except as disclosed on Schedule 5.10, to the knowledge of Seller, the Assets are and theoperation of the Assets has been and currently is, in substantial compliance with the provisions andrequirements of all Laws (excluding Environmental Laws, which are addressed in Section 5.15) of allGovernmental Bodies having jurisdiction with respect to the Assets, or the ownership, operation,development, maintenance, or use of any thereof.

Section 5.11 Contracts .

Seller is not and, to Seller’s knowledge, no other party is, in default under any Contract except asdisclosed on Schedule 5.11(a) and except such defaults as would not, individually or in the aggregate,have a Material Adverse Effect. Schedule 5.11(b) sets forth all of the following Contracts included in theAssets or to which any of the Assets will be bound as of the Closing: (i) any agreement with anyAffiliate; (ii) any agreement or contract for the sale, exchange, or other disposition of Hydrocarbonsproduced from or attributable to Seller’s interest in the Assets that is not cancelable without penalty orother material payment on not more than ninety (90) days prior written notice; (iii) any agreement of orbinding upon Seller to sell, lease, farmout, or otherwise dispose of any interest in any of the Assets afterthe Effective Time, other than conventional rights of reassignment arising in connection with Seller’ssurrender or release of any of the Assets and

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(iv) joint operating agreements, area of mutual interest agreements and farmout and farmin agreements.

Section 5.12 Payments for Production .

Except as set forth on Schedule 5.12, Seller is not obligated under any contract or agreementcontaining a take-or-pay, advance payment, prepayment, or similar provision, or under any gathering,transmission, or any other contract or agreement with respect to any of the Assets to sell, gather, deliver,process, or transport any Hydrocarbons without then or thereafter receiving full payment therefor. ToSeller’s knowledge, all royalties and in-lieu royalties with respect to the Assets which accrued or areattributable to the period prior to the Effective Time have been properly and fully paid, or are includedwithin the Suspended Proceeds.

Section 5.13 Governmental Authorizations .

Except as disclosed on Schedule 5.13, to the knowledge of Seller, Seller has obtained and ismaintaining all federal, state and local governmental licenses, permits, franchises, orders, exemptions,variances, waivers, authorizations, certificates, consents, rights, privileges and applications therefor (the“ Governmental Authorizations ”) that are presently necessary or required for the operation of theSeller Operated Assets as currently operated (excluding those required under Environmental Laws), theloss of which would have, individually or in the aggregate, a Material Adverse Effect.

Section 5.14 Consents and Preferential Purchase Rights .

None of the Leases, Units or Wells, or any portion thereof, is subject to any (i) preferential rightsto purchase, (ii) restrictions on assignment or required third-party consents to assignment that if notobtained in connection with an assignment to Purchaser would result in a termination of Seller’s title tosuch Asset or (iii) to the best of Seller’s knowledge, other third-party consents to assignment, which areapplicable to the transactions contemplated by this Agreement, except for (x) consents and approvals byGovernmental Bodies of assignments that are customarily obtained after Closing, (y) preferential rights,consents and restrictions contained in easements, rights-of-way, Surface Contracts or equipment leasesand (z) preferential rights, consents and restrictions as are set forth on Schedule 5.14.

Section 5.15 Environmental Laws .

Except as disclosed on Schedule 5.15, to Seller’s knowledge the Properties and the operationthereof are in compliance with applicable Environmental Laws, except for incidents of noncompliancethat, individually or in the aggregate, would not reasonably be expected to have a Material AdverseEffect. Notwithstanding anything to the contrary in this Section 5.15 or elsewhere in this Agreement,Seller makes no, and disclaims any, representation or warranty, express or implied, with respect to thepresence or absence of NORM, asbestos, mercury, drilling fluids and chemicals, and produced watersand Hydrocarbons in or on the Properties or Equipment. The representation and warranty in this Section5.15 constitutes the only representation and warranty with respect to Environmental Laws orEnvironmental Liabilities and no other representation or warranty appearing in this Agreement shall beconstrued to cover Environmental Laws or Environmental Liabilities.

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Section 5.16 Bankruptcy .

There are no bankruptcy, reorganization or receivership proceedings pending, being contemplatedby or, to Seller’s knowledge, threatened against Seller.

Section 5.17 Imbalances .

To Seller’s knowledge, Schedule 5.17 accurately sets forth in all material respects all of Seller’sImbalances as of the respective dates set forth therein, arising with respect to the Assets.

Section 5.18 Oil and Gas Operations .

To Seller’s knowledge, all Wells have been drilled, completed, operated and produced inaccordance with generally accepted oil and gas field practices in compliance in all material respects withapplicable leases, pooling and unit agreements, joint operating agreements and Laws.

Section 5.19 Non-Consent Operations .

To Seller’s knowledge, no operations are being conducted or have been conducted with respect tothe Assets as to which Seller has elected to be a nonconsenting party under the terms of the applicableoperating agreement and with respect to which Seller has not yet recovered its full participation.

Section 5.20 Sufficiency of Assets .

Subject to Section 3.4(c), the Assets include in all material respects the equipment, materials andsimilar property necessary for the continued operation, following the Closing, of the Seller’s business asconducted as of the date hereof with respect to the Assets.

ARTICLE 6

REPRESENTATIONS AND WARRANTIES OF PURCHASER

Purchaser represents and warrants to Seller the following:

Section 6.1 Existence and Qualification .

Purchaser is a limited partnership organized, validly existing and in good standing under theLaws of the state of Delaware; and Purchaser is duly qualified to do business as a foreign limitedpartnership in every jurisdiction in which it is required to qualify in order to conduct its business exceptwhere the failure to so qualify would not have a material adverse effect on Purchaser or its properties;and Purchaser is or will be duly qualified to do business as a foreign limited liability company in therespective jurisdictions where the Assets to be transferred to it are located.

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Section 6.2 Power .

Purchaser has the requisite power to enter into and perform this Agreement and consummate thetransactions contemplated by this Agreement.

Section 6.3 Authorization and Enforceability .

The execution, delivery and performance of this Agreement, and the performance of thetransactions contemplated hereby, have been duly and validly authorized by all necessary action on thepart of Purchaser. This Agreement has been duly executed and delivered by Purchaser (and alldocuments required hereunder to be executed and delivered by Purchaser at Closing will be dulyexecuted and delivered by Purchaser) and this Agreement constitutes, and at the Closing such documentswill constitute, the valid and binding obligations of Purchaser, enforceable in accordance with their termsexcept as such enforceability may be limited by applicable bankruptcy or other similar Laws affectingthe rights and remedies of creditors generally as well as to general principles of equity (regardless ofwhether such enforceability is considered in a proceeding in equity or at Law).

Section 6.4 No Conflicts .

The execution, delivery and performance of this Agreement by Purchaser, and the transactionscontemplated by this Agreement will not (i) violate any provision of the limited liability companyagreement, bylaws, limited partnership agreement or other governing or charter documents of Purchaser,(ii) result in a material default (with due notice or lapse of time or both) or the creation of any lien orencumbrance, or give rise to any right of termination, cancellation or acceleration under any of the terms,conditions or provisions of any promissory note, bond, mortgage, indenture, loan or similar financinginstrument to which Purchaser is a party or which affects Purchaser’s assets, (iii) violate any judgment,order, ruling, or regulation applicable to Purchaser as a party in interest or (iv) violate any Lawsapplicable to Purchaser or any of its assets, except any matters described in clauses (ii), (iii) or (iv) abovewhich would not have a material adverse effect on Purchaser.

Section 6.5 Liability for Brokers’ Fees .

Seller shall not directly or indirectly have any responsibility, liability or expense, as a result ofundertakings or agreements of Purchaser, for brokerage fees, finder’s fees, agent’s commissions or othersimilar forms of compensation in connection with this Agreement or any agreement or transactioncontemplated hereby.

Section 6.6 Litigation .

As of the date of the execution of this Agreement, there are no actions, suits or proceedingspending, or to Purchaser’s knowledge, threatened in writing before any Governmental Body againstPurchaser or any subsidiary of Purchaser which are reasonably likely to impair materially Purchaser’sability to perform its obligations under this Agreement.

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Section 6.7 Financing .

Purchaser has sufficient cash, available lines of credit or other sources of immediately availablefunds (in United States dollars) to enable it to pay the Closing Payment to Seller at the Closing.

Section 6.8 Independent Investigation .

Purchaser (a) is sophisticated in the evaluation, purchase, ownership and operation of oil and gasproperties and related facilities and is aware of the risks associated with the purchase, ownership andoperation of such properties and facilities, (b) is capable of evaluating, and hereby acknowledges that ithas so evaluated, the merits and risks of the Assets, ownership and operation thereof and its obligationshereunder, and (c) is able to bear the economic risks associated with the Assets, ownership and operationthereof and its obligations hereunder. In making its decision to enter into this Agreement and toconsummate the transactions contemplated hereby, Purchaser (i) has relied or shall rely solely on its ownindependent investigation and evaluation of the Assets and the advice of its own legal, Tax, economic,environmental, engineering, geological and geophysical advisors and acknowledges and agrees that (A) ithas not been induced by and has not relied upon any representations, warranties or statements, whetherexpress or implied, made at any time by any Seller or any of its or their directors, officers, shareholders,employees, Affiliates, controlling persons, agents, advisors or representatives or any other Person,whether or not any such representations, warranties or statements were made in writing or orally, (B) noSeller nor any of its or their respective directors, officers, shareholders, employees, Affiliates, controllingpersons, agents, advisors or representatives or any other Person makes or has made any representation orwarranty, either express or implied, as to the accuracy or completeness of any of the informationprovided or made available to Purchaser or its directors, officers, employees, Affiliates, controllingpersons, agents or representatives, including any information, document or material provided or madeavailable, or statements made or provided to any Seller (including its directors, officers, employees,Affiliates, controlling persons, agents or representatives) in connection with the transactionscontemplated by this Agreement, including without limitation, any such information contained in orprovided in “data rooms”, management presentations or supplemental due diligence informationprovided by a Seller or discussions or access to management of a Seller; and (C) the information referredto in (B) above may include certain projections, estimates and other forecasts and plans and that there areuncertainties inherent in attempting to make such projections, estimates and other forecasts and plans andPurchaser is familiar with such uncertainties and takes full responsibility for making its own evaluationof the adequacy and accuracy of all such projections, estimates and other forecasts and plans and any useor reliance by Purchaser on such information referred to in (B) above is (or the projections, estimates andother forecasts and plans that may be contained therein) at Purchaser’s sole risk; (ii) has satisfied or shallsatisfy itself through its own due diligence as to the environmental and physical condition of andcontractual arrangements and other matters affecting the Assets; and (iii) agrees to the fullest extentpermitted by Law that no Seller nor any of its or their directors, officers, employees, Affiliates,controlling persons, agents or representatives shall have any liability or responsibility whatsoever toPurchaser or its directors, officers, employees, Affiliates, controlling persons, agents or representativeson any basis (including in contract or tort, under Federal or state securities laws or otherwise) resultingfrom the distribution to Purchaser or Purchaser’s use of any of the information referred to in clause (i)(B)above. Purchaser acknowledges and affirms as of

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the Closing Date that (i) it has made all such reviews and inspections of the Assets as it has deemednecessary or appropriate and (ii) except for the express representations, warranties, covenants andremedies provided in this Agreement, it is acquiring the Assets on an as-is, where-is basis with all faults,and has not relied upon any other representations, warranties, covenants or statements of Seller inentering into this Agreement.

Section 6.9 Bankruptcy .

There are no bankruptcy, reorganization or receivership proceedings pending against, beingcontemplated by, or, to Purchaser’s knowledge, threatened against Purchaser.

Section 6.10 Qualification .

Purchaser, or its designee Affiliate operator, shall be, at Closing, and thereafter, for so long asPurchaser shall own the Assets, shall continue to be, qualified to own and assume operatorship of federaland state oil, gas and mineral leases in all jurisdictions where the Assets to be transferred to it arelocated, and the consummation of the transactions contemplated in this Agreement will not causePurchaser and its designee operator to be disqualified as such an owner or operator. To the extentrequired by applicable Law, as of the Closing, Purchaser or its designee Affiliate operator currently has,and will continue to maintain, lease bonds, area-wide bonds or any other surety bonds as may be requiredby, and in accordance with, such state or federal regulations governing the ownership and operation ofsuch leases.

Section 6.11 Consents .

Except for consents and approvals for the assignment of the Assets to Purchaser that arecustomarily and lawfully obtained after the assignment of properties similar to the Assets, there are noconsents, approvals or other restrictions on assignment applicable to Purchaser that Purchaser isobligated to obtain or furnish, including requirements for consents from third parties to any assignment(in each case), that would be applicable in connection with the consummation of the transactionscontemplated by this Agreement and perform and observe the covenants and obligations of Purchaser.

ARTICLE 7

COVENANTS OF THE PARTIES

Section 7.1 Access .

Between the date of execution of this Agreement and continuing until the Closing Date, Sellerwill give Purchaser and its representatives access to Seller’s offices and the Records, including the rightto copy, at Purchaser’s expense, the Records in Seller’s possession, for the sole purpose of conducting aninvestigation of the Assets, but only to the extent that Seller may do so without violating any applicableLaw or obligations to any third Person and to the extent that Seller has authority to grant such accesswithout breaching any restriction binding on Seller. Such access by Purchaser shall be subject toapplicable limitations in Section 4.1 and shall be limited to Seller’s normal business hours, and anyweekends and after hours requested by Purchaser that can be reasonably accommodated by Seller, andPurchaser’s investigation shall be conducted in a manner

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that minimizes interference with the operation of the Assets. All information obtained by and accessgranted to Purchaser and its representatives under this Section shall be subject to the terms of Section 7.6and the terms of the Confidentiality Agreement.

Section 7.2 Government Reviews .

Each Party shall in a timely manner (a) make all required filings, if any, with and prepareapplications to and conduct negotiations with, each Governmental Body as to which such filings,applications or negotiations are necessary or appropriate for such Party to consummate the transactionscontemplated hereby, and (b) provide such information as the other Party may reasonably request tomake such filings, prepare such applications and conduct such negotiations. Each Party shall cooperatewith and use all commercially reasonable efforts to assist the other with respect to such filings,applications and negotiations.

Section 7.3 Notification of Breaches .

Until the Closing,

(a) Purchaser shall notify Seller promptly after Purchaser obtains actual knowledgethat any representation or warranty of Seller contained in this Agreement is untrue in any materialrespect or will be untrue in any material respect as of the Closing Date or that any covenant oragreement to be performed or observed by Seller prior to or on the Closing Date has not been soperformed or observed in any material respect or (ii) any representation or warranty of Purchasercontained in this Agreement is untrue in any material respect.

(b) Seller shall notify Purchaser promptly after Seller obtains actual knowledge thatany representation or warranty of Purchaser contained in this Agreement is untrue in any materialrespect or will be untrue in any material respect as of the Closing Date or that any covenant oragreement to be performed or observed by Purchaser prior to or on the Closing Date has not beenso performed or observed in a material respect.

If any of Purchaser’s or Seller’s representations or warranties is untrue or shall become untrue inany material respect between the date of execution of this Agreement and the Closing Date, or if any ofPurchaser’s or Seller’s covenants or agreements to be performed or observed prior to or on the ClosingDate (other than on a specified date) shall not have been so performed or observed in any materialrespect, but if such breach of representation, warranty, covenant or agreement shall (if curable) be curedby the Closing (or, if the Closing does not occur, by the date set forth in Section 10.1), then such breachshall be considered not to have occurred for all purposes of this Agreement.

Section 7.4 Operatorship .

Seller will assist Purchaser in its efforts to have Purchaser or its Affiliate designee succeed Selleras operator of any Wells included in the Seller Operated Assets. Seller makes no representation and doesnot warrant or guarantee that Purchaser or its Affiliate designee will succeed in being appointedsuccessor operator. Purchaser shall promptly, following Closing (or earlier to the extent provided underSection 12.7), file and diligently pursue until receipt of any

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acknowledgement, consent or confirmation by applicable agencies all appropriate or required forms,applications, permit transfers, declarations, guarantees, or bonds or other financial support with federaland state agencies relative to its assumption, or the assumption by its Affiliate designee, of operatorship. For all Seller Operated Assets, with respect to which Purchaser, or its Affiliate designee, receives thenecessary Governmental Body approvals to succeed Seller as operator, Seller shall execute and deliver toPurchaser, on forms, prepared by Seller and acceptable to Purchaser, and Purchaser shall promptly file,or cause to be filed, the applicable forms transferring operatorship of such Seller Operated Assets toPurchaser, or its Affiliate designee.

Section 7.5 Operation of Business .

Except as set forth on Schedule 7.5, as may be required to deal with an emergency, or forexpenditures or operations set forth on Schedule 5.9, and except as otherwise consented to in writing byPurchaser, which consent shall not be unreasonably withheld or delayed, until the Closing, Seller (i) willoperate the Seller Operated Assets in the ordinary course consistent with past practices, (ii) will notcommit to any single operation, or series of related operations, reasonably anticipated by Seller to requirefuture capital expenditures by the owner of the Assets in excess of Fifty Thousand Dollars ($50,000.00)(net to Seller’s interest) or make any capital expenditures related to the Assets in excess of FiftyThousand Dollars ($50,000.00) (net to Seller’s interest), (iii) will not terminate, materially amend,execute or extend any material agreements affecting the Assets, (iv) will maintain its current insurancecoverage on the Assets, if any, presently furnished by nonaffiliated third Persons in the amounts and ofthe types presently in force, (v) will use commercially reasonable efforts to maintain in full force andeffect all Leases, (vi) will maintain all material Governmental Authorizations necessary for theownership or operation of the Assets as currently operated, (vii) will not transfer, farmout, sell,hypothecate, encumber or otherwise dispose of any material Assets except for sales and dispositions ofHydrocarbon production and Equipment made in the ordinary course of business consistent with pastpractices and (viii) will not commit to do any act prohibited by the foregoing clauses (i)-(viii). Purchaser’s approval of any action restricted by this Section 7.5 shall be considered grantedwithin five (5) days (unless a shorter time is reasonably required by the circumstances and such shortertime is specified in Seller’s written notice) of Seller’s notice to Purchaser requesting such consent unlessPurchaser notifies Seller to the contrary during that period. In the event of an emergency, Seller maytake such action as a prudent operator would take and shall notify Purchaser of such action promptlythereafter.

Notwithstanding anything to the contrary in this Agreement, Seller shall have no liability toPurchaser for the incorrect payment of delay rentals, royalties, overriding royalties, shut-in paymentpayments or similar payments made during the Adjustment Period or for failure to make such paymentsthrough mistake or oversight during the Adjustment Period (including Seller’s negligence or other fault),except that, to the extent such incorrect payment causes Seller to have less than Defensible Title to aProperty prior to Closing, Purchaser may, until the Title Claim Date, assert a Title Defect under Section3.4(a) with respect to such matter.

Notwithstanding anything to the contrary contained in this Agreement, with respect to any Assetfor which Seller is not the operator, Seller shall not be deemed to have breached or otherwise violatedany of its covenants or agreements contained in this Agreement that are applicable to any

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such Assets so long as Seller exercise reasonable commercial efforts to cause any third-party operator ofsuch Assets to comply with such covenant or agreement.

Purchaser acknowledges that Seller may own an undivided interest in certain of the Assets andPurchaser agrees that the acts or omissions of the other working interest owners who are not affiliatedwith Seller shall not constitute a violation of the provisions of this Article 7 nor shall any action requiredby a vote of working interest owners constitute such a violation so long as Seller has voted its interest ina manner consistent with the provisions of this Article 7.

Section 7.6 Indemnity Regarding Access .

Purchaser, on behalf of itself and the Purchaser Indemnitees, hereby releases and agrees toindemnify, defend and hold harmless all Seller Indemnitees and the other owners of interests in the leasesand wells described on Exhibit A or Exhibit A-1 from and against any and all claims, liabilities, losses,costs and expenses (including court costs, expert fees and reasonable attorneys’ fees), including claims,liabilities, losses, costs and expenses attributable to personal injuries, death, or property damage, arisingout of or relating to access to the Assets by the Purchaser Indemnitees, the Records and other relatedactivities or information prior to the Closing by Purchaser Indemnitees, EVEN IF CAUSED INWHOLE OR IN PART BY THE NEGLIGENCE (WHETHER SOLE, JOINT ORCONCURRENT), STRICT LIABILITY OR OTHER LEGAL FAULT OF ANY INDEMNIFIEDPERSON EXCLUDING, HOWEVER, ANY CLAIMS, LIABILITIES, LOSSES, COSTS OREXPENSES CAUSED BY THE WILLFUL MISCONDUCT OF ANY INDEMNIFIED PERSON.

Section 7.7 Other Preferential Rights .

Should a third party fail to exercise its preferential right to purchase as to any portion of theAssets prior to Closing and the time for exercise or waiver has not yet expired, subject to the remainingprovisions of this Section 7.7, such Assets shall be included in the transaction at Closing, suchpreferential right to purchase shall be a Permitted Encumbrance hereunder, and the following proceduresshall be applicable. If one or more of the holders of any such preferential right to purchase notifies Sellersubsequent to the Closing that it intends to assert its preferential purchase right, Seller shall give noticethereof to Purchaser, whereupon Purchaser shall satisfy all such preferential purchaser right obligationsof Seller to such holders and shall indemnify and hold harmless all Seller Indemnitees from and againstany and all claims, liabilities, losses, damages, costs and expenses (including court costs, expert fees andreasonable attorney’s fees) in connection therewith, and Purchaser shall be entitled to receive (and Sellerhereby assigns to Purchaser all of Seller’s rights to) all proceeds, received from such holders inconnection with such preferential rights to purchase.

Prior to Closing, should any third Person bring any suit, action or other proceeding seeking torestrain, enjoin or otherwise prohibit the consummation of the transactions contemplated hereby inconnection with a claim to enforce preferential rights, the Assets or portion thereof subject to such suit,action or other proceeding shall be excluded from the Assets transferred at Closing and the PurchasePrice shall be reduced by the Allocated Value of such excluded Assets or portions thereof. Promptlyafter the suit, action or other proceeding is dismissed or settled or a judgment is rendered in favor ofSeller, as applicable, Seller shall sell to Purchaser, and Purchaser shall

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purchase from Seller, all such Assets or portions thereof not being sold to the third Person for a purchaseprice equal to the Allocated Value of such Assets or portions thereof, adjusted as provided in Section2.2; providedSeller shall have no obligation of sale under this paragraph if the applicable dismissal,settlement or judgment does not occur on or before one hundred and eighty (180) days following the dateClosing occurs; providedfurtherPurchaser shall have no obligation to purchase under this paragraph ifthe applicable dismissal, settlement or judgment does not occur on or before one hundred and eighty(180) days following the date Closing occurs.

Section 7.8 Tax Matters .

(a) Subject to the provisions of Section 12.3, Seller shall be responsible for all Taxesrelated to the ownership or operation of the Assets that are attributable to any taxable period, orportion thereof, that ends at or prior to the Effective Time. Purchaser shall be responsible for allother Taxes related to the ownership or operation of the Assets. Regardless of which Party isresponsible for Taxes pursuant to the preceding sentences of this Section 7.8(a), Seller shallhandle payment to the appropriate Governmental Body of all Taxes related to the ownership oroperation of the Assets which are required to be paid prior to Closing (and shall file all TaxReturns with respect to such Taxes); provided,thatto the extent such Taxes relate to the periodsfrom and after the Effective Time, as determined pursuant to Section 1.4(c), such payment shallbe on behalf of Purchaser, and promptly following the Closing Date, following Seller’s request,Purchaser shall pay to Seller any such Taxes ( but only to the extent that such amounts have notalready been accounted for under Section 2.2). Purchaser shall handle payment to the appropriateGovernmental Body of all Taxes related to the ownership or operation of the Assets which arerequired to be paid after Closing (and shall file all Tax Returns with respect to such Taxes);provided, that in the event that Seller is required by applicable Law to file a Tax Return withrespect to such Taxes after the Closing Date which includes all or a portion of a Tax period forwhich Purchaser is liable for such Taxes, following Seller’s request, Purchaser shall promptly payto Seller all such Taxes allocable to the period or portion thereof beginning at or after theEffective Time (but only to the extent that such amounts have not already been accounted forunder Section 2.2). Notwithstanding the foregoing, this Section 7.8(a) shall not apply to income,franchise, corporate, business and occupation, business license and similar Taxes (includingTaxes based on net profits, margin, revenues, gross receipts or similar measure), and Tax Returnstherefor, which shall be borne, paid and filed by the Party responsible for such Taxes underapplicable Law. If requested by Purchaser, Seller will assist Purchaser with preparation of all advalorem and property Tax Returns due on or before thirty (30) days after Closing (including anyextensions requested). Seller shall deliver to Purchaser within thirty (30) days of filing copies ofall Tax Returns filed by Seller after the Closing Date relating to the Assets and any supportingdocumentation provided by Seller to Governmental Bodies.

(b) If Seller or Purchaser (or an Affiliate of Seller or Purchaser) receives a refund ofany Taxes (whether by payment, credit offset or otherwise, with any interest thereon) covered bySection 7.8(a) that are paid by and required to be borne by the other Party, the Party that received(or whose Affiliate that received) such refund shall promptly (but no later than thirty (30) daysafter receipt) remit payment to such other Party of an amount equal to the refund amount, withany interest thereon, including all relevant

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documentation. Each Party shall cooperate with the other and its Affiliates in order to take allreasonably necessary steps to claim any refund to which it is entitled. Purchaser agrees to notifySeller within ten (10) days following the discovery of a right to claim any refund to which Selleris entitled and upon receipt of any such refund.

(c) Except to the extent required by applicable Laws, Purchaser shall not and shallnot permit its Affiliates to amend any Tax Return with respect to Taxes for which Seller is liableunder this Section 7.8 or for which Seller may be liable to indemnify Purchaser under Section11.2. Any Tax Return prepared by Purchaser for a taxable period, or portion thereof, beginningbefore the Effective Time shall be prepared in accordance with Seller’s prior practice and shallnot be filed without Seller’s written consent (not to be unreasonably withheld, conditioned ordelayed) after providing Seller a copy thereof reasonably in advance of the due date for filingsuch Tax Returns. In the event that Seller is required by applicable Law to file any Tax Returnwith respect to Taxes for which Purchaser is responsible hereunder, Seller shall prepare andtimely file such Tax Return but shall not file such Tax Return without Purchaser’s written consent(not to be unreasonably withheld, conditioned or delayed) after providing Purchaser a copythereof reasonably in advance of the due date for filing such Tax Return. If Seller or Purchaserdisputes any item on a Tax Return described in this Section 7.8(c), it shall notify the other Partyof such disputed item (or items) and the basis for its objection. The Parties shall act in good faithto resolve any such dispute prior to the date on which the relevant Tax Return is required to befiled. Purchaser and Seller shall each provide the other with all information reasonably necessaryto prepare any Tax Return described in this Section 7.8(c).

(d) After the Closing, Purchaser or Seller, as applicable, shall notify the other Party inwriting within fifteen (15) days of the receipt of the notice of any proposed assessment orcommencement of any Tax audit or administrative or judicial proceeding and of any Tax demandor claim on Purchaser or any of its Affiliates or Seller or any of its Affiliates that, if determinedadversely to the taxpayer or after the lapse of time, could reasonably be grounds forindemnification by Seller or would be reasonably likely to materially increase the Tax liability ofPurchaser or any of its Affiliates; provided, thatfailure to timely provide such notice shall notaffect the right of Purchaser’s indemnification hereunder, except to the extent Seller is prejudicedby such delay or omission. Such notice shall contain factual information describing the assertedTax liability in reasonable detail and shall include copies of any notice or other documentreceived from any Governmental Body in respect of any such asserted Tax liability. Seller shallcontrol any proceeding with respect to any Taxes or Tax Returns relating to or with respect to anyAsset (“ Tax Audit ”) for any item relating to a Tax for which Seller is reasonably likely to beresponsible, in whole or in part, pursuant to Section 7.8(a) or for which Seller may be liable toindemnify Purchaser under Section 11.2. Neither Purchaser nor Seller shall settle any such TaxAudit in a way that would adversely affect the other Party without the other Party’s writtenconsent, which consent the other Party shall not unreasonably withhold, delay orcondition. Purchaser and Seller shall each provide the other with all information reasonablynecessary to conduct a Tax Audit with respect to Taxes or the transactions contemplated by thisAgreement.

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(e) If, prior to Closing, Seller has paid on behalf of other working interest owners,

royalty interest owners, overriding royalty interest owners and other interest owners in the Assets,ad valorem, property, severance, production and similar Taxes imposed on the ownership of theAssets or the production of Hydrocarbons produced from such Assets for Tax periods or portionsthereof after the Effective Time (such amounts, “ Post-Effective Time Tax Advances ”) and hasnot recouped such Post-Effective Time Tax Advances before the Closing Date from such workinginterest owners, royalty interest owners, overriding royalty interest owners and other interestowners in the Assets, Purchaser shall use its commercially reasonable efforts to recoup the Post-Effective Time Tax Advances from such other working interest owners, royalty interest owners,overriding royalty interest owners and other interest owners in such Assets and shall promptlyremit any such recovered Post-Effective Time Tax Advance amounts to Seller.

Section 7.9 Special Warranty of Title .

(a) The Conveyance shall contain a covenant of Seller to warrant Defensible Title tothe Properties after Closing from and against the lawful claims of third Persons arising by,through or under Seller, but not otherwise, that are not reflected or referred to of record in thecounties where the lands covered by the Leases and Units are located or in the materials madeavailable to Purchaser prior to the Title Claim Date (the “ Special Warranty ”).

(b) Prior to the expiration of the period of time commencing as of the Closing Dateand ending at 5:00 P.M. (central time) on the second anniversary thereof (the “ Survival Period”), Purchaser shall furnish Seller a Title Defect Notice meeting the requirements of Section 3.4(a)setting forth any and all matters which Purchaser intends to assert as a breach of the SpecialWarranty (collectively, the “ Special Warranty Notices ” and, individually, a “ SpecialWarranty Notice ”). Seller shall have a reasonable opportunity, but not the obligation, to cureany breach of the Special Warranty asserted by Purchaser pursuant to this Section7.9(b). Purchaser shall reasonably cooperate with any attempt by Seller to cure any suchbreach. For all purposes of this Agreement, Purchaser shall be deemed to have waived, andSeller shall have no further liability for, any breach of the Special Warranty that Purchaser fails toassert by a Special Warranty Notice given to Seller before the expiration of the Survival Period.

(c) Recovery by Purchaser for any breach by Seller of the Special Warranty shall belimited to an amount (without any interest accruing thereon) equal to the reduction to thePurchase Price to which Purchaser would have been entitled had Purchaser asserted the defectgiving rise to such breach of the Special Warranty as a Title Defect prior to the Title Claim Datepursuant to Section 3.4(a) and taking into account the last sentence of this Section 7.9(c), and inno event shall that recovery exceed the Allocated Value of the affected Property. Purchaser shallnot be entitled to recover any amount for any breach of the Special Warranty to the extent that thePurchase Price is or has been reduced for the same Title Defect pursuant to Section 3.4.

(d) Seller shall have no liability for breach of the Special Warranty for matters forwhich and to the extent Purchaser had knowledge prior to the Title Claim Date that

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such matters constituted a Title Defect hereunder and failed to assert the same under thisAgreement prior to the Title Claim Date.

Section 7.10 Suspended Proceeds .

Seller shall transfer and remit to Purchaser, in the form of a post-Closing adjustment to thePurchase Price, all monies representing the value or proceeds of production removed or sold from theProperties and held by Seller at the time of the Closing for accounts from which payment has beensuspended, such monies, net of applicable rights of set off or recoupment, being hereinafter called “Suspended Proceeds ”. Purchaser shall be solely responsible for the proper distribution of suchSuspended Proceeds to the Person or Persons which or who are entitled to receive payment of the same.

Section 7.11 Further Assurances .

After Closing, Seller and Purchaser each agrees to take such further actions and to execute,acknowledge and deliver all such further documents as are reasonably requested by the other Party forcarrying out the purposes of this Agreement or of any document delivered pursuant to this Agreement.

Section 7.12 Contingent Payment .

(a) Reservation of Contingent Payment . Seller RESERVES AND EXCEPTS fromthe Assets the “ Contingent Payment ,” which shall mean Seller’s interest in and to the SubjectHydrocarbons and the Subject Wells to the extent of a term and cost-free (bearing no costs ofexploration, development, operations, or pre- or post-production costs), dollar-denominated,payment from the proceeds from the sale of any Subject Hydrocarbons produced, saved and soldfrom any Subject Wells prior to the Termination Date, as and to the extent calculated inaccordance with Section 7.12(b) (and to be paid to Seller in accordance with Section 7.12(c)) upto a maximum aggregate amount of Two Million Five Hundred Thousand Dollars($2,500,000.00), together with a lien on such Subject Hydrocarbons and Subject Wells necessaryto secure Purchaser’s (or its Affiliate’s) performance of its obligations with respect to suchpayments to Seller.

(b) Calculation of Contingent Payment . The Contingent Payment shall be calculatedas follows: for each rolling thirty (30) day period prior to October 1, 2017 and up to and prior tothe Termination Date (each such rolling thirty (30) day period, a “ Determination Period ”), ifthe Average Henry Hub Determination Price for such Determination Period is greater than $3.10,then the Contingent Payment owed to Seller with respect to such Determination Period shall be(without duplication of any prior Contingent Payments received by Seller) an amount in Dollarsequal to the product of:

(i) the aggregate number of all Mcfe (or fractions thereof) which comprisethe sales of the Subject Hydrocarbons during such Determination Period, multiplied by:

(ii) the positive difference expressed in Dollars between (x) the AverageHenry Hub Determination Price during such Determination Period, minus(y) $3.10

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(provided that if (x) minus (y) for such Determination Period exceeds $0.25, then (x)minus (y) shall be deemed to be $0.25 for such Determination Period for purposes of thisSection 7.12(b)(ii)).

(c) Payment to Seller . Any Contingent Payment shall be due to Seller on the fifthBusiness Day following the first calendar day of any calendar quarter, in each case with respect toall Contingent Payments for all Determination Periods falling within the immediately precedingcalendar quarter. Such Contingent Payments amounts shall be paid to Seller in immediatelyavailable funds by wire transfer, to any account that Seller directs.

(d) Attendant Rights . Purchaser (or its Affiliates or successor or assigns) shallperiodically, upon reasonable request from Seller, provide to Seller audit rights with respect toreserve, production, sales, costs and similar information related to operations and production fromthe Subject Wells and relevant to any calculation to be performed under this Section 7.12. Therights of Seller under this Section 7.12 shall be covenants running with and burdening the Landsor Units (including units or pools created after the date hereof that incorporate any portion of theLands).

(e) Contingent Payment Definitions . For the purposes of this Section 7.12:

(i) “ Average Henry Hub Determination Price ” means, as determined withrespect to each rolling thirty (30) day period that is a Determination Period, a number,expressed in Dollars to four decimal places, that is equal to the average of the applicabledaily “Dollars per Million Btu” figure reported by the U.S. Energy InformationAdministration on the natural gas “Spot Prices” chart (which chart may be accessed at thefollowing link: https://www.eia.gov/dnav/ng/hist/rngwhhdd.htm or any successor sourceof the same information) for all days during such rolling thirty (30) day period that is aDetermination Period (i.e., without considering into such averaging calculation anyweekend day, holiday or other day during such rolling thirty (30) day period for which theU.S. Energy Information Administration does not generate or report a “Dollars perMillion Btu” figure for such day); for the avoidance of doubt, and as an examplecalculation of the “Average Henry Hub Determination Price” for the hypothetical rollingthirty (30) day period beginning April 3, 2017, and ending May 3, 2017, such “AverageHenry Hub Determination Price” for such hypothetical Determination Period equals$3.1091.

(ii) “ Mcfe ” means the Mcf for any gaseous hydrocarbons plus the Mcfequivalent for any liquid hydrocarbons (using the ratio of six Mcf of gaseoushydrocarbons to one Bbl of crude oil, condensate or other liquid hydrocarbons), expressedas a total heat value volume of natural gas (with the terms “Mcf” and “Bbl’ having theirindustry-standard meaning when used in such calculations);

(iii) A “ Subject Well ” means any Well, together with any hydrocarbon wellhereafter owned, directly or indirectly, by Seller or any of Affiliates or successors andassigns and located on or attributable to any portion of the Lands or Units (including unitsor pools created after the date hereof that incorporate any

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portion of the Lands), in each case as of the time of determination of any DeterminationPeriod under this Section 7.12;

(iv) “ Subject Hydrocarbons ” means all natural gas, casinghead gas andother gaseous hydrocarbons together with crude oil, condensate and other liquidhydrocarbons produced from any Subject Well, to the extent attributable to the right, titleand interest of Seller in and to the Lands or Units (including units or pools created afterthe date hereof that incorporate any portion of the Lands) herein conveyed to Purchaser;and

(v) “ Termination Date ” means the earlier to occur of, (i) the date on whichSeller shall have received and realized from all Contingent Payments the full sum of TwoMillion Five Hundred Thousand Dollars ($2,500,000.00) through the payment to Seller ofall Contingent Payments, and (ii) October 1, 2019 (provided that, if as of October 1, 2019,any Contingent Payment has previously accrued with respect to Determination Periodsprior to October 1, 2019, then such accrued Contingent Payment will be due and owingand paid to Seller under the terms of Section 7.12(c) without limitation by the terms ofthis definition).

ARTICLE 8

CONDITIONS TO CLOSING

Section 8.1 Conditions of Seller to Closing .

The obligations of Seller to consummate the transactions contemplated by this Agreement aresubject, at the option of Seller, to the satisfaction on or prior to Closing of each of the followingconditions:

(a) Representations . The representations and warranties of Purchaser set forth inArticle 6 shall be true and correct as of the date of this Agreement and as of the Closing Date asthough made on and as of the Closing Date (other than representations and warranties that refer toa specified date, which need only be true and correct on and as of such specified date), except forsuch breaches, if any, as would not have a Material Adverse Effect ( provided,thatto the extentsuch representation or warranty is qualified by its terms by materiality or Material AdverseEffect, such qualification in its terms shall be inapplicable for purposes of this Section and theMaterial Adverse Effect qualification contained in this Section 8.1 shall apply in lieu thereof);

(b) Performance . Purchaser shall have performed and observed, in all materialrespects, all covenants and agreements to be performed or observed by it under this Agreementprior to or on the Closing Date;

(c) Pending Litigation . No suit, action or other proceeding by any GovernmentalBody seeking to restrain, enjoin or otherwise prohibit the consummation of the transactionscontemplated by this Agreement shall be pending before any Governmental Body;

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(d) Deliveries . Purchaser shall have delivered to Seller duly executed counterparts of

the Conveyances and the other documents and certificates to be delivered by Purchaser underSection 9.3;

(e) Title Defects, Casualty or Condemnation and Environmental Liabilities . Theaggregate amount of (i) the sum of all reasonable Title Defect Amounts for Title Defects assertedin good faith and in accordance with Section 3.4(a) by Purchaser covered by Section 3.4(d)(i)(excluding unsatisfied consents or preferential rights of purchase treated as Title Defects underSection 3.5), less the sum of all Title Benefit Amounts for actual Title Benefits, as determinedunder Article 3, plus (ii) the sum of all reasonable adjustments to the Purchase Price forEnvironmental Liabilities asserted in good faith and in accordance with Section 4.3 by Purchasercovered by Section 4.4(a), plus (iii) the aggregate amount of the Allocated Values of allProperties excluded from the Properties to be conveyed to Purchaser at Closing pursuant toSection 3.6 shall not exceed an amount equal to twenty percent (20%) of the Purchase Price; and

(f) Payment . Purchaser shall be ready, willing and able to pay the Closing Payment.

Section 8.2 Conditions of Purchaser to Closing .

The obligations of Purchaser to consummate the transactions contemplated by this Agreement aresubject, at the option of Purchaser, to the satisfaction on or prior to Closing of each of the followingconditions:

(a) Representations . The representations and warranties of Seller set forth in Article5 shall be true and correct as of the date of this Agreement and as of the Closing Date as thoughmade on and as of the Closing Date (other than representations and warranties that refer to aspecified date, which need only be true and correct on and as of such specified date), except forsuch breaches, if any, as would not have a Material Adverse Effect ( provided,thatto the extentsuch representation or warranty is qualified by its terms by materiality or Material AdverseEffect, such qualification in its terms shall be inapplicable for purposes of this Section and theMaterial Adverse Effect qualification contained in this Section 8.2 shall apply in lieu thereof);

(b) Performance . Seller shall have performed and observed, in all material respects,all covenants and agreements to be performed or observed by it under this Agreement prior to oron the Closing Date;

(c) Pending Litigation . No suit, action or other proceeding by any GovernmentalBody seeking to restrain, enjoin or otherwise prohibit the consummation of the transactionscontemplated by this Agreement shall be pending before any Governmental Body;

(d) Deliveries . Seller shall be ready, willing and able to deliver to Purchaser dulyexecuted counterparts of the Conveyances and the other documents and certificates to bedelivered by Seller under Section 9.2; and

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(e) Title Defects, Casualty or Condemnation and Environmental Liabilities . The

aggregate amount of (i) the sum of all reasonable Title Defect Amounts for Title Defects assertedin good faith and in accordance with Section 3.4(a) by Purchaser covered by Section 3.4(d)(i),less the sum (excluding unsatisfied consents or preferential rights of purchase treated as TitleDefects under Section 3.5), less the sum of all Title Benefit Amounts for actual Title Benefits, asdetermined under Article 3, plus (ii) the sum of all reasonable adjustments to the Purchase Pricefor Environmental Liabilities asserted in good faith and in accordance with Section 4.3 byPurchaser covered by Section 4.4(a), plus (iii) the aggregate amount of the Allocated Values ofall Properties excluded from the Properties to be conveyed to Purchaser at Closing pursuant toSection 3.6 shall not exceed an amount equal to twenty percent (20%) of the Purchase Price.

ARTICLE 9

CLOSING

Section 9.1 Time and Place of Closing .

(a) Consummation of the purchase and sale transaction as contemplated by thisAgreement (the “ Closing ”), shall, unless otherwise agreed to in writing by Purchaser and Seller,take place at the offices of Baker Botts L.L.P. at 98 San Jacinto Boulevard, Suite 1500, Austin,Texas 78701-4078, at 9:00 A.M. local time, on (i) August 1, 2017 or (ii) if all conditions inArticle 8 to be satisfied prior to Closing have not yet been satisfied or waived on such date, assoon as thereafter as such conditions have been satisfied or waived, subject to the rights of theparties under Article 10.

(b) The date on which the Closing occurs is herein referred to as the “ Closing Date.”

Section 9.2 Obligations of Seller at Closing .

At the Closing, upon the terms and subject to the conditions of this Agreement, Seller shallprepare, deliver or cause to be delivered to Purchaser, among other things, the following:

(a) the Conveyance, in sufficient duplicate originals to allow recording in allappropriate jurisdictions and offices, duly executed by Seller;

(b) the Preliminary Settlement Statement, duly executed by Seller;

(c) to the extent applicable assignments, on appropriate forms, of state and of federalleases comprising portions of the Assets, duly executed by Seller;

(d) to the extent required under any law or Governmental Body, Seller and Purchasershall deliver federal and state change of operator forms designating Purchaser or its Affiliatedesignee as the operator of the Properties currently operated by Seller;

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(e) letters-in-lieu of division or transfer orders covering the Assets reasonably

satisfactory to Seller to reflect the transactions contemplated hereby, duly executed by Seller;

(f) a certificate duly executed by an authorized officer of Seller, dated as of Closing,certifying on behalf of Seller that to the best of its knowledge the conditions set forth in Sections8.2(a) and 8.2(b) have been fulfilled; and

(g) an executed statement described in Treasury Regulation §1.1445-2(b)(2)certifying that Seller is not a foreign person within the meaning of the Internal Revenue Code of1986, as amended.

Section 9.3 Obligations of Purchaser at Closing .

At the Closing, upon the terms and subject to the conditions of this Agreement, Purchaser shalldeliver or cause to be delivered to Seller, among other things, the following:

(a) a wire transfer of the Closing Payment in same-day funds;

(b) the Preliminary Settlement Statement, duly executed by Purchaser;

(c) the Conveyance, duly executed by Purchaser;

(d) copies of all bonds, letters of credit and guarantees required to be obtained byPurchaser, or its Affiliate designee, under Section 12.6 or other written evidence that Purchaser,or its Affiliate designee, is not required under Section 12.6 to obtain such items;

(e) letters-in-lieu of division and transfer orders covering the Assets, duly executedby Purchaser; and

(f) a certificate by an authorized officer of Purchaser, dated as of Closing, certifyingon behalf of Purchaser that the conditions set forth in Sections 8.1(a) and 8.1(b) have beenfulfilled.

Section 9.4 Closing Payment and Post-Closing Purchase Price Adjustments .

(a) Not later than two (2) days prior to the Closing Date, Seller shall prepare anddeliver to Purchaser, based upon the best information available to Seller, a preliminary settlementstatement estimating the Adjusted Purchase Price after giving effect to all Purchase Priceadjustments set forth in Section 2.2 and the Deposit (the “ Preliminary Settlement Statement”). In the event that Purchaser objects to the Preliminary Settlement Statement and Seller andPurchaser cannot come to a resolution with respect to Purchaser’s objection, Seller’s PreliminarySettlement Statement shall be used for the purposes of Closing and the estimate delivered inaccordance with this Section 9.4(a) shall constitute the dollar amount to be paid by Purchaser toSeller at the Closing (the “ Closing Payment ”).

(b) As soon as reasonably practicable after the Closing but not later than ninety (90)days following the Closing Date, Seller shall prepare and deliver to Purchaser a

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statement setting forth the final calculation of the Adjusted Purchase Price and showing thecalculation of each adjustment, based, to the extent possible on actual credits, charges, receiptsand other items before and after the Effective Time and taking into account all adjustmentsprovided for in this Agreement. Seller shall at Purchaser’s request supply reasonabledocumentation available to support any credit, charge, receipt or other item. As soon asreasonably practicable but not later than the 30th day following receipt of Seller’s statementhereunder, Purchaser shall deliver to Seller a written report containing any changes that Purchaserproposes be made to such Statement. The Parties shall undertake to agree on the final statementof the Adjusted Purchase Price no later than one hundred thirty (130) days after the ClosingDate. In the event that the parties cannot agree on the Adjusted Purchase Price within onehundred thirty (130) days after the Closing, such determination will be automatically referred toan independent expert of the parties choosing with at least ten (10) years of oil and gasaccounting experience for arbitration (the “ Independent Expert ”). If the Parties are unable toagree upon an Independent Expert, then such Independent Expert shall be selected by any FederalDistrict Court Judge or State District Court Judge in Houston, Texas. The burden of proof in thedetermination of the Adjusted Purchase Price shall be upon Purchaser. The Independent Expertshall conduct the arbitration proceedings in Houston, Texas in accordance with the CommercialArbitration Rules of the American Arbitration Association, to the extent such rules do not conflictwith the terms of this Section. The Independent Expert’s determination shall be made withinthirty (30) days after submission of the matters in dispute and shall be final and binding on bothParties, without right of appeal. In determining the proper amount of any adjustment to thePurchase Price, the Independent Expert shall not increase the Purchase Price more than theincrease proposed by Seller nor decrease the Purchase Price more than the decrease proposed byPurchaser, as applicable. The Independent Expert shall act as an expert for the limited purpose ofdetermining the specific disputed matters submitted by either Party and may not award damagesor penalties to either Party with respect to any matter. Each Party shall each bear its own legalfees and other costs of presenting its case. Each Party shall bear one-half of the costs andexpenses of the Independent Expert. Within ten (10) days after the date on which the Parties orthe Independent Expert, as applicable, finally determines the disputed matters, (i) Purchaser shallpay to Seller the amount by which the Adjusted Purchase Price exceeds the Closing Payment or(ii) Seller shall pay to Purchaser the amount by which the Closing Payment exceeds the AdjustedPurchase Price, as applicable. Any post-closing payment pursuant to this Section 9.4 shall bearinterest from the Closing Date to the date of payment at the Agreed Interest Rate.

(c) All payments made or to be made hereunder to Seller shall be by electronictransfer of immediately available funds to the account of Seller pursuant to the wiring instructionsreflected in Schedule 9.4(c) or as separately provided in writing. All payments made or to bemade hereunder to Purchaser shall be by electronic transfer of immediately available funds to abank and account specified by Purchaser in writing to Seller.

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ARTICLE 10

TERMINATION

Section 10.1 Termination .

Subject to Section 10.2, this Agreement may be terminated: (i) at any time prior to Closing bythe mutual prior written consent of Seller and Purchaser; (ii) by Seller or Purchaser if Closing has notoccurred on or before the day that is sixty (60) days from the date hereof; (iii) by Purchaser if anycondition set forth in Section 8.2 has not been satisfied or waived at Closing or (iv) by Seller if anycondition set forth in Section 8.1 has not been satisfied or waived at Closing; provided,however, thattermination under clauses (ii), (iii) or (iv) shall not be effective until the Party electing to terminate hasdelivered written notice to the other Party of its election to so terminate.

Section 10.2 Effect of Termination .

If this Agreement is terminated pursuant to Section 10.1, except as set forth in this Section 10.2and in Section 10.3, this Agreement shall become void and of no further force or effect (except for theprovisions of Sections 5.6, 6.5, 7.6, 11.6, 12.2, 12.4 12.5, 12.7, 12.8, 12.9, 12.10 12.11, 12.12, 12.13,12.14, 12.15, 12.16, 12.17, 12.18, and 12.19 and of the Confidentiality Agreement, all of which shallcontinue in full force and effect in accordance with their terms) and Seller shall be free immediately toenjoy all rights of ownership of the Assets and to sell, transfer, encumber or otherwise dispose of theAssets to any Person without any restriction under this Agreement. Subject to Section 10.3, thetermination of this Agreement under Section 10.1(ii), (iii) or (iv) shall not relieve any Party from liabilityto the other Party at Law or in equity for any failure to perform or observe in any material respect any ofits agreements or covenants contained herein which are to be performed or observed at or prior toClosing.

Section 10.3 Distribution of Deposit Upon Termination .

(a) If this Agreement is terminated by Seller pursuant to Section 10.1(ii) or Section10.1(iv) and Seller has performed or is ready, willing and able to perform all of its agreementsand covenants contained herein which are to be performed or observed at or prior to Closing, andall conditions to Purchaser’s obligation to consummate the transaction contemplated by thisAgreement under Section 8.2 have been satisfied or waived by Purchaser, then Seller, as its soleremedy shall retain the Deposit as liquidated damages as Seller's sole and exclusive remedy forany breach or failure to perform by Purchaser under this Agreement, and all other remedies(except those under Section 7.6 and the Confidentiality Agreement, which shall remain in fullforce and effect) are hereby expressly waived by Seller. Seller and Purchaser agree upon theDeposit as liquidated damages due to the difficulty and inconvenience of measuring actualdamages and the uncertainty thereof, and Seller and Purchaser agree that such amount would be areasonable estimate of Seller’s loss in the event of any such breach or failure to perform byPurchaser. Upon such termination, Seller shall be free immediately to enjoy all rights ofownership of the Assets and to sell, transfer, encumber or otherwise dispose of the Assets to anyPerson without any restriction under this Agreement.

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(b) If this Agreement is terminated by Purchaser pursuant to Section 10.1(iii) and

Purchaser has performed or is ready, willing and able to perform all of its agreements andcovenants contained herein which are to be performed or observed at or prior to Closing, then atPurchaser’s option:

(i) upon notice from Purchaser, Seller shall pay the Deposit to Purchaser, andPurchaser shall be entitled to seek money damages from Seller available at Law forSeller’s applicable breach of this Agreement, as Purchaser’s sole and exclusive remedyfor any breach or failure to perform by Seller under this Agreement, and all otherremedies (except those under the Confidentiality Agreement, which shall remain in fullforce and effect) are hereby expressly waived by Purchaser, and Seller shall be freeimmediately to enjoy all rights of ownership of the Assets and to sell, transfer, encumberor otherwise dispose of the Assets to any Person without any restriction under thisAgreement; or

(ii) in lieu of termination of this Agreement, Purchaser as its sole andexclusive remedy for any breach or failure to perform by Seller under this Agreement,shall be entitled to specific performance of this Agreement, it being specifically agreedthat monetary damages will not be sufficient to compensate Purchaser. If Purchaser electsto seek specific performance of this Agreement pursuant to this Section 10.3(b)(ii), Sellershall retain the Deposit, until a non-appealable final judgment or award on Purchaser’sclaim for specific performance is rendered, at which time the Deposit shall be distributedas provided in the judgment or award resolving the specific performance claim or shall beapplied as provided in Section 2.4 of this Agreement.

(c) If this Agreement terminates for reasons other than those set forth in Section10.3(a) or Section 10.3(b), Seller shall pay the Deposit to Purchaser, free of any claims by Selleror any other Person with respect thereto, and each Party shall have no further liability hereunderof any nature whatsoever to the other Party, including any liability for Damages (except for theprovisions of Sections 5.6, 6.5, 7.6 and 12.4 and the Confidentiality Agreement which shallcontinue in full force and effect in accordance with their terms), and Seller shall be freeimmediately to enjoy all rights of ownership of the Assets and to sell, transfer, encumber orotherwise dispose of the Assets to any Person without any restriction under this Agreement.

(d) Purchaser shall not be entitled to receive interest on the Deposit, regardless ofwhether the Deposit is applied against the Purchase Price or returned to Purchaser pursuant to thisSection 10.3.

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ARTICLE 11

POST-CLOSING OBLIGATIONS; INDEMNIFICATION;

LIMITATIONS; DISCLAIMERS AND WAIVERS

Section 11.1 Receipts .

(a) Except as otherwise provided in this Agreement, any production from orattributable to the Assets (and all products and proceeds attributable thereto) and any otherincome, proceeds, receipts and credits attributable to the Assets which are not reflected in theadjustments to the Purchase Price following the final adjustment pursuant to Section 9.4(b) shallbe treated as follows: (i) all production from or attributable to the Assets (and all products andproceeds attributable thereto) and all other income, proceeds, receipts and credits earned withrespect to the Assets to which Purchaser is entitled under Section 1.4 shall be the sole propertyand entitlement of Purchaser, and, to the extent received by Seller, Seller shall fully disclose,account for and remit the same to Purchaser within ten (10) days, and (ii) all production from orattributable to the Assets (and all products and proceeds attributable thereto) and all other income,proceeds, receipts and credits earned with respect to the Assets to which Seller is entitled underSection 1.4 shall be the sole property and entitlement of Seller and, to the extent received byPurchaser, Purchaser shall fully disclose, account for and remit the same to Seller within ten (10)days.

(b) Notwithstanding any other provisions of this Agreement to the contrary, Sellershall be entitled to retain (and Purchaser shall not be entitled to any decrease to the PurchasePrice in respect of) all overhead charges it has collected, billed or which shall be billed later, fromnon-operating third Person owners relating to the Seller Operated Assets and relating to theperiod from the Effective Time to the date Seller relinquishes operatorship of the applicableSeller Operated Assets, even if after the date of Closing.

Section 11.2 Assumption and Indemnification .

(a) Without limiting Purchaser’s rights to indemnity under this Article 11, on theClosing Date, Purchaser shall assume and hereby agrees to timely fulfill, perform, pay anddischarge (or cause to be fulfilled, performed, paid or discharged) all of the obligations andliabilities of Seller, known or unknown, with respect to the Assets, regardless of whether suchobligations or liabilities arose prior to, on or after the Effective Time, including but not limited to(1) obligations to furnish makeup gas according to the terms of applicable gas sales, gathering ortransportation contracts, (2) gas balancing obligations and other obligations arising fromImbalances, (3) obligations to pay Property Costs and other costs and expenses attributable to theownership or operation of the Assets incurred from and after the Effective Time, (4) obligationsto pay working interests, royalties, overriding royalties and other interests as to the SuspendedProceeds transferred by Seller to Purchaser, (5) obligations to plug or abandon wells andassociated equipment and dismantle structures, and to restore and/or remediate the Assets inaccordance with applicable agreements, Leases or Laws (including Environmental Laws), (6) anyclaims regarding the general method, manner or practice of calculating or making royaltypayments (or payments for overriding royalties or similar burdens on production) with

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respect to the Properties for production occurring from and after the Effective Time, and (7)continuing obligations, not in breach, if any, under any Contracts or other agreements pursuant towhich Seller or its Affiliates purchased or acquired Assets prior to the Closing (all of saidobligations and liabilities, subject to the exclusions below, herein being referred to as the “Assumed Obligations ”); provided,however, that the Assumed Obligations do not include andPurchaser does not assume any obligations or liabilities of Seller to the extent that they are SellerIndemnity Obligations.

(b) Except for Damages for which Seller is required to indemnify PurchaserIndemnitees under Section 11.2(c), at the time an applicable Claim Notice is provided to Seller,Purchaser shall indemnify, defend and hold harmless the Seller Indemnitees from and against allDamages incurred or suffered by the Seller Indemnitees:

(i) caused by, arising out of, resulting from or relating to the AssumedObligations;

(ii) caused by, arising out of or resulting from Purchaser’s breach of any ofPurchaser’s covenants or agreements that survive the Closing;

(iii) caused by, arising out of or resulting from any breach of anyrepresentation or warranty made by Purchaser contained in Article 6 of this Agreement orin the certificate delivered by Purchaser at Closing pursuant to Section 9.3(f); or

(iv) caused by, arising out of or resulting from any claims or actions assertedby Persons (including Governmental Bodies) with respect to (1) any condition affectingany Asset that violates or requires remediation under Environmental Law, (2) anyoperations conducted on such Asset that violate any Environmental Law or (3) anyremediation required for an Asset under any Environmental Law regardless of whetherknown or unknown, or whether attributable to periods of time before, on or after theEffective Time.

EVEN IF SUCH DAMAGES ARE CAUSED IN WHOLE OR IN PART BY THENEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT), STRICT LIABILITYOR OTHER LEGAL FAULT OF SELLER INDEMNITEES OR ANY INDEMNIFIEDPERSON .

(c) Seller shall indemnify, defend and hold harmless Purchaser Indemnitees againstand from all Damages incurred or suffered by Purchaser Indemnitees to the extent (the “ SellerIndemnity Obligations ”):

(i) caused by, arising out of or resulting from any breach asserted during theapplicable survival period of any of Seller’s covenants or agreements that survive theClosing;

(ii) caused by, arising out of or resulting from any breach asserted during theapplicable survival period of any representation or warranty made by

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Seller contained in Article 5 of this Agreement or in the certificate delivered by Seller atClosing pursuant to Section 9.2(f);

(iii) caused by, arising out of, resulting from or related to the ExcludedAssets; and

(iv) caused by the Seller Retained Liabilities.

(d) Notwithstanding anything to the contrary contained in this Agreement, except forthe rights of the Parties under Article 10, Section 7.6 and the Special Warranty in the Conveyance(subject to Section 7.9), this Section 11.2 contains the Parties’ exclusive remedy against eachother with respect to breaches of this Agreement, including breaches of the representations andwarranties contained in Articles 5 and 6, the covenants and agreements that survive the Closingpursuant to the terms of this Agreement and the affirmations of such representations, warranties,covenants and agreements contained in the certificates delivered by the Parties at Closingpursuant to Sections 9.2(f) or 9.3(f), as applicable. Except for the remedies contained in thisSection 11.2 and for the rights of the Parties under Article 10, Section 7.6 and the SpecialWarranty in the Conveyance (subject to Section 7.9), Purchaser (on behalf of itself, each of theother Purchaser Indemnitees and their respective insurers and successors in interest) releases,remises and forever discharges the Seller Indemnitees from any and all suits, legal oradministrative proceedings, claims, remedies, demands, damages, losses, costs, liabilities,interest, or causes of action whatsoever, in Law or in equity, known or unknown, which suchparties might now or subsequently may have, based on, relating to or arising out of thisAgreement, Seller’s, Seller’s predecessor’s or their respective co-owner’s ownership, use oroperation of the Assets, or the condition, quality, status or nature of the Assets, including rights tocontribution under CERCLA, as amended, and under other Environmental Laws, breaches ofstatutory or implied warranties, nuisance or other tort actions, rights to punitive damages andcommon law rights of contribution, rights under agreements between Seller and any Persons whoare Affiliates of Seller, and rights under insurance maintained by Seller or any Person who is anAffiliate of Seller, EVEN IF CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE(WHETHER SOLE, JOINT OR CONCURRENT, BUT EXCLUDING WILLFULMISCONDUCT), OF ANY RELEASED PERSON .

(e) “ Damages ”, for purposes of this Agreement, shall mean the amount of anyactual liability, loss, cost, diminution in value, expense, claim, demand, notice of violation,investigation by any Governmental Body, administrative proceeding, payment, charge,obligation, fine, penalty, deficiency, award or judgment incurred or suffered by any IndemnifiedParty arising out of or resulting from the indemnified matter, including reasonable fees andexpenses of attorneys, consultants, accountants or other agents and experts reasonably incident tomatters indemnified against, and the costs of investigation and/or monitoring of such matters, andthe costs of enforcement of the indemnity; provided,however, that no Purchaser Indemnitee shallbe entitled to indemnification under this Section 11.2 for Damages that constitute (i) loss ofprofits or other consequential, special or indirect damages suffered by Purchaser, or any punitivedamages, or (ii) any liability, loss, cost, expense, claim, award or judgment to the extent resultingfrom or increased by the actions or omissions of any Purchaser Indemnitee after the EffectiveTime.

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(f) Notwithstanding any other provision of this Agreement or a document to be

delivered hereto to the contrary, any claim for indemnity to which a Seller Indemnitee orPurchaser Indemnitee is entitled must be asserted by and through Seller or Purchaser, asapplicable.

Section 11.3 Indemnification Actions .

Except as otherwise provided in Section 7.8(d), all claims for indemnification under Section 11.2shall be asserted and resolved as follows:

(a) For purposes of this Article 11, the term “ Indemnifying Party ” when used inconnection with particular Damages shall mean the Party having an obligation to indemnifyanother Person or Persons with respect to such Damages pursuant to this Article 11, and the term“ Indemnified Party ” when used in connection with particular Damages shall mean the Personor Persons having the right to be indemnified with respect to such Damages by another Partypursuant to this Article 11, subject to Section 11.2(f).

(b) To make a claim for indemnification under Article 11, an Indemnified Party shallnotify the Indemnifying Party of its claim under this Section 11.3, including the specific details ofand specific basis under this Agreement for its claim (the “ Claim Notice ”). In the event that theclaim 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 theIndemnified Party has actual knowledge of the Third Party Claim and shall enclose a copy of allpapers (if any) served with respect to the Third Party Claim; provided, that the failure of anyIndemnified Party to give notice of a Third Party Claim as provided in this Section 11.3 shall notrelieve the Indemnifying Party of its obligations under Section 11.2 except to the extent suchfailure prejudices the Indemnifying Party’s ability to defend against the Third Party Claim. In theevent 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 which was inaccurate or breached.

(c) In the case of a claim for indemnification based upon a Third Party Claim, theIndemnifying Party shall have fourteen (14) days from its receipt of the Claim Notice to notifythe Indemnified Party whether it admits or denies its liability to defend the Indemnified Partyagainst such Third Party Claim at the sole cost and expense of the Indemnifying Party. TheIndemnified Party is authorized, prior to and during such fourteen (14)-day period, to file anymotion, answer or other pleading that it shall deem necessary or appropriate to protect its interestsor those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party all costsof which shall be included as Damages in respect of such claim for indemnification. The failureto provide notice to the Indemnified Party shall be deemed to be acceptance of liability.

(d) If the Indemnifying Party admits its liability, it shall have the right and obligationto diligently defend, at its sole cost and expense, the Third Party Claim. The Indemnifying Partyshall have full control of such defense and proceedings, including any compromise or settlementthereof. If requested by the Indemnifying Party, the Indemnified

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Party agrees to cooperate, at the sole cost of the Indemnifying Party, in contesting any ThirdParty Claim which the Indemnifying Party elects to contest. The Indemnified Party mayparticipate in, but not control, at its sole cost without any right of reimbursement, any defense orsettlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section11.3(d). Irrespective of whether the Indemnified Party elects to participate in contesting a ThirdParty Claim subject to this Section 11.3(d) in accordance with the foregoing sentence, theIndemnifying Party at its sole cost and expense shall provide to the Indemnified Party thefollowing information with respect to the Third Party Claim: all filings made by any party; allwritten communications exchanged between any parties to the extent available to theIndemnifying Party and not subject to a restriction on disclosure to the Indemnified Party; and allorders, opinions, rulings or motions. The Indemnifying Party shall deliver the foregoing items tothe Indemnified Party promptly after they become available to the Indemnifying Party. AnIndemnifying Party shall not, without the written consent of the Indemnified Party (which shallnot be unreasonably withheld, conditioned or delayed), (i) settle any Third Party Claim or consentto the entry of any judgment with respect thereto which does not include an unconditional writtenrelease 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 anymanner that may materially and adversely affect the Indemnified Party (other than as a result ofmoney damages paid by the Indemnifying Party or covered fully by the indemnity).

(e) If the Indemnifying Party does not admit its liability or admits its liability but failsto diligently prosecute or settle the Third Party Claim, then the Indemnified Party shall have theright to defend against the Third Party Claim at the sole cost and expense of the IndemnifyingParty, with counsel of the Indemnified Party’s choosing, subject to the right of the IndemnifyingParty to admit its liability and assume the defense of the Third Party Claim at any time prior tosettlement or final determination thereof. If the Indemnifying Party has not yet admitted itsliability for a Third Party Claim, the Indemnified Party shall send written notice to theIndemnifying Party of any proposed settlement and the Indemnifying Party shall have the optionfor ten (10) days following receipt of such notice to (i) admit in writing its liability for the ThirdParty Claim and (ii) if liability is so admitted, reject, in its reasonable judgment, the proposedsettlement. If Indemnifying Party fails to respond and admit in writing its liability during suchten (10) day period, the Indemnifying Party will be deemed to have approved such proposedsettlement.

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

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Section 11.4 Limitation on Actions .

(a) All representations and warranties of Seller and Purchaser contained herein shallsurvive until the first anniversary of the Closing Date (including the date of the first anniversary)and expire thereafter. The covenants and other agreements of Seller and Purchaser set forth inthis Agreement to be performed on or before Closing shall expire on the day following theClosing Date and each other covenant and agreement of Seller and Purchaser shall, subject to thisSection 11.4, survive the Closing until fully performed in accordance with its terms and expirethereafter. The affirmations of representations, warranties, covenants and agreements containedin the certificate delivered by each Party at Closing pursuant to Sections 9.2(f) and 9.3(f), asapplicable, shall survive the Closing as to each representation, warranty covenant and agreementso affirmed for the same period of time that the specific representation, warranty, covenant oragreement survives the Closing pursuant to this Section 11.4, and shall expirethereafter. Representations, warranties, covenants and agreements shall terminate and be of nofurther force and effect after the respective date of their expiration, after which time no claim maybe asserted thereunder by any Person, provided, that there shall be no termination of any bonafide claim timely asserted pursuant to Section 11.4(c).

(b) The indemnities in Sections 11.2(b)(ii) and 11.2(b)(iii) shall terminate as of thetermination date of each respective representation, warranty, covenant or agreement that issubject to indemnification, except in each case as to matters for which a specific written claim forindemnity has been delivered to the Indemnifying Party on or before such terminationdate. Purchaser’s indemnities in Sections 7.6, 11.2(b)(i), and 11.2(b)(iv) shall continue withouttime limit. The indemnities in Section 11.2(c) shall terminate on the date that is one hundredeighty (180) days counted from and after the Closing Date (including such one hundred eightieth(180th) day).

(c) Notwithstanding anything to the contrary contained elsewhere in this Agreement,except for claims for breaches of the Special Warranty and any payments in respect thereof:

(i) Seller shall not be required to indemnify any Person under Section 11.2(c)for any individual liability, loss, cost, expense, claim, award or judgment that does notexceed Fifty Thousand Dollars ($50,000.00);

(ii) Subject to Section 11.4(c)(i), Seller shall not have any liability forindemnification under Section 11.2(c) until and unless the aggregate amount of theliability for all Damages for which Claim Notices are timely delivered by Purchaserexceeds a deductible amount equal to two percent (2%) of the Purchase Price (the “Indemnity Deductible ”), after which point Purchaser (or Purchaser Indemnitees) shallbe entitled to claim Damages in excess of the Indemnity Deductible;

(iii) Seller shall not be required to indemnify Purchaser and PurchaserIndemnitees for aggregate Damages claimed by Purchaser and Purchaser Indemnitees inexcess of fifteen percent (15%) of the Purchase Price; and

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(iv) Seller shall not be required to indemnify any Person under Section 11.2(c)

unless Seller has received a Claim Notice with respect to such claim at or prior to the firstanniversary of the Closing Date (including the date that is the first anniversary of theClosing Date).

(d) Seller and Purchaser acknowledge that after the Closing the payment of money, aslimited by the terms of this Agreement, shall be adequate compensation for breach of anyrepresentation, warranty, covenant or agreement contained in this Agreement or for any otherclaim arising in connection with or with respect to the transactions contemplated in thisAgreement. As the payment of money shall be adequate compensation, Purchaser, Seller waivesany right to rescind this Agreement or any of the transactions contemplated hereby.

Section 11.5 Recording .

As soon as practicable after Closing, Purchaser shall record the Conveyances in the appropriatecounties as well as the appropriate governmental agencies and provide Seller with copies of all recordedor approved instruments.

Section 11.6 Waivers .

(a) The Parties do not intend that any implied obligation of good faith or fair dealingrequires any Party to incur, suffer or perform any act, condition or obligation contrary to theterms of this Agreement or any documents delivered in connection herewith and that it would beunfair, and that they do not intend, to increase any of the obligations of any Party under thisAgreement or any documents delivered in connection herewith on the basis of any such impliedobligation.

(b) Purchaser acknowledges that plugging, abandonment, removal and restorationobligations for the Assets are material and significant. Purchaser acknowledges that Purchaser hasconducted its own investigation and evaluation as to the cost and timing of such obligations and that,other than the representations and warranties set forth in this Agreement, Seller has made norepresentation or warranty as to the expected cost or timetable for incurring costs of plugging,abandonment, removal and restoration obligations for the Assets. Purchaser acknowledges that Seller isentering into this Agreement in reliance upon Purchaser's agreement to assume such obligations and allother Assumed Obligations and that assumption of the Assumed Obligations constitutes material agreedconsideration to Seller in consideration for the Assets.

Section 11.7 Insurance .

The amount of any liability for which Purchaser is entitled to indemnification under thisAgreement or in connection with or with respect to the transactions contemplated by this Agreementshall be reduced by any corresponding insurance proceeds from insurance policies carried by Purchaserrealized or that could reasonably be expected to be realized by Purchaser if a claim were properlypursued under the relevant insurance arrangements.

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Section 11.8 Tax Treatment of Indemnification Payments .

The Parties agree that any payments made by one Party to the other Party pursuant to this ‎Article11 shall be treated for all Tax purposes as an adjustment to the purchase price for the Assets unlessotherwise required by applicable Law.

ARTICLE 12

MISCELLANEOUS

Section 12.1 Counterparts .

This Agreement may be executed in counterparts, each of which shall be deemed an originalinstrument, but all such counterparts together shall constitute but one agreement. Delivery of anexecuted counterpart signature page by facsimile or electronic transmittal (PDF) is as effective asexecuting and delivering this Agreement in the presence of other Parties to this Agreement.

Section 12.2 Notice .

All notices which are required or may be given pursuant to this Agreement shall be sufficient inall respects if given in writing and delivered personally, by facsimile or by registered or certified mail,postage prepaid, as follows:

If to Seller: Jones Energy, Inc.807 Las Cimas ParkwayAustin, Texas 78746Attn: Steve BrysonEmail: [email protected] WITH A COPY TO: Baker Botts L.L.P.98 San Jacinto Blvd. Suite 1500Austin, TX 78701-4078Attn: Mike BengtsonEmail: [email protected]

If to Purchaser:

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Foundation Energy Management,LLC1801 Broadway, Suite 1500Denver, Colorado 80202Attention: Joel P. Sauer, Vice PresidentTelephone 303-244-8113Facsimile: 303-244-0604Email: [email protected] WITH A COPY TO: Foundation Energy Management, LLC808 Travis Street, Suite 452Houston, Texas 77002Attention: Jay PollardTelephone: 972-707-2518Email: [email protected]

Either Party may change its address for notice by notice to the other in the manner set forth

above. All notices shall be deemed to have been duly given (i) when physically delivered in person tothe Party to which such notice is addressed, (ii) when transmitted to the Party to which such notice isaddressed by confirmed facsimile transmission, or (iii) at the time of receipt by the Party to which suchnotice is addressed. Notwithstanding the foregoing, delivery by Seller or Purchaser (as applicable) of aTitle Defect Notice, Title Benefit Notice or statement of the Purchase Price under Section 9.4, or aresponse to any of the foregoing, shall be deemed to have been duly given to the other Party when (i)transmitted via electronic mail to the address(es) of the representative(s) of such Party named above thatwere previously furnished to the delivering Party and (ii) the delivering Party has provided notice to theother Party of such electronic mail pursuant to the previous sentence.

Section 12.3 Sales or Use Tax, Recording Fees, and Similar Taxes and Fees .

Purchaser shall bear any sales, use, excise, real property transfer, gross receipts, goods andservices, registration, capital, documentary, stamp or transfer Taxes, recording fees and similar Taxesand fees incurred and imposed upon, or with respect to, the property transfers or other transactionscontemplated hereby (“ Transfer Taxes ”). Seller will determine, and Purchaser agrees to cooperatewith Seller in determining, Transfer Taxes, if any, that applicable law requires Seller to collect fromPurchaser in connection with the sale of Assets hereunder, and Purchaser agrees to pay any such tax toSeller at Closing; provided,however, that Seller’s failure to collect any such Transfer Taxes at Closingshall not absolve Purchaser from Purchaser’s responsibility for such Transfer Taxes. If such transfers ortransactions are exempt from any such Taxes or fees upon the filing of an appropriate certificate or otherevidence of exemption, Purchaser will timely furnish to Seller such certificate or evidence.

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Section 12.4 Expenses .

Except as provided in Section 12.3, all expenses incurred by Seller in connection with or relatedto the authorization, preparation or execution of this Agreement, the conveyances delivered hereunderand the Exhibits and Schedules hereto and thereto, and all other matters related to the Closing, includingall fees and expenses of counsel, accountants and financial advisers employed by Seller, shall be bornesolely and entirely by Seller, and all such expenses incurred by Purchaser shall be borne solely andentirely by Purchaser.

Section 12.5 Change of Name .

Unless otherwise authorized by Seller in writing, as promptly as practicable, but in any casewithin thirty (30) days after the Closing Date, Purchaser shall eliminate the name “Jones” and anyvariants thereof from the Assets acquired pursuant to this Agreement and, except with respect to suchgrace period for eliminating existing usage, shall have no right to use any logos, trademarks or tradenames belonging to Seller or any of its Affiliates.

Section 12.6 Replacement of Bonds and Guarantees .

(a) Purchaser acknowledges that none of the bonds, letters of credit and guarantees, ifany, posted by Seller or its Affiliates with any Governmental Bodies and/or relating to the Assets,including those set forth in Schedule 12.6(a) (the “ Governmental Bonds ”), are transferable toPurchaser. On or before Closing, Purchaser shall obtain, or cause to be obtained in the name ofPurchaser, or its Affiliate designee, replacements for such Governmental Bonds to the extent suchreplacements are necessary (i) for Purchaser’s ownership of the Assets, and (ii) to permit thecancellation of the Governmental Bonds posted by Seller and/or any Affiliate of Seller withrespect to the Assets. In addition, at or prior to Closing, Purchaser shall deliver to Seller evidenceof the posting of bonds or other security with all applicable Governmental Bodies meeting therequirements of such Governmental Bodies to own and, if applicable, operate the Assets.

(b) Purchaser shall cooperate with Seller in order to cause Seller and its Affiliates tobe released, as of the Closing Date, from all guarantees, performance bonds, letters of credit,escrow accounts and other forms of financial assurance previously put in place by Seller withThird Parties that are not Governmental Bodies in connection with its ownership and operation ofthe Assets and which are as set forth in Schedule 12.6(b) (the “ Guarantees ”). Without limitingthe foregoing, if required by a counterparty to any Guarantee, Purchaser shall, and, if applicable,shall cause its Affiliates to, provide, effective as of the Closing Date or such later date as may berequired by such counterparty, substitute guarantee or similar arrangements for all periodscovered by the Guarantees, which guarantee or similar arrangements shall (i) constitute a type ofsecurity, and (ii) be provided by a party whose creditworthiness is, in each case, equivalent to orbetter than that required by the counterparty to such Guarantee.

(c) In the event that any counterparty to any such Guarantee does not release Seller orany of its Affiliates or in the event that any Governmental Body does not permit the cancellationof any Governmental Bond posted by Seller and/or any Affiliate of Seller

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with respect to the Assets, then, from and after Closing, Purchaser shall indemnify Seller or anyAffiliate of Seller, as applicable, against all amounts incurred by Seller or any Affiliate of Seller,as applicable, under such Guarantee or such Governmental Bond (and all costs incurred inconnection with such Guarantee or such Governmental Bond) if applicable to the Assets acquiredby Purchaser. Notwithstanding anything to the contrary contained in this Agreement, any cashplaced in escrow by Seller or any Affiliate of Seller pursuant to the Guarantees must be returnedto Seller as soon as practicable and shall be deemed an Excluded Asset for all purposeshereunder.

Section 12.7 Governing Law and Venue .

This Agreement and the legal relations between the Parties shall be governed by and construed inaccordance with the Laws of the State of Texas without regard to principles of conflicts of Law thatwould direct the application of the Law of another jurisdiction. The venue for any action brought underthis Agreement shall be Harris County, Texas.

Section 12.8 Jurisdiction; Waiver of Jury Trial .

EACH PARTY CONSENTS TO PERSONAL JURISDICTION IN ANY ACTION BROUGHTIN THE UNITED STATES FEDERAL COURTS LOCATED WITHIN HARRIS COUNTY, TEXAS(OR, IF JURISDICTION IS NOT AVAILABLE IN THE UNITED STATES FEDERAL COURTS, TOPERSONAL JURISDICTION IN ANY ACTION BROUGHT IN THE STATE COURTS LOCATEDIN HARRIS COUNTY, TEXAS) WITH RESPECT TO ANY DISPUTE, CLAIM OR CONTROVERSYARISING OUT OF OR IN RELATION TO OR IN CONNECTION WITH THIS AGREEMENT, ANDEACH OF THE PARTIES AGREES THAT ANY ACTION INSTITUTED BY IT AGAINST THEOTHER WITH RESPECT TO ANY SUCH DISPUTE, CONTROVERSY OR CLAIM (EXCEPT TOTHE EXTENT A DISPUTE, CONTROVERSY, OR CLAIM ARISING OUT OF OR IN RELATIONTO OR IN CONNECTION WITH THE DETERMINATION OF A TITLE DEFECT AMOUNT ORTITLE BENEFIT AMOUNT PURSUANT TO SECTION 3.4(H) , OR THE DETERMINATION OFPURCHASE PRICE ADJUSTMENTS PURSUANT TO SECTION 9.4(B) IS REFERRED TO ANEXPERT PURSUANT TO THOSE SECTIONS) WILL BE INSTITUTED EXCLUSIVELY THEUNITED STATES FEDERAL COURTS LOCATED WITHIN HARRIS COUNTY, TEXAS (OR, IFJURISDICTION IS NOT AVAILABLE IN THE UNITED STATES FEDERAL COURTS, TOPERSONAL JURISDICTION IN ANY ACTION BROUGHT IN THE STATE COURTS LOCATEDIN HARRIS COUNTY, TEXAS). THE PARTIES HEREBY WAIVE TRIAL BY JURY IN ANYACTION, PROCEEDING OR COUNTERCLAIM BROUGHT BY ANY PARTY AGAINSTANOTHER IN ANY MATTER WHATSOEVER ARISING OUT OF OR IN RELATION TO OR INCONNECTION WITH THIS AGREEMENT. IN ADDITION, EACH PARTY IRREVOCABLYWAIVES ANY OBJECTION, INCLUDING ANY OBJECTION TO THE LAYING OF VENUE ORBASED ON THE GROUNDS OF FORUM NON CONVENIENS, WHICH IT MAY NOW ORHEREAFTER HAVE TO THE BRINGING OF ANY SUCH ACTION IN THE RESPECTIVEJURISDICTIONS REFERENCED IN THIS SECTION.

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Section 12.9 Captions .

The captions in this Agreement are for convenience only and shall not be considered a part of oraffect the construction or interpretation of any provision of this Agreement.

Section 12.10 Waivers .

Any failure by any Party to comply with any of its obligations, agreements or conditions hereincontained may be waived in writing, but not in any other manner, by the party or parties to whom suchcompliance is owed. No waiver of, or consent to a change in, any of the provisions of this Agreementshall be deemed or shall constitute a waiver of, or consent to a change in, other provisions hereof(whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expresslyprovided.

Section 12.11 Assignment .

Neither Party shall assign all or any part of this Agreement, nor shall any Party assign or delegateany of its rights or duties hereunder, without the prior written consent of the other Party and anyassignment or delegation made without such consent shall be void; provided, that in the event thatPurchaser is permitted to assign all or any part of this Agreement or the Assets (a) such assignment shallnot relieve Purchaser of any liability or obligation under this Agreement and (b) such assignee shallagree, in writing, to assume Purchaser’s obligations under this Agreement and be jointly and severallyliable with Purchaser for all of Purchaser’s liabilities and obligations under this Agreement.

Section 12.12 Entire Agreement .

This Agreement and the documents to be executed hereunder and the Exhibits and Schedulesattached hereto, together with the Confidentiality Agreement, constitute the entire agreement between theParties 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 matterhereof. In the event of a conflict between the Confidentiality Agreement and this Agreement, the termsand provisions of this Agreement shall prevail.

Section 12.13 Amendment .

(a) This Agreement may be amended or modified only by an agreement in writingexecuted by both Parties.

(b) No waiver of any right under this Agreement shall be binding unless executed inwriting by the Party to be bound thereby.

Section 12.14 No Third-Party Beneficiaries .

Nothing in this Agreement shall entitle any Person other than Purchaser and Seller to any claims,cause of action, remedy or right of any kind, except the rights expressly provided to the Personsdescribed in Section 11.2(f).

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Section 12.15 Public Announcements .

The Parties acknowledge and agree that no press release or other public announcement, or publicstatement or comment in response to any inquiry, or other disclosure that is reasonably expected to resultin a press release or public announcement, relating to the subject matter of this Agreement shall be issuedor made by Seller or Purchaser, or their respective Affiliates, without the joint written approval of Sellerand Purchaser; provided, that , a press release or other public announcement, or public statement orcomment in response to any inquiry, made without such joint approval shall not be in violation of thisSection if it is made in order for the disclosing Party or any of its Affiliates to comply with applicableLaws or stock exchange rules or regulations and provided it is limited to those disclosures that arerequired to so comply.

Section 12.16 Invalid Provisions .

If any provision of this Agreement is held to be illegal, invalid or unenforceable under present orfuture Laws effective during the term hereof, such provision shall be fully severable; this Agreementshall be construed and enforced as if such illegal, invalid or unenforceable provision had nevercomprised a part hereof; and the remaining provisions of this Agreement shall remain in full force andeffect and shall not be effected by the illegal, invalid or unenforceable provision or by its severance fromthis Agreement.

Section 12.17 References .

In this Agreement:

(a) References to any gender includes a reference to all other genders;

(b) References to the singular includes the plural, and vice versa;

(c) Reference to any Article or Section means an Article or Section of thisAgreement;

(d) Reference to any Exhibit or Schedule means an Exhibit or Schedule to thisAgreement, all of which are incorporated into and made a part of this Agreement;

(e) References to $ or Dollars means United States Dollars;

(f) Unless expressly provided to the contrary, “hereunder”, “hereof”, “herein” andwords of similar import are references to this Agreement as a whole and not any particularSection or other provision of this Agreement; and

(g) “Include” and “including” shall mean include or including without limiting thegenerality of the description preceding such term.

Section 12.18 Construction .

Each of Seller and Purchaser has had substantial input into the drafting and preparation of thisAgreement and has had the opportunity to exercise business discretion in relation to the

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negotiation of the details of the transaction contemplated hereby. This Agreement is the result of arm’s-length negotiations from equal bargaining positions.

Section 12.19 Limitation on Damages .

NOTWITHSTANDING ANYTHING TO THE CONTRARY CONTAINED HEREIN, NONEOF PURCHASER, SELLER OR ANY OF THEIR RESPECTIVE AFFILIATES OR INDEMNITEESSHALL BE ENTITLED TO EITHER PUNITIVE, SPECIAL, INDIRECT OR CONSEQUENTIALDAMAGES IN CONNECTION WITH THIS AGREEMENT AND THE TRANSACTIONSCONTEMPLATED HEREBY AND EACH OF PURCHASER AND SELLER, FOR ITSELF AND ONBEHALF OF ITS AFFILIATES AND INDEMNITEES, HEREBY EXPRESSLY WAIVES ANYRIGHT TO PUNITIVE, SPECIAL, INDIRECT OR CONSEQUENTIAL DAMAGES INCONNECTION WITH THIS AGREEMENT AND THE TRANSACTIONS CONTEMPLATEDHEREBY, EXCEPT TO THE EXTENT AN INDEMNIFIED PARTY IS REQUIRED TO PAYPUNITIVE, SPECIAL, INDIRECT OR CONSEQUENTIAL DAMAGES TO A THIRD PARTY THATIS NOT AN INDEMNIFIED PARTY.

ARTICLE 13

DEFINITIONS

“ Adjusted Purchase Price ” has the meaning set forth in Section 2.1.

“ Adjustment Period ” has the meaning set forth in Section 2.2(a).

“ Affiliates ” with respect to any Person, means any Person that directly or indirectly controls, iscontrolled by or is under common control with such Person.

“ Agreed Interest Rate ” shall mean simple interest computed at the rate of the prime interestrate as published in the Wall Street Journal.

“ Agreement ” has the meaning set forth in the first paragraph of this Agreement.

“ Allocated Value ” has the meaning set forth in Section 2.3.

“ Assessment ” has the meaning set forth in Section 4.1.

“ Assets ” has the meaning set forth in Section 1.2.

“ Assumed Obligations ” has the meaning set forth in Section 11.2(a).

“ Business Day ” means each calendar day except Saturdays, Sundays, and Federal holidays.

“ CERCLA ” has the meaning set forth in the definition of Environmental Laws.

“ Claim Notice ” has the meaning set forth in Section 11.3(b).

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“ Closing ” has the meaning set forth in Section 9.1(a).

“ Closing Date ” has the meaning set forth in Section 9.1(b).

“ Closing Payment ” has the meaning set forth in Section 9.4(a).

“ Confidentiality Agreement ” means the Confidentiality Agreement between FoundationEnergy Management, LLC, Purchaser’s parent, and Seller dated April 21, 2017.

“ Contingent Payment ” has the meaning set forth in Section 7.12(a).

“ Contracts ” has the meaning set forth in Section 1.2(d).

“ Conveyance ” has the meaning set forth in Section 3.1(b).

“ COPAS ” has the meaning set forth in Section 1.4(b).

“ Cure Period ” has the meaning set forth in Section 3.4(c).

“ Damages ” has the meaning set forth in Section 11.2(e).

“ Defect Deductible ” has the meaning set forth in Section 3.4(i).

“ Defect Property ” has the meaning set forth in Section 3.4(a).

“ Defensible Title ” has the meaning set forth in Section 3.2(a).

“ Deposit ” has the meaning set forth in Section 2.4.

“ Determination Period ” has the meaning set forth in Section 7.12(b).

“ Effective Time ” has the meaning set forth in Section 1.4(a).

“ Environmental Arbitrator ” has the meaning set forth in Section 4.4.

“ Environmental Claim Date ” has the meaning set forth in Section 4.3.

“ Environmental Consultant ” has the meaning set forth in Section 4.1.

“ Environmental Defect Notice ” has the meaning set forth in Section 4.3.

“ Environmental Laws ” means, as the same have been amended as of the Effective Time, theComprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9601 et seq . (“CERCLA ”); the Resource Conservation and Recovery Act, 42 U.S.C. § 6901 et seq. ; the Federal WaterPollution Control Act, 33 U.S.C. § 1251 et seq .; the Clean Air Act, 42 U.S.C. § 7401 et seq . theHazardous Materials Transportation Act, 49 U.S.C. § 1471 et seq .; the Toxic Substances Control Act, 15U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et seq .; the Emergency Planningand Community Right-to-Know Act, 42 U.S.C. § 11001 et seq .; and the Safe Drinking Water Act, 42U.S.C. §§ 300f through 300j; and all Laws as of the Effective

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Time of any Governmental Body having jurisdiction over the property in question governing operationof the Assets, and otherwise addressing pollution or protection of the environment and all regulationsimplementing the foregoing. Notwithstanding the foregoing, the phrase “violation of EnvironmentalLaws” and words of similar import used herein shall mean, as to any given Asset, the violation of orfailure to meet specific objective requirements or standards that are clearly applicable to such Assetunder applicable Environmental Laws where such requirements or standards are in effect as of theEffective Time. The phrase does not include good or desirable operating practices or standards that maybe employed or adopted by other oil or gas well operators or recommended by a Governmental Body.

“ Environmental Liabilities ” shall mean any and all environmental response costs (includingcosts of remediation), Damages, natural resource damages, settlements, consulting fees, expenses,penalties, fines, orphan share, prejudgment and post-judgment interest, court costs, attorneys’ fees, andother liabilities incurred or imposed (i) pursuant to any order, notice of responsibility, directive(including requirements embodied in Environmental Laws), injunction, judgment or similar act(including settlements) by any Governmental Body to the extent arising out of any violation of anyEnvironmental Law which is attributable to the ownership or operation of the Properties prior to theEffective Time or (ii) pursuant to any claim or cause of action by a Governmental Body or other Personfor personal injury, property damage, damage to natural resources to the extent arising out of anyviolation of any Environmental Law to the extent attributable to the ownership or operation of theProperties prior to the Effective Time, provided, that Environmental Liabilities excludes any of theforegoing liabilities to the extent disclosed in any Schedule.

“ Equipment ” has the meaning set forth in Section 1.2(f).

“ Excluded Assets ” has the meaning set forth in Section 1.3.

“ GAAP ” means United States generally accepted accounting principles.

“ Geological Data ” means all seismic, geological, geochemical or geophysical data (includingcores and other physical samples of materials from wells or tests) belonging to Seller or licensed fromthird parties relating to the Properties that can be transferred without additional consideration to suchthird parties (or including such licensed data in the event Purchaser agrees to pay such additionalconsideration), including all such data having been acquired by Seller from its predecessors in title, andincluding, to the extent they exist, all isopach maps, contour maps, structural maps, net pay maps,whether such mapping was undertaken and created by Seller or Seller’s predecessors in title, butexcluding any other interpretations of such data prepared or created by Seller.

“ Governmental Authorizations ” has the meaning set forth in Section 5.13.

“ Governmental Body ” means any federal, state, local, municipal, or other governments; anygovernmental, regulatory or administrative agency, commission, body or other authority exercising orentitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxingauthority or power; and any court or governmental tribunal.

“ Governmental Bonds ” has the meaning set forth in Section 12.6(a).

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“ Guarantees ” has the meaning set forth in Section 12.6(b).

“ Hydrocarbons ” means oil, gas, condensate and other gaseous and liquid hydrocarbons or anycombination thereof, including scrubber liquid inventory and ethane, propane, isobutene, nor-butane andgasoline inventories (excluding tank bottoms), and sulphur and other minerals extracted from orproduced from the foregoing hydrocarbons.

“ Imbalance ” means any over-production, under-production, over-delivery, under-delivery orsimilar imbalance of Hydrocarbons produced from or allocated to the Assets, regardless of whether suchimbalance arises at the platform, wellhead, pipeline, gathering system, transportation system, processingplant or other location.

“ Indemnified Party ” has the meaning set forth in Section 11.3(a).

“ Indemnifying Party ” has the meaning set forth in Section 11.3(a).

“ Indemnity Deductible ” has the meaning set forth in Section 11.4(c)(ii).

“ Independent Expert ” has the meaning set forth in Section 9.4(b).

“ Lands ” has the meaning set forth in Section 1.2(a).

“ Law ” or “ Laws ” means all statutes, rules, regulations, ordinances, orders, and codes ofGovernmental Bodies.

“ Leases ” has the meaning set forth in Section 1.2(a).

“ Lowest Cost Response ” means the response required or allowed under Environmental Lawsthat cures, remediates, removes or remedies the applicable present condition alleged pursuant to anEnvironmental Defect Notice at the lowest cost (considered as a whole taking into consideration anymaterial negative impact such response may have on the operations of the relevant Assets and anypotential material additional costs or liabilities that may likely arise as a result of such response)sufficient to comply with Environmental Laws as compared to any other response that is required orallowed under Environmental Laws. The Lowest Cost Response shall include taking no action, leavingthe condition unaddressed, periodic monitoring or the recording of notices in lieu of remediation, if suchresponses are allowed under Environmental Laws.

“ Material Adverse Effect ” means any adverse effect on the ownership, operation or value ofthe Assets, as currently operated, which is material to the ownership, operation or value of the Assets,taken as a whole; provided, however , that “Material Adverse Effect” shall not include any materialadverse effects resulting from: (a) changes in general market, economic, financial or political conditions(including changes in commodity prices, fuel supply or transportation markets, interest or rates) in thearea in which the Assets are located, the United States or worldwide; (b) changes in Laws or inregulatory policies from and after the date of this Agreement; (c) changes or conditions resulting fromcivil unrest or terrorism or acts of God or natural disasters; (d) change or conditions resulting from thefailure of a Governmental Body to act or omit to act pursuant to Law; (e) entering into this Agreement orthe announcement of the transactions contemplated by this Agreement; (f) changes in conditions ordevelopments generally applicable to the oil and gas

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industry in the area where the Assets are located; (g) matters that are cured or no longer exist by theearlier of the Closing and the termination of this Agreement, without cost to Purchaser; (h)reclassification or recalculation of reserves in the ordinary course of business; (i) changes in the prices ofHydrocarbons; and (j) natural declines in well performance.

“ Net Acre ” means, as calculated separately with respect to Lands covered by each Lease in aPLSS Section, the product of: (i) the number of gross acres of land covered by such Lease, multipliedby(ii) the mineral interest ownership in the Hydrocarbons covered by such Lease (i.e. the lessor’s mineralinterest ownership and the non-executive mineral ownership, if any, covered by the particular Lease),multipliedby (iii) the Seller’s aggregate undivided interest in such Lease; provided, however, if items(ii) and/or (iii) vary as to different areas of such lands covered by such Lease as identified on Exhibit A ,a separate calculation shall be performed with respect to such area.

“ Net Revenue Interest ” has the meaning set forth in Section 3.2(a)(i).

“ NORM ” means naturally occurring radioactive material.

“ Permitted Encumbrances ” has the meaning set forth in Section 3.3.

“ Party ” or “ Parties ” has the meaning set forth in the Preamble to this Agreement.

“ Person ” means any individual, firm, corporation, partnership, limited liability company, jointventure, association, trust, unincorporated organization, government or agency or subdivision thereof orany other entity.

“ PLSS Section ” means a section designated by the applicable public land survey system andidentified on Schedule 2.3 as a “PLSS Section”.

“ Post-Effective Time Tax Advances ” has the meaning set forth in Section 7.8(e).

“ Preliminary Settlement Statement ” has the meaning set forth in Section 9.4(a).

“ Properties ” and “ Property ” have the meanings set forth in Section 1.2(c).

“ Property Costs ” has the meaning set forth in Section 1.4(c).

“ Property Defect Threshold ” has the meaning set forth in Section 3.4(i).

“ Purchase Price ” has the meaning set forth in Section 2.1.

“ Purchaser ” has the meaning set forth in the first paragraph of this Agreement.

“ Purchaser Indemnitees ” means Purchaser, its Affiliates, and the officers, directors, managers,members, stockholders, general or limited partners, employees, agents, representatives, advisors,subsidiaries, successors and assigns of Purchaser or its Affiliates.

“ Records ” has the meaning set forth in Section 1.2(i).

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“ Required Consent ” has the meaning set forth in Section 3.5(a).

“ Schedule Supplement ” has the meaning set forth in Section 5.1(e).

“ Seller ” has the meaning set forth in the first paragraph of this Agreement.

“ Seller Indemnitees ” shall mean Seller, its Affiliates, and the officers, directors, managers,members, stockholders, general or limited partners, coventurers, employees, agents, representatives,advisors, subsidiaries, successors and assigns of Seller or its Affiliates.

“ Seller Indemnity Obligations ” has the meaning set forth in Section 11.2(c).

“ Seller Operated Assets ” shall mean Assets operated by Seller or its Affiliates as of the date ofthis Agreement.

“Seller Retained Liabilities” means those liabilities and obligations of the Seller arising fromthe following:

(a) all liabilities for Taxes allocated to Seller under Section 7.8(a);

(b) the death or physical injury to any Person to the extent attributable to Seller’sownership or operation of the Assets for periods prior to the Closing Date, including death orphysical injuries suffered prior to the Closing Date which are Environmental Liabilities; and

(c) the off-site disposal of any substance produced from the Properties and definedor regulated as a “pollutant,” “hazardous waste” or “hazardous substance” under anyEnvironmental Law;

(d) save and except as to the Suspended Proceeds transferred by Seller toPurchaser, the accounting for, failure to pay, underpayment, or incorrect payment of any and allvalid royalties, overriding royalties, production payments, net profits interests, Working Interestsowned by third parties (except, with respect to Assets operated by third party operators, to theextent a person other than Seller receives the benefit of such failure or incorrect payment), andother burdens upon, measured by or payable out of production with respect to any Propertyattributable to the period that Hydrocarbons were produced and marketed from any Property priorto the Effective Time;

(e) all losses, claims, damages, costs and liabilities arising from any actions, suitsor proceedings pending for which Seller has received written notice prior to the date hereof,including the actions, suits and proceedings described in Schedule 5.7;

(f) the Excluded Assets;

(g) borrowed money (whether by loan, the issuance and sale of debt securities, orthe sale of property to another person subject to an understanding or agreement, contingent orotherwise, to repurchase such property from such other person); and all obligations of Sellerevidenced by a note, bond, debenture, or similar instrument or

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security in respect thereof, in each case put in place by Seller and burdening Seller’s interest inany of the Assets;

(h) all employment relationships of Seller or any Affiliate of Seller, including anyof their respective present or former employees or the termination of any such employmentrelationships, including the compensation or reimbursement for work performed with respect tothe Properties to the extent attributable to periods prior to the Closing Date; and

(i) Materialman’s, mechanic’s, repairman’s, employee’s, contractor’s, operator’s andother similar liens or charges which are Permitted Encumbrances and which are being contestedby Seller in good faith by appropriate actions, as provided under Section 3.3(f).

“ Special Warranty ” has the meaning set forth in Section 7.9(a).

“ Special Warranty Notice ” has the meaning set forth in Section 7.9(b).

“ Surface Contracts ” has the meaning set forth in Section 1.2(e).

“ Survival Period ” has the meaning set forth in Section 7.9(b).

“ Suspended Proceeds ” has the meaning set forth in Section 7.10.

“ Tax Audit ” has the meaning set forth in Section 7.8(d).

“ Tax Returns ” has the meaning set forth in Section 5.8.

“ Taxes ” means all federal, state, local, and foreign income, profits, franchise, sales, use, advalorem, property, severance, production, excise, stamp, documentary, real property transfer or gain,gross receipts, goods and services, registration, capital, transfer, or withholding Taxes or othergovernmental fees or charges imposed by any taxing authority, including any interest, penalties oradditional amounts which may be imposed with respect thereto.

“ Third Party Claim ” has the meaning set forth in Section 11.3(b).

“ Title Arbitrator ” has the meaning set forth in Section 3.4(h).

“ Title Benefit ” has the meaning set forth in Section 3.2(b).

“ Title Benefit Amount ” has the meaning set forth in Section 3.4(g).

“ Title Benefit Notice ” has the meaning set forth in Section 3.4(b).

“ Title Benefit Property ” has the meaning set forth in Section 3.4(b).

“ Title Claim Date ” has the meaning set forth in Section 3.4(a).

“ Title Defect ” has the meaning set forth in Section 3.2(c).

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“ Title Defect Amount ” has the meaning set forth in Section 3.4(f).

“ Title Defect Notice ” has the meaning set forth in Section 3.4(a).

“ Transfer Taxes ” has the meaning set forth in Section 12.3.

“ Units ” has the meaning set forth in Section 1.2(c).

“ Wells ” has the meaning set forth in Section 1.2(b).

“ Working Interest ” has the meaning set forth in Section 3.2(a)(ii).

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IN WITNESS WHEREOF, this Agreement has been signed by each of the Parties on the date

first above written.

/s/ Jonny Jones

SELLER

JONES ENERGY HOLDINGS, LLC

By: /s/ Jonny JonesName: Jonny JonesTitle: Chief Executive Officer

[Signature page to Purchase and Sale Agreement]

___

/s/ Joel P. Sauer

PURCHASER

FOUNDATION ENERGY FUND VI-A, LP

By: Foundation Energy Management, LLC itsSole Manager By: /s/ Joel P. SauerName: Joel P. SauerTitle: Executive Vice President

[Signature page to Purchase and Sale Agreement]

Exhibit A

Leases

The Parties agree that Exhibit A is intended to list all of the Leases which are intended to be included aspart of the Assets to be conveyed to Purchaser hereunder. In the event that between the date of theexecution of this Agreement and Closing it is determined that there are Leases that have beeninadvertently omitted from or incorrectly described on Exhibit A, Seller, with the consent of Purchaser,which consent shall not be unreasonably withheld or delayed, shall be permitted to supplement Exhibit Ato include those Leases which have been inadvertently omitted or incorrectly described.

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Exhibit 31.1

Certification by Chief Executive Officer pursuant toRule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,

as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 I, Jonny Jones, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Jones Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material factnecessary to make the statements made, in light of the circumstances under which such statements were made, notmisleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all

material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periodspresented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and

procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (asdefined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed

under our supervision, to ensure that material information relating to the registrant, including its consolidatedsubsidiaries, is made known to us by others within those entities, particularly during the period in which this reportis being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be

designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting andthe preparation of financial statements for external purposes in accordance with generally accepted accountingprinciples;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered bythis report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during

the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) thathas materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financialreporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over

financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or personsperforming the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial

reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize andreport financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the

registrant’s internal control over financial reporting. By: /s/ Jonny Jones Jonny Jones Chief Executive Officer Date: August 7, 2017

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Exhibit 31.2

Certification by Chief Financial Officer pursuant toRule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,

as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 I, Robert J. Brooks, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Jones Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material factnecessary to make the statements made, in light of the circumstances under which such statements were made, notmisleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all

material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periodspresented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and

procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (asdefined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed

under our supervision, to ensure that material information relating to the registrant, including its consolidatedsubsidiaries, is made known to us by others within those entities, particularly during the period in which this reportis being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be

designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting andthe preparation of financial statements for external purposes in accordance with generally accepted accountingprinciples;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered bythis report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during

the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) thathas materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financialreporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over

financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or personsperforming the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial

reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize andreport financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the

registrant’s internal control over financial reporting. By: /s/ Robert J. Brooks Robert J. Brooks Chief Financial Officer Date: August 7, 2017

Table of Contents

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Table of Contents

Exhibit 32.1

Certification Pursuant to18 U.S.C. Section 1350,

as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the quarterly report of Jones Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended June 30,2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jonny Jones, Chief ExecutiveOfficer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of2002 (“Section 906”), that, to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, asamended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of

operations of the Company. By: /s/ Jonny Jones Jonny Jones Chief Executive Officer Date: August 7, 2017

A signed original of this written statement required by Section 906 has been provided to the Company and will be retainedand furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32.2

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Exhibit 32.2

Certification Pursuant to18 U.S.C. Section 1350,

as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the quarterly report of Jones Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended June 30,2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert J. Brooks, Chief FinancialOfficer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of2002 (“Section 906”), that, to my knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, asamended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of

operations of the Company. By: /s/ Robert J. Brooks Robert J. Brooks Chief Financial Officer Date: August 7, 2017

A signed original of this written statement required by Section 906 has been provided to the Company and will be retainedand furnished to the Securities and Exchange Commission or its staff upon request.

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