Jones Energy, Inc. (Form: 10-Q, Received: 08/07/2017 07:04:53)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, 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

☐ 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 Employer
Incorporation 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. Brooks

807 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 during the 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 the past 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 be submitted 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 registrant was 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 emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the 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 or revised 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.

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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 of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this report that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this report specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, our expectations regarding our ability to drill the recently acquired acreage in the Merge, our potential decrease in capital spending if profitability or cash flows are lower than anticipated, our ability to mitigate commodity price risk through our hedging program, our ability 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 successfully execute our 2017 development plan. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. 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 planned capital expenditures, availability and method of funding acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, customers’ elections to reject ethane and include it as part of the natural gas stream, ability to fund our 2017 capital expenditure budget, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company’s business and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the SEC.

Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

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PART 1—FINANCIAL INFORMATIO N

Item 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 and 57,048,076 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 issued and 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 Special Stock Dividend, as defined in Note 11, “Stockholders’ and Mezzanine equity”, distributed on March 31, 2017.

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

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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 ASU 2016-09	—		—	—		—	—		—		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 A shares	8		—	(8)		—	—		—		118		—		(123)		(5)
Dividends and accretion on preferred stock	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

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

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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

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

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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 entity and the holding company of Jones Energy Holdings, LLC (“JEH”). As the sole managing member of JEH, the Company is responsible for all operational, management and administrative decisions relating to JEH’s business and consolidates the financial results of JEH and its subsidiaries.

JEH was formed as a Delaware limited liability company on December 16, 2009 through investments made by the Jones family, certain members of management and through private equity funds managed by Metalmark Capital, among others. JEH acts 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 B common 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 of common units representing membership interests in JEH (“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 other similar transactions. The Class B common stock has no economic rights but entitles its holders to one vote on all matters to be voted on by the Company’s stockholders generally. As of June 30, 2017, the Company held 66,649,057 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 29,823,927 JEH Units are held by the Class B shareholders. The Class B shareholders have no voting rights with respect to their economic interest in JEH, resulting in the Company 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 more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by the Board of Directors of the Company and may differ from those of any and all other 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, par value $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 the mid-continent United States, spanning areas of Texas and Oklahoma. The Company’s assets are located within the Eastern Anadarko 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, and are 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 generally accepted in the United States of America (“GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission. All significant intercompany transactions and balances have been eliminated in consolidation. The Company’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 Company and 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 have been prepared in accordance with GAAP for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. Certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted in this Quarterly Report. The Company believes the disclosures made are adequate to make the information presented not misleading. The unaudited condensed consolidated financial statements contained in this report include all normal and recurring 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 condensed consolidated financial statements should be read in conjunction with our most recent audited consolidated financial statements included 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 on Form 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 for qualified wells on which taxes were initially paid between October 2012 and September 2016. The Company received a net production tax refund of $3.3 million, which was recorded as a reduction in Production and ad valorem taxes on the Company’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 is intended to simplify the accounting for share-based payment awards to employees, specifically in regard to (1) the income tax consequences, (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, the Company has adopted ASU 2016-09 effective as of January 1, 2017. Upon adoption of ASU 2016-09, the Company elected to change its accounting policy to account for forfeitures as they occur. The change was applied on a modified retrospective basis with a cumulative effect adjustment to retained earnings for forfeitures of $0.7 million as of January 1, 2017. As a result of the valuation allowance against the Company’s deferred tax assets, there was no net adjustment to retained earnings for the change in accounting for unrecognized windfall tax benefits.

In May 2017, the FASB issued ASU 2017-09, “Scope of Modification Accounting” as it relates to “Compensation—Stock Compensation” (Topic 718). This amendment clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. The new guidance is expected to reduce diversity in practice and result in fewer changes to the terms of an award being accounted for as modifications. Under ASU 2017-09, an entity will not apply modification accounting to a share-based payment award if the award’s fair value, vesting conditions and classification as an equity or liability instrument are the same immediately before and after the change. The amendments are effective for interim and annual reporting periods beginning after December 15, 2017. Early adoption is permitted and the Company chose to early adopt ASU 2017-09 beginning April 1, 2017. The change was applied prospectively to awards modified on or after the adoption 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 the Accounting Standards Codification (“ASC”), topic 606, “Revenue from Contracts with Customers.” This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09 by one year. The amendments are now effective for interim and annual reporting periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis. Early adoption is permitted. The Company is in the process of comparing our current revenue recognition policies to the new requirements for each 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. The Company will continue to further evaluate the effect that the adoption of Update 2014-09 and Update 2015-14 will have on our financial statements and our anticipated method of adoption. We anticipate adoption of Update 2014-09 and Update 2015-14 effective as of January 1, 2018.

In February 2016, the FASB issued ASU 2016-02, “Leases” (Topic 842). This amendment requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-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 lease term. 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 for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases. We anticipate adoption of ASU 2016-02 effective 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 purchase and 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 $134.4 million, net of the final working capital settlement of $2.4 million received in the first quarter of 2017. The oil and gas properties acquired in the Merge Acquisition, on a closed and funded basis, principally consist of 16,975 undeveloped net acres in Canadian, Grady and McClain Counties, Oklahoma. This transaction has been accounted for as an asset acquisition. The Company used proceeds from our equity offerings to fund a portion of the purchase. See Note 11, “Stockholders’ and Mezzanine 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 business combination. 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 related facilities”, based on the respective fair values of the assets acquired. Additionally, the Company allocated $6.4 million to our ARO liability associated with those proved properties. As of June 30, 2017, the measurement-period has closed. The Anadarko Acquisition did not result in a significant impact to revenues or net income and as such, pro forma financial information is not included. 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, the acquired 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 up to $2.5 million in contingent payments based on natural gas prices. No amounts have been recorded related to this contingent payment as of June 30, 2017. The Company received a deposit of $4.9 million associated with the pending sale which has been included 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 to the pending Arkoma Divestiture. Upon the classification change occurring on June 30, 2017, the Company ceased recording depletion on the Held for sale assets. Based on the Company’s anticipated sales price, the Company has recognized an impairment charge of $161.9 million at June 30, 2017 which has been included in Impairment of oil and gas properties on the Company’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 of accounting. 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 were capitalized 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 six months while activities are in progress to bring the assets to their intended use. During the six months ended June 30, 2017, the Company capitalized $0.2 million associated with such in progress projects. The Company did not capitalize any interest during the six months ended June 30, 2016 as no projects lasted more than six months. Costs incurred to maintain wells and related 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 unproved properties were recorded as a result of our standard impairment assessment during the six months ended June 30, 2017 or 2016. However, as noted in Note 3, “Acquisitions and Divestitures - Assets held for sale,” the Company has recognized an impairment 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 three and six months ended June 30, 2017, respectively, and $0.3 million and $0.6 million for the three and six months ended June 30, 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 to repay all outstanding borrowings under the Term Loan (as defined below) ($160.0 million), a portion of the outstanding borrowings 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 of 6.75% per year, payable semi-annually on April 1 and October 1 of each year beginning October 1, 2014. The 2022 Notes were 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 Notes were issued at a discounted price equal to 94.59% of the principal amount. The Company used the $236.5 million net proceeds from the issuance of the 2023 Notes to repay outstanding borrowings under the Revolver and for working capital and general corporate purposes. The 2023 Notes bear interest at a rate of 9.25% per year, payable semi-annually on March 15 and September 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 through several open market and privately negotiated purchases. The Company purchased $90.9 million principal amount of its 2022 Notes for $38.1 million, and $100.0 million principal amount of its 2023 Notes for $46.5 million, in each case excluding accrued interest and including any associated fees. The Company used cash on hand and borrowings from its Revolver to fund the note purchases. In conjunction with the extinguishment of this debt, JEH recognized cancellation of debt income of $99.5 million for the twelve months ended December 31, 2016, on a pre-tax basis. This income is recorded in Gain on debt extinguishment on the Company’s Consolidated Statement of Operations. Of the Company’s total repurchases, $20.3 million principal amount of its 2022 Notes were not cancelled and are available for future reissuance, subject to applicable securities laws.

The 2022 Notes and 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of its significant subsidiaries. The 2022 Notes and 2023 Notes will be senior in right of payment to any future subordinated indebtedness of the Issuers.

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 after March 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 other things, limit the ability of the Company to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or other payments from the Company’s restricted subsidiaries to the Company, consolidate, merge or transfer all of the Company’s assets, engage in transactions with affiliates or create unrestricted subsidiaries. If at any time when the 2022 Notes or 2023 Notes 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 covenants pertaining 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 Secured Revolving Credit Facility (the “Revolver”) and the Second Lien Term Loan (the “Term Loan”). On April 1, 2014, the Term Loan was repaid in full and terminated in connection with the issuance of the 2022 Notes. On November 6, 2014, the Company amended the Revolver to, among other things, extend the maturity date of the Revolver to November 6, 2019. The Company’s oil 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 the Company'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 giving effect to such borrowing or issuance of Letter of Credit, will have, a Consolidated Cash Balance (as defined in the Revolver) in excess of $30.0 million (in each case giving effect to the anticipated use of proceeds thereof) and (iii) set the borrowing base under the Revolver at $425.0 million. The borrowing base was reaffirmed at this level during the most recent semi-annual borrowing base re-determination effective May 15, 2017. On August 1, 2017, upon closing of the Arkoma Divestiture, the Company’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 borrowing base, which limits the amount of borrowings which may be drawn thereunder. The borrowing base will be re-determined by the lenders at least semi-annually on or about April 1 and October 1 of each year, with such re-determination based primarily on reserve 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 revolving credit facility exceeding the borrowing 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 for the 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 rate announced 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 level of borrowing base utilization at such time. For the three and six months ended June 30, 2017, the average interest rates under the 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% and 2.43%, 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 ended June 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 the requirement 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 day of any fiscal quarter; and

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a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.00 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 requirements in our covenants. We were in compliance with all terms of our Revolver at June 30, 2017, and we expect to maintain compliance throughout the next twelve-month period. However, factors including those outside of our control, such as commodity price declines, may prevent us from maintaining compliance with these covenants, at future measurement dates in 2017 and beyond. In the event it were to become 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 would be able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change of control, 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 limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or 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 months ended June 30, 2017, respectively. The Company recognized net losses on derivative instruments of $40.0 million and $22.8 million 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 and 2017, the Company realized certain mark-to-market gains associated with oil and natural gas hedges the Company had in place for years 2018 and 2019. The gains were effectively realized by purchasing, as opposed to selling, oil and natural gas swap contracts for the equal volume that was associated with the initial hedge transaction. Therefore, as prices fluctuate, the loss (or gain) on any single contract in 2018 and 2019 will be offset by an equal gain (or loss). This essentially leaves the underlying production open to fluctuations in market prices. Based on the original contract terms of these purchased swaps, the gains would be recognized as the hedge contracts mature in 2018 and 2019. See further discussion below. Information related to these purchased oil and natural gas swap contracts is presented in the table above as the “offset exercise price”, and the volumes 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 hedges resulting 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 our counterparties or their affiliates are also lenders under the Revolver. We are not generally required to post additional collateral under our derivative agreements.

Our derivative agreements contain set-off provisions that state that in the event of default or early termination, any obligation owed 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 Consolidated Balance 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 derivative contracts
Assets	$	58,023	$	(12,286)	$	45,737	$	—	$	45,737
Liabilities		(15,445)		12,286		(3,159)		—		(3,159)
December 31, 2016
Commodity derivative contracts
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. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

The Company enters into a variety of derivative financial instruments, which may include over-the-counter instruments, such as natural gas, crude oil, and natural gas liquid contracts. The Company utilizes valuation techniques that maximize the use of observable inputs, where available. If listed market prices or quotes are not published, fair value is determined based upon a market quote, adjusted by other market-based or independently sourced market data, such as trading volume, historical commodity volatility, and counterparty-specific considerations. These adjustments may include amounts to reflect counterparty credit 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 fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have low default rates and equal credit quality. Therefore, an adjustment may be necessary to reflect the quality of a specific counterparty to determine the fair value of the instrument. The Company currently has all derivative positions placed and held by 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 financial instruments that trade in less active markets. Exchange traded contracts are valued at market value without making any additional 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 the transparency of inputs to the valuation of an asset or liability as of the measurement date. A financial instrument’s categorization within the hierarchy is based upon the input that requires the highest degree of judgment in the determination of the 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 a recognized exchange or are tied to pricing transactions for which forward curve pricing is readily available are classified as Level 2 instruments. These include natural gas, crude oil and some natural gas liquids price swaps and natural 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. The Company obtains estimates from independent third parties for its open positions and subjects those to the credit adjustment criteria described above.

The financial instruments carried at fair value as of June 30, 2017 and December 31, 2016, by consolidated balance sheet caption 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 our Consolidated 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 Consolidated Balance Sheet as of December 31, 2016. Our agreements include set-off provisions, as noted in Note 6, “Derivative Instruments 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 the Company’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 liquid swaps	$	(252)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$22.89 - $23.94 per barrel
Crude oil collars	$	2,766	Use a discounted option model approach using inputs including interpolated volatilities for certain settlement months where market volatility quotes were unavailable for the option strike price	Market volatility quotes at the option strike for certain settlement months in 2019	$45.00 - $61.00 per barrel
Natural gas collars	$	(761)	Use a discounted option model approach using inputs including interpolated volatilities for certain settlement months where market volatility quotes were unavailable for the option strike price	Market volatility quotes at the option strike for certain settlement months in 2019	$2.55 - $3.41 per barrel

Significant increases/decreases in natural gas liquid prices in isolation would result in a significantly lower/higher fair value measurement. 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 in other income (expense). New contracts entered into during the year are generally entered into at no cost with changes in fair value from the date of agreement representing the entire fair value of the instrument. Transfers between levels are evaluated at the end of the reporting period.

The following table summarizes the Company’s commodity derivative contract activity involving Level 3 instruments during the 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 consolidated financial 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 and no 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 prices for 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 prices for 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 less costs 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 membership interests in JEH to members of senior management (“Management Units”). These awards had various vesting schedules, and a portion 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 Units and shares of Class B common stock. The JEH Units (together with a corresponding number of shares of Class B common stock) will become exchangeable under this plan into a like number of shares of Class A common stock upon vesting or forfeiture. No new Management Units have been awarded since the IPO and no new JEH Units or shares of Class B common stock 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 six months 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 conjunction with the Company’s IPO and restated on May 4, 2016 following approval by the Company’s stockholders, the Company has reserved 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 in shares, 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, 2016 and 2017. During 2016 and 2017, the Company also granted performance unit awards to certain members of the senior management team under the LTIP.

All share and earnings per share information presented for awards made under the LTIP has been recast to retrospectively adjust for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 11, “Stockholders’ and Mezzanine equity”, 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 the LTIP. The fair value of the restricted stock unit awards is based on the value of the Company’s Class A common stock on the date 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 June 30, 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, 2017 preferred stock dividend for the portion of such dividend paid in shares of the Company’s Class A common stock, as described in Note 11 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards. This increase is in addition to the adjustment for the effects of the Special Stock Dividend previously disclosed in our Quarterly Report 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 for the three and six months ended June 30, 2017, respectively, and $0.9 million and $1.0 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.

Performance Share Unit Awards

The Company has outstanding performance share unit awards granted to certain members of the senior management team of the Company under the LTIP. Prior to the second quarter of 2016, the performance share unit awards were described in the Company’s filings as performance unit awards. During the second quarter of 2016, the Company created a new class of equity award, described below as a performance unit award, that is settled in cash rather than shares of the Company’s Class A common stock. As a result, references to performance unit awards in the Company’s filings prior to the second quarter of 2016 refer 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 performance share units. The percent of awarded performance share units in which each recipient vests at such time, if any, will range from 0% to 200% based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. Each vested performance share unit is exchangeable for one share of the Company’s Class A common stock. The grant date fair value of the performance share units was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned. The fair value of the performance share units is expensed on 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 simulation

model 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 senior management 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, 2017 preferred stock dividend for the portion of such dividend paid in shares of the Company’s Class A common stock, as described in Note 11 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards. This increase is in addition to the adjustment for the effects of the Special Stock Dividend previously disclosed in our Quarterly Report 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 three and six months ended June 30, 2017, respectively, and $0.6 million and $1.0 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.

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 $200.00 per performance unit based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. For accounting purposes, the performance units are treated as a liability award with the liability being re-measured at the end of each reporting period. Therefore, the expense associated with these awards is subject to volatility until the payout is finally determined at the end of the performance period. The value of the performance units was determined using a Monte Carlo simulation model, as of the grant date, which resulted in an estimated final value upon vesting of $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 simulation

model 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 for the three and six months ended June 30, 2017, respectively, as a result of the decrease in market value of the outstanding awards and less than $0.1 million for the three and six months ended June 30, 2016, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. As of June 30, 2017, $0.5 million of unrecognized 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, is expected 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 the Company under the LTIP. The restricted stock will vest upon the director serving as a director of the Company for a one-year service period in accordance with the terms of the award. The fair value of the awards was based on the price of the Company’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 $0.3 million for the three and six months ended June 30, 2017, respectively, and $0.2 million and $0.3 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.

10. Income Taxes

The Company records federal and state income tax liabilities associated with its status as a corporation. The Company recognizes a tax liability on its share of pre-tax book income, exclusive of the non-controlling interest. JEH is not subject to income 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, and 17.4% and 14.3% for the three and six months ended June 30, 2016, respectively. The effective tax rate reduction is primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets. The effective rate differs from the 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 tax accounting.

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 and non-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 its deferred taxes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of June 30, 2017, we have a valuation allowance 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 Company to make payments to certain current and former owners equal to 85% of the applicable cash savings that the Company realizes as a result of tax attributes arising from exchanges of JEH Units and shares of the Company’s Class B common stock held by those 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 the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers, and the portion of the Company’s payments under the TRA constituting imputed interest. In the event that the Company records a valuation allowance against its deferred tax assets associated with an exchange, the TRA liability will also be reduced as the payment 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 valuation allowance recorded against the Company’s deferred tax assets. To the extent the Company does not realize all of the tax benefits 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, after adjusting for the TRA liability reduction, along with corresponding deferred tax assets, net of valuation allowance, of $14.5 million, 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 have exchanged JEH Units and Class B common stock for Class A common stock. The Company anticipates making a payment of approximately $0.6 million under the TRA with respect to cash savings that the Company will realize on its 2016 tax returns as a 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 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 its unitholders (including us) based on income allocated to its unitholders through the end of each relevant quarter, as adjusted to take into account good faith projections by the Company of taxable income or loss for the remainder of the 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 in such 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 to its unitholders towards its total 2016 projected tax distribution obligation. The distributions were made pro-rata to all members of JEH, and included a $9.9 million payment to the Company, and a $10.1 million payment to JEH unitholders other than the Company. 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. The Class B common stock is held by the owners of JEH prior to the Company’s IPO and can be exchanged (together with a corresponding 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 other similar transactions. The Class B common stock has no economic rights but entitles its holders to one vote on all matters to be voted 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 contain various 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, as the 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 Shares from 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 of Class A Shares to a Manager as principal would be pursuant to the terms of a separate terms agreement between the Company and such Manager. Sales of the Class A Shares, if any, will be made by means of ordinary brokers’ transactions, to or through a market maker or directly on or through an electronic communication network, a “dark pool” or any similar market venue, or as 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 A Shares, respectively, under the Equity Distribution Agreement for net proceeds of approximately $5.6 million ($5.8 million gross proceeds, net of approximately $0.2 million in commissions and professional services expenses) and $8.4 million ($8.7 million 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 in aggregate 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 public offering, and on September 12, 2016 the Company issued an additional 3,150,000 shares of Class A common stock in connection with the exercise of the underwriters’ over-allotment option. The total net proceeds (after underwriters’ discounts and 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 public offering 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 per share of the Series A Preferred Stock, payable quarterly in arrears on February 15, May 15, August 15 and November 15 of each year, beginning on November 15, 2016. Dividends may be paid in cash or, subject to certain limitations, in Class A common 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, or purchase, redeem or otherwise acquire for consideration, shares of the Company’s Class A common stock, or any junior stock or parity stock currently outstanding or issued in the future, will be subject to certain restrictions in the event that the Company does not pay in full or declare and set aside for payment in full all accrued and unpaid dividends on the Series A preferred stock (including certain unpaid excess cash payment amounts excused from payment as a dividend due to restrictions in credit facilities 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’s option at any time, into approximately 17.0683 shares of Class A common stock after adjusting the conversion ratio for the effects of the Special Stock Dividend, as defined in Note 11, “Stockholders’ and Mezzanine equity”, (which is equivalent to a conversion price of approximately $2.93 per share after adjusting for the effects of the Special Stock Dividend), subject to specified 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 preferred stock.

On or after August 15, 2021, the Company may, at its option, give notice of its election to cause all outstanding shares of Series A preferred stock to be automatically converted into shares of Class A common stock at the conversion rate, if the closing sale price of the Class A common stock equals or exceeds 175% of the conversion price for at least 20 trading days in a period 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 any or all Series A preferred stock held by such holder outstanding on the designated redemption date at a redemption price equal to a liquidation preference of $50.00 per share plus all accrued dividends on the shares up to but excluding the designated redemption date that have not been paid plus any Unpaid Excess Cash Payment Amounts (the “redemption price”). At our option, the redemption price may be paid in cash or, subject to certain limitations, in Class A common stock, or a combination thereof.

Except as required by law or the Company’s certificate of incorporation, which includes the certificate of designations for the Series A preferred stock, the holders of Series A preferred stock have no voting rights (other than with respect to certain matters regarding the Series A preferred stock or when dividends payable on the Series A preferred stock have not been paid for an aggregate of six quarterly dividend periods, or more, whether or not consecutive, as provided in the certificate of designations 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 listed on 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 on the liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock. This dividend is for the period beginning on the last payment date of November 15, 2016 through February 14, 2017 and was paid in 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 the liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock. On May 15, 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 price per share of the Class A common stock used to determine the number of shares issued was equal to 95% of the average volume-weighted average price per share for each day during the five-consecutive day trading period ending immediately prior to the payment date. This dividend was for the period beginning on the last payment date of February 15, 2017 through May 14, 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 A common stock to holders of record as of March 15, 2017. From time-to-time, JEH makes cash distributions to the holders of JEH Units to cover tax obligations that may occur as a result of any net taxable income of JEH allocable to holders of JEH Units. As a holder of JEH Units, the Company has received such cash distributions from JEH in excess of the amount required to satisfy the Company’s associated tax obligations. As a result, the Company used the excess cash of approximately $17.5 million 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 to the number of JEH Units held by the Company, and the aggregate number of shares of Class A common stock issued in the Special Stock Dividend equaled the number of additional JEH Units the Company purchased from JEH. The Company purchased 4,999,927 JEH Units at a price of $3.50 per share, which is the volume weighted average price per share of the Class A common stock for the five trading days ended February 28, 2017. Immaterial cash payments were made in lieu of fractional shares. The comparative earnings per share information has been recast to retrospectively adjust for the effects of the Special Stock Dividend.

12. Earnings per Share

Basic earnings per share (“EPS”) is computed by dividing net income (loss) attributable to controlling interests by the weighted average number of shares of Class A common stock outstanding during the period. Shares of Class B common stock are not included in the calculation of earnings per share because they are not participating securities and have no economic interest in the Company. Diluted earnings per share takes into account the potential dilutive effect of shares that could be issued by the Company in conjunction with the Series A preferred stock and from stock awards that have been granted to directors and employees. Awards of non-vested shares are considered outstanding as of the respective grant dates for purposes of 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 A preferred 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 stock outstanding 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 controlling interests	$	(89,239)	$	(23,245)	$	(90,626)	$	(4,334)
Less: Dividends and accretion on preferred stock		(1,966)		—		(3,993)		—
Net income (loss) attributable to common shareholder	$	(91,205)	$	(23,245)	$	(94,619)	$	(4,334)
Weighted-average shares (denominator): (1)
Weighted-average number of shares of Class A common stock - basic		65,681		33,598		63,948		33,410
Weighted-average number of shares of Class A common stock - diluted		65,681		33,598		63,948		33,410
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)

(1)

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 dedicated properties, 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 by Monarch, based on a set liquids recovery percentage, and the amount received from the sale of the residue gas, after deducting a fixed volume for fuel, lost and unaccounted-for gas. The Company produced approximately 1.4 MMBoe of natural gas and NGLs for the year ended December 31, 2014, from the properties that became subject to the Monarch agreement. During the year ended December 31, 2014, the Company recognized $37.0 million of revenue associated with the aforementioned natural gas and NGL production. Effective May 1, 2015, the rights to gather natural gas under the sale and purchase agreement transferred from Monarch to Enable Midstream Partners LP, (“Enable”), an unaffiliated third-party. Prior to closing of the transfer of these rights, the Company produced approximately 1.0 MMBoe of natural gas and NGLs for the year ended December 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’s Consolidated 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 the outstanding equity interests of Monarch. In addition, Metalmark Capital beneficially owns in excess of five percent of the Company’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 into the 2013 Monarch agreement.

In connection with the Company’s entering into the 2013 Monarch agreement, Monarch issued to JEH equity interests in Monarch, having an estimated fair value of $15.0 million, in return for marketing services to be provided throughout the term of 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 $0.5 million 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 to Jonny Jones, the Company’s chief executive officer and chairman of the Board of Directors, and reserved $2.6 million of the equity interests for future distribution through an incentive plan to certain of the Company’s officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10.0 million of Monarch equity interests was distributed to certain of the Class B shareholders, which included, among others, Metalmark Capital, the Jones family entities, and certain of the Company’s officers and directors, including Jonny Jones, Mike McConnell and Eric Niccum. As of June 30, 2017, equity interests in Monarch of $0.7 million are included in Other assets on the Company’s Consolidated Balance Sheet. During the six months ended June 30, 2017, no equity interests were distributed to management under the incentive plan. The Company recognized expense of $0.1 million and $0.2 million during the three and six months ended June 30, 2017, respectively, in connection 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 gathering system to dedicated Company leases in Texas. At the time the Company entered into the agreement, Metalmark Capital owned the majority of the outstanding equity interests of Monarch Oil Pipeline LLC and/or its parent. The system began service during the fourth quarter of 2015 and provides connectivity to both a regional refinery market as well as the Cushing market hub. The Company incurred gathering fees, which were paid to Monarch Oil Pipeline LLC, of $0.6 million and $1.3 million for the three and six months ended June 30, 2017, respectively, associated with the approximately 0.3 MMBoe and 0.6 MMBoe, respectively, of oil production transported under the agreement. These costs are recorded as an offset to Oil and gas sales in the Company’s Consolidated Statement of Operations. The aforementioned production was recognized as Oil and gas sales on the Company’s Consolidated Statement of Operations at the time it was sold to the purchasers, who are unaffiliated third parties, after passing through the gathering and transportation system. The audit committee of the Board of Directors reviewed 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 outstanding 2023 Notes from investment funds managed by Magnetar Capital and its affiliates, which investment funds collectively then owned more than 5% of a class of voting securities of the Company, for approximately $23.3 million excluding accrued interest 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 Group Management L.L.C. and its affiliates, which investment funds collectively then owned more than 5% of a class of voting securities of the Company, for approximately $23.3 million excluding accrued interest and including any associated fees. In conjunction with the extinguishment of this $100.0 million principal amount of debt, JEH recognized cancellation of debt income of $48.3 million on a pre-tax basis. This income is recorded in Gain on debt extinguishment on the Company’s Consolidated 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 as described above under “Item 11. Stockholders’ and Mezzanine equity—Offering of Class A Common Stock,” affiliates of JVL Advisors, L.L.C. (“JVL”), who then owned more than 5% of a class of voting securities of the Company, purchased 9,025,270 shares of Class A common stock, prior to adjustment for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 11, “Stockholders’ and Mezzanine equity”, in the offering, for gross proceeds to the Company of $25.0 million, 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 Company entered into a letter agreement with JVL (the “JVL Letter Agreement”) in connection with the offering. The JVL Letter Agreement approved, pursuant to Section 203 of the Delaware General Corporation Law (“Section 203”), the purchase of shares 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 not affiliated 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 and restated, the “Restated Registration Rights Agreement”) to add JVL as a party in order to facilitate an orderly distribution of JVL’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 as described above under “Item 11. Stockholders’ and Mezzanine equity—Offering of 8.0% Series A Perpetual Convertible Preferred Stock,” affiliates of Metalmark, who then owned more than 5% of a class of voting securities of the Company and had two representatives on our Board of Directors, purchased 200,000 shares of Series A preferred stock in the offering, for gross 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 “Restated Agreement”) 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, dated July 29, 2013 (the “Original Agreement”), by and among the Company, Metalmark and the Jones Family Entities, to, among other things, provide JVL with certain rights, in addition to those rights granted to Metalmark and the Jones Family Entities in the 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 a majority in interest of the JVL holders who hold certain equity securities of the Company or securities convertible or exchangeable into equity securities of the Company. The Company is not obligated to affect any demand registration in which the anticipated aggregate offering price included in such offering is equal to or less than $50,000,000 ($25,000,000 where the registration is on a Form S-3). Furthermore, if, at any time, the Company proposes to register an offering of Class A common stock (subject to certain exceptions) for the Company’s own account, then it must give prompt notice to Metalmark, JVL and the Jones Family Entities to allow them to include a specified number of their shares in that registration statement. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of 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 all registration expenses in connection with the registration obligations, regardless of whether a registration statement is filed or becomes effective. The Restated Agreement also includes customary provisions dealing with indemnification, contribution and allocation 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, we record accruals for contingencies when it is probable that a liability will be incurred and the amount of loss can be reasonably estimated. While the outcome of lawsuits and other proceedings against us cannot be predicted with certainty, in the opinion of management, 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 st District Court of Hemphill County, Texas, Donna Kim Flowers and Mitchell Kirk Flowers v. Jones Energy, LLC f/k/a Jones Energy Limited, LLC f/k/a Jones Energy, Ltd. (Case No. 7225), the Company was sued by Donna Kim Flowers and Mitchell Kirk Flowers (the “plaintiffs”). The plaintiffs own surface rights to property located in Hemphill County, Texas. The mineral rights are leased to third parties, and the Company is the operator of the Oil and Gas Mineral Lease. On May 28, 2010, the plaintiffs and the Company entered into a Surface Use Agreement concerning the 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 $1.5 million related to its estimated obligation under this settlement offer. This accrual was included in accrued liabilities on the Company’s Consolidated Balance Sheet as of December 31, 2016, and the charge was recorded as general and administrative expense 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 cash during June 2017. Upon settlement, the Company recognized an additional charge of $1.4 million which was recorded as general and administrative expense on the Company’s Consolidated Statement of Operations during the three months ended June 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 the liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock, to be paid entirely in shares of Class A common stock (the “August Preferred Dividend”). The price per share of the Class A common stock used to determine the number of shares issued will equal to 95% of the average volume-weighted average price per share for each day during the 5-consecutive day trading period ending immediately prior to the payment date. The August Preferred Dividend will be paid on August 15, 2017 for the period beginning on the last payment date of May 15, 2017 through August 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 to customary 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 (together with a corresponding number of JEH Units) for shares of Class A common stock on a one-for-one basis (the “July Exchanges”). 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 shares of Class B common stock, after adjusting for the TRA liability reduction as a result of the increase in tax basis arising from such exchanges. After the July Exchanges, the gross TRA liability increased by approximately $18.7 million. The increase in TRA liability will be offset entirely as a result of the valuation allowance recorded against the deferred asset generated in the exchange 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 current subsidiaries (except Jones Energy Finance Corp. and two immaterial subsidiaries) and certain future subsidiaries, including any future subsidiaries that guarantee any indebtedness under the Revolver. Each subsidiary guarantor is 100% owned by JEH, and all guarantees are full and unconditional, subject to customary exceptions pursuant to the indentures governing our 2022 Notes and 2023 Notes, as discussed below, and joint and several with all other subsidiary guarantees and the parent guarantee. Any subsidiaries 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 Company and by all of its significant subsidiaries, other than Nosley SCOOP, LLC and Nosley Acquisition, LLC. These subsidiaries have since become guarantors during the first quarter of 2017 and are therefore presented accordingly in the accompanying condensed consolidated guarantor financial information.

Guarantees of the 2022 Notes and 2023 Notes will be released under certain circumstances, including (i) in connection with any sale or other disposition of (a) all or substantially all of the properties or assets of a guarantor (including by way of merger or consolidation) or (b) all of the capital stock of such guarantor, in each case, to a person that is not the Company or a restricted subsidiary of the Company, (ii) if the Company designates any restricted subsidiary that is a guarantor as an unrestricted subsidiary, (iii) upon legal defeasance, covenant defeasance or satisfaction and discharge of the applicable indenture, or (iv) at such time as such guarantor ceases to guarantee any other indebtedness of the Company or any other guarantor.

The Company is a holding company whose sole material asset is an equity interest in JEH. The Company is the sole managing member of JEH and is responsible for all operational, management and administrative decisions related to JEH’s business. In accordance with JEH’s limited liability company agreement, the Company may not be removed as the sole managing member of 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 interests in JEH, and the remaining 29,823,927 JEH Units are held by the Class B shareholders. The Class B shareholders have no voting 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 B common stock, and one series of preferred stock, Series A preferred stock. Pursuant to the Company’s certificate of incorporation, each share of Class A common stock is entitled to one vote per share, and the shares of Class A common stock are entitled to 100% of the economic interests in the Company. Each share of Class B common stock has no economic rights in the Company, but entitles its holder to one vote on all matters to be voted on by the Company’s stockholders generally. Except as required by law or the Company’s certificate of incorporation, which includes the certificate of designations for the Series A preferred stock, the holders of Series A preferred stock have no voting rights (other than with respect to certain matters regarding the Series A preferred stock or when dividends payable on the Series A preferred stock have not been paid for an aggregate of six quarterly dividend periods, or more, whether or not consecutive, as provided in the certificate of designations for the Series A preferred stock).

In connection with a reorganization that occurred immediately prior to the IPO, each Existing Owner was issued a number of shares of Class B common stock that was equal to the number of JEH Units that such Class B shareholders held. Holders of the Company’s Class A common stock and Class B common stock generally vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval. Accordingly, the Class B shareholders collectively have a number 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 and each of the Class B shareholders (the “Exchange Agreement”), to exchange their JEH Units (together with a corresponding number of shares of Class B common stock) 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 other similar transactions. As a result, the Company expects that over time the Company will have an increasing economic interest in JEH as Class B common stock and JEH Units are exchanged for Class A common stock. Moreover, any transfers of JEH Units outside of the Exchange Agreement (other than permitted transfers to affiliates) must be approved by the Company. The Company intends to retain full voting and management control over JEH.

During the preparation of the condensed consolidating financial information of Jones Energy, Inc. and Subsidiaries as of and for the three and six months period ended June 30, 2017, it was determined that the Issuer Investment in subsidiaries and the related Eliminations at December 31, 2016 as filed in the Company’s 2016 Form 10-K were improperly calculated and understated by $453.2 million. Additionally, it was determined that the Guarantor Subsidiaries Intercompany payable balances and the related Eliminations and the Issuer Intercompany receivable and the related Eliminations at December 31, 2016 as filed in 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 the three and six months period ended June 30, 2016 as filed in the Company’s second quarter 2016 Form 10-Q were improperly calculated and understated by $35.7 million and $5.8 million, respectively. Lastly, it was determined that the Issuer Adjustments to reconcile net income (loss) to net cash provided by operating activities and the related Eliminations for the six months period ended June 30, 2016 as filed in the Company’s second quarter 2016 Form 10-Q was improperly calculated and overstated 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 the Parent or the Guarantor Subsidiaries and are eliminated upon consolidation, and therefore have no impact on the Company’s consolidated financial condition, results of operations or cash flows.

The Company has revised the Condensed Consolidating Balance Sheets for the Issuer, Guarantor Subsidiaries and Eliminations as of December 31, 2016, the Condensed Consolidating Income Statements for the Issuer and Eliminations for the three and six months period ended June 30, 2016 and the Condensed Consolidating Statement of Cash Flows for the six months 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 the successful 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 at June 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 shares outstanding at June 30, 2017		67		—		—		—		—		67
Class B common stock, $0.001 par value; 29,823,927 shares issued and outstanding at June 30, 2017		30		—		—		—		—		30
Treasury stock, at cost: 22,602 shares at June 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 the successful 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 at December 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 57,025,474 shares outstanding at December 31, 2016		57		—		—		—		—		57
Class B common stock, $0.001 par value; 29,832,098 shares issued and outstanding at December 31, 2016		30		—		—		—		—		30
Treasury stock, at cost: 22,602 shares at December 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
Operating revenues
Oil and gas sales	$	—	$	—	$	48,114	$	—	$	—	$	48,114
Other revenues		—		485		27		—		—		512
Total operating revenues		—		485		48,141		—		—		48,626
Operating costs and expenses
Lease operating		—		—		9,425		—		—		9,425
Production and ad valorem taxes		—		—		2,790		—		—		2,790
Exploration		—		—		6,725		—		—		6,725
Depletion, depreciation and amortization		—		—		45,313		23		—		45,336
Impairment of oil and gas properties		—		—		161,886		—		—		161,886
Accretion of ARO liability		—		—		266		—		—		266
General and administrative		—		2,920		5,626		87		—		8,633
Total operating expenses		—		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) on commodity derivatives		—		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 in income (loss)		(121,557)		(56,107)		—		—		177,664		—
Income tax provision (benefit)		(2,405)		(14)		—		—		—		(2,419)
Net income (loss)		(89,239)		(49,966)		(183,681)		(110)		177,664		(145,332)
Net income (loss) attributable to non-controlling interests		—		—		—		—		(56,093)		(56,093)
Net income (loss) attributable to controlling interests	$	(89,239)	$	(49,966)	$	(183,681)	$	(110)	$	233,757	$	(89,239)
Dividends and accretion on preferred stock		(1,966)		—		—		—		—		(1,966)
Net income (loss) attributable to common shareholders	$	(91,205)	$	(49,966)	$	(183,681)	$	(110)	$	233,757	$	(91,205)

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

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 operating revenues		—		942		88,917		—		—		89,859
Operating costs and expenses
Lease operating		—		—		18,231		—		—		18,231
Production and ad valorem taxes		—		—		1,884		—		—		1,884
Exploration		—		—		9,669		—		—		9,669
Depletion, depreciation and amortization		—		—		80,945		45		—		80,990
Impairment of oil and gas properties		—		—		161,886		—		—		161,886
Accretion of ARO liability		—		—		467		—		—		467
General and administrative		—		5,913		10,630		131		—		16,674
Total operating expenses		—		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) on commodity derivatives		—		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) before income tax		30,581		13,073		(194,723)		(176)		—		(151,245)
Equity interest in income (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 to controlling interests	$	(90,626)	$	(45,148)	$	(194,723)	$	(176)	$	240,047	$	(90,626)
Dividends and accretion on preferred stock		(3,993)		—		—		—		—		(3,993)
Net income (loss) attributable to common shareholders	$	(94,619)	$	(45,148)	$	(194,723)	$	(176)	$	240,047	$	(94,619)

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

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 operating revenues		—		596		28,548		—		—		29,144
Operating costs and expenses
Lease operating		—		—		7,545		—		—		7,545
Production and ad valorem taxes		—		—		1,727		—		—		1,727
Exploration		—		—		77		—		—		77
Depletion, depreciation and amortization		—		—		38,118		19		—		38,137
Accretion of ARO liability		—		—		297		—		—		297
General and administrative		—		3,293		4,806		27		—		8,126
Total operating expenses		—		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 debt extinguishment		—		8,878		—		—		—		8,878
Net gain (loss) on commodity derivatives		—		(40,002)		—		—		—		(40,002)
Other income (expense)		(267)		(73)		2		—		—		(338)
Other income (expense), net		(267)		(43,924)		(78)		—		—		(44,269)
Income (loss) before income tax		(267)		(46,621)		(24,100)		(46)		—		(71,034)
Equity interest in income (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 to controlling interests	$	(23,245)	$	(82,022)	$	(24,100)	$	(46)	$	106,168	$	(23,245)

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Six 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	$	—	$	—	$	53,478	$	—	$	—	$	53,478
Other revenues		—		1,241		283		—		—		1,524
Total operating revenues		—		1,241		53,761		—		—		55,002
Operating costs and expenses
Lease operating		—		—		16,162		—		—		16,162
Production and ad valorem taxes		—		—		3,328		—		—		3,328
Exploration		—		—		239		—		—		239
Depletion, depreciation and amortization		—		—		79,857		42		—		79,899
Accretion of ARO liability		—		—		590		—		—		590
General and administrative		—		6,171		9,407		52		—		15,630
Total operating expenses		—		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 debt extinguishment		—		99,530		—		—		—		99,530
Net gain (loss) on commodity derivatives		—		(22,783)		—		—		—		(22,783)
Other income (expense)		162		(274)		(1)		—		—		(113)
Other income (expense), net		162		48,707		160		—		—		49,029
Income (loss) before income tax		162		43,777		(55,662)		(94)		—		(11,817)
Equity interest in income (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 to controlling 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

Six Months Ended June 30, 2017


					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 by operations		(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 of properties acquired		—		—		2,391		—		—		2,391
Proceeds from sales of assets		—		—		2,730		—		—		2,730
Acquisition of other property, plant and equipment		—		—		(436)		—		—		(436)
Current period settlements of matured derivative contracts		—		45,738		—		—		—		45,738
Net cash (used in) / provided by investing		—		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 preferred stock		(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 by financing		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

Six Months Ended June 30, 2016


					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 by operations		(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 and equipment		—		—		12		—		—		12
Current period settlements of matured derivative contracts		—		77,622		—		—		—		77,622
Net cash (used in) / provided by investing		—		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 by financing		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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016, filed on March 10, 2017 with the Securities and Exchange Commission, and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report and in our quarterly report for the quarter ended March 31, 2017, filed on May 5, 2017 with the Securities and Exchange Commission. Unless indicated otherwise in this Quarterly Report or the context requires otherwise, all references to “Jones Energy,” the “Company,” “our company,” “we,” “our” and “us” refer to Jones Energy, Inc. and its subsidiaries, including Jones Energy Holdings, LLC (“JEH”). Jones Energy, Inc. (“JONE”) is a holding company whose sole material asset is an equity interest in JEH.

Overview

We are an independent oil and gas company engaged in the exploration, development, production and acquisition of oil and natural gas 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 to the 1920’s. We have grown rapidly by leveraging our focus on low cost drilling and completion methods and our horizontal drilling expertise to develop our inventory and execute several strategic acquisitions. We have accumulated extensive knowledge and experience in developing the Anadarko basin, having concentrated our operations in the Anadarko basin for over 25 years. We have drilled over 880 total wells as operator, including approximately 705 horizontal wells, since our formation and delivered compelling rates of return over various commodity price cycles. Our operations are focused on horizontal drilling and completions within two distinct 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 the STACK/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 are recognized as one of the lowest cost drilling and completion operators in the Cleveland shale formation. We believe that our low-cost drilling expertise will apply directly to our new drilling in the Merge area, which is located approximately 150 miles to the east of our Cleveland 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 of Arkoma 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 frac designs 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-controlling interests		(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 common shareholders	$	(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 consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

We define EBITDAX as earnings before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, gains and losses from derivatives less the current period settlements of matured derivative contracts and the other items described 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 performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX has limitations as an analytical tool and should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historical costs of depreciable assets. Our presentation of EBITDAX should not be construed as an inference that our results will be unaffected by unusual or nonrecurring items. 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 the periods indicated:


	Three Months Ended June 30,				Six 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 management and external users of the Company’s consolidated financial statements. We define Adjusted Net Income as net income excluding the impact of certain non-cash items including gains or losses on commodity derivative instruments not yet settled, impairment of oil and gas properties, non-cash compensation expense, and the other items described below. We define Adjusted Earnings per Share as earnings per share plus that portion of the components of adjusted net income allocated to the controlling interests divided by weighted average shares outstanding. We believe adjusted net income and adjusted earnings per share are useful to investors because they provide readers with a more meaningful measure of our profitability before recording certain items for which the timing or amount cannot be reasonably determined. However, these measures are provided in addition to, not as an alternative for, and should be 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 other companies.

The following tables provide a reconciliation of net income (loss) as determined in accordance with GAAP to adjusted net income for the periods indicated:


	Three Months Ended June 30,						Six 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 tax rate to each adjustment and then allocating the tax impact between the controlling and non-controlling interests.

(2)

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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

Oil and gas sales. Oil and gas sales increased $ 19.7 million, or 69.4%, to $48.1 million for the three months ended June 30, 2017, as compared to $28.4 million for the three months ended June 30, 2016. The increase was attributable to the increase in production volumes ($10.9 million) and the increase in commodity prices ($8.8 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 of commodity derivative instruments, increased from $40.68 per Bbl for the three months ended June 30, 2016 to $44.40 per Bbl for the three months ended June 30, 2017, or 9.1%. The average realized natural gas price, excluding the effects of commodity derivative instruments, increased from $1.11 per Mcf for the three months ended June 30, 2016 to $2.19 per Mcf for the three months ended June 30, 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 to 18,604 Boe per day for the three months ended June 30, 2016.

Costs and expenses

Lease operating. 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 primarily attributable to the increase in number of producing wells. On a per unit basis, lease operating expenses decreased $0.11 per Boe, or 2.5%, 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.

Production and ad valorem taxes. Production and ad valorem taxes increased by $1.1 million, or 64.7%, to $2.8 million for the three months ended June 30, 2017, as compared to $1.7 million for the three months ended June 30, 2016. Production taxes increased $0.9 million, from $1.4 million for the three months ended June 30, 2016 to $2.3 million for the three months ended June 30, 2017. The increase was attributable to the increase in production volumes. Production tax rates vary between states, products, and production levels; 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 the three months ended June 30, 2017. The average effective rate excluding the impact of ad valorem taxes remained constant at 4.8% for the 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 three months ended June 30, 2017. The Company recognized charges for lease abandonment of $5.2 million relating to certain leases that the Company decided during the second quarter of 2017 not to develop. Spending during 2017 primarily related to geological data and seismic processing associated with unproved acreage. No exploratory wells resulted in exploration expense during the second quarter of either year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $7.2 million, or 18.9%, to $45.3 million for the three months ended June 30, 2017, as compared to $38.1 million for the three months ended June 30, 2016. The increase 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 three months ended June 30, 2017. The decrease was primarily the result of lower production and capital spending throughout 2016, driven by a temporary suspension of the drilling program late in 2015 and continuing into early 2016.

Impairment of oil and gas properties. As of June 30, 2017, the Company’s Arkoma Basin oil and gas property assets and related liabilities were classified as held for sale due to the pending Arkoma Divestiture. Based on the Company’s anticipated sales price, an impairment charge of $161.9 million was recognized at June 30, 2017 due to the loss on disposal. No impairment charges were recognized during the three months ended June 30, 2016.

General and administrative. General and administrative expenses increased by $0.5 million, or 6.2%, to $8.6 million for the three months ended June 30, 2017, as compared to $8.1 million for the three months ended June 30, 2016. The increase was driven by a litigation 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 $0.2 million, 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 a per unit basis, general and administrative expenses, excluding all non-cash items, decreased from $2.63 per Boe for the three months ended June 30, 2016 to $2.57 per Boe for the three months ended June 30, 2017.

Interest expense. Interest expense decreased by $0.1 million, or 0.8%, to $12.7 million for three months ended June 30, 2017, as compared to $12.8 million for the three months ended June 30, 2016. The decrease was driven by a reduction in the outstanding balance 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 million and $150.0 million under the Revolver, the 2022 Notes and the 2023 Notes, respectively.

Net gain (loss) on commodity derivatives. The net gain (loss) on commodity derivatives was a net gain of $21.5 million for the three months ended June 30, 2017, as compared to a net loss of $40.0 million for the three months ended June 30, 2016. The gain was primarily driven by lower average crude oil and natural gas prices ($48.10 per barrel and $3.08 per Mcf, respectively) for the three months 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 of approximately $8.1 million for the three months ended June 30, 2017. See Note 6, “Derivative Instruments and Hedging Activities,” for further details.

Other income (expense). Other income (expense) for the three months ended June 30, 2017 was a net income of $29.8 million, as compared to a net expense of $0.3 million for the three months ended June 30, 2016. Other income (expense) during the six months ended June 30, 2017 primarily related to an increase in the TRA valuation allowance which resulted in income of $29.9 million.

Income taxes. The provision for federal and state income taxes for the three months ended June 30, 2017 was a benefit of $2.4 million resulting 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 $12.4 million 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 conduct business and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest. The effective tax rate reduction 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.

Results of Operations - Six months ended June 30, 2017 as compared to the six months ended June 30, 2016

Operating revenues

Oil and gas sales. Oil and gas sales increased $35.3 million, or 66.0%, to $88.8 million for the six months ended June 30, 2017, as compared 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 of commodity derivative instruments, increased from $33.63 per Bbl for the six months ended June 30, 2016 to $45.69 per Bbl for the six months ended June 30, 2017, or 35.9%. The average realized natural gas price, excluding the effects of commodity derivative instruments, 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, increased from $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 Boe per day for the six months ended June 30, 2016.

Costs and expenses

Lease operating. 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 primarily attributable 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 in the six months ended June 30, 2017.

Production and ad valorem taxes. Production and ad valorem taxes decreased by $1.4 million, or 42.4%, to $1.9 million for the six months ended June 30, 2017, as compared to $3.3 million for the six months ended June 30, 2016. During the first quarter of 2017, the Company's application for High-Cost Gas Incentive refunds in Texas was approved for qualified wells on which taxes were initially paid between October 2012 and September 2016. The Company received a net production tax refund of $3.3 million during the six months ended June 30, 2017, which was recorded as a reduction in Production and ad valorem taxes on the Company’s Consolidated Statement of Operations. Production taxes, excluding the impact of this refund, increased from $2.5 million for the six months ended June 30, 2016 to $4.1 million for the six months ended June 30, 2017. The increase was attributable to the increase in production volumes. Production tax rates vary between states, products, and production levels; 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 $0.3 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 rate excluding the impact of ad valorem taxes decreased from 4.8% for the six months ended June 30, 2016 to 1.0% for the six months ended 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 six months ended June 30, 2017. The Company recognized charges for lease abandonment of $6.9 million relating to certain leases that the Company decided during 2017 not to develop. Spending during 2017 primarily related to geological data and seismic processing associated with unproved acreage. No exploratory wells resulted in exploration expense during the six months ended June 30 of either year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $1.1 million, or 1.4%, to $81.0 million for the six months ended June 30, 2017, as compared to $79.9 million for the six months ended June 30, 2016. The increase was primarily the result of capital spending related to our drilling program. On a per unit basis, depletion expense decreased $1.58 per Boe 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 ended June 30, 2017. The decrease was primarily the result of lower production and capital spending throughout 2016, driven by a temporary suspension of the drilling program late in 2015 and continuing into early 2016.

General and administrative. General and administrative expenses increased by $1.1 million, or 7.1%, to $16.7 million for the six months ended June 30, 2017, as compared to $15.6 million for the six months ended June 30, 2016. The increase was driven by a litigation 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 months ended 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 six months ended June 30, 2017.

Interest expense. Interest expense decreased by $2.0 million, or 7.2%, to $25.6 million for six months ended June 30, 2017, as compared to $27.6 million for the six months ended June 30, 2016. The decrease was driven by a reduction in the outstanding balance of 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% and 9.25%, 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.

Net gain (loss) on commodity derivatives. The net gain (loss) on commodity derivatives was a net gain of $43.8 million for the six months ended June 30, 2017, as compared to a net loss of $22.8 million for the six months ended June 30, 2016. The gain was primarily driven by lower average crude oil and natural gas prices ($49.85 per barrel and $3.05 per Mcf, respectively) for the six months 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. See Note 6, “Derivative Instruments and Hedging Activities,” for further details.

Other income (expense). Other income (expense) for the six months ended June 30, 2017 was a net income of $30.4 million, as compared to a net expense of $0.1 million for the six months ended June 30, 2016. Other income (expense) during the six months ended June 30, 2017 primarily related to an increase in the TRA valuation allowance which resulted in income of $30.6 million.

Income taxes. The provision for federal and state income taxes for the six months ended June 30, 2017 was a benefit of $2.4 million resulting 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 $1.7 million 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. 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 conduct business and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest. The effective tax rate reduction 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 credit facilities and cash flows from operations. Our primary use of capital has been for the exploration, development and acquisition of oil and gas properties. As we pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. 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 the profitability, timing and concentration of the development of our non-proved locations, we may be required to generate or raise significant amounts of capital to develop all of our potential drilling locations should we endeavor to do so. In the event our profitability or cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending. Our balance sheet at June 30, 2017 reflects a negative working capital balance. We have historically and in the future expect to maintain a negative working capital balance, and we use our Revolver to 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, 2017 was $425.0 million of which $181.0 million was utilized leaving an unused capacity of $244.0 million. On August 1, 2017, upon closing 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 on reserve 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 repay the 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 other activity or operation other than, among other exceptions described therein, its ownership of equity interests in JEH and the activities of a passive holding company and assets and operations incidental thereto (including the maintenance of cash and reserves for the payment of operational costs and expenses).

Jones Energy, Inc. and its consolidated subsidiaries are also subject to certain covenants under the Revolver, including the requirement 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 any fiscal 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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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 years 2018 and 2019. The gains were effectively realized by purchasing, as opposed to selling, oil and natural gas swap contracts for the equal volume that was associated with the initial hedge transaction. During the three and six months ended June 30, 2017, the Company 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’s Consolidated Statement of Operations. The estimated mark-to-market value of the Company’s remaining realized gains as a result of these offsetting hedges were approximately $15.1 million relating to the year ended December 31, 2018, incorporating NYMEX strip pricing 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 gas prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses of liquidity and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We continuously 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, contractual obligations, 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 million during the six months ended June 30, 2016. The increase in operating cash flows was primarily due to the $35.3 million increase in oil and gas revenues for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016, primarily driven by the increase 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 provided by investing activities of $50.0 million during the six months ended June 30, 2016. The decrease in investing cash flow was primarily driven by increased capital spending, following the temporary suspension of the drilling program late in 2015 and continuing into early 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 in financing activities of $18.6 million during the six months ended June 30, 2016. The increase in financing cash flows was primarily due 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 to purchase 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 the six months ended June 30, 2016 to $0.6 million during the six months ended June 30, 2017. Additionally, there was an increase in proceeds 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 $8.4 million during the six months ended June 30, 2017. These increases in cash flow were partially offset by the payment of dividends on Series 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 its unitholders (including us) based on income allocated to its unitholders through the end of each relevant quarter, as adjusted to take into account good faith projections by the Company of taxable income or loss for the remainder of the calendar year, to the extent JEH has cash available for such distributions and subject to certain other restrictions. This tax distribution is computed based on the estimate of net taxable income of JEH allocated to each holder of JEH Units multiplied by the highest marginal effective rate of federal, state and local income tax applicable to an individual resident in New York, New York, without regard for the federal benefit of 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 of JEH’s 2016 taxable income (all of which is passed-through and taxed to us and JEH’s other unitholders), during the first quarter of 2017, we made further income tax payments to federal and state taxing authorities of $4.1 million and JEH made further tax distributions 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 or that JEH will make any additional tax distributions during the remainder of 2017. Estimating the tax distributions required under the operating 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 year ended 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-K for 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 risk contained in our Annual Report on Form 10-K for the year ended December 31, 2016, as well as with the unaudited consolidated financial 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. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes. 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 have continued into 2017 and historically low commodity prices may exist for an extended period. Taking into consideration the business environment in which we operate, we continually review our held for use oil and gas properties for indicators of potential impairment on an undiscounted basis. While no such indicators were present at June 30, 2017, assets held for sale related to the Arkoma Divestiture 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 to be highly volatile. The recent volatility in crude oil and natural gas prices increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. Although we are unable to predict future commodity prices, a prolonged period of depressed commodity prices may have a significant impact on the volumetric quantities of our proved reserves. The impact of commodity prices on our estimated proved reserves can be illustrated as follows: if the prices used for our December 31, 2016 Reserve Report had been replaced with the unweighted arithmetic average of the first-day-of-the-month prices for the applicable commodity for the trailing twelve-month period ended June 30, 2017 (without regard to our commodity derivative positions and without assuming any change in development plans, costs, or other variables), then estimated proved reserves volumes as of December 31, 2016 would have increased by approximately 3.1%. The use of this pricing example is for illustration purposes only, and does not indicate management’s view on future commodity prices, costs or other variables, or represent a forecast or estimate of the actual amount by which our proved reserves 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 terminations of 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, some factors, such as oil and natural gas prices, have historically been highly volatile and may be highly volatile in the future. This high degree of volatility causes a high degree of uncertainty associated with the estimation of reserve quantities and estimated future cash flows. Therefore, future results are highly uncertain and subject to potentially significant revisions. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future 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 of assets that may be material. Any future impairments are difficult to predict, and although it is not reasonably practicable to quantify the 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 are subject to change due to fluctuations in such prices. Realized prices are primarily driven by the prevailing prices for oil and regional spot 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 management policy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. The fair 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 of our counterparties, but do not require them to post collateral. The majority of our derivative contracts currently in place are with lenders 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 senior secured revolving credit facility provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 0.50% to 2.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. The base rate margins under the terminated term loan were 6.0% to 7.0% depending on the base rate used and the amount 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 a weighted average rate of 2.84%, 6.75% and 9.25%, respectively. 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% 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 materially affected, 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 our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our principal executive officer and principal financial officer concluded that as of June 30, 2017, the end of the period covered by this report, our disclosure controls and procedures 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 with the SEC to include a management report on such company’s internal control over financial reporting in its annual report. Pursuant to the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we are no longer an “emerging growth company” as defined in the JOBS Act. Our Annual Report on Form 10-K for the year ended December 31, 2016 included a report of management’s assessment regarding internal control over financial reporting.

Table of Contents

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 Financial Statements for further discussion appearing in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated in this item by 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 our Annual Report on Form 10-K for the year ended December 31, 2016, could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also 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 on Form 10-K for the year ended December 31, 2016. There have been no material changes in our risk factors from those described in our 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.		Description
2.1*		Purchase and Sale Agreement, dated June 22, 2017, between Jones Energy Holdings, LLC and the purchaser party thereto.
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 on Form 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

Table of Contents

SIGNATURE S

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


	Jones Energy, Inc.

	(registrant)


Date: August 7, 2017	By:	/s/ Robert J. Brooks
	Name: Robert J. Brooks
	Title: Chief Financial Officer (Principal Financial Officer)

Signature Page to Form 10-Q (Q2 2017)

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


		Page
ARTICLE 1 PURCHASE AND SALE		1
Section 1.1	Purchase and Sale.	1
Section 1.2	Assets.	1
Section 1.3	Excluded Assets.	3
Section 1.4	Effective Time; Proration of Costs and Revenues.	5
Section 1.5	Delivery and Maintenance of Records and Retained Records.	6
ARTICLE 2 PURCHASE PRICE		7
Section 2.1	Purchase Price.	7
Section 2.2	Adjustments to Purchase Price.	7
Section 2.3	Allocation of Purchase Price.	9
Section 2.4	Deposit.	9
ARTICLE 3 TITLE MATTERS		10
Section 3.1	Seller’s Title.	10
Section 3.2	Certain Definitions.	10
Section 3.3	Definition of Permitted Encumbrances.	12
Section 3.4	Notice of Title Defects Defect Adjustments.	14
Section 3.5	Consents to Assignment and Preferential Rights to Purchase.	18
Section 3.6	Casualty or Condemnation Loss.	20
Section 3.7	Limitations on Applicability.	21
ARTICLE 4 ENVIRONMENTAL MATTERS		21
Section 4.1	Assessment.	21
Section 4.2	NORM.	22
Section 4.3	Notice of Violations of Environmental Laws.	22
Section 4.4	Remedies for Violations of Environmental Laws.	23
Section 4.5	Limitations.	25
ARTICLE 5 REPRESENTATIONS AND WARRANTIES OF SELLER		25
Section 5.1	Disclaimers.	25
Section 5.2	Existence and Qualification.	27
Section 5.3	Power.	28
Section 5.4	Authorization and Enforceability.	28
Section 5.5	No Conflicts.	28
Section 5.6	Liability for Brokers’ Fees.	28
Section 5.7	Litigation.	28
Section 5.8	Taxes and Assessments.	29
Section 5.9	Outstanding Capital Commitments.	29
Section 5.10	Compliance with Laws.	29
Section 5.11	Contracts.	29
Section 5.12	Payments for Production.	30
Section 5.13	Governmental Authorizations.	30

-i-

Table of Contents

(continued)


		Page
Section 5.14	Consents and Preferential Purchase Rights.	30
Section 5.15	Environmental Laws.	30
Section 5.16	Bankruptcy.	31
Section 5.17	Imbalances.	31
Section 5.18	Oil and Gas Operations.	31
Section 5.19	Non-Consent Operations.	31
Section 5.20	Sufficiency of Assets.	31
ARTICLE 6 REPRESENTATIONS AND WARRANTIES OF PURCHASER		31
Section 6.1	Existence and Qualification.	31
Section 6.2	Power.	32
Section 6.3	Authorization and Enforceability.	32
Section 6.4	No Conflicts.	32
Section 6.5	Liability for Brokers’ Fees.	32
Section 6.6	Litigation.	32
Section 6.7	Financing.	33
Section 6.8	Independent Investigation.	33
Section 6.9	Bankruptcy.	34
Section 6.10	Qualification.	34
Section 6.11	Consents.	34
ARTICLE 7 COVENANTS OF THE PARTIES		34
Section 7.1	Access.	34
Section 7.2	Government Reviews.	35
Section 7.3	Notification of Breaches.	35
Section 7.4	Operatorship.	35
Section 7.5	Operation of Business.	36
Section 7.6	Indemnity Regarding Access.	37
Section 7.7	Other Preferential Rights.	37
Section 7.8	Tax Matters.	38
Section 7.9	Special Warranty of Title.	40
Section 7.10	Suspended Proceeds.	41
Section 7.11	Further Assurances.	41
Section 7.12	Contingent Payment.	41
ARTICLE 8 CONDITIONS TO CLOSING		43
Section 8.1	Conditions of Seller to Closing.	43
Section 8.2	Conditions of Purchaser to Closing.	44
ARTICLE 9 CLOSING		45
Section 9.1	Time and Place of Closing.	45
Section 9.2	Obligations of Seller at Closing.	45
Section 9.3	Obligations of Purchaser at Closing.	46

-ii-

Table of Contents

(continued)


		Page
Section 9.4	Closing Payment and Post-Closing Purchase Price Adjustments.	46
ARTICLE 10 TERMINATION		48
Section 10.1	Termination.	48
Section 10.2	Effect of Termination.	48
Section 10.3	Distribution of Deposit Upon Termination.	48
ARTICLE 11 POST-CLOSING OBLIGATIONS; INDEMNIFICATION; LIMITATIONS; DISCLAIMERS AND WAIVERS		50
Section 11.1	Receipts.	50
Section 11.2	Assumption and Indemnification.	50
Section 11.3	Indemnification Actions.	53
Section 11.4	Limitation on Actions.	54
Section 11.5	Recording.	56
Section 11.6	Waivers.	56
Section 11.7	Insurance.	56
Section 11.8	Tax Treatment of Indemnification Payments.	57
ARTICLE 12 MISCELLANEOUS		57
Section 12.1	Counterparts.	57
Section 12.2	Notice.	57
Section 12.3	Sales or Use Tax, Recording Fees, and Similar Taxes and Fees.	58
Section 12.4	Expenses.	58
Section 12.5	Change of Name.	59
Section 12.6	Replacement of Bonds and Guarantees.	59
Section 12.7	Governing Law and Venue.	60
Section 12.8	Jurisdiction; Waiver of Jury Trial.	60
Section 12.9	Captions.	60
Section 12.10	Waivers.	60
Section 12.11	Assignment.	61
Section 12.12	Entire Agreement.	61
Section 12.13	Amendment.	61
Section 12.14	No Third-Party Beneficiaries.	61
Section 12.15	Public Announcements.	61
Section 12.16	Invalid Provisions.	62
Section 12.17	References.	62
Section 12.18	Construction.	62
Section 12.19	Limitation on Damages.	62
ARTICLE 13 DEFINITIONS		63

-iii-

EXHIBITS AND SCHEDULES


Exhibit A	Leases
Exhibit A-1	Properties
Exhibit A-2	Excluded Equipment
Exhibit B	Conveyance
Exhibit C	Persons with Knowledge

Schedule 1.2(d)	Contracts
Schedule 1.2(e)	Surface Contracts
Schedule 1.3(h)	Excluded Permits
Schedule 2.3	Allocated Value
Schedule 3.3(n)	Other Permitted Encumbrances
Schedule 5.7	Litigation
Schedule 5.8	Taxes and Assessments
Schedule 5.9	Outstanding Capital Commitments
Schedule 5.10	Compliance With Laws
Schedule 5.11(a)	Defaults
Schedule 5.11(b)	Certain Contracts
Schedule 5.12	Payments For Production
Schedule 5.13	Governmental Authorizations
Schedule 5.14	Preferential Rights & Consents to Assign
Schedule 5.15	Environmental Laws
Schedule 5.17	Imbalances
Schedule 7.5	Operation of Business
Schedule 9.4(c)	Seller’s Wiring Instructions
Schedule 12.6(a)	Governmental Bonds
Schedule 12.6(b)	Guarantees

-iv-

PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (the “ Agreement ”), is executed on June 22, 2017, by and between Jones Energy Holdings, LLC, a Delaware limited liability company ( “ Seller ”) and Foundation Energy Fund VI-A, LP, a Delaware limited partnership (“ Purchaser ”). Seller and Purchaser may each be 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 the Assets, 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 other valuable 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 agrees to sell and convey to Purchaser and Purchaser agrees to purchase, accept and pay for the Assets and assume the Assumed Obligations. Capitalized terms used herein shall have the respective meanings ascribed 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 or immovable, 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 other leaseholds, carried interests, mineral fee interests, overriding royalty interests, reversionary rights, farmout rights, options, and other properties and interests described on Exhibit A, subject to such depth limitations and other restrictions and limitations as may be set forth on Exhibit A or in the instruments that constitute (or are assignments or conveyances in the chain of title to) the foregoing properties and interests (collectively, the “ Leases ”), together with, subject to such limitations and restrictions, each and every kind and character of right, title, claim, and interest that 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 the wells 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 any Leases or any Wells, including those pools or units referred to on Exhibit A-1 (the “ Units ”, such Units together with the Leases, Lands and Wells, or in cases when there is no Unit, the Leases together 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 Hydrocarbon production from any such Unit, whether such Unit Hydrocarbon production comes from Wells located on or off of a Lease, and all tenements, hereditaments and appurtenances belonging to the Leases and Units;

(d) All contracts, agreements and instruments by which the Properties are bound, or that relate to or are otherwise applicable to the Properties, but in each case only to the extent applicable to the Properties and not other properties of Seller not included in the Assets, including operating agreements, unitization, pooling and communitization agreements, declarations and orders, joint venture agreements, farmin and farmout agreements, water rights agreements, exploration agreements, area of mutual interest agreements, participation agreements, exchange agreements, transportation or gathering agreements, agreements for the sale and purchase of Hydrocarbons and processing agreements, and further including those agreements and instruments identified on Schedule 1.2(d) (hereinafter collectively referred to as the “ Contracts ”), provided that “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 or third-party agreement and the necessary consents to transfer are not obtained pursuant to Section 3.5, or (B) subject to payment of a fee or other consideration under any license agreement or other agreement with a Person other than an Affiliate of Seller, and for which no consent to transfer has been received or for which Purchaser has not agreed in writing to pay the fee or other consideration, as applicable and (iii) the instruments constituting the Leases, Surface Contracts and the assignments or conveyances in Seller’s chain of title to the Leases;

(e) All easements, permits, licenses, servitudes, rights-of-way, surface leases and other surface rights appurtenant to, and used or held for use primarily in connection with, the Properties, including those identified on Schedule 1.2(e) (hereinafter collectively referred to as the “ Surface Contracts ”), provided that “Surface Contracts” shall exclude any permits and other appurtenances to the extent transfer is (i) restricted by their respective terms or third-party agreement 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 other agreement with a Person other than an Affiliate of Seller, and for which no consent to transfer has been received or for which Purchaser has not agreed in writing to pay the fee or other consideration, as applicable;

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

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, but excluding 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 after the Effective Time and all inventories of Hydrocarbons produced from or attributable to the Properties 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, land files, 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 the Assets, 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 extent disclosure or transfer is restricted by third-party agreement or applicable Law and the necessary consents to transfer are not obtained pursuant to Section 3.5, or subjected to payment of a fee or other consideration by any license agreement or other agreement with a Person other than an Affiliate of Seller, or by applicable Law, and for which no consent to transfer has been received or for which Purchaser has not agreed in writing to pay the fee or other consideration, as applicable; (ii) computer software; (iii) all legal records and legal files of Seller, work product of Seller’s legal counsel and records protected by attorney-client privilege, but excluding in each case 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 and excluded from the purchase and sale contemplated hereby (collectively, the “ Excluded Assets ”):

(a) (i) All corporate, partnership, limited liability company, financial, tax and legal records 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 by Seller pursuant to Section 1.2(i), and (iv) copies of any other records retained by Seller pursuant to Section 1.5;

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

(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 predecessors in interest and title attributable to periods prior to the Effective Time;

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

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

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

(h) Seller’s area-wide bonds, permits and licenses or other permits, licenses or authorizations 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 amounts receivable, and other receivables attributable to the Assets (excluding Hydrocarbon inventories subject 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 with GAAP;

(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 temporarily located on the Properties and not presently required for the operation of the Properties as currently operated;

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

(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 to Sections 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 the Closing, but certain financial benefits and obligations of the Assets shall be transferred effective as 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 made under Section 2.2, (i) Purchaser shall be entitled to all production from or attributable to the Properties at and after the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to the Assets at or after the Effective Time, and (ii) Seller shall be entitled to all production from or attributable to the Properties prior to the Effective Time (and all products and proceeds attributable thereto), and to all other income, proceeds, receipts and credits earned with respect to the Assets prior to the Effective Time. The terms “earned” and “incurred”, as used in this Agreement, shall be interpreted in accordance with GAAP and Council of Petroleum Accountants Society (“ COPAS ”) standards, as implemented by Seller in the ordinary course of business consistent with past practice. 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, said production passes through connecting pipelines/flowlines to storage facilities, whether or not owned 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 pipelines through which they are transported from such lands and (ii) gaseous Hydrocarbons shall be deemed to be “from or attributable to” the Leases, Units and Wells when they pass through the delivery point sales meters or similar meters at the entry point into the pipelines through which they are transported from such lands. Seller shall utilize reasonable interpolative procedures to arrive at an allocation of production when exact meter readings or gauging and strapping data is not available.

(c) As used herein, “ Property Costs ” means (i) all costs attributable to the ownership, 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 or additions to Tax imposed by a Governmental Body in connection

with such Taxes) based upon or measured by the ownership or operation of the Assets or the production of Hydrocarbons therefrom, but excluding any other Taxes, (ii) capital expenditures incurred in the ownership, development, operation and maintenance of the Assets in the ordinary course of business, (iii) where applicable, such costs and capital expenditures charged in accordance 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 the same basis as charged on the date of this Agreement, and (iv) overhead costs charged to the Assets 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 this Agreement; provided that “Property Costs” shall exclude, without limitation, liabilities, losses, costs, and expenses attributable to (A) claims, investigations, administrative proceedings or litigation directly or indirectly arising out of or resulting from actual or claimed personal injury or death, property damage or violation of any Law (including private rights or causes of action under 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 around such wells, facilities and pits, (D) obligations to cure, address or remediate any contamination of groundwater, 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 or transportation contracts, (F) gas balancing obligations and similar obligations arising from Imbalances and (G) obligations to pay working interests, royalties, overriding royalties or other interests held in suspense, all of which are addressed in Section 11.2 or elsewhere in this Agreement. Subject to the other provisions herein, Seller shall bear and be responsible for all Property Costs incurred or arising prior to the Effective Time and Purchaser shall bear and be responsible for all Property Costs incurred or arising at and after the Effective Time. For the purposes of calculating the adjustments to the Purchase Price under Section 2.2 or implementing the terms of Section 7.8 or Article 11, (1) right-of-way fees, insurance premiums and Property Costs (excluding Taxes which are addressed in clauses (2), (3), and (4) of this sentence) delay rentals, lease bonuses, minimum royalties, option payments, lease extension payments and shut-in royalties) that are paid periodically shall be prorated based on the number of days in the applicable 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 of production of Hydrocarbons shall be apportioned between Seller and Purchaser based on the number of units or value of production actually produced, as applicable, before, and after, the Effective Time, (3) other ad valorem, property, severance, production or similar Taxes shall be prorated based on the number of days in the applicable period falling before, or at and after, the Effective Time, and (4) all other Taxes shall be apportioned based on an interim closing of the books 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 in Seller’s possession or control (FOB Seller’s office), to Purchaser within thirty (30) days following Closing. Seller may retain original Records and/or copies of any Records.

(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 and representatives with access to the Records during normal business hours for review and copying at Seller’s expense and (iii) provide Seller, its Affiliates, and its and their officers, employees and legal counsel with access, during normal business hours, to materials received or produced after Closing relating to any claim for indemnification made under Section 11.2 of this Agreement (excluding, however, attorney work product and attorney-client communications protected by privilege and prepared with respect to any such claim being brought by Purchaser and information subject to an applicable confidentiality restriction in favor of third parties) for review and 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 being determined in accordance with GAAP and COPAS standards (with such adjustments being made so as to not give duplicative effect):

(a) Reduced by the aggregate amount of the following proceeds received and retained by Seller between the Effective Time and the Closing Date (with the period between the Effective Time and the Closing Date referred to as the “ Adjustment Period ”): proceeds from the sale of Hydrocarbons (net of any royalties, overriding royalties or other burdens on or payable out of production, 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 or attributable to the Properties during the Adjustment Period;

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

(c) Reduced in accordance with Section 7.7 by an amount equal to the Allocated Value of those Properties that are subject to a suit, action or proceeding prior to Closing seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated hereby 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 a result of Title Defects for which the Title Defect Amount has been finally determined

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

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

(f) Reduced by (i) subject to Section 4.4, any amount agreed upon by Purchaser and Seller pursuant to Section 4.4(a) regarding the reasonable estimate of the cost of curing Environmental Liabilities for any affected Property not retained by Seller, and (ii) the Allocated Value 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 of Hydrocarbons produced from or attributable to the Properties that are in storage above the load line or pipeline connection, as applicable, as of the Effective Time (which value shall be computed using the applicable contract price at the Effective Time), less any applicable severance Taxes, royalties and similar burdens; provided, however , that the adjustment contemplated by this paragraph shall be only made to the extent that Seller does not receive and retain the proceeds, or portion thereof, attributable to the sale of such Hydrocarbons;

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

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

(j) Increased by an overhead charge of $35,000 per month (pro-rated for any partial months as applicable) for the period of time beginning at the Effective Time and ending on the Closing Date (it being understood that no other Seller overhead charge will be charged to the Assets 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 the adjustment, Purchaser’s entitlement under Section 1.4 to Hydrocarbon production from or attributable to the Properties during the Adjustment Period, and to the value of other income, proceeds, receipts and credits earned with respect to the Assets during the Adjustment Period, and Purchaser shall not have any separate rights to receive any production or income, proceeds, receipts and credits with respect to which an adjustment has been made.

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 among each of the Wells and PLSS Sections. Such allocation of value is attached to this Agreement as Schedule 2.3. The “ Allocated Value ” for any Well and PLSS Section equals the portion of the unadjusted Purchase Price allocated to such Well and PLSS Section on Schedule 2.3, increased or decreased as described in Section 2.2.

(b) For federal income tax purposes, Purchaser and Seller shall use commercially reasonable efforts to agree on an allocation of the Purchase Price within thirty (30) days after the determination of the Adjusted Purchase Price. In this respect, the allocation of value reflected in Schedule 2.3 for the unadjusted Purchase Price is to be modified by the Parties to take into account the adjustments made which determine the Adjusted Purchase Price. Seller and Purchaser agree (a) that the agreed allocation shall be used by Seller and Purchaser as the basis for 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 applicable Law, neither they nor their Affiliates will take positions inconsistent with the agreed allocation in any Tax Returns, in notices to Governmental Bodies, in audit or other proceedings with respect to Taxes, in notices to preferential purchase right holders, or in other documents or notices relating to the transactions contemplated by this Agreement without the consent of the other Party. Each Party shall promptly notify the other Party in writing upon receipt of notice of any pending or threatened Tax audit or assessment challenging the agreed allocation, and neither party shall agree to any proposed adjustment to the agreed allocation by any Governmental Body without first giving to the other party prior written notice. However, nothing contained herein shall prevent either party from settling any proposed deficiency or adjustment by any Governmental Body based upon or arising out of the agreed allocation, and neither party shall be required to litigate any proposed deficiency or adjustment by any Governmental Body challenging such agreed allocation.

Section 2.4 Deposit .

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

Article 3

TITLE MATTERS

Section 3.1 Seller’s Title .

(a) This Article 3 and the Special Warranty in the Conveyance (subject to Section 7.9) shall, to the fullest extent permitted by applicable Law, be the exclusive right and remedy of Purchaser with respect to title to the Assets.

(b) The conveyance of the Assets to be delivered by Seller to Purchaser shall be substantially 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 Seller that:

(i) Entitles Seller to receive a share of the Hydrocarbons produced, saved and marketed from such Property (after satisfaction of all royalties, overriding royalties, nonparticipating royalties, net profits interests or other similar burdens on or measured by production of Hydrocarbons) (a “ Net Revenue Interest ”), of not less than the “net revenue interest” share shown in Schedule 2.3 for such Well, except for decreases in connection with those operations permitted under Section 7.5 in which Seller may after the Effective Time be a non-consenting party, decreases resulting from the election to ratify 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 past underproduction or pipelines to make up past under deliveries, and decreases resulting from reversionary interests, carried interests, horizontal or vertical severances or other matters or changes in interest stated in Schedule 2.3;

(ii) Obligates Seller to bear a percentage of the costs and expenses for the maintenance 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 from contribution requirements with respect to defaulting parties under applicable operating, unit, pooling, pre-pooling or similar agreements and increases that are accompanied by at least a proportionate increase in Seller’s Net Revenue Interest; and

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

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

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 any Well shown on Schedule 2.3, without causing a greater than proportionate increase in Seller’s Working Interest above that shown in Schedule 2.3 or (ii) increase the number of Net Acres of Seller 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 shown on Schedule 2.3 to be less than Defensible Title; provided that “Title Defect” shall exclude the following:

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

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

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

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

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

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

(vii) defects based upon the failure to record any state or federal Leases or any assignments 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 of business in compliance with this Agreement;

(ix) encumbrances created under deeds of trust, mortgages and similar instruments by the lessor under a Lease covering the lessor’s surface and mineral interests in the land covered thereby that would customarily be accepted in taking or purchasing such Leases and for which the lessee would not customarily seek a subordination of such encumbrance to the oil and gas leasehold estate prior to conducting drilling activities on the Lease;

(x) encumbrances created under deeds of trust, mortgages and similar instruments by the grantor under a right-of-way that would customarily be accepted in taking 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 any overriding 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 that shown in Schedule 2.3 or increase Seller’s Working Interest above that shown in Schedule 2.3 without 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, agreements and instruments applicable to the Assets, to the extent that they do not, individually or in the aggregate: (i) reduce Seller’s Net Revenue Interest or Net Acres below that shown in Schedule 2.3 or increase Seller’s Working Interest above that shown in Schedule 2.3 without a corresponding increase in the Net Revenue Interest and (ii) materially interfere with the ownership and operation of the Assets as currently owned and operated;

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

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

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

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

(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 not required 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 or any part of the Assets;

(i) Easements, rights-of-way, servitudes, permits, surface leases and other rights in respect 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 and operated as of the Effective Time;

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

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

(l) Any encumbrance on or affecting the Assets which is expressly assumed, bonded or 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 not been commenced as of the Closing Date, any permits, easements, rights of way, unit designations or 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 or transportation pipelines or facilities that do not constitute any of the Assets;

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

in Schedule 2.3, or increase Seller’s Working Interest above that shown in Schedule 2.3 without a corresponding 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 Title Defect 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 necessary for Seller (as well as any title attorney or examiner hired by Seller) to verify the existence of the alleged Title Defect(s) and (v) the amount by which Purchaser reasonably believes the Allocated Values of each Defect Property are reduced by the alleged Title Defect(s) and the computations and information upon which Purchaser’s belief is based. Purchaser shall be deemed to have waived for all purposes hereunder all Title Defects that were not included in a Title Defect Notice delivered to Seller on or before the Title Claim Date. To give Seller an opportunity to commence reviewing and curing alleged Title Defects, Purchaser agrees to provide Seller, on or before the end of each calendar week prior to the Title Claim Date, written notices of all Title Defects discovered by Purchaser during the preceding calendar week, which notice may be preliminary in nature and supplemented prior to the Title Claim Date. Purchaser shall also promptly furnish Seller with written notice of any Title Benefit that is discovered by any of Purchaser’s representatives, title attorneys, landmen or other title examiners while conducting Purchaser’s due diligence 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 with respect to each Title Benefit a written notice (a “ Title Benefit Notice ”) asserting such Title Benefit on or before the Title Claim Date. Each Title Benefit Notice shall include (i) a description 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 or examiner hired by Purchaser) to verify the existence of the alleged Title Benefit(s) and (v) the amount by which Seller reasonably believes the Allocated Values of those Wells and PLSS Sections are increased by the Title Benefit, and the computations and information upon which Seller’s belief is based. Seller shall be deemed to have waived for all purposes hereunder all Title Benefits that were not included in a Title Benefit Notice delivered to Purchaser on or before the Title Claim Date.

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

days from and after the Title Claim Date (the “ Cure Period ”), unless the Parties otherwise agree. If Seller has provided notice at or prior to the Closing Date of Seller’s intent to attempt to cure a Title Defect within the Cure Period, there shall be no reduction to the Purchase Price with respect to the Title Defect for purposes of Closing. If at the end of the Cure Period Seller and Purchaser agree that the Title Defect is not cured, or, in the absence of agreement of the Seller and Purchaser, the Title Arbitrator determines that such Title Defect is not cured at the end of the Cure 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 the Purchase Price adjustment required in connection with the selected option under this Article 3 shall be made in the final statement of the Adjusted Purchase Price pursuant to Section 9.4(b). No action of Seller in electing or attempting to cure a Title Defect shall constitute a waiver of Seller’s right to dispute the existence, nature or value of, or cost to cure, the Title Defect.

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

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

(ii) with the consent of Purchaser, (A) at Closing, retain the Property that is associated with such Title Defect, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Property or (B) promptly after expiration of the Cure Period have Purchaser reconvey the Property that is associated with such Title Defect to Seller, in which event the Purchase Price shall be reduced by an amount equal to the 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 Section 3.4(b) is not waived by Seller, then:

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

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

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

(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 is undisputed and liquidated in amount, then the Title Defect Amount shall be the amount necessary to be paid to remove the Title Defect from the Defect Property;

(iii) if the Title Defect represents a discrepancy between (A) the Net Revenue Interest 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 Defect Property multiplied by a fraction, the numerator of which is the actual amount of the decrease in Net Revenue Interest from that stated on Schedule 2.3 and the denominator of which is the Net Revenue Interest stated on Schedule 2.3; provided, however , that if the Title Defect does not affect the Defect Property throughout its entire life, the Title Defect Amount shall be reduced to take into account the applicable time period only;

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

(v) if the Title Defect represents (A) a discrepancy between (1) the Net Revenue Interest for any Defect Property and (2) the Net Revenue Interest stated on Schedule 2.3, and (B) an obligation, encumbrance, burden or charge upon or other defect in title to the Defect Property, then the Title Defect Amount shall be determined by applying both of Section 3.4(f)(iii) and Section 3.4(f)(iv) to such Title Defect, without duplication;

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

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

(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 2.3 shall 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 that stated on Schedule 2.3 and the denominator of which is the Net Revenue Interest stated on Schedule 2.3; provided, however , that if the Title Benefit does not affect the applicable Title Benefit Property throughout its entire life, the Title Benefit Amount shall be reduced to take into account the applicable time period only and (ii) the result of the Net Acres in a Title Benefit Property being greater than that stated on Schedule 2.3 shall be the product of the Allocated Value of the Title Benefit Property set forth on Schedule 2.3 and a fraction, the numerator of which is the actual Net Acres actually owned for such PLSS Section less an amount equal to the number of Net Acres shown for such PLSS Section on Schedule 2.3, and the denominator of which 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 and received on or before the Title Claim Date, Seller and Purchaser shall attempt to agree on all Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts on or before the day before the Closing Date, subject to Seller and Purchaser’s rights under Sections 3.4(d)(ii). If Seller and Purchaser are unable to agree by that date, then subject to Section 3.4(c) and Seller and Purchaser’s rights under Sections 3.4(d)(ii), Seller’s good faith estimate shall be used for purposes 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 exclusively and finally resolved by arbitration pursuant to this Section 3.4(h). Likewise, if Seller has provided notice at or prior to the Closing Date of Seller’s intent to attempt to cure a Title Defect and by the end of the Cure Period, Seller and Purchaser have been unable to agree upon whether such Title Defect has been cured, or Seller has failed to cure any Title Defects which Seller provided notice that Seller would attempt to cure and Seller and Purchaser have been unable to agree on the Title Defect Amounts for such Title Defects, then the cure and/or Title Defect Amounts and Title Benefit Amounts in dispute shall be exclusively and finally resolved by arbitration pursuant to this Section 3.4(h), subject to Seller and Purchaser’s rights under Section 3.4(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 agreement of Purchaser and Seller within fifteen (15) days after the end of the Cure Period (or such other time as mutually agreed) and absent such agreement on the selection of the arbitrator, the arbitrator shall be selected by the Oklahoma City, Oklahoma office of the American Arbitration Association; provided, however , that in any case such attorney shall not have worked as an employee of or outside counsel for either Seller or Purchaser or any of their Affiliates during the 5-year period preceding the applicable arbitration or have any financial interest in the applicable dispute (such attorney, the “ Title Arbitrator ”). The arbitration proceeding shall be held in Houston, Texas and shall be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section. The Title Arbitrator’s determination shall be made within twenty (20) days after submission of the matters in dispute and shall be final and binding upon both Parties, without right of appeal. In making his determination, the Title Arbitrator shall be bound by the rules set

forth in Section 3.4(a), Section 3.4(b), Section 3.4(c), Section 3.4(d), Section 3.4(e), Section 3.4(f), Section 3.4(g) and Section 3.4(i) and may consider such other matters as in the opinion of the Title Arbitrator are necessary or helpful to make a proper determination. Additionally, the Title 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 purpose of determining the specific disputed Title Defects, Title Benefits, Title Defect Amounts and Title Benefit Amounts submitted by either Party and may not award damages, interest or penalties to either Party with respect to any matter. Each Party shall bear its own legal fees and other costs of presenting 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 any adjustments to the Purchase Price or other remedies provided by Seller for any Title Defects relating to a Defect Property unless the aggregate Title Defect Amount for the Title Defects relating 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 the Purchase Price or other remedies provided by Seller for Title Defects unless the sum of (i) the aggregate amount of all Title Defect Amounts for Title Defects covered by Section 3.4(d)(i) that satisfy the Property Defect Threshold, plus (ii) the aggregate amount of all Environmental Liabilities covered by Section 4.4(a) that satisfy the Property Defect Threshold (that is, the aggregate Environmental Liabilities relating to a Property exceed the sum of Fifty Thousand Dollars ($50,000.00)), exceeds a deductible in an amount equal to two percent (2%) of the Purchase Price (the “ Defect Deductible ”), after which point Purchaser shall be entitled to adjustments to the Purchase Price or other available remedies under this Article 3 with respect to all 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 not apply to Title Defects relating to consent to assignment and preferential rights to purchase which shall be handled or treated under Section 3.5. The Allocated Value of any Property retained by Seller 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) any mortgages, deeds of trust, or other encumbrances created by Seller, or Affiliates of Seller, to secure money borrowed or other form of financing, and (ii) any mechanic liens of record, to the extent relating to pre-Effective Time claims, asserted against any part of portion of the Assets arising from operations having been conducted by Seller or an Affiliate of Seller. Any notice by Purchaser to Seller regarding the existence of any such liens or encumbrances need not be by the Title 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 the third 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 the holders of any applicable preferential rights to purchase any Asset requesting waivers of such preferential rights to purchase, in each case that would be triggered by the purchase and

sale contemplated by this Agreement, and of which Seller has knowledge. The consideration payable under this Agreement for any particular Assets for purposes of preferential purchase right notices shall be the Allocated Value for such Assets (proportionately reduced if an Asset is only partially affected). Seller shall use commercially reasonable efforts to cause such consents and waivers of preferential rights to purchase (or the exercise thereof) to be obtained and delivered prior to Closing. Purchaser shall cooperate with Seller in seeking to obtain such consents to assignment and waivers of preferential rights. Notwithstanding anything contained herein to the contrary, Seller shall have 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 Claim Date of all required third-party consents to the assignment of the Assets to Purchaser which have not been obtained and the Assets to which they pertain. In no event shall there be included in the Conveyances at Closing any Asset subject to an unsatisfied consent requirement that would be triggered by the purchase and sale contemplated by this Agreement and provides that transfer of the Asset without consent will result in a termination or other material impairment of any existing rights in relation to such Asset (such consent, a “ Required Consent ”). In cases where the Asset subject to such a Required Consent is a Contract and Purchaser is assigned the Properties to which the Contract relates, but the Contract is not transferred to Purchaser due to the unwaived consent requirement, Seller shall continue after Closing to use commercially reasonable efforts to obtain such consent so that Seller’s right, title and interest in such Contract can be transferred to Purchaser upon receipt of such consent. In cases where the Asset subject to such a Required Consent is a Property and the third-party consent to the sale and transfer of the Property is not obtained prior to the Closing Date, Purchaser may elect to treat the unsatisfied Required Consent as a Title Defect by giving Seller notice thereof in accordance with Section 3.4(a), except that such 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, and Seller may elect to cure such unsatisfied consent under Section 3.4(c), in which event the provisions of Section 3.4(c) shall apply (provided the affected Asset shall be excluded from the Assets for purposes of Closing until the Required Consent is waived or satisfied (unless otherwise agreed by Seller and Purchaser)). In cases where an Asset is subject to a third-party consent requirement 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 be responsible after Closing for satisfying such consent requirement at its sole cost, risk and expense, to the extent the applicable consent was not obtained or waived on or prior to Closing. If an unsatisfied Required Consent with respect to which a Purchase Price adjustment is made under Section 3.4 is subsequently satisfied prior to the date of the final adjustment to the Purchase Price under Section 9.4(b), Seller shall receive an additional upward adjustment to the Purchase Price in the final adjustments made under Section 9.4(b) equal to the amount of the previous reduction in the Purchase Price on account of such Required Consent and the provisions of this Section 3.5 shall 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 finally determined, whether by agreement between Seller and Purchaser or the determination of an Independent Expert under Section 9.4(b) (or both), Seller shall assign to Purchaser using the form attached as

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

(b) Exercised Preferential Rights to Purchase . If any preferential right to purchase any Property that would be triggered by the purchase and sale contemplated by this Agreement is exercised prior to Closing, the Property transferred to a third Person as a result of the exercise of such preferential right shall be treated as if it was subject to a Title Defect resulting in the complete loss of title and the Purchase Price shall be reduced under Section 2.2(b) by the Allocated Value for such Property (proportionately reduced if the preferential right affects only a portion of such Property), without application of the Defect Deductible. Seller shall retain the consideration 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 in meeting the Defect Deductible. If, on or before ninety (90) days following the Closing Date, such holder of such preferential right fails to consummate the purchase of the Property (or portion thereof) covered by such preferential right then (A) Seller shall so notify Purchaser on or before one hundred (100) days following the Closing Date, and (B) Purchaser shall purchase, on or before 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 terms of this Agreement and for a price equal to the amount by which the Purchase Price was reduced at Closing with respect to such excluded Property (or portion thereof), subject to adjustments applicable to such Property under Section 2.2 above, and (C) Seller shall assign to Purchaser the Property (or portion thereof) so excluded at Closing pursuant to an instrument in substantially the same form as the Conveyance. If any preferential right to purchase any Asset is not exercised and does 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 but prior to the Closing Date, any portion of the Assets is destroyed by fire or other casualty or is taken in condemnation or under right of eminent domain, and the loss as a result of such individual casualty or taking exceeds One Hundred Thousand Dollars ($100,000.00), Seller shall elect by written notice to Purchaser prior to Closing either (i) to cause the Assets affected by any casualty to be repaired or restored prior to Closing to at least its condition prior to such casualty, at Seller’s sole cost (without an adjustment to the Purchase Price pursuant to Section 2.2 or otherwise), as promptly as reasonably practicable (which work may extend thirty (30) days after the Closing Date), or (ii) unless such casualty or taking is waived by Purchaser, to exclude the affected Property or Properties from the Assets and reduce the Purchase Price by the Allocated Value thereof; provided, however , that any adjustment to the Purchase Price pursuant to this Section 3.6 may not be used in meeting the Defect Deductible. In each case, Seller shall retain all of the aforementioned rights to insurance and other claims against third Persons with respect to the casualty or taking except to the extent the Parties otherwise agree in writing.

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 Title Claim Date and be of no further force and effect thereafter, provided there shall be no termination of Purchaser’s or Seller’s rights under Section 3.4 with respect to any bona fide Title Defect properly reported in a Title Defect Notice or bona fide Title Benefit properly reported in a Title Benefit Notice on or before the Title Claim Date. Except as provided in this Article 3 and for the Special Warranty in the Conveyance (subject to Section 7.9), Purchaser releases, remises and forever discharges the Seller Indemnitees 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 Title Defect 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 earlier termination 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 or engineering firm approved in advance in writing by Seller (the “ Environmental Consultant ”) an environmental 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 with Environmental Laws (the “ Assessment ”). In connection with the foregoing, Seller hereby consents to [_____] ,should such Person become Purchaser’s Environmental Consultant. The Assessment shall be conducted at the sole risk, cost and expense of Purchaser, and all of Purchaser’s and the Environmental Consultant’s activity conducted under this Section 4.1 and Section 7.1 shall be subject to the indemnity provisions of Section 7.6. Purchaser’s right of access shall not entitle Purchaser or the Environmental Consultant 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 the right to be present during any activities conducted on the Assets as part of the Assessment. Purchaser shall give Seller reasonable prior written notice before gaining physical access to the Assets. Purchaser shall coordinate the Assessment with Seller to minimize any inconvenience to or interruption of the conduct of business by Seller. Purchaser shall abide by Seller’s, and any third party operator’s, safety rules, regulations and operating policies while conducting its due diligence evaluation of the Assets including the Assessment. Purchaser shall promptly provide, but not later than the Environmental Claim Date, copies of all reports, results, and other documentation and data prepared or compiled by Purchaser and/or any of its representatives or agents in connection with the Assessment (excluding all documentation subject to the attorney-client privilege). Upon completion of the Assessment, Purchaser shall 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 diligence conducted by Purchaser’s environmental consulting or engineering firm), (ii) if applicable, restore the Assets to the approximate same condition as, or

better condition than, they were prior to commencement of the Assessment, and (iii) remove all equipment, tools and other property brought onto the Assets in connection with the Assessment. Any disturbance to the Assets (including the leasehold associated therewith) resulting from the Assessment will be promptly corrected by Purchaser at Purchaser’s sole cost and expense. Seller shall not be deemed by 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 the information contained therein. During all periods that Purchaser or any of its representatives or contractors 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 7.6 specifically naming Seller as an insured party. All information (including all reports, results and documentation containing such information) acquired by Purchaser, its agents or representatives, or the Environmental Consultant, in conducting the Assessment under this Section shall be subject to the Confidentiality Agreement.

Section 4.2 NORM .

Purchaser acknowledges the following:

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

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

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

(e) NORM containing material and other wastes or hazardous substances may have come 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 Claim Date ”), of each individual environmental matter disclosed by the Assessment that Purchaser reasonably believes in good faith may constitute or result in (including with notice or solely with the passage of time) Environmental Liabilities which, utilizing the Lowest Cost Response to address the matter, satisfy the Property Defect Threshold, including in the Environmental Defect Notice (i) a reasonably detailed description of the specific matter that is an alleged violation of Environmental Laws, including (A) the written conclusion of Purchaser or

Purchaser’s Environmental Consultant that Environmental Liabilities exist, which conclusion shall be reasonably substantiated by the factual data gathered in Purchaser’s Assessment and (B) a separate specific citation of the provisions of Environmental Laws alleged to be violated and the related facts that substantiate such violation; (ii) the Wells or associated Assets affected; (iii) a detailed estimate of the Lowest Cost Response to cure or eliminate the alleged matter in question; (iv) supporting documents reasonably necessary for Seller (as well as any consultant, inspector or expert hired by Seller to verify the existence of the facts alleged in the Environmental Defect Notice); and (v) information reflecting the satisfaction of the Property Defect Threshold. The failure of an Environmental Defect Notice to contain the information required by item nos. (i) through (iv) of the prior sentence on or prior to the Environmental Claim Date shall render such notice ineffective. Purchaser shall furnish Seller, on or before the end of each calendar week prior to the Environmental Claim Date, Environmental Defect Notices with respect to any Environmental Liability that any of Purchaser’s or any of its Affiliate’s employees, representatives, attorney or other environmental personnel or contractors, including the Environmental Consultant, discover or become aware of during the preceding calendar week, which notice 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 an Environmental Defect Notice delivered pursuant to Section 4.3 may constitute or result in Environmental Liabilities for which, when utilizing the Lowest Cost Response to address such matters, exceeds the Property Defect Threshold, then Seller shall elect to:

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

(b) with the consent of Purchaser, retain the Property that is associated with such Environmental Defect Notice and affected by such matter, in which event the Purchase Price shall be reduced by an amount equal to the Allocated Value of such Property; provided, however , that if 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 consent of Purchaser; or

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

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

(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 have failed to agree by Closing on the reduction to the Purchase Price (which agreement Seller and Purchaser shall 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) or submit such dispute to arbitration pursuant to this Section 4.4. In the event that Seller elects to proceed under Section 4.4(d) and Purchaser and Seller have failed to agree by Closing on the terms of the agreement contemplated thereby (which agreement Seller and Purchaser shall use good faith efforts to reach), Seller shall then proceed with respect to such matter under any of Sections 4.4(b), (c), or (e) or submit 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 single arbitrator, who shall be an environmental consultant with at least ten (10) years’ relevant experience as selected by mutual agreement of Purchaser and Seller within fifteen (15) days of an election by Seller to submit such dispute to arbitration. Absent such agreement on the selection of the arbitrator, the arbitrator shall 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 be conducted in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section. The Environmental Arbitrator’s determination shall be made within twenty (20) days after submission of the matters in dispute and shall be final and binding upon both parties, without right of appeal. In making his determination, the Environmental Arbitrator shall be bound by the rules set forth in this Article 4 and may consider such other matters as in the opinion of the Environmental Arbitrator are necessary or helpful to make a proper determination. In connection with the determination of a matter submitted to the Environmental Arbitrator Purchaser may not assert any violation of Environmental Law that is not specified by Purchaser in the applicable Environmental Claim Notice. The Environmental Arbitrator shall act as an expert for the limited purpose of determining the specific disputed Environmental Liability or the Lowest Cost Response for such Environmental Liability submitted by Seller and may not award damages, interest or penalties to either Party with respect to any matter nor may it award Purchaser a greater amount with respect to the applicable Environmental Liability than the Lowest Cost Response set forth by Purchaser in the applicable Environmental Claim Notice. Seller and Purchaser shall each bear its own legal fees and other costs of presenting its case. Each Party shall bear one-half of the costs and expenses of the Environmental Arbitrator. If the validity of any Environmental Liability or the Lowest Cost Response attributable thereto, is not determined prior to Closing by the Environmental Arbitrator pursuant to this Section 4.4, all affected Properties shall be conveyed to Purchaser at Closing and the purchase price paid by Purchaser at Closing shall not be reduced by virtue of such dispute and upon final resolution of such dispute the Lowest Cost Response for such Environmental Liability as determined by the Environmental Arbitrator shall, subject to the terms of this this Section 4.4, be promptly refunded by Seller to Purchaser.

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

Property Defect Threshold; and (ii) in no event shall there be any adjustments to the Purchase Price or other remedies provided by Seller for Environmental Liabilities unless and until the sum of (i) the aggregate amount of all Title Defect Amounts for Title Defects covered by Section 3.4(d)(i) that satisfy the Property Defect Threshold, plus (ii) the aggregate amount of all Environmental Liabilities covered by Section 4.4(a) that satisfy the Property Defect Threshold, exceeds the Defect Deductible, after which point Purchaser shall be entitled to adjustments to the Purchase Price or other available remedies under this Section 4.4 with respect to Environmental Liabilities in excess of such Defect Deductible, subject to Seller’s elections under this Section 4.4 and the last sentence of this Section 4.4. The Allocated Value of any Property (or affected portion thereof) retained by Seller in accordance with Section 4.4(b) may not be used in meeting the Defect Deductible.

Section 4.5 Limitations .

Notwithstanding anything to the contrary in this Agreement, except for the indemnity provided under Section 11.2(c) as it relates to breaches of the representation in Section 5.15, this Article 4 is intended to be the sole and exclusive remedy that Purchaser Indemnitees shall have against Seller Indemnitees with respect to any matter or circumstance relating to Environmental Laws, the release of materials into the environment or protection of the environment or health. Except to the limited extent necessary to enforce the terms of this Article 4 and the indemnity provided under Section 11.2(c) as it relates to breaches of the representation in Section 5.15, Purchaser (on behalf of itself, each of the other Purchaser Indemnitees and their respective insurers and successors in interest) hereby releases and discharges any and all claims and remedies at Law or in equity, known or unknown, whether now existing or arising in the future, contingent or otherwise, against the Seller Indemnitees with respect to any matter or circumstance relating to Environmental Laws, Environmental Liabilities, the release or threatened 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 ARE CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT, EXCLUDING WILLFUL MISCONDUCT), STRICT LIABILITY OR OTHER LEGAL 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 warranty regarding any matter or circumstance relating to Environmental Laws, Environmental Liabilities, the release or threatened release of materials into the environment or protection of the environment, natural resources, threatened or endangered species, or health, and that nothing in Article 5 or otherwise shall be construed 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 Article 5 of this Agreement OR in the certificate of Seller to be delivered pursuant to Section 9.2(f), OR FOR THE SPECIAL WARRANTY IN THE CONVEYANCE ( subject to Section 7.9 ) , with respect to the Assets and the transactions contemplated hereby (i) SELLER

MAKES NO REPRESENTATIONS OR WARRANTIES, STATUTORY, EXPRESS OR IMPLIED, AND (ii) PURCHASER HAS NOT RELIED UPON, AND SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR, ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO PURCHASER OR ANY OF ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, OFFICERS, DIRECTORS, MEMBERS, MANAGERS, EQUITY OWNERS, CONSULTANTS, REPRESENTATIVES OR ADVISORS (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO PURCHASER BY ANY EMPLOYEE, AGENT, OFFICER, DIRECTOR, MEMBER, MANAGER, EQUITY OWNER, CONSULTANT, REPRESENTATIVE OR ADVISOR OF SELLER OR ANY OF ITS AFFILIATES).

(b) EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN ARTICLE 5 OR IN THE CERTIFICATE OF SELLER TO BE DELIVERED PURSUANT TO Section 9.2(f) , OR FOR THE SPECIAL WARRANTY IN THE CONVEYANCE ( subject to Section 7.9 ) , WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS, AND PURCHASER ACKNOWLEDGES AND AGREES THAT IT 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 REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (iii) THE QUANTITY, QUALITY OR RECOVERABILITY OF PETROLEUM SUBSTANCES IN OR FROM THE ASSETS, (iv) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (v) THE PRODUCTION OF PETROLEUM SUBSTANCES FROM THE ASSETS, (vi) ANY ESTIMATES OF OPERATING 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) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE OR COMMUNICATED TO PURCHASER OR ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, OFFICERS, DIRECTORS, MEMBERS, MANAGERS, EQUITY OWNERS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO, AND FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, STATUTORY, EXPRESS OR IMPLIED, OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY EQUIPMENT, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT PURCHASER HAS INSPECTED, OR WAIVED PURCHASER’S RIGHT TO INSPECT, THE ASSETS FOR ALL PURPOSES AND SATISFIED ITSELF AS TO THEIR PHYSICAL AND ENVIRONMENTAL

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

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

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

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

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

Section 5.2 Existence and Qualification .

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

Section 5.3 Power .

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

Section 5.4 Authorization and Enforceability .

The execution, delivery and performance of this Agreement, and the performance of the transactions contemplated hereby, have been duly and validly authorized by all necessary action on the part of Seller. This Agreement has been duly executed and delivered by Seller (and all documents required hereunder to be executed and delivered by Seller at Closing will be duly executed and delivered by Seller) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Seller, enforceable in accordance with their terms except as such enforceability may be limited by applicable bankruptcy or other similar Laws affecting the rights and remedies of creditors generally as well as to general principles of equity (regardless of whether such enforceability 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 transactions contemplated 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 or encumbrance, 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 financing instrument 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 or any of the Assets (except for rights to consent by, required notices to, and filings with or other actions by Governmental 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 in the 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 result of undertakings or agreements of Seller, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

Section 5.7 Litigation .

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

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 with respect to Taxes (the “ Tax Returns ”) relating to the ownership or operation of the Assets required to be filed by Seller have been timely filed (taking into account all applicable extensions) with the appropriate Governmental Body in all jurisdictions in which such Tax Returns are required to be filed; (b) such Tax Returns are true and correct in all material respects, and all material Taxes reported and due on such Tax Returns have been paid; (c) there is not currently in effect any extension or waiver of any statute of limitations regarding the assessment or collection of any Tax with respect to the Assets, which period has not yet expired; (d) there are no administrative proceedings or lawsuits pending with respect to the Assets by any taxing authority for which Seller has received written notice; and (e) none of the Assets is held 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 the exclusive representations and warranties with respect to Tax matters, and no other Section in this Article 5 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 expenditure which is binding on the Assets, the value of which Seller reasonably anticipates exceeds Fifty Thousand Dollars ($50,000.00) chargeable to Seller’s interests participating in the operation covered by such authority 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 the operation of the Assets has been and currently is, in substantial compliance with the provisions and requirements of all Laws (excluding Environmental Laws, which are addressed in Section 5.15) of all Governmental 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 as disclosed 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 the Assets or to which any of the Assets will be bound as of the Closing: (i) any agreement with any Affiliate; (ii) any agreement or contract for the sale, exchange, or other disposition of Hydrocarbons produced from or attributable to Seller’s interest in the Assets that is not cancelable without penalty or other material payment on not more than ninety (90) days prior written notice; (iii) any agreement of or binding upon Seller to sell, lease, farmout, or otherwise dispose of any interest in any of the Assets after the Effective Time, other than conventional rights of reassignment arising in connection with Seller’s surrender or release of any of the Assets and

(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 agreement containing 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. To Seller’s knowledge, all royalties and in-lieu royalties with respect to the Assets which accrued or are attributable to the period prior to the Effective Time have been properly and fully paid, or are included within the Suspended Proceeds.

Section 5.13 Governmental Authorizations .

Except as disclosed on Schedule 5.13, to the knowledge of Seller, Seller has obtained and is maintaining 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 the Seller Operated Assets as currently operated (excluding those required under Environmental Laws), the loss 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 rights to purchase, (ii) restrictions on assignment or required third-party consents to assignment that if not obtained in connection with an assignment to Purchaser would result in a termination of Seller’s title to such Asset or (iii) to the best of Seller’s knowledge, other third-party consents to assignment, which are applicable to the transactions contemplated by this Agreement, except for (x) consents and approvals by Governmental 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 leases and (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 operation thereof are in compliance with applicable Environmental Laws, except for incidents of noncompliance that, individually or in the aggregate, would not reasonably be expected to have a Material Adverse Effect. 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 the presence or absence of NORM, asbestos, mercury, drilling fluids and chemicals, and produced waters and Hydrocarbons in or on the Properties or Equipment. The representation and warranty in this Section 5.15 constitutes the only representation and warranty with respect to Environmental Laws or Environmental Liabilities and no other representation or warranty appearing in this Agreement shall be construed to cover Environmental Laws or Environmental Liabilities.

Section 5.16 Bankruptcy .

There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by 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’s Imbalances 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 in accordance with generally accepted oil and gas field practices in compliance in all material respects with applicable 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 to the Assets as to which Seller has elected to be a nonconsenting party under the terms of the applicable operating 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 and similar property necessary for the continued operation, following the Closing, of the Seller’s business as conducted 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 the Laws of the state of Delaware; and Purchaser is duly qualified to do business as a foreign limited partnership in every jurisdiction in which it is required to qualify in order to conduct its business except where 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 the respective jurisdictions where the Assets to be transferred to it are located.

Section 6.2 Power .

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

Section 6.3 Authorization and Enforceability .

The execution, delivery and performance of this Agreement, and the performance of the transactions contemplated hereby, have been duly and validly authorized by all necessary action on the part of Purchaser. This Agreement has been duly executed and delivered by Purchaser (and all documents required hereunder to be executed and delivered by Purchaser at Closing will be duly executed and delivered by Purchaser) and this Agreement constitutes, and at the Closing such documents will constitute, the valid and binding obligations of Purchaser, enforceable in accordance with their terms except as such enforceability may be limited by applicable bankruptcy or other similar Laws affecting the rights and remedies of creditors generally as well as to general principles of equity (regardless of whether 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 transactions contemplated by this Agreement will not (i) violate any provision of the limited liability company agreement, 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 or encumbrance, 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 financing instrument 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 Laws applicable to Purchaser or any of its assets, except any matters described in clauses (ii), (iii) or (iv) above which 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 of undertakings or agreements of Purchaser, for brokerage fees, finder’s fees, agent’s commissions or other similar forms of compensation in connection with this Agreement or any agreement or transaction contemplated hereby.

Section 6.6 Litigation .

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

Section 6.7 Financing .

Purchaser has sufficient cash, available lines of credit or other sources of immediately available funds (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 gas properties and related facilities and is aware of the risks associated with the purchase, ownership and operation of such properties and facilities, (b) is capable of evaluating, and hereby acknowledges that it has so evaluated, the merits and risks of the Assets, ownership and operation thereof and its obligations hereunder, and (c) is able to bear the economic risks associated with the Assets, ownership and operation thereof and its obligations hereunder. In making its decision to enter into this Agreement and to consummate the transactions contemplated hereby, Purchaser (i) has relied or shall rely solely on its own independent investigation and evaluation of the Assets and the advice of its own legal, Tax, economic, environmental, engineering, geological and geophysical advisors and acknowledges and agrees that (A) it has not been induced by and has not relied upon any representations, warranties or statements, whether express 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) no Seller nor any of its or their respective directors, officers, shareholders, employees, Affiliates, controlling persons, agents, advisors or representatives or any other Person makes or has made any representation or warranty, either express or implied, as to the accuracy or completeness of any of the information provided or made available to Purchaser or its directors, officers, employees, Affiliates, controlling persons, agents or representatives, including any information, document or material provided or made available, or statements made or provided to any Seller (including its directors, officers, employees, Affiliates, controlling persons, agents or representatives) in connection with the transactions contemplated by this Agreement, including without limitation, any such information contained in or provided in “data rooms”, management presentations or supplemental due diligence information provided by a Seller or discussions or access to management of a Seller; and (C) the information referred to in (B) above may include certain projections, estimates and other forecasts and plans and that there are uncertainties inherent in attempting to make such projections, estimates and other forecasts and plans and Purchaser is familiar with such uncertainties and takes full responsibility for making its own evaluation of the adequacy and accuracy of all such projections, estimates and other forecasts and plans and any use or reliance by Purchaser on such information referred to in (B) above is (or the projections, estimates and other forecasts and plans that may be contained therein) at Purchaser’s sole risk; (ii) has satisfied or shall satisfy itself through its own due diligence as to the environmental and physical condition of and contractual arrangements and other matters affecting the Assets; and (iii) agrees to the fullest extent permitted 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 to Purchaser or its directors, officers, employees, Affiliates, controlling persons, agents or representatives on any basis (including in contract or tort, under Federal or state securities laws or otherwise) resulting from 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

the Closing Date that (i) it has made all such reviews and inspections of the Assets as it has deemed necessary or appropriate and (ii) except for the express representations, warranties, covenants and remedies 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 in entering into this Agreement.

Section 6.9 Bankruptcy .

There are no bankruptcy, reorganization or receivership proceedings pending against, being contemplated 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 as Purchaser shall own the Assets, shall continue to be, qualified to own and assume operatorship of federal and state oil, gas and mineral leases in all jurisdictions where the Assets to be transferred to it are located, and the consummation of the transactions contemplated in this Agreement will not cause Purchaser and its designee operator to be disqualified as such an owner or operator. To the extent required 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 required by, and in accordance with, such state or federal regulations governing the ownership and operation of such leases.

Section 6.11 Consents .

Except for consents and approvals for the assignment of the Assets to Purchaser that are customarily and lawfully obtained after the assignment of properties similar to the Assets, there are no consents, approvals or other restrictions on assignment applicable to Purchaser that Purchaser is obligated 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 transactions contemplated 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, Seller will give Purchaser and its representatives access to Seller’s offices and the Records, including the right to copy, at Purchaser’s expense, the Records in Seller’s possession, for the sole purpose of conducting an investigation of the Assets, but only to the extent that Seller may do so without violating any applicable Law or obligations to any third Person and to the extent that Seller has authority to grant such access without breaching any restriction binding on Seller. Such access by Purchaser shall be subject to applicable limitations in Section 4.1 and shall be limited to Seller’s normal business hours, and any weekends and after hours requested by Purchaser that can be reasonably accommodated by Seller, and Purchaser’s investigation shall be conducted in a manner

that minimizes interference with the operation of the Assets. All information obtained by and access granted to Purchaser and its representatives under this Section shall be subject to the terms of Section 7.6 and 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 prepare applications 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 transactions contemplated hereby, and (b) provide such information as the other Party may reasonably request to make such filings, prepare such applications and conduct such negotiations. Each Party shall cooperate with 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 knowledge that any representation or warranty of Seller contained in this Agreement is untrue in any material respect or will be untrue in any material respect as of the Closing Date or that any covenant or agreement to be performed or observed by Seller prior to or on the Closing Date has not been so performed or observed in any material respect or (ii) any representation or warranty of Purchaser contained in this Agreement is untrue in any material respect.

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

If any of Purchaser’s or Seller’s representations or warranties is untrue or shall become untrue in any material respect between the date of execution of this Agreement and the Closing Date, or if any of Purchaser’s or Seller’s covenants or agreements to be performed or observed prior to or on the Closing Date (other than on a specified date) shall not have been so performed or observed in any material respect, but if such breach of representation, warranty, covenant or agreement shall (if curable) be cured by the Closing (or, if the Closing does not occur, by the date set forth in Section 10.1), then such breach shall 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 Seller as operator of any Wells included in the Seller Operated Assets. Seller makes no representation and does not warrant or guarantee that Purchaser or its Affiliate designee will succeed in being appointed successor operator. Purchaser shall promptly, following Closing (or earlier to the extent provided under Section 12.7), file and diligently pursue until receipt of any

acknowledgement, consent or confirmation by applicable agencies all appropriate or required forms, applications, permit transfers, declarations, guarantees, or bonds or other financial support with federal and 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 the necessary Governmental Body approvals to succeed Seller as operator, Seller shall execute and deliver to Purchaser, 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 to Purchaser, 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 for expenditures or operations set forth on Schedule 5.9, and except as otherwise consented to in writing by Purchaser, which consent shall not be unreasonably withheld or delayed, until the Closing, Seller (i) will operate the Seller Operated Assets in the ordinary course consistent with past practices, (ii) will not commit to any single operation, or series of related operations, reasonably anticipated by Seller to require future 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 Fifty Thousand 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 insurance coverage on the Assets, if any, presently furnished by nonaffiliated third Persons in the amounts and of the types presently in force, (v) will use commercially reasonable efforts to maintain in full force and effect all Leases, (vi) will maintain all material Governmental Authorizations necessary for the ownership 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 of Hydrocarbon production and Equipment made in the ordinary course of business consistent with past practices 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 granted within five (5) days (unless a shorter time is reasonably required by the circumstances and such shorter time is specified in Seller’s written notice) of Seller’s notice to Purchaser requesting such consent unless Purchaser notifies Seller to the contrary during that period. In the event of an emergency, Seller may take such action as a prudent operator would take and shall notify Purchaser of such action promptly thereafter.

Notwithstanding anything to the contrary in this Agreement, Seller shall have no liability to Purchaser for the incorrect payment of delay rentals, royalties, overriding royalties, shut-in payment payments or similar payments made during the Adjustment Period or for failure to make such payments through 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 a Property prior to Closing, Purchaser may, until the Title Claim Date, assert a Title Defect under Section 3.4(a) with respect to such matter.

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

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

Purchaser acknowledges that Seller may own an undivided interest in certain of the Assets and Purchaser agrees that the acts or omissions of the other working interest owners who are not affiliated with Seller shall not constitute a violation of the provisions of this Article 7 nor shall any action required by a vote of working interest owners constitute such a violation so long as Seller has voted its interest in a 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 to indemnify, defend and hold harmless all Seller Indemnitees and the other owners of interests in the leases and 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, arising out of or relating to access to the Assets by the Purchaser Indemnitees, the Records and other related activities or information prior to the Closing by Purchaser Indemnitees, EVEN IF CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT), STRICT LIABILITY OR OTHER LEGAL FAULT OF ANY INDEMNIFIED PERSON EXCLUDING, HOWEVER, ANY CLAIMS, LIABILITIES, LOSSES, COSTS OR EXPENSES 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 the Assets prior to Closing and the time for exercise or waiver has not yet expired, subject to the remaining provisions of this Section 7.7, such Assets shall be included in the transaction at Closing, such preferential right to purchase shall be a Permitted Encumbrance hereunder, and the following procedures shall be applicable. If one or more of the holders of any such preferential right to purchase notifies Seller subsequent to the Closing that it intends to assert its preferential purchase right, Seller shall give notice thereof to Purchaser, whereupon Purchaser shall satisfy all such preferential purchaser right obligations of Seller to such holders and shall indemnify and hold harmless all Seller Indemnitees from and against any and all claims, liabilities, losses, damages, costs and expenses (including court costs, expert fees and reasonable attorney’s fees) in connection therewith, and Purchaser shall be entitled to receive (and Seller hereby assigns to Purchaser all of Seller’s rights to) all proceeds, received from such holders in connection with such preferential rights to purchase.

Prior to Closing, should any third Person bring any suit, action or other proceeding seeking to restrain, enjoin or otherwise prohibit the consummation of the transactions contemplated hereby in connection 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 Purchase Price shall be reduced by the Allocated Value of such excluded Assets or portions thereof. Promptly after the suit, action or other proceeding is dismissed or settled or a judgment is rendered in favor of Seller, as applicable, Seller shall sell to Purchaser, and Purchaser shall

purchase from Seller, all such Assets or portions thereof not being sold to the third Person for a purchase price equal to the Allocated Value of such Assets or portions thereof, adjusted as provided in Section 2.2; provided Seller 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 date Closing occurs; provided further Purchaser shall have no obligation to purchase under this paragraph if the 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 Taxes related to the ownership or operation of the Assets that are attributable to any taxable period, or portion thereof, that ends at or prior to the Effective Time. Purchaser shall be responsible for all other Taxes related to the ownership or operation of the Assets. Regardless of which Party is responsible for Taxes pursuant to the preceding sentences of this Section 7.8(a), Seller shall handle payment to the appropriate Governmental Body of all Taxes related to the ownership or operation of the Assets which are required to be paid prior to Closing (and shall file all Tax Returns with respect to such Taxes); provided, that to the extent such Taxes relate to the periods from and after the Effective Time, as determined pursuant to Section 1.4(c), such payment shall be 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 not already been accounted for under Section 2.2). Purchaser shall handle payment to the appropriate Governmental Body of all Taxes related to the ownership or operation of the Assets which are required 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 with respect to such Taxes after the Closing Date which includes all or a portion of a Tax period for which Purchaser is liable for such Taxes, following Seller’s request, Purchaser shall promptly pay to Seller all such Taxes allocable to the period or portion thereof beginning at or after the Effective Time (but only to the extent that such amounts have not already been accounted for under 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 (including Taxes based on net profits, margin, revenues, gross receipts or similar measure), and Tax Returns therefor, which shall be borne, paid and filed by the Party responsible for such Taxes under applicable Law. If requested by Purchaser, Seller will assist Purchaser with preparation of all ad valorem and property Tax Returns due on or before thirty (30) days after Closing (including any extensions requested). Seller shall deliver to Purchaser within thirty (30) days of filing copies of all Tax Returns filed by Seller after the Closing Date relating to the Assets and any supporting documentation provided by Seller to Governmental Bodies.

(b) If Seller or Purchaser (or an Affiliate of Seller or Purchaser) receives a refund of any Taxes (whether by payment, credit offset or otherwise, with any interest thereon) covered by Section 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) days after receipt) remit payment to such other Party of an amount equal to the refund amount, with any interest thereon, including all relevant

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

(c) Except to the extent required by applicable Laws, Purchaser shall not and shall not permit its Affiliates to amend any Tax Return with respect to Taxes for which Seller is liable under this Section 7.8 or for which Seller may be liable to indemnify Purchaser under Section 11.2. Any Tax Return prepared by Purchaser for a taxable period, or portion thereof, beginning before the Effective Time shall be prepared in accordance with Seller’s prior practice and shall not be filed without Seller’s written consent (not to be unreasonably withheld, conditioned or delayed) after providing Seller a copy thereof reasonably in advance of the due date for filing such Tax Returns. In the event that Seller is required by applicable Law to file any Tax Return with respect to Taxes for which Purchaser is responsible hereunder, Seller shall prepare and timely 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 copy thereof reasonably in advance of the due date for filing such Tax Return. If Seller or Purchaser disputes any item on a Tax Return described in this Section 7.8(c), it shall notify the other Party of such disputed item (or items) and the basis for its objection. The Parties shall act in good faith to resolve any such dispute prior to the date on which the relevant Tax Return is required to be filed. Purchaser and Seller shall each provide the other with all information reasonably necessary to 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 in writing within fifteen (15) days of the receipt of the notice of any proposed assessment or commencement of any Tax audit or administrative or judicial proceeding and of any Tax demand or claim on Purchaser or any of its Affiliates or Seller or any of its Affiliates that, if determined adversely to the taxpayer or after the lapse of time, could reasonably be grounds for indemnification by Seller or would be reasonably likely to materially increase the Tax liability of Purchaser or any of its Affiliates; provided, that failure to timely provide such notice shall not affect the right of Purchaser’s indemnification hereunder, except to the extent Seller is prejudiced by such delay or omission. Such notice shall contain factual information describing the asserted Tax liability in reasonable detail and shall include copies of any notice or other document received from any Governmental Body in respect of any such asserted Tax liability. Seller shall control any proceeding with respect to any Taxes or Tax Returns relating to or with respect to any Asset (“ Tax Audit ”) for any item relating to a Tax for which Seller is reasonably likely to be responsible, in whole or in part, pursuant to Section 7.8(a) or for which Seller may be liable to indemnify Purchaser under Section 11.2. Neither Purchaser nor Seller shall settle any such Tax Audit in a way that would adversely affect the other Party without the other Party’s written consent, which consent the other Party shall not unreasonably withhold, delay or condition. Purchaser and Seller shall each provide the other with all information reasonably necessary to conduct a Tax Audit with respect to Taxes or the transactions contemplated by this Agreement.

(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 the Assets or the production of Hydrocarbons produced from such Assets for Tax periods or portions thereof after the Effective Time (such amounts, “ Post-Effective Time Tax Advances ”) and has not recouped such Post-Effective Time Tax Advances before the Closing Date from such working interest owners, royalty interest owners, overriding royalty interest owners and other interest owners 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 promptly remit 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 to the 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 the counties where the lands covered by the Leases and Units are located or in the materials made available 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 Date and 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 Special Warranty (collectively, the “ Special Warranty Notices ” and, individually, a “ Special Warranty Notice ”). Seller shall have a reasonable opportunity, but not the obligation, to cure any breach of the Special Warranty asserted by Purchaser pursuant to this Section 7.9(b). Purchaser shall reasonably cooperate with any attempt by Seller to cure any such breach. For all purposes of this Agreement, Purchaser shall be deemed to have waived, and Seller shall have no further liability for, any breach of the Special Warranty that Purchaser fails to assert 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 be limited to an amount (without any interest accruing thereon) equal to the reduction to the Purchase Price to which Purchaser would have been entitled had Purchaser asserted the defect giving rise to such breach of the Special Warranty as a Title Defect prior to the Title Claim Date pursuant to Section 3.4(a) and taking into account the last sentence of this Section 7.9(c), and in no event shall that recovery exceed the Allocated Value of the affected Property. Purchaser shall not be entitled to recover any amount for any breach of the Special Warranty to the extent that the Purchase 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 for which and to the extent Purchaser had knowledge prior to the Title Claim Date that

such matters constituted a Title Defect hereunder and failed to assert the same under this Agreement 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 the Purchase Price, all monies representing the value or proceeds of production removed or sold from the Properties and held by Seller at the time of the Closing for accounts from which payment has been suspended, 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 such Suspended 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 for carrying 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 from the Assets the “ Contingent Payment ,” which shall mean Seller’s interest in and to the Subject Hydrocarbons and the Subject Wells to the extent of a term and cost-free (bearing no costs of exploration, development, operations, or pre- or post-production costs), dollar-denominated, payment from the proceeds from the sale of any Subject Hydrocarbons produced, saved and sold from any Subject Wells prior to the Termination Date, as and to the extent calculated in accordance with Section 7.12(b) (and to be paid to Seller in accordance with Section 7.12(c)) up to 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 necessary to secure Purchaser’s (or its Affiliate’s) performance of its obligations with respect to such payments to Seller.

(b) Calculation of Contingent Payment . The Contingent Payment shall be calculated as follows: for each rolling thirty (30) day period prior to October 1, 2017 and up to and prior to the Termination Date (each such rolling thirty (30) day period, a “ Determination Period ”), if the 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 Dollars equal to the product of:

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

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

(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 this Section 7.12(b)(ii)).

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

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

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

(i) “ Average Henry Hub Determination Price ” means, as determined with respect 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 applicable daily “Dollars per Million Btu” figure reported by the U.S. Energy Information Administration on the natural gas “Spot Prices” chart (which chart may be accessed at the following link: https://www.eia.gov/dnav/ng/hist/rngwhhdd.htm or any successor source of the same information) for all days during such rolling thirty (30) day period that is a Determination Period (i.e., without considering into such averaging calculation any weekend day, holiday or other day during such rolling thirty (30) day period for which the U.S. Energy Information Administration does not generate or report a “Dollars per Million Btu” figure for such day); for the avoidance of doubt, and as an example calculation of the “Average Henry Hub Determination Price” for the hypothetical rolling thirty (30) day period beginning April 3, 2017, and ending May 3, 2017, such “Average Henry Hub Determination Price” for such hypothetical Determination Period equals $3.1091.

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

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

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

(iv) “ Subject Hydrocarbons ” means all natural gas, casinghead gas and other gaseous hydrocarbons together with crude oil, condensate and other liquid hydrocarbons produced from any Subject Well, to the extent attributable to the right, title and interest of Seller in and to the Lands or Units (including units or pools created after the 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 which Seller shall have received and realized from all Contingent Payments the full sum of Two Million Five Hundred Thousand Dollars ($2,500,000.00) through the payment to Seller of all 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 Periods prior to October 1, 2019, then such accrued Contingent Payment will be due and owing and paid to Seller under the terms of Section 7.12(c) without limitation by the terms of this 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 are subject, at the option of Seller, to the satisfaction on or prior to Closing of each of the following conditions:

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

(b) Performance . Purchaser 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 or on the Closing Date;

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

(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 under Section 9.3;

(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 asserted in 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 under Section 3.5), less the sum of all Title Benefit Amounts for actual Title Benefits, as determined under Article 3, plus (ii) the sum of all reasonable adjustments to the Purchase Price for Environmental Liabilities asserted in good faith and in accordance with Section 4.3 by Purchaser covered by Section 4.4(a), plus (iii) the aggregate amount of the Allocated Values of all Properties excluded from the Properties to be conveyed to Purchaser at Closing pursuant to Section 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 are subject, at the option of Purchaser, to the satisfaction on or prior to Closing of each of the following conditions:

(a) Representations . The representations and warranties of Seller set forth in Article 5 shall be true and correct as of the date of this Agreement and as of the Closing Date as though made on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date), except for such breaches, if any, as would not have a Material Adverse Effect ( provided, that to the extent such representation or warranty is qualified by its terms by materiality or Material Adverse Effect, such qualification in its terms shall be inapplicable for purposes of this Section and the Material 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 or on the Closing Date;

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

(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 asserted in 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 Title Defects under Section 3.5), less the sum of all Title Benefit Amounts for actual Title Benefits, as determined under Article 3, plus (ii) the sum of all reasonable adjustments to the Purchase Price for Environmental Liabilities asserted in good faith and in accordance with Section 4.3 by Purchaser covered by Section 4.4(a), plus (iii) the aggregate amount of the Allocated Values of all Properties excluded from the Properties to be conveyed to Purchaser at Closing pursuant to Section 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 this Agreement (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 in Article 8 to be satisfied prior to Closing have not yet been satisfied or waived on such date, as soon as thereafter as such conditions have been satisfied or waived, subject to the rights of the parties 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 shall prepare, deliver or cause to be delivered to Purchaser, among other things, the following:

(a) the Conveyance, in sufficient duplicate originals to allow recording in all appropriate 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 federal leases comprising portions of the Assets, duly executed by Seller;

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

(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 Sections 8.2(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 of 1986, 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 shall deliver 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;

(d) copies of all bonds, letters of credit and guarantees required to be obtained by Purchaser, 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 executed by Purchaser; and

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

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 and deliver to Purchaser, based upon the best information available to Seller, a preliminary settlement statement estimating the Adjusted Purchase Price after giving effect to all Purchase Price adjustments 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 and Purchaser cannot come to a resolution with respect to Purchaser’s objection, Seller’s Preliminary Settlement Statement shall be used for the purposes of Closing and the estimate delivered in accordance with this Section 9.4(a) shall constitute the dollar amount to be paid by Purchaser to Seller 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

statement setting forth the final calculation of the Adjusted Purchase Price and showing the calculation of each adjustment, based, to the extent possible on actual credits, charges, receipts and other items before and after the Effective Time and taking into account all adjustments provided for in this Agreement. Seller shall at Purchaser’s request supply reasonable documentation available to support any credit, charge, receipt or other item. As soon as reasonably practicable but not later than the 30th day following receipt of Seller’s statement hereunder, Purchaser shall deliver to Seller a written report containing any changes that Purchaser proposes be made to such Statement. The Parties shall undertake to agree on the final statement of the Adjusted Purchase Price no later than one hundred thirty (130) days after the Closing Date. In the event that the parties cannot agree on the Adjusted Purchase Price within one hundred thirty (130) days after the Closing, such determination will be automatically referred to an independent expert of the parties choosing with at least ten (10) years of oil and gas accounting experience for arbitration (the “ Independent Expert ”). If the Parties are unable to agree upon an Independent Expert, then such Independent Expert shall be selected by any Federal District Court Judge or State District Court Judge in Houston, Texas. The burden of proof in the determination of the Adjusted Purchase Price shall be upon Purchaser. The Independent Expert shall conduct the arbitration proceedings in Houston, Texas in accordance with the Commercial Arbitration Rules of the American Arbitration Association, to the extent such rules do not conflict with the terms of this Section. The Independent Expert’s determination shall be made within thirty (30) days after submission of the matters in dispute and shall be final and binding on both Parties, without right of appeal. In determining the proper amount of any adjustment to the Purchase Price, the Independent Expert shall not increase the Purchase Price more than the increase proposed by Seller nor decrease the Purchase Price more than the decrease proposed by Purchaser, as applicable. The Independent Expert shall act as an expert for the limited purpose of determining the specific disputed matters submitted by either Party and may not award damages or penalties to either Party with respect to any matter. Each Party shall each bear its own legal fees and other costs of presenting its case. Each Party shall bear one-half of the costs and expenses of the Independent Expert. Within ten (10) days after the date on which the Parties or the Independent Expert, as applicable, finally determines the disputed matters, (i) Purchaser shall pay 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 Adjusted Purchase Price, as applicable. Any post-closing payment pursuant to this Section 9.4 shall bear interest 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 electronic transfer of immediately available funds to the account of Seller pursuant to the wiring instructions reflected in Schedule 9.4(c) or as separately provided in writing. All payments made or to be made hereunder to Purchaser shall be by electronic transfer of immediately available funds to a bank and account specified by Purchaser in writing to Seller.

Article 10

TERMINATION

Section 10.1 Termination .

Subject to Section 10.2, this Agreement may be terminated: (i) at any time prior to Closing by the mutual prior written consent of Seller and Purchaser; (ii) by Seller or Purchaser if Closing has not occurred on or before the day that is sixty (60) days from the date hereof; (iii) by Purchaser if any condition set forth in Section 8.2 has not been satisfied or waived at Closing or (iv) by Seller if any condition set forth in Section 8.1 has not been satisfied or waived at Closing; provided, however , that termination under clauses (ii), (iii) or (iv) shall not be effective until the Party electing to terminate has delivered 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 10.2 and in Section 10.3, this Agreement shall become void and of no further force or effect (except for the provisions 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 shall continue in full force and effect in accordance with their terms) and Seller shall be free immediately to enjoy all rights of ownership of the Assets and to sell, transfer, encumber or otherwise dispose of the Assets to any Person without any restriction under this Agreement. Subject to Section 10.3, the termination of this Agreement under Section 10.1(ii), (iii) or (iv) shall not relieve any Party from liability to the other Party at Law or in equity for any failure to perform or observe in any material respect any of its agreements or covenants contained herein which are to be performed or observed at or prior to Closing.

Section 10.3 Distribution of Deposit Upon Termination .

(a) If this Agreement is terminated by Seller pursuant to Section 10.1(ii) or Section 10.1(iv) and Seller has performed or is ready, willing and able to perform all of its agreements and covenants contained herein which are to be performed or observed at or prior to Closing, and all conditions to Purchaser’s obligation to consummate the transaction contemplated by this Agreement under Section 8.2 have been satisfied or waived by Purchaser, then Seller, as its sole remedy shall retain the Deposit as liquidated damages as Seller's sole and exclusive remedy for any 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 full force and effect) are hereby expressly waived by Seller. Seller and Purchaser agree upon the Deposit as liquidated damages due to the difficulty and inconvenience of measuring actual damages and the uncertainty thereof, and Seller and Purchaser agree that such amount would be a reasonable estimate of Seller’s loss in the event of any such breach or failure to perform by Purchaser. Upon such termination, Seller shall be free immediately to enjoy all rights of ownership of the Assets and to sell, transfer, encumber or otherwise dispose of the Assets to any Person without any restriction under this Agreement.

(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 and covenants contained herein which are to be performed or observed at or prior to Closing, then at Purchaser’s option:

(i) upon notice from Purchaser, Seller shall pay the Deposit to Purchaser, and Purchaser shall be entitled to seek money damages from Seller available at Law for Seller’s applicable breach of this Agreement, as Purchaser’s sole and exclusive remedy for any breach or failure to perform by Seller under this Agreement, and all other remedies (except those under the Confidentiality Agreement, which shall remain in full force and effect) are hereby expressly waived by Purchaser, and Seller shall be free immediately to enjoy all rights of ownership of the Assets and to sell, transfer, encumber or otherwise dispose of the Assets to any Person without any restriction under this Agreement; or

(ii) in lieu of termination of this Agreement, Purchaser as its sole and exclusive 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 agreed that monetary damages will not be sufficient to compensate Purchaser. If Purchaser elects to seek specific performance of this Agreement pursuant to this Section 10.3(b)(ii), Seller shall retain the Deposit, until a non-appealable final judgment or award on Purchaser’s claim for specific performance is rendered, at which time the Deposit shall be distributed as provided in the judgment or award resolving the specific performance claim or shall be applied as provided in Section 2.4 of this Agreement.

(c) If this Agreement terminates for reasons other than those set forth in Section 10.3(a) or Section 10.3(b), Seller shall pay the Deposit to Purchaser, free of any claims by Seller or any other Person with respect thereto, and each Party shall have no further liability hereunder of any nature whatsoever to the other Party, including any liability for Damages (except for the provisions of Sections 5.6, 6.5, 7.6 and 12.4 and the Confidentiality Agreement which shall continue in full force and effect in accordance with their terms), and Seller shall be free immediately to enjoy all rights of ownership of the Assets and to sell, transfer, encumber or otherwise 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 of whether the Deposit is applied against the Purchase Price or returned to Purchaser pursuant to this Section 10.3.

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 or attributable to the Assets (and all products and proceeds attributable thereto) and any other income, proceeds, receipts and credits attributable to the Assets which are not reflected in the adjustments to the Purchase Price following the final adjustment pursuant to Section 9.4(b) shall be treated as follows: (i) all production from or attributable 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 Purchaser is entitled under Section 1.4 shall be the sole property and 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 or attributable 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 under Section 1.4 shall be the sole property and entitlement of Seller and, to the extent received by Purchaser, 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, Seller shall be entitled to retain (and Purchaser shall not be entitled to any decrease to the Purchase Price in respect of) all overhead charges it has collected, billed or which shall be billed later, from non-operating third Person owners relating to the Seller Operated Assets and relating to the period from the Effective Time to the date Seller relinquishes operatorship of the applicable Seller 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 the Closing Date, Purchaser shall assume and hereby agrees to timely fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the obligations and liabilities of Seller, known or unknown, with respect to the Assets, regardless of whether such obligations 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 or transportation contracts, (2) gas balancing obligations and other obligations arising from Imbalances, (3) obligations to pay Property Costs and other costs and expenses attributable to the ownership or operation of the Assets incurred from and after the Effective Time, (4) obligations to pay working interests, royalties, overriding royalties and other interests as to the Suspended Proceeds transferred by Seller to Purchaser, (5) obligations to plug or abandon wells and associated equipment and dismantle structures, and to restore and/or remediate the Assets in accordance with applicable agreements, Leases or Laws (including Environmental Laws), (6) any claims regarding the general method, manner or practice of calculating or making royalty payments (or payments for overriding royalties or similar burdens on production) with

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 to which Seller or its Affiliates purchased or acquired Assets prior to the Closing (all of said obligations and liabilities, subject to the exclusions below, herein being referred to as the “ Assumed Obligations ”); provided, however , that the Assumed Obligations do not include and Purchaser does not assume any obligations or liabilities of Seller to the extent that they are Seller Indemnity Obligations.

(b) Except for Damages for which Seller is required to indemnify Purchaser Indemnitees 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 all Damages incurred or suffered by the Seller Indemnitees:

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

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

(iii) caused by, arising out of or resulting from any breach of any representation or warranty made by Purchaser contained in Article 6 of this Agreement or in 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 asserted by Persons (including Governmental Bodies) with respect to (1) any condition affecting any Asset that violates or requires remediation under Environmental Law, (2) any operations conducted on such Asset that violate any Environmental Law or (3) any remediation required for an Asset under any Environmental Law regardless of whether known or unknown, or whether attributable to periods of time before, on or after the Effective Time.

EVEN IF SUCH DAMAGES ARE CAUSED IN WHOLE OR IN PART BY THE NEGLIGENCE (WHETHER SOLE, JOINT OR CONCURRENT), STRICT LIABILITY OR OTHER LEGAL FAULT OF SELLER INDEMNITEES OR ANY INDEMNIFIED PERSON .

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

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

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

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

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

(iv) caused by the Seller Retained Liabilities.

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

(e) “ Damages ”, for purposes of this Agreement, shall mean the amount of any actual 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 Indemnified Party arising out of or resulting from the indemnified matter, including reasonable fees and expenses of attorneys, consultants, accountants or other agents and experts reasonably incident to matters indemnified against, and the costs of investigation and/or monitoring of such matters, and the costs of enforcement of the indemnity; provided, however , that no Purchaser Indemnitee shall be entitled to indemnification under this Section 11.2 for Damages that constitute (i) loss of profits or other consequential, special or indirect damages suffered by Purchaser, or any punitive damages, or (ii) any liability, loss, cost, expense, claim, award or judgment to the extent resulting from or increased by the actions or omissions of any Purchaser Indemnitee after the Effective Time.

(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 or Purchaser Indemnitee is entitled must be asserted by and through Seller or Purchaser, as applicable.

Section 11.3 Indemnification Actions .

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

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

(b) To make a claim for indemnification under Article 11, an Indemnified Party shall notify the Indemnifying Party of its claim under this Section 11.3, including the specific details of and specific basis under this Agreement for its claim (the “ Claim Notice ”). In the event that the claim for indemnification is based upon a claim by a third party against the Indemnified Party (a “ Third Party Claim ”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has actual knowledge of the Third Party Claim and shall enclose a copy of all papers (if any) served with respect to the Third Party Claim; provided, that the failure of any Indemnified Party to give notice of a Third Party Claim as provided in this Section 11.3 shall not relieve the Indemnifying Party of its obligations under Section 11.2 except to the extent such failure prejudices the Indemnifying Party’s ability to defend against the Third Party Claim. In the event that the claim for indemnification is based upon an inaccuracy or breach of a representation, warranty, covenant or agreement, the Claim Notice shall specify the representation, warranty, covenant or agreement which was inaccurate or breached.

(c) In the case of a claim for indemnification based upon a Third Party Claim, the Indemnifying Party shall have fourteen (14) days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its liability to defend the Indemnified Party against such Third Party Claim at the sole cost and expense of the Indemnifying Party. The Indemnified Party is authorized, prior to and during such fourteen (14)-day period, to file any motion, answer or other pleading that it shall deem necessary or appropriate to protect its interests or those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party all costs of which shall be included as Damages in respect of such claim for indemnification. The failure to 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 obligation to diligently defend, at its sole cost and expense, the Third Party Claim. The Indemnifying Party shall have full control of such defense and proceedings, including any compromise or settlement thereof. If requested by the Indemnifying Party, the Indemnified

Party agrees to cooperate, at the sole cost of the Indemnifying Party, in contesting any Third Party Claim which the Indemnifying Party elects to contest. The Indemnified Party may participate in, but not control, at its sole cost without any right of reimbursement, any defense or settlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section 11.3(d). Irrespective of whether the Indemnified Party elects to participate in contesting a Third Party Claim subject to this Section 11.3(d) in accordance with the foregoing sentence, the Indemnifying Party at its sole cost and expense shall provide to the Indemnified Party the following information with respect to the Third Party Claim: all filings made by any party; all written communications exchanged between any parties to the extent available to the Indemnifying Party and not subject to a restriction on disclosure to the Indemnified Party; and all orders, opinions, rulings or motions. The Indemnifying Party shall deliver the foregoing items to the Indemnified Party promptly after they become available to the Indemnifying Party. An Indemnifying Party shall not, without the written consent of the Indemnified Party (which shall not be unreasonably withheld, conditioned or delayed), (i) settle any Third Party Claim or consent to the entry of any judgment with respect thereto which does not include an unconditional written release of the Indemnified Party from all liability in respect of such Third Party Claim or (ii) settle any Third Party Claim or consent to the entry of any judgment with respect thereto in any manner that may materially and adversely affect the Indemnified Party (other than as a result of money damages 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 fails to diligently prosecute or settle the Third Party Claim, then the Indemnified Party shall have the right to defend against the Third Party Claim at the sole cost and expense of the Indemnifying Party, with counsel of the Indemnified Party’s choosing, subject to the right of the Indemnifying Party to admit its liability and assume the defense of the Third Party Claim at any time prior to settlement or final determination thereof. If the Indemnifying Party has not yet admitted its liability for a Third Party Claim, the Indemnified Party shall send written notice to the Indemnifying Party of any proposed settlement and the Indemnifying Party shall have the option for ten (10) days following receipt of such notice to (i) admit in writing its liability for the Third Party Claim and (ii) if liability is so admitted, reject, in its reasonable judgment, the proposed settlement. If Indemnifying Party fails to respond and admit in writing its liability during such ten (10) day period, the Indemnifying Party will be deemed to have approved such proposed settlement.

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

Section 11.4 Limitation on Actions .

(a) All representations and warranties of Seller and Purchaser contained herein shall survive 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 in this Agreement to be performed on or before Closing shall expire on the day following the Closing Date and each other covenant and agreement of Seller and Purchaser shall, subject to this Section 11.4, survive the Closing until fully performed in accordance with its terms and expire thereafter. The affirmations of representations, warranties, covenants and agreements contained in the certificate delivered by each Party at Closing pursuant to Sections 9.2(f) and 9.3(f), as applicable, shall survive the Closing as to each representation, warranty covenant and agreement so affirmed for the same period of time that the specific representation, warranty, covenant or agreement survives the Closing pursuant to this Section 11.4, and shall expire thereafter. Representations, warranties, covenants and agreements shall terminate and be of no further force and effect after the respective date of their expiration, after which time no claim may be asserted thereunder by any Person, provided, that there shall be no termination of any bona fide 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 the termination date of each respective representation, warranty, covenant or agreement that is subject to indemnification, except in each case as to matters for which a specific written claim for indemnity has been delivered to the Indemnifying Party on or before such termination date. Purchaser’s indemnities in Sections 7.6, 11.2(b)(i), and 11.2(b)(iv) shall continue without time limit. The indemnities in Section 11.2(c) shall terminate on the date that is one hundred eighty (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 not exceed Fifty Thousand Dollars ($50,000.00);

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

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

(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 first anniversary of the Closing Date (including the date that is the first anniversary of the Closing Date).

(d) Seller and Purchaser acknowledge that after the Closing the payment of money, as limited by the terms of this Agreement, shall be adequate compensation for breach of any representation, warranty, covenant or agreement contained in this Agreement or for any other claim arising in connection with or with respect to the transactions contemplated in this Agreement. As the payment of money shall be adequate compensation, Purchaser, Seller waives any 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 appropriate counties as well as the appropriate governmental agencies and provide Seller with copies of all recorded or approved instruments.

Section 11.6 Waivers .

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

(b) Purchaser acknowledges that plugging, abandonment, removal and restoration obligations for the Assets are material and significant. Purchaser acknowledges that Purchaser has conducted 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 no representation 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 is entering into this Agreement in reliance upon Purchaser's agreement to assume such obligations and all other Assumed Obligations and that assumption of the Assumed Obligations constitutes material agreed consideration to Seller in consideration for the Assets.

Section 11.7 Insurance .

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

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 ‎Article 11 shall be treated for all Tax purposes as an adjustment to the purchase price for the Assets unless otherwise 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 original instrument, but all such counterparts together shall constitute but one agreement. Delivery of an executed counterpart signature page by facsimile or electronic transmittal (PDF) is as effective as executing 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 in all 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 Parkway

Austin, Texas 78746

Attn: Steve Bryson

Email: sbryson@jonesenergy.com

WITH A COPY TO:

Baker Botts L.L.P.

98 San Jacinto Blvd. Suite 1500

Austin, TX 78701-4078

Attn: Mike Bengtson

Email: mike.bengtson@bakerbotts.com

If to Purchaser:

Foundation Energy Management, LLC

1801 Broadway, Suite 1500

Denver, Colorado 80202

Attention: Joel P. Sauer, Vice President

Telephone 303-244-8113

Facsimile: 303-244-0604

Email: jsauer@foundationenergy.com

WITH A COPY TO:

Foundation Energy Management, LLC

808 Travis Street, Suite 452

Houston, Texas 77002

Attention: Jay Pollard

Telephone: 972-707-2518

Email: jpollard@foundationenergy.com

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 to the Party to which such notice is addressed, (ii) when transmitted to the Party to which such notice is addressed by confirmed facsimile transmission, or (iii) at the time of receipt by the Party to which such notice is addressed. Notwithstanding the foregoing, delivery by Seller or Purchaser (as applicable) of a Title Defect Notice, Title Benefit Notice or statement of the Purchase Price under Section 9.4, or a response 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 that were previously furnished to the delivering Party and (ii) the delivering Party has provided notice to the other 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 and services, registration, capital, documentary, stamp or transfer Taxes, recording fees and similar Taxes and fees incurred and imposed upon, or with respect to, the property transfers or other transactions contemplated hereby (“ Transfer Taxes ”). Seller will determine, and Purchaser agrees to cooperate with Seller in determining, Transfer Taxes, if any, that applicable law requires Seller to collect from Purchaser in connection with the sale of Assets hereunder, and Purchaser agrees to pay any such tax to Seller at Closing; provided, however , that Seller’s failure to collect any such Transfer Taxes at Closing shall not absolve Purchaser from Purchaser’s responsibility for such Transfer Taxes. If such transfers or transactions are exempt from any such Taxes or fees upon the filing of an appropriate certificate or other evidence of exemption, Purchaser will timely furnish to Seller such certificate or evidence.

Section 12.4 Expenses .

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

Section 12.5 Change of Name .

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

Section 12.6 Replacement of Bonds and Guarantees .

(a) Purchaser acknowledges that none of the bonds, letters of credit and guarantees, if any, 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 to Purchaser. On or before Closing, Purchaser shall obtain, or cause to be obtained in the name of Purchaser, or its Affiliate designee, replacements for such Governmental Bonds to the extent such replacements are necessary (i) for Purchaser’s ownership of the Assets, and (ii) to permit the cancellation of the Governmental Bonds posted by Seller and/or any Affiliate of Seller with respect to the Assets. In addition, at or prior to Closing, Purchaser shall deliver to Seller evidence of the posting of bonds or other security with all applicable Governmental Bodies meeting the requirements 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 to be 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 with Third Parties that are not Governmental Bodies in connection with its ownership and operation of the Assets and which are as set forth in Schedule 12.6(b) (the “ Guarantees ”). Without limiting the 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 be required by such counterparty, substitute guarantee or similar arrangements for all periods covered by the Guarantees, which guarantee or similar arrangements shall (i) constitute a type of security, and (ii) be provided by a party whose creditworthiness is, in each case, equivalent to or better than that required by the counterparty to such Guarantee.

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

with respect to the Assets, then, from and after Closing, Purchaser shall indemnify Seller or any Affiliate 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 in connection with such Guarantee or such Governmental Bond) if applicable to the Assets acquired by Purchaser. Notwithstanding anything to the contrary contained in this Agreement, any cash placed in escrow by Seller or any Affiliate of Seller pursuant to the Guarantees must be returned to Seller as soon as practicable and shall be deemed an Excluded Asset for all purposes hereunder.

Section 12.7 Governing Law and Venue .

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

Section 12.8 Jurisdiction; Waiver of Jury Trial .

EACH PARTY CONSENTS TO PERSONAL JURISDICTION IN ANY ACTION BROUGHT IN THE UNITED STATES FEDERAL COURTS LOCATED WITHIN HARRIS COUNTY, TEXAS (OR, IF JURISDICTION IS NOT AVAILABLE IN THE UNITED STATES FEDERAL COURTS, TO PERSONAL JURISDICTION IN ANY ACTION BROUGHT IN THE STATE COURTS LOCATED IN HARRIS COUNTY, TEXAS) WITH RESPECT TO ANY DISPUTE, CLAIM OR CONTROVERSY ARISING OUT OF OR IN RELATION TO OR IN CONNECTION WITH THIS AGREEMENT, AND EACH OF THE PARTIES AGREES THAT ANY ACTION INSTITUTED BY IT AGAINST THE OTHER WITH RESPECT TO ANY SUCH DISPUTE, CONTROVERSY OR CLAIM (EXCEPT TO THE EXTENT A DISPUTE, CONTROVERSY, OR CLAIM ARISING OUT OF OR IN RELATION TO OR IN CONNECTION WITH THE DETERMINATION OF A TITLE DEFECT AMOUNT OR TITLE BENEFIT AMOUNT PURSUANT TO Section 3.4(h) , OR THE DETERMINATION OF PURCHASE PRICE ADJUSTMENTS PURSUANT TO Section 9.4(b) IS REFERRED TO AN EXPERT PURSUANT TO THOSE SECTIONS) WILL BE INSTITUTED EXCLUSIVELY THE UNITED STATES FEDERAL COURTS LOCATED WITHIN HARRIS COUNTY, TEXAS (OR, IF JURISDICTION IS NOT AVAILABLE IN THE UNITED STATES FEDERAL COURTS, TO PERSONAL JURISDICTION IN ANY ACTION BROUGHT IN THE STATE COURTS LOCATED IN HARRIS COUNTY, TEXAS). THE PARTIES HEREBY WAIVE TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM BROUGHT BY ANY PARTY AGAINST ANOTHER IN ANY MATTER WHATSOEVER ARISING OUT OF OR IN RELATION TO OR IN CONNECTION WITH THIS AGREEMENT. IN ADDITION, EACH PARTY IRREVOCABLY WAIVES ANY OBJECTION, INCLUDING ANY OBJECTION TO THE LAYING OF VENUE OR BASED ON THE GROUNDS OF FORUM NON CONVENIENS, WHICH IT MAY NOW OR HEREAFTER HAVE TO THE BRINGING OF ANY SUCH ACTION IN THE RESPECTIVE JURISDICTIONS REFERENCED IN THIS SECTION.

Section 12.9 Captions .

The captions in this Agreement are for convenience only and shall not be considered a part of or affect 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 herein contained may be waived in writing, but not in any other manner, by the party or parties to whom such compliance is owed. No waiver of, or consent to a change in, any of the provisions of this Agreement shall 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 expressly provided.

Section 12.11 Assignment .

Neither Party shall assign all or any part of this Agreement, nor shall any Party assign or delegate any of its rights or duties hereunder, without the prior written consent of the other Party and any assignment or delegation made without such consent shall be void; provided, that in the event that Purchaser is permitted to assign all or any part of this Agreement or the Assets (a) such assignment shall not relieve Purchaser of any liability or obligation under this Agreement and (b) such assignee shall agree, in writing, to assume Purchaser’s obligations under this Agreement and be jointly and severally liable 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 Schedules attached hereto, together with the Confidentiality Agreement, constitute the entire agreement between the Parties pertaining to the subject matter hereof, and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the Parties pertaining to the subject matter hereof. In the event of a conflict between the Confidentiality Agreement and this Agreement, the terms and provisions of this Agreement shall prevail.

Section 12.13 Amendment .

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

(b) No waiver of any right under this Agreement shall be binding unless executed in writing 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 Persons described in Section 11.2(f).

Section 12.15 Public Announcements .

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

Section 12.16 Invalid Provisions .

If any provision of this Agreement is held to be illegal, invalid or unenforceable under present or future Laws effective during the term hereof, such provision shall be fully severable; this Agreement shall be construed and enforced as if such illegal, invalid or unenforceable provision had never comprised a part hereof; and the remaining provisions of this Agreement shall remain in full force and effect and shall not be effected by the illegal, invalid or unenforceable provision or by its severance from this 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;

(d) Reference to any Exhibit or Schedule means an Exhibit or Schedule to this Agreement, 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” and words of similar import are references to this Agreement as a whole and not any particular Section or other provision of this Agreement; and

(g) “Include” and “including” shall mean include or including without limiting the generality 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 this Agreement and has had the opportunity to exercise business discretion in relation to the

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, none of Purchaser, Seller or any of their respective Affiliates OR INDEMNITEES shall be entitled to either punitive, SPECIAL, INDIRECT or consequential damages in connection with this Agreement and the transactions contemplated hereby and each of Purchaser and Seller, for itself and on behalf of its Affiliates AND INDEMNITEES, hereby expressly waives any right to punitive, SPECIAL, INDIRECT or consequential damages in connection with this Agreement and the transactions contemplated hereby, except to the extent an Indemnified Party is required to pay punitive, SPECIAL, INDIRECT or consequential damages to a third party that is 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, is controlled by or is under common control with such Person.

“ Agreed Interest Rate ” shall mean simple interest computed at the rate of the prime interest rate 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).

“ 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 Foundation Energy 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, the Comprehensive 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 Water Pollution Control Act, 33 U.S.C. § 1251 et seq .; the Clean Air Act, 42 U.S.C. § 7401 et seq . the Hazardous Materials Transportation Act, 49 U.S.C. § 1471 et seq .; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act, 33 U.S.C. § 2701 et seq .; the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. § 11001 et seq .; and the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; and all Laws as of the Effective

Time of any Governmental Body having jurisdiction over the property in question governing operation of the Assets, and otherwise addressing pollution or protection of the environment and all regulations implementing the foregoing. Notwithstanding the foregoing, the phrase “violation of Environmental Laws” and words of similar import used herein shall mean, as to any given Asset, the violation of or failure to meet specific objective requirements or standards that are clearly applicable to such Asset under applicable Environmental Laws where such requirements or standards are in effect as of the Effective Time. The phrase does not include good or desirable operating practices or standards that may be 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 (including costs of remediation), Damages, natural resource damages, settlements, consulting fees, expenses, penalties, fines, orphan share, prejudgment and post-judgment interest, court costs, attorneys’ fees, and other 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 any Environmental Law which is attributable to the ownership or operation of the Properties prior to the Effective Time or (ii) pursuant to any claim or cause of action by a Governmental Body or other Person for personal injury, property damage, damage to natural resources to the extent arising out of any violation of any Environmental Law to the extent attributable to the ownership or operation of the Properties prior to the Effective Time, provided, that Environmental Liabilities excludes any of the foregoing 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 (including cores and other physical samples of materials from wells or tests) belonging to Seller or licensed from third parties relating to the Properties that can be transferred without additional consideration to such third parties (or including such licensed data in the event Purchaser agrees to pay such additional consideration), including all such data having been acquired by Seller from its predecessors in title, and including, 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, but excluding 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; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal.

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

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

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

“ Imbalance ” means any over-production, under-production, over-delivery, under-delivery or similar imbalance of Hydrocarbons produced from or allocated to the Assets, regardless of whether such imbalance arises at the platform, wellhead, pipeline, gathering system, transportation system, processing plant 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 of Governmental Bodies.

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

“ Lowest Cost Response ” means the response required or allowed under Environmental Laws that cures, remediates, removes or remedies the applicable present condition alleged pursuant to an Environmental Defect Notice at the lowest cost (considered as a whole taking into consideration any material negative impact such response may have on the operations of the relevant Assets and any potential 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 or allowed under Environmental Laws. The Lowest Cost Response shall include taking no action, leaving the condition unaddressed, periodic monitoring or the recording of notices in lieu of remediation, if such responses are allowed under Environmental Laws.

“ Material Adverse Effect ” means any adverse effect on the ownership, operation or value of the 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 material adverse 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 the area in which the Assets are located, the United States or worldwide; (b) changes in Laws or in regulatory policies from and after the date of this Agreement; (c) changes or conditions resulting from civil unrest or terrorism or acts of God or natural disasters; (d) change or conditions resulting from the failure of a Governmental Body to act or omit to act pursuant to Law; (e) entering into this Agreement or the announcement of the transactions contemplated by this Agreement; (f) changes in conditions or developments generally applicable to the oil and gas

industry in the area where the Assets are located; (g) matters that are cured or no longer exist by the earlier 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 of Hydrocarbons; and (j) natural declines in well performance.

“ Net Acre ” means, as calculated separately with respect to Lands covered by each Lease in a PLSS Section, the product of: (i) the number of gross acres of land covered by such Lease, multiplied by (ii) the mineral interest ownership in the Hydrocarbons covered by such Lease (i.e. the lessor’s mineral interest ownership and the non-executive mineral ownership, if any, covered by the particular Lease), multiplied by (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, joint venture, association, trust, unincorporated organization, government or agency or subdivision thereof or any other entity.

“ PLSS Section ” means a section designated by the applicable public land survey system and identified 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).

“ 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 of this Agreement.

“Seller Retained Liabilities” means those liabilities and obligations of the Seller arising from the 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’s ownership or operation of the Assets for periods prior to the Closing Date, including death or physical 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 defined or regulated as a “pollutant,” “hazardous waste” or “hazardous substance” under any Environmental Law;

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

(e) all losses, claims, damages, costs and liabilities arising from any actions, suits or 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, or the sale of property to another person subject to an understanding or agreement, contingent or otherwise, to repurchase such property from such other person); and all obligations of Seller evidenced by a note, bond, debenture, or similar instrument or

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

(h) all employment relationships of Seller or any Affiliate of Seller, including any of their respective present or former employees or the termination of any such employment relationships, including the compensation or reimbursement for work performed with respect to the 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 and other similar liens or charges which are Permitted Encumbrances and which are being contested by 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, ad valorem, property, severance, production, excise, stamp, documentary, real property transfer or gain, gross receipts, goods and services, registration, capital, transfer, or withholding Taxes or other governmental fees or charges imposed by any taxing authority, including any interest, penalties or additional 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).

“ 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).

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 Jones

Name: Jonny Jones

Title: 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 its Sole Manager

By: /s/ Joel P. Sauer

Name: Joel P. Sauer

Title: 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 as part of the Assets to be conveyed to Purchaser hereunder. In the event that between the date of the execution of this Agreement and Closing it is determined that there are Leases that have been inadvertently 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 A to include those Leases which have been inadvertently omitted or incorrectly described.

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Exhibit 31.1

Certification by Chief Executive Officer pursuant to

Rule 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:

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

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

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 periods presented in this report;

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 (as defined 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 consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is 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 and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(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 by this 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) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

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 persons performing 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 and report 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 to

Rule 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:

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

(a)

(b)

(c)

(d)

(a)

(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

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Exhibit 32.1

Certification Pursuant to

18 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 Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge:

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

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 retained and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32.2

Certification Pursuant to

18 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 Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge:

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

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