Jones Energy, Inc. (Form: 10-Q, Received: 11/04/2016 07:05:30)

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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 September 30, 2016

☐ 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, or a smaller reporting company. See the definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting 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)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

On October 28, 2016, the Registrant had 57,009,550 shares of Class A common stock outstanding and 29,832,098 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

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	34

Item 3. Quantitative and Qualitative Disclosures About Market Risk	46

Item 4. Controls and Procedures	47

PART II—OTHER INFORMATION	49

Item 1. Legal Proceedings	49

Item 1A. Risk Factors	49

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, including guidance regarding the timing and location of our anticipated drilling and completion activity, including with respect to the recently acquired acreage in the Merge, our ability to increase capital spending in connection with leasing, our ability to mitigate commodity price risk through our hedging program, our revised 2016 capital expenditure program, our ability to maintain compliance with our debt covenants, JEH’s obligations to pay cash distributions, and our ability to successfully execute our 2016 development plan and guidance for the remaining quarter and full year 2016. 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 2016 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)


	September 30,		December 31,
(in thousands of dollars)	2016		2015
Assets
Current assets
Cash	$	24,041	$	21,893
Accounts receivable, net
Oil and gas sales		20,720		19,292
Joint interest owners		4,880		11,314
Other		10,015		15,170
Commodity derivative assets		48,784		124,207
Other current assets		2,603		2,298
Total current assets		111,043		194,174
Oil and gas properties, net, at cost under the successful efforts method		1,742,165		1,635,766
Other property, plant and equipment, net		3,186		3,873
Commodity derivative assets		50,469		93,302
Other assets		6,406		8,039
Total assets	$	1,913,269	$	1,935,154
Liabilities and Stockholders' Equity
Current liabilities
Trade accounts payable	$	27,328	$	7,467
Oil and gas sales payable		26,445		32,408
Accrued liabilities		28,793		27,011
Commodity derivative liabilities		1,618		11
Asset retirement obligations		679		679
Total current liabilities		84,863		67,576
Long-term debt		688,432		837,654
Deferred revenue		9,589		11,417
Commodity derivative liabilities		526		—
Asset retirement obligations		27,452		20,301
Liability under tax receivable agreement		43,212		38,052
Other liabilities		656		330
Deferred tax liabilities		16,070		22,972
Total liabilities		870,800		998,302
Commitments and contingencies (Note 14)
Mezzanine equity
Series A preferred stock, $0.001 par value; 1,840,000 shares issued and outstanding at September 30, 2016 and no shares issued and outstanding at December 31, 2015		88,743		—
Stockholders' equity
Class A common stock, $0.001 par value; 56,991,824 shares issued and 56,969,222 shares outstanding at September 30, 2016 and 30,573,509 shares issued and 30,550,907 shares outstanding at December 31, 2015		57		31
Class B common stock, $0.001 par value; 29,872,426 shares issued and outstanding at September 30, 2016 and 31,273,130 shares issued and outstanding at December 31, 2015		30		31
Treasury stock, at cost: 22,602 shares at September 30, 2016 and December 31, 2015		(358)		(358)
Additional paid-in-capital		447,400		363,723
Retained (deficit) / earnings		21,617		36,569
Stockholders' equity		468,746		399,996
Non-controlling interest		484,980		536,856
Total stockholders’ equity		953,726		936,852
Total liabilities and stockholders' equity	$	1,913,269	$	1,935,154

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 September 30,				Nine months ended September 30,
(in thousands of dollars except per share data)	2016		2015		2016		2015
Operating revenues
Oil and gas sales	$	32,582	$	46,499	$	86,060	$	156,955
Other revenues		771		653		2,295		2,210
Total operating revenues		33,353		47,152		88,355		159,165
Operating costs and expenses
Lease operating		7,865		8,872		24,027		32,930
Production and ad valorem taxes		1,733		2,513		5,061		9,292
Exploration		998		5,556		1,237		6,184
Depletion, depreciation and amortization		36,550		52,766		116,449		156,151
Accretion of ARO liability		323		210		913		610
General and administrative		6,448		9,628		22,078		27,572
Other operating		—		—		—		4,188
Total operating expenses		53,917		79,545		169,765		236,927
Operating income (loss)		(20,564)		(32,393)		(81,410)		(77,762)
Other income (expense)
Interest expense		(12,792)		(16,722)		(40,397)		(47,553)
Gain on debt extinguishment		—		—		99,530		—
Net gain (loss) on commodity derivatives		4,014		90,483		(18,769)		111,714
Other income (expense)		364		(7)		251		(1,631)
Other income (expense), net		(8,414)		73,754		40,615		62,530
Income (loss) before income tax		(28,978)		41,361		(40,795)		(15,232)
Income tax provision (benefit)		(6,549)		6,519		(8,234)		(4,590)
Net income (loss)		(22,429)		34,842		(32,561)		(10,642)
Net income (loss) attributable to non-controlling interests		(12,576)		21,604		(18,374)		(7,625)
Net income (loss) attributable to controlling interests	$	(9,853)	$	13,238	$	(14,187)	$	(3,017)
Dividends and accretion on preferred stock		(765)		—		(765)		—
Net income (loss) attributable to common shareholders	$	(10,618)	$	13,238	$	(14,952)	$	(3,017)

Earnings (loss) per share:
Basic - Net income (loss) attributable to common shareholders	$	(0.26)	$	0.44	$	(0.44)	$	(0.12)
Diluted - Net income (loss) attributable to common shareholders	$	(0.26)	$	0.44	$	(0.44)	$	(0.12)

Weighted average shares outstanding:
Basic		41,375		30,432		34,300		25,591
Diluted		41,375		30,432		34,300		25,591

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, 2015	30,551	$	31	31,273	$	31	23	$	(358)	$	363,723	$	36,569	$	536,856	$	936,852
Stock-compensation expense	—		—	—		—	—		—		5,269		—		—		5,269
Vested restricted shares	369		—	—		—	—		—		—		—		—		—
Distributions from partnership (Cash tax distribution)	—		—	—		—	—		—		—		—		(10,109)		(10,109)
Sale of common stock	24,648		25	—		—	—		—		65,523		—		—		65,548
Exchange of Class B shares for Class A shares	1,401		1	(1,401)		(1)	—		—		12,885		—		(23,393)		(10,508)
Preferred dividends on redeemable non-controlling interest	—		—	—		—	—		—		—		(716)		—		(716)
Accretion of redeemable non-controlling interest	—		—	—		—	—		—		—		(49)		—		(49)
Net income (loss)	—		—	—		—	—		—		—		(14,187)		(18,374)		(32,561)
Balance at September 30, 2016	56,969	$	57	29,872	$	30	23	$	(358)	$	447,400	$	21,617	$	484,980	$	953,726

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)


	Nine months ended September 30,
(in thousands of dollars)	2016		2015
Cash flows from operating activities
Net income (loss)	$	(32,561)	$	(10,642)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, and amortization		116,449		156,151
Exploration (dry hole and lease abandonment)		945		5,250
Accretion of ARO liability		913		610
Amortization of debt issuance costs		3,083		3,379
Stock compensation expense		5,269		5,287
Deferred and other non-cash compensation expense		614		326
Amortization of deferred revenue		(1,828)		(1,521)
(Gain) loss on commodity derivatives		18,769		(111,714)
(Gain) loss on sales of assets		(68)		(10)
(Gain) on debt extinguishment		(99,530)		—
Deferred income tax provision		(11,824)		(4,590)
Other - net		805		1,178
Changes in operating assets and liabilities
Accounts receivable		8,964		54,244
Other assets		(466)		719
Accrued interest expense		(1,050)		9,577
Accounts payable and accrued liabilities		6,425		(19,185)
Net cash provided by operations		14,909		89,059
Cash flows from investing activities
Additions to oil and gas properties		(210,878)		(280,528)
Proceeds from sales of assets		74		37
Acquisition of other property, plant and equipment		(194)		(1,034)
Current period settlements of matured derivative contracts		106,151		103,858
Net cash (used in) investing		(104,847)		(177,667)
Cash flows from financing activities
Proceeds from issuance of long-term debt		75,000		75,000
Repayment under long-term debt		(42,000)		(335,000)
Proceeds from senior notes		—		236,475
Purchase of senior notes		(84,589)		—
Payment of debt issuance costs		—		(1,514)
Net distributions paid to JEH unitholders		(10,109)		—
Proceeds from sale of common stock		65,548		122,779
Proceeds from sale of preferred stock		88,236		—
Net cash provided by financing		92,086		97,740
Net increase (decrease) in cash		2,148		9,132
Cash
Beginning of period		21,893		13,566
End of period	$	24,041	$	22,698
Supplemental disclosure of cash flow information
Cash paid for interest	$	38,380	$	34,594
Change in accrued additions to oil and gas properties		9,031		(94,552)
Asset retirement obligations incurred, including changes in estimate		6,785		1,370

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 and through private equity funds managed by Metalmark Capital and Wells Fargo Energy Capital (collectively, the “Pre-IPO Owners”). 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 owners of JEH prior to the Company’s initial public offering (“IPO”) 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 September 30, 2016, the Company held 56,969,222 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 29,872,426 JEH Units are held by the Pre-IPO Owners. The Pre-IPO Owners 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 1.84 million 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, for gross proceeds of approximately $92 million, before underwriting discounts and commissions of $3.68 million. 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. The Company’s assets are located within the Western Anadarko, Eastern Anadarko and Arkoma basins of Texas and Oklahoma, 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, 2015 and the

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financial statements reported for September 30, 2016 and 2015 and the three and nine 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 September 30, 2016 and 2015 have been prepared in accordance with GAAP accounting principles 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, 2015.

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, 2015.

Recent Accounting Pronouncements

Adopted in the current year-to-date period:

In January 2015, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2015-01, “Income Statement—Extraordinary and Unusual Items.” This ASU removes the concept of extraordinary items from GAAP. Under existing guidance, an entity is required to separately disclose extraordinary items, net of tax, in the income statement after income from continuing operations if an event or transaction is of an unusual nature and occurs infrequently. This separate, net of tax presentation will no longer be allowed. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. Therefore, the Company adopted ASU No. 2015-01 beginning in the period ended March 31, 2016. Adoption did not have a material impact on the financial position, cash flows or results of operations.

In April 2015, the FASB issued ASU No. 2015-03, “Interest—Imputation of Interest” (Subtopic 835-30): “Simplifying the Presentation of Debt Issuance Costs.” Entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. The ASU does not change the recognition, measurement, or subsequent measurement guidance for debt issuance costs. Adoption of this ASU will be applied retrospectively. In August 2015, the FASB issued ASU No. 2015-15, “Interest—Imputation of Interest” (Subtopic 835-30), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within ASU No. 2015-03 for debt issuance costs related to line-of-credit arrangements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. Therefore, the Company adopted ASU No. 2015-03 beginning with the period ended March 31, 2016. Changes to the balance sheet have been applied on a retrospective basis. This resulted in the reclassification of debt issuance costs of $10.3 million from Other assets to Long-term debt in the Consolidated Balance Sheet for the period ended December 31, 2015. Adoption did not have a material impact on the financial position, cash flows or results of operations.

To be adopted in a future period:

In May 2014, the FASB issued ASU No. 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

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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 currently evaluating the effect that the adoption of Update 2014‑09 and Update 2015‑14 will have on our financial statements.

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.

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. Early adoption is permitted. The Company is currently evaluating the effect that the adoption of ASU 2016-09 will have on our financial statements.

3. Acquisitions

Merge Acquisition

On August 18, 2016, JEH entered into a definitive purchase and sale agreement with SCOOP Energy Company, LLC, an Oklahoma limited liability company, to acquire oil and gas properties located in the Merge area of the STACK/SCOOP (the “Merge”) play in Central Oklahoma (the “Merge Acquisition”). The oil and gas properties acquired in the Merge Acquisition principally consist of approximately 18,000 undeveloped net acres in Canadian, Grady and McClain Counties, Oklahoma. The Company closed the Merge Acquisition on September 22, 2016, for cash consideration of approximately $136.5 million, subject to customary post-closing adjustments. This transaction has been accounted for as an asset acquisition. The Company used proceeds from our equity offerings to fund the purchase. See Note 11, “Stockholders’ and Mezzanine equity”.

Anadarko Acquisition

On August 3, 2016, JEH LLC entered into a definitive agreement to acquire producing and undeveloped oil and gas assets in the Western Anadarko Basin (the “Anadarko Acquisition”) for $27.1 million, subject to customary closing adjustments. 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, subject to reductions for exercised preferential purchase rights and failures to obtain required consents. The Company closed the Anadarko Acquisition on August 25, 2016, at which time, the acquired acreage was producing approximately 900 barrels of oil equivalent per day. This transaction was accounted for as a business combination. The Company allocated the entire purchase price of $27.1 million to “Oil and gas properties,” based on the respective fair values of the assets acquired. The Anadarko Acquisition did not result in a significant impact to net income and as such, pro forma financial information was not included. The Company funded the Anadarko Acquisition with cash on hand.

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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 September 30, 2016 and December 31, 2015:


	September 30,		December 31,
(in thousands of dollars)	2016		2015
Mineral interests in properties
Unproved	$	205,589	$	75,308
Proved		1,060,465		1,031,669
Wells and equipment and related facilities		1,353,160		1,289,323
		2,619,214		2,396,300
Less: Accumulated depletion and impairment		(877,049)		(760,534)
Net oil and gas properties	$	1,742,165	$	1,635,766

One exploratory well was drilled during the nine months ended September 30, 2016, for which associated costs of $1.2 million were capitalized. There were no exploratory wells drilled during the nine months ended September 30, 2015 and, as such, no associated costs were capitalized. No exploratory wells resulted in exploration expense during either year.

The Company did not capitalize any interest during the nine months ended September 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 $36.3 million and $115.6 million for the three and nine months ended September 30, 2016, respectively, and $52.5 million and $155.3 million for the three and nine months ended September 30, 2015, respectively.

Due to recent fluctuations in forward commodity prices, the Company continued to monitor its proved and unproved properties for impairment as of September 30, 2016, and no impairment charges were recorded in the quarter.

Other Property, Plant and Equipment

Other property, plant and equipment consisted of the following at September 30, 2016 and December 31, 2015:


	September 30,		December 31,
(in thousands of dollars)	2016		2015
Leasehold improvements	$	1,213	$	1,260
Furniture, fixtures, computers and software		4,124		4,090
Vehicles		1,606		1,537
Aircraft		910		910
Other		284		247
		8,137		8,044
Less: Accumulated depreciation and amortization		(4,951)		(4,171)
Net other property, plant and equipment	$	3,186	$	3,873

Depreciation and amortization of other property, plant and equipment amounted to $0.3 million and $0.9 million for the three and nine months ended September 30, 2016, respectively, and $0.3 million and $0.9 million for the three and nine months ended September 30, 2015, respectively.

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5. Long-Term Debt

Long-term debt consisted of the following at September 30, 2016 and December 31, 2015:


(in thousands of dollars)	September 30, 2016		December 31, 2015
Revolver	$	143,000	$	110,000
2022 Notes		409,148		500,000
2023 Notes		150,000		250,000
Total principal amount		702,148		860,000
Less: unamortized discount		(6,494)		(12,088)
Less: debt issuance costs, net		(7,222)		(10,258)
Total carrying amount	$	688,432	$	837,654

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 the nine months ended September 30, 2016, through several open market and privately negotiated purchases, the Company purchased an aggregate principal amount of $190.9 million of its senior unsecured notes. As of September 30, 2016, the Company had 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 nine months ended September 30, 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 other than the new subsidiary formed to acquire the properties in the Merge Acquisition, which is required to become a guarantor no later than January 31, 2017. 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,

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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 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 September 30, 2016, 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. The borrowing base on the Revolver was subsequently adjusted to $562.5 million in accordance with its terms as a result of the issuance of the 2023 Notes in February 2015 and was reaffirmed at this level effective April 1, 2015. Effective October 8, 2015, the borrowing base was reduced to $510.0 million during the semi-annual borrowing base re-determination.

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 semi-annual borrowing base re-determination effective October 24, 2016.

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 nine months ended September 30, 2016, the average interest rates under the Revolver were 2.29% and 2.38%, respectively, on average outstanding balances of $184.5 million and $170.9 million, respectively. For the three and nine months ended September 30, 2015, the average interest rates under the Revolver were 2.31% and 2.40%, respectively, on average outstanding balances of $100.0 million and $156.7 million, respectively.

Total interest and commitment fees under the Revolver were $1.3 million and $4.0 million for the three and nine months ended September 30, 2016, respectively, and $1.0 million and $4.0 million for the three and nine months ended September 30, 2015, respectively.

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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 4.00 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.

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 September 30, 2016 and December 31, 2015:

Hedging Positions


	September 30, 2016
						Weighted		Final
		Low		High		Average		Expiration
Oil swaps	Exercise price	$	41.59	$	90.50	$	65.43	June 2019
	Offset exercise price	$	34.70	$	49.00		46.04
	Net barrels per month		—		156,000		93,333
Natural gas swaps	Exercise price	$	2.25	$	5.25	$	3.71	June 2019
	Offset exercise price	$	2.34	$	3.02	$	2.83
	Net mmbtu per month		—		1,470,000		1,018,182
Basis swaps	Contract differential	$	(0.30)	$	(0.15)	$	(0.18)	December 2016
	mmbtu per month		1,190,000		1,220,000		1,203,333
Natural gas liquids swaps	Exercise price	$	8.90	$	78.86	$	25.43	December 2017
	Barrels per month		110,000		126,000		116,467
Oil collars	Puts (floors)	$	45.00	$	50.00	$	48.46	December 2019
	Calls (ceilings)	$	56.60	$	61.00		59.62
	Net barrels per month		65,000		65,000		65,000


	December 31, 2015
						Weighted		Final
		Low		High		Average		Expiration
Oil swaps	Exercise price	$	54.53	$	100.87	$	79.16	June 2019
	Barrels per month		54,000		194,000		97,119
Natural gas swaps	Exercise price	$	3.22	$	6.45	$	4.25	June 2019
	mmbtu per month		700,000		1,640,000		1,042,857
Basis swaps	Contract differential	$	(0.39)	$	(0.11)	$	(0.18)	December 2016
	mmbtu per month		1,190,000		1,730,000		1,360,833
Natural gas liquids swaps	Exercise price	$	8.90	$	95.24	$	32.62	December 2017
	Barrels per month		2,000		112,000		51,792

The Company recognized net gains on derivative instruments of $4.0 million and net losses of $18.8 million for the three and nine months ended September 30, 2016, respectively. The Company recognized net gains on derivative instruments of $90.5 million and $111.7 million for the three and nine months ended September 30, 2015, respectively.

The Company routinely enters into oil and natural gas swap contracts as seller, thus resulting in a fixed price. In early 2016, 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

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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 current contract terms, the gains will be recognized as the hedge contracts mature in 2018 and 2019. 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.

Offsetting Assets and Liabilities

As of September 30, 2016, 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 September 30, 2016 and December 31, 2015:


					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
September 30, 2016
Commodity derivative contracts
Assets	$	119,012	$	(19,759)	$	99,253	$	—	$	99,253
Liabilities		(21,903)		19,759		(2,144)		—		(2,144)
December 31, 2015
Commodity derivative contracts
Assets	$	218,036	$	(527)	$	217,509	$	—	$	217,509
Liabilities		(538)		527		(11)		—		(11)

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

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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.

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 September 30, 2016 and December 31, 2015, by consolidated balance sheet caption and by valuation hierarchy, as described above are as follows:


(in thousands of dollars)	September 30, 2016
	Fair Value Measurements Using
Commodity Price Hedges	(Level 1)		(Level 2)		(Level 3)		Total
Current assets (1)	$	—	$	49,168	$	(384)	$	48,784
Long-term assets (1)		—		51,189		(720)		50,469
Current liabilities		—		1,563		55		1,618
Long-term liabilities		—		526		—		526


(in thousands of dollars)	December 31, 2015
	Fair Value Measurements Using
Commodity Price Hedges	(Level 1)		(Level 2)		(Level 3)		Total
Current assets	$	—	$	122,779	$	1,428	$	124,207
Long-term assets		—		93,302		—		93,302
Current liabilities		—		11		—		11
Long-term liabilities		—		—		—		—

(1)

Level 3 current assets are negative as a result of the netting of our commodity derivative reflected on our Consolidated Balance Sheet as of September 30, 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 September 30, 2016:


	Quantitative Information About Level 3 Fair Value Measurements
	Fair Value			Unobservable
Commodity Price Hedges	(000’s)		Valuation Technique	Input	Range
Natural gas liquid swaps	$	(562)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$8.90 - $25.20 per barrel
Crude oil collars	$	(597)	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

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 nine months ended September 30, 2016. 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.


(in thousands of dollars)
Balance at December 31, 2015, net	$	1,428
Purchases		(3,339)
Settlements		(667)
Transfers to Level 2		2,363
Transfers to Level 3		—
Changes in fair value		(944)
Balance at September 30, 2016, net	$	(1,159)

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:


	September 30, 2016				December 31, 2015
	Principal				Principal
(in thousands of dollars)	Amount		Fair Value		Amount		Fair Value
Debt:
Revolver	$	143,000	$	143,000	$	110,000	$	110,000
2022 Notes		409,148		352,121		500,000		260,000
2023 Notes		150,000		142,032		250,000		153,283

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.

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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.

The Company reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. As such, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

8. Asset Retirement Obligations

A summary of the Company’s Asset Retirement Obligations (“ARO”) for the nine months ended September 30, 2016 is as follows:


(in thousands of dollars)
Balance at December 31, 2015	$	20,980
Liabilities incurred (1)		6,736
Accretion of ARO liability		913
Liabilities settled due to sale of related properties		(446)
Liabilities settled due to plugging and abandonment		(101)
Change in estimate		49
Total ARO balance at September 30, 2016		28,131
Less: Current portion of ARO		(679)
Total long-term ARO at September 30, 2016	$	27,452

(1)

Includes $6.4 million related to wells acquired in the Anadarko Acquisition. See Note 3, “Acquisitions”.

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 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 September 30, 2016:


		Weighted Average
		Grant Date Fair Value
	JEH Units	per Share
Unvested at December 31, 2015	189,355	$	15.00
Granted	40,630		15.00
Forfeited	(40,630)		15.00
Vested	(98,593)		15.00
Unvested at September 30, 2016	90,762	$	15.00

Stock compensation expense associated with the Management Units was $0.2 million and $1.0 million for the three and nine months ended September 30, 2016, respectively, and $0.3 million and $0.9 million for the three

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and nine months ended September 30, 2015, 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 amended on May 4, 2016 following approval by the Company’s stockholders, the Company has reserved a total of 7,350,000 shares of Class A common stock for non-employee director, consultant, and employee stock-based compensation awards.

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 and 2016. During 2016, the Company also granted performance unit awards to certain members of the senior management team under the LTIP.

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.

The following table summarizes information related to the total number of units awarded to officers and employees as of September 30, 2016:


	Restricted	Weighted Average
	Stock Unit	Grant Date Fair Value
	Awards	per Share
Unvested at December 31, 2015	757,245	$	11.65
Granted	941,010		3.99
Forfeited	(194,258)		9.96
Vested	(229,388)		11.75
Unvested at September 30, 2016	1,274,609	$	6.24

Stock compensation expense associated with the employee restricted stock unit awards was $1.0 million and $2.0 million for the three and nine months ended September 30, 2016, respectively, and $0.9 million and $2.1 million for the three and nine months ended September 30, 2015, 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.

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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 nine months ended September 30, 2016:


Forecast period (years)	2.60
Risk-free interest rate	1.00	%
Jones stock price volatility	71.47	%

For the performance share units granted during the nine months ended September 30, 2016, the Monte Carlo simulation model resulted in approximately 69% of performance share units expected to be earned.

The following table summarizes information related to the total number of performance share units awarded to the senior management team as of September 30, 2016:


	Performance	Weighted Average
	Share Unit	Grant Date Fair Value
	Awards	per Share
Unvested at December 31, 2015	539,188	$	14.22
Granted	551,252		4.75
Forfeited	(55,235)		13.27
Vested	—		—
Unvested at September 30, 2016	1,035,205	$	9.23

Stock compensation expense associated with the performance share unit awards was $0.8 million and $1.9 million for the three and nine months ended September 30, 2016, respectively, and $0.7 million and $1.7 million for the three and nine months ended September 30, 2015, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

Performance Unit Awards

The Company has outstanding performance unit awards, granted initially in 2016, to certain members of the senior management team of the Company under the LTIP. References to performance unit awards in prior filings do not correspond to these newly created performance unit awards. Upon the completion of the applicable three-year performance period, each recipient may vest in a number of performance units. The value of awarded performance units in which each recipient vests at such time, if any, will range from $0.0 to $200.0 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 results in an estimated final value upon vesting of $1.3 million. The fair value measured as of September 30, 2016 was the same as the grant date value of $1.3 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 nine months ended September 30, 2016:


Forecast period (years)	2.60
Risk-free interest rate	1.00	%
Jones stock price volatility	71.47	%

For the performance units granted during the nine months ended September 30, 2016, the Monte Carlo simulation model resulted in a payout of $67.38 per performance unit was expected to be earned as of the grant date.

Stock compensation expense associated with the performance unit awards was $0.1 million and $0.2 million for the three and nine months ended September 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. As of September 30, 2016, $1.1 million of

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unrecognized compensation expense related to the performance unit awards, 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 2.25 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 September 30, 2016:


		Weighted Average
	Restricted	Grant Date Fair Value
	Stock Awards	per Share
Unvested at December 31, 2015	67,380	$	7.30
Granted	139,825		4.00
Forfeited	—		—
Vested	(67,380)		7.30
Unvested at September 30, 2016	139,825	$	4.00

Stock compensation expense associated with awards to the members of the Board of Directors was $0.1 million and $0.4 million for the three and nine months ended September 30, 2016, respectively, and $0.1 million and $0.4 million for the three and nine months ended September 30, 2015, 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 22.6% and 20.2% for the three and nine months ended September 30, 2016, respectively and 15.8% and 30.1% for the three and nine months ended September 30, 2015, respectively. 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, and other permanent differences between book and tax accounting.

The Company had an income tax benefit of $6.5 million and $8.2 million for the three and nine months ended September 30, 2016, respectively, and an expense of $6.5 million and a benefit of $4.6 million for the three and nine months ended September 30, 2015, 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 September 30,				Nine Months Ended September 30,
(in thousands of dollars)	2016		2015		2016		2015
Jones Energy, Inc.	$	(6,254)	$	7,157	$	(7,900)	$	(3,195)
Non-controlling interest		(295)		(638)		(334)		(1,395)
Income tax provision (benefit)	$	(6,549)	$	6,519	$	(8,234)	$	(4,590)

The Company had deferred tax assets for its federal and state net operating loss carry forwards at September 30, 2016 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 September 30, 2016, we have a valuation allowance of $2.7 million as a result of management’s assessment of the realizability of deferred tax assets in Oklahoma. 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

As of September 30, 2016 and December 31, 2015 the Company had recorded a Tax Receivable Agreement (“TRA”) liability of $43.2 million and $38.1 million net of valuation allowance, respectively, for the estimated payments that will be made to the pre-IPO members who have exchanged JEH Units (and shares of Class B common stock) for shares of Class A common stock. Such exchanges generated tax basis increases leading to deferred tax assets as of September 30, 2016 and December 31, 2015 of $50.6 million and $44.8 million, respectively, net of valuation allowance. The amount of the TRA liability was increased by $5.3 million and $5.5 million during the three and nine months ended September 30, 2016, respectively, as a result of exchanges that have occurred year to date. During the three and nine months ended September 30, 2016 the TRA liability increase has been offset by $0.1 and $0.3 million, respectively, as a result of the valuation allowance recorded against the Company’s deferred tax assets. Of the change, during the three and nine months ended September 30, 2016, $0.3 million and $0.4 million, respectively, has been included in other income (expense) on the Company’s Consolidated Statement of Operations with the remainder recorded against equity. 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 September 30, 2016, the Company had not made any payments under the TRA to pre-IPO members who have exchanged JEH Units and Class B common stock for Class A common stock.

Cash Tax Distributions

The holders of JEH Units, including Jones Energy, Inc., 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 of $20.0 million to its unitholders towards its total 2016 projected tax distribution obligation. The distributions were made with respect to the first and second quarters of 2016, pro-rata to all members of JEH, and included a $9.9 million payment to the Company. The 2016 tax distributions are the result of taxable income generated by our operations and debt extinguishment.

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 Jones Energy Holdings, LLC entered into an Equity Distribution Agreement (“Equity Distribution Agreement”) with Citigroup Global Markets Inc. and Wells Fargo Securities, LLC (each, a

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“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 nine months ended September 30, 2016, the Company sold approximately 0.5 million Class A Shares under the Equity Distribution Agreement for net proceeds of approximately $1.8 million ($2.1 million gross proceeds, net of approximately $0.3 million in commissions and professional services expenses). The Company used the net proceeds for general corporate purposes. At September 30, 2016, approximately $70.9 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 19, 2016, the Company and JEH LLC entered into an underwriting agreement (the “Common Stock Underwriting Agreement”) with Credit Suisse Securities (USA) LLC and J.P. Morgan Securities LLC, as representatives of the underwriters named therein (the “Common Stock Underwriters”), with respect to the offer and sale of 21,000,000 shares of the Company’s Class A common stock, par value $0.001 per share (the “Class A Common Stock”). The Common Stock Underwriting Agreement also provided the Common Stock Underwriters an option (the “Common Stock Option”) to purchase an additional 3,150,000 shares of Class A Common Stock (the “Additional Offering”) within 30 days of the date of the Common Stock Underwriting Agreement. On September 7, 2016, the Underwriters exercised the Common Stock Option in full. The total net proceeds from the offering of Class A Common Stock (after underwriters’ compensation, but before estimated expenses) pursuant to the Common Stock Underwriting Agreement, including the exercise of the Common Stock Option, was $64.0 million. The Class A Common Stock was issued pursuant to the Company’s shelf registration statement on Form S-3 (Registration No. 333-211568), which became effective July 26, 2016, and a prospectus, which consists of a base prospectus, dated as of July 26, 2016, and a prospectus supplement, dated August 19, 2016. The closing of the sale of Class A Common Stock occurred on August 26, 2016 and the Additional Offering closed on September 12, 2016.

Offering of 8.0% Series A Perpetual Convertible Preferred Stock

On August 19, 2016, the Company and JEH LLC entered into an underwriting agreement (the “Preferred Stock Underwriting Agreement”) with Credit Suisse Securities (USA) LLC and J.P. Morgan Securities LLC (the “Preferred Stock Underwriters”) with respect to the offer and sale of 1,600,000 shares of the Series A preferred stock. The Preferred Stock Underwriting Agreement also provided the Preferred Stock Underwriters an option (the “Preferred Stock Option”) to purchase an additional 240,000 shares of Series A preferred stock, which was exercised in full. The total net proceeds from the offering of Series A preferred stock (after underwriters’ compensation, but before estimated expenses) pursuant to the Preferred Stock Underwriting Agreement, including the exercise of the Preferred Stock Option, was $88.3 million. The Series A preferred stock was issued pursuant to the Company’s shelf registration statement on Form S-3 (Registration No. 333-211568), which became effective July 26, 2016, and an additional registration statement with respect thereto on Form S-3 (Registration No. 333-213201) filed under Rule 462(b) of the Act, which became effective upon filing on August 19, 2016. The closing of the sale of Series A preferred stock occurred on August 26, 2016.

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, initially into approximately 15.6961 shares of Class A common stock (which is equivalent to an initial conversion price of approximately $3.19 per share), subject to specified adjustments and limitations as set forth in the certificate of designations for the Series A preferred stock. Based on the initial conversion rate and the full exercise of the Preferred Stock Underwriters’ over-allotment option, approximately 28.9 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.

Mezzanine equity consisted of the following at September 30, 2016:


(in thousands of dollars)	September 30, 2016
Series A preferred stock, at issuance	$	87,978
Dividends on preferred stock		716
Accretion on preferred stock		49
Mezzanine equity at September 30, 2016	$	88,743

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 nonvested 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 nine months ending September 30, 2016, 1,274,611 restricted stock units, 1,035,205 performance share units, and 28,880,824 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:


	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands, except per share data)	2016		2015		2016		2015
Income (numerator):
Net income (loss) attributable to controlling interests	$	(9,853)	$	13,238	$	(14,187)	$	(3,017)
Less: Dividends and accretion on preferred stock		(765)		—		(765)		—
Net income (loss) attributable to common shareholder	$	(10,618)	$	13,238	$	(14,952)	$	(3,017)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock - basic		41,375		30,432		34,300		25,591
Weighted-average number of shares of Class A common stock - diluted		41,375		30,432		34,300		25,591
Earnings (loss) per share:
Basic - Net income (loss) attributable to common shareholders	$	(0.26)	$	0.44	$	(0.44)	$	(0.12)
Diluted - Net income (loss) attributable to common shareholders	$	(0.26)	$	0.44	$	(0.44)	$	(0.12)

The sum of the quarterly earnings (loss) per share amounts differ from the total earnings (loss) per share for the nine months ended September 30, 2016 due to the change in weighted-average shares outstanding.

13. Related Parties

Related Party Transactions

Transactions with Our Executive Officers, Directors and 5% Stockholders

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. 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. Therefore, no related party revenue relating to natural gas and NGL production was recognized during 2016 associated with the aforementioned agreement. 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 directors, Howard I. Hoffen and Gregory D. Myers, are managing directors of Metalmark Capital.

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 $0.6 million and $1.8 million, respectively, of the deferred revenue balance during the three and nine months ended September 30, 2016 and $0.5 million and $1.5 million, respectively, during the three and nine months ended September 30, 2015. This revenue is included in other revenues on the Company’s Consolidated Statement of Operations.

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

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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 $0.7 million and $2.0 million for the three and nine months ended September 30, 2016, respectively, associated with the approximately 0.3 MMBoe and 1.0 MMBoe 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.

Purchase 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 own 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 own 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.

14. Commitments and Contingencies

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 fracking 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 has 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 September 30, 2016, and the charge was recorded as general and administrative expense on the Company’s Consolidated Statement of Operations for the nine months ended September 30, 2016. However, no certainty exists that a settlement will be reached or if so, the amount of any such settlement. Therefore, the ultimate loss could be greater or less than the amount accrued. In the event the plaintiffs and the Company are not able to reach a settlement, a court date has been set for May 30, 2017.

15. Subsequent Events

Preferred Stock Dividend Declared

On October 18, 2016, the Company’s Board of Directors declared a prorated quarterly cash dividend per share equal to 8.0% based on the liquidation preference of $50.00 per share on an annualized basis, or approximately $0.8777778 per share, on the Company’s 8.0% Series A Perpetual Convertible Preferred Stock. This dividend is

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prorated for the period beginning on the issue date of August 26, 2016 through November 14, 2016 and will be payable in cash on November 15, 2016 to shareholders of record as of November 1, 2016.

Borrowing Base Redetermination

Availability under the Revolver is subject to a borrowing base. The borrowing base is 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. Our borrowing base at September 30, 2016 was $425.0 million. The borrowing base was reaffirmed at this level during the semi-annual borrowing base re-determination effective October 24, 2016.

16. Subsidiary Guarantors

On April 1, 2014, the Issuers sold $500.0 million in aggregate principal amount of the 2022 Notes. On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of the 2023 Notes.

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., two immaterial subsidiaries and the new subsidiary formed to acquire the properties in the Merge Acquisition, which is required to become a guarantor no later than January 31, 2017) 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.

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.

As of September 30, 2016, the Company held 56,969,222 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 29,872,426 JEH Units are held by a group of investors that owned interests in JEH prior to the Company’s IPO (the “Pre-IPO Owners”). The Pre-IPO Owners 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 Existing Owner 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.

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Accordingly, the Pre-IPO Owners collectively have a number of votes in the Company equal to the aggregate number of JEH Units that they hold.

The Pre-IPO Owners have the right, pursuant to the terms of an exchange agreement by and among the Company, JEH and each of the Pre-IPO Owners (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.

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Jones Energy, Inc.

Condensed Consolidating Balance Sheet

September 30, 2016


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Assets
Current assets
Cash	$	15,015	$	8,503	$	503	$	20	$	—	$	24,041
Accounts receivable, net
Oil and gas sales		—		—		20,720		—		—		20,720
Joint interest owners		—		—		4,880		—		—		4,880
Other		—		9,912		103		—		—		10,015
Commodity derivative assets		—		48,784		—		—		—		48,784
Other current assets		—		531		2,072		—		—		2,603
Intercompany receivable		13,815		1,139,451		—		—		(1,153,266)		—
Total current assets		28,830		1,207,181		28,278		20		(1,153,266)		111,043
Oil and gas properties, net, at cost under the successful efforts method		—		—		1,604,716		137,449		—		1,742,165
Other property, plant and equipment, net		—		—		2,545		641		—		3,186
Commodity derivative assets		—		50,469		—		—		—		50,469
Other assets		—		5,666		740		—		—		6,406
Investment in subsidiaries		589,523		—		—		—		(589,523)		—
Total assets	$	618,353	$	1,263,316	$	1,636,279	$	138,110	$	(1,742,789)	$	1,913,269
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	469	$	53	$	26,806	$	—	$	—	$	27,328
Oil and gas sales payable		—		—		26,445		—		—		26,445
Accrued liabilities		3,608		14,735		10,450		—		—		28,793
Commodity derivative liabilities		—		1,618		—		—		—		1,618
Asset retirement obligations		—		—		679		—		—		679
Intercompany payable		—		—		1,399,870		140,092		(1,539,962)		—
Total current liabilities		4,077		16,406		1,464,250		140,092		(1,539,962)		84,863
Long-term debt		—		688,432		—		—		—		688,432
Deferred revenue		—		9,589		—		—		—		9,589
Commodity derivative liabilities		—		526		—		—		—		526
Asset retirement obligations		—		—		27,452		—		—		27,452
Liability under tax receivable agreement		43,212		—		—		—		—		43,212
Other liabilities		—		168		488		—		—		656
Deferred tax liabilities		13,575		2,495		—		—		—		16,070
Total liabilities		60,864		717,616		1,492,190		140,092		(1,539,962)		870,800
Mezzanine equity
Series A preferred stock, $0.001 par value; 1,840,000 shares issued and outstanding at September 30, 2016		88,743		—		—		—		—		88,743
Stockholders’/ members' equity
Members' equity		—		545,700		144,089		(1,982)		(687,807)		—
Class A common stock, $0.001 par value; 56,991,824 shares issued and 56,969,222 shares outstanding at September 30, 2016		57		—		—		—		—		57
Class B common stock, $0.001 par value; 29,872,426 shares issued and outstanding at September 30, 2016		30		—		—		—		—		30
Treasury stock, at cost: 22,602 shares at September 30, 2016		(358)		—		—		—		—		(358)
Additional paid-in-capital		447,400		—		—		—		—		447,400
Retained earnings (deficit)		21,617		—		—		—		—		21,617
Stockholders' equity		468,746		545,700		144,089		(1,982)		(687,807)		468,746
Non-controlling interest		—		—		—		—		484,980		484,980
Total stockholders’ equity		468,746		545,700		144,089		(1,982)		(202,827)		953,726
Total liabilities and stockholders’ equity	$	618,353	$	1,263,316	$	1,636,279	$	138,110	$	(1,742,789)	$	1,913,269

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Jones Energy, Inc.

Condensed Consolidating Balance Sheet

December 31, 2015


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Assets
Current assets
Cash	$	100	$	12,448	$	9,325	$	20	$	—	$	21,893
Accounts receivable, net
Oil and gas sales		—		—		19,292		—		—		19,292
Joint interest owners		—		—		11,314		—		—		11,314
Other		—		14,444		726		—		—		15,170
Commodity derivative assets		—		124,207		—		—		—		124,207
Other current assets		—		444		1,854		—		—		2,298
Intercompany receivable		12,866		1,161,997		—		—		(1,174,863)		—
Total current assets		12,966		1,313,540		42,511		20		(1,174,863)		194,174
Oil and gas properties, net, at cost under the successful efforts method		—		—		1,635,766		—		—		1,635,766
Other property, plant and equipment, net		—		—		3,168		705		—		3,873
Commodity derivative assets		—		93,302		—		—		—		93,302
Other assets		—		7,456		583		—		—		8,039
Investment in subsidiaries		444,362		—		—		—		(444,362)		—
Total assets	$	457,328	$	1,414,298	$	1,682,028	$	725	$	(1,619,225)	$	1,935,154
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	—	$	388	$	7,079	$	—	$	—	$	7,467
Oil and gas sales payable		—		—		32,408		—		—		32,408
Accrued liabilities		—		15,741		11,270		—		—		27,011
Commodity derivative liabilities		—		11		—		—		—		11
Asset retirement obligations		—		—		679		—		—		679
Intercompany payable		—		—		1,391,838		2,434		(1,394,272)		—
Total current liabilities		—		16,140		1,443,274		2,434		(1,394,272)		67,576
Long-term debt		—		837,654		—		—		—		837,654
Deferred revenue		—		11,417		—		—		—		11,417
Asset retirement obligations		—		—		20,301		—		—		20,301
Liability under tax receivable agreement		38,052		—		—		—		—		38,052
Other liabilities		—		—		330		—		—		330
Deferred tax liabilities		19,280		3,692		—		—		—		22,972
Total liabilities		57,332		868,903		1,463,905		2,434		(1,394,272)		998,302
Stockholders’/ members' equity
Members' equity		—		545,395		218,123		(1,709)		(761,809)		—
Class A common stock, $0.001 par value; 30,573,509 shares issued and 30,550,907 shares outstanding at December 31, 2015		31		—		—		—		—		31
Class B common stock, $0.001 par value; 31,273,130 shares issued and outstanding at December 31, 2015		31		—		—		—		—		31
Treasury stock, at cost: 22,602 shares at December 31, 2015		(358)		—		—		—		—		(358)
Additional paid-in-capital		363,723		—		—		—		—		363,723
Retained earnings (deficit)		36,569		—		—		—		—		36,569
Stockholders' equity		399,996		545,395		218,123		(1,709)		(761,809)		399,996
Non-controlling interest		—		—		—		—		536,856		536,856
Total stockholders’ equity		399,996		545,395		218,123		(1,709)		(224,953)		936,852
Total liabilities and stockholders’ equity	$	457,328	$	1,414,298	$	1,682,028	$	725	$	(1,619,225)	$	1,935,154

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2016


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—	$	—	$	32,582	$	—	$	—	$	32,582
Other revenues		—		587		184		—		—		771
Total operating revenues		—		587		32,766		—		—		33,353
Operating costs and expenses
Lease operating		—		—		7,865		—		—		7,865
Production and ad valorem taxes		—		—		1,733		—		—		1,733
Exploration		—		—		998		—		—		998
Depletion, depreciation and amortization		—		—		36,527		23		—		36,550
Accretion of ARO liability		—		—		323		—		—		323
General and administrative		—		2,928		3,476		44		—		6,448
Total operating expenses		—		2,928		50,922		67		—		53,917
Operating income (loss)		—		(2,341)		(18,156)		(67)		—		(20,564)
Other income (expense)
Interest expense		—		(12,652)		(140)		—		—		(12,792)
Net gain (loss) on commodity derivatives		—		4,014		—		—		—		4,014
Other income (expense)		261		(25)		128		—		—		364
Other income (expense), net		261		(8,663)		(12)		—		—		(8,414)
Income (loss) before income tax		261		(11,004)		(18,168)		(67)		—		(28,978)
Equity interest in income		(15,999)		—		—		—		15,999		—
Income tax provision (benefit)		(5,885)		(664)		—		—		—		(6,549)
Net income (loss)		(9,853)		(10,340)		(18,168)		(67)		15,999		(22,429)
Net income (loss) attributable to non-controlling interests										(12,576)		(12,576)
Net income (loss) attributable to controlling interests	$	(9,853)	$	—	$	—	$	—	$	—	$	(9,853)
Dividends and accretion on preferred stock		(765)		—		—		—		—		(765)
Net income (loss) attributable to common shareholders	$	(10,618)	$	—	$	—	$	—	$	—	$	(10,618)

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2016


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—	$	—	$	86,060	$	—	$	—	$	86,060
Other revenues		—		1,828		467		—		—		2,295
Total operating revenues		—		1,828		86,527		—		—		88,355
Operating costs and expenses
Lease operating		—		—		24,027		—		—		24,027
Production and ad valorem taxes		—		—		5,061		—		—		5,061
Exploration		—		—		1,237		—		—		1,237
Depletion, depreciation and amortization		—		—		116,385		64		—		116,449
Accretion of ARO liability		—		—		913		—		—		913
General and administrative		—		8,782		13,087		209		—		22,078
Total operating expenses		—		8,782		160,710		273		—		169,765
Operating income (loss)		—		(6,954)		(74,183)		(273)		—		(81,410)
Other income (expense)
Interest expense		—		(40,417)		20		—		—		(40,397)
Gain on debt extinguishment		—		99,530		—		—		—		99,530
Net gain (loss) on commodity derivatives		—		(18,769)		—		—		—		(18,769)
Other income (expense)		423		(298)		126		—		—		251
Other income (expense), net		423		40,046		146		—		—		40,615
Income (loss) before income tax		423		33,092		(74,037)		(273)		—		(40,795)
Equity interest in income		(22,130)		—		—		—		22,130		—
Income tax provision (benefit)		(7,520)		(714)		—		—		—		(8,234)
Net income (loss)		(14,187)		33,806		(74,037)		(273)		22,130		(32,561)
Net income (loss) attributable to non-controlling interests		—		—		—		—		(18,374)		(18,374)
Net income (loss) attributable to controlling interests	$	(14,187)	$	—	$	—	$	—	$	—	$	(14,187)
Dividends and accretion on preferred stock		(765)		—		—		—		—		(765)
Net income (loss) attributable to common shareholders	$	(14,952)	$	—	$	—	$	—	$	—	$	(14,952)

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2015


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—	$	—	$	46,499	$	—	$	—	$	46,499
Other revenues		—		493		160		—		—		653
Total operating revenues		—		493		46,659		—		—		47,152
Operating costs and expenses
Lease operating		—		—		8,872		—		—		8,872
Production and ad valorem taxes		—		—		2,513		—		—		2,513
Exploration		—		—		5,556		—		—		5,556
Depletion, depreciation and amortization		—		—		52,743		23		—		52,766
Accretion of ARO liability		—		—		210		—		—		210
General and administrative		—		6,730		2,853		45		—		9,628
Total operating expenses		—		6,730		72,747		68		—		79,545
Operating income (loss)		—		(6,237)		(26,088)		(68)		—		(32,393)
Other income (expense)
Interest expense		—		(16,533)		(189)		—		—		(16,722)
Net gain (loss) on commodity derivatives		—		90,483		—		—		—		90,483
Other income (expense)		—		(23)		16		—		—		(7)
Other income (expense), net		—		73,927		(173)		—		—		73,754
Income (loss) before income tax		—		67,690		(26,261)		(68)		—		41,361
Equity interest in income		20,509		—		—		—		(20,509)		—
Income tax provision (benefit)		7,271		(752)		—		—		—		6,519
Net income (loss)		13,238		68,442		(26,261)		(68)		(20,509)		34,842
Net income (loss) attributable to non-controlling interests		—		—		—		—		21,604		21,604
Net income (loss) attributable to controlling interests	$	13,238	$	—	$	—	$	—	$	—	$	13,238

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2015


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—	$	—	$	156,955	$	—	$	—	$	156,955
Other revenues		—		1,521		689		—		—		2,210
Total operating revenues		—		1,521		157,644		—		—		159,165
Operating costs and expenses
Lease operating		—		—		32,930		—		—		32,930
Production and ad valorem taxes		—		—		9,292		—		—		9,292
Exploration		—		—		6,184		—		—		6,184
Depletion, depreciation and amortization		—		—		156,083		68		—		156,151
Accretion of ARO liability		—		—		610		—		—		610
General and administrative		—		9,715		17,765		92		—		27,572
Other operating		—		—		4,188		—		—		4,188
Total operating expenses		—		9,715		227,052		160		—		236,927
Operating income (loss)		—		(8,194)		(69,408)		(160)		—		(77,762)
Other income (expense)
Interest expense		—		(46,681)		(872)		—		—		(47,553)
Net gain (loss) on commodity derivatives		—		111,714		—		—		—		111,714
Other income (expense)		—		(2,324)		693		—		—		(1,631)
Other income (expense), net		—		62,709		(179)		—		—		62,530
Income (loss) before income tax		—		54,515		(69,587)		(160)		—		(15,232)
Equity interest in income		(5,587)		—		—		—		5,587		—
Income tax provision (benefit)		(2,570)		(2,020)		—		—		—		(4,590)
Net income (loss)		(3,017)		56,535		(69,587)		(160)		5,587		(10,642)
Net income (loss) attributable to non-controlling interests		—		—		—		—		(7,625)		(7,625)
Net income (loss) attributable to controlling interests	$	(3,017)	$	—	$	—	$	—	$	—	$	(3,017)

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Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2016


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Cash flows from operating activities
Net income (loss)	$	(14,187)	$	33,806	$	(74,037)	$	(273)	$	22,130	$	(32,561)
Adjustments to reconcile net income (loss) to net cash provided by operating activities		(134,592)		(72,294)		276,076		410		(22,130)		47,470
Net cash (used in) / provided by operations		(148,779)		(38,488)		202,039		137		—		14,909
Cash flows from investing activities
Additions to oil and gas properties		—		—		(210,741)		(137)		—		(210,878)
Proceeds from sales of assets		—		—		74		—		—		74
Acquisition of other property, plant and equipment		—		—		(194)		—		—		(194)
Current period settlements of matured derivative contracts		—		106,151		—		—		—		106,151
Net cash (used in) / provided by investing		—		106,151		(210,861)		(137)		—		(104,847)
Cash flows from financing activities
Proceeds from issuance of long-term debt		—		75,000		—		—		—		75,000
Repayment under long-term debt		—		(42,000)		—		—		—		(42,000)
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		65,548		—		—		—		—		65,548
Proceeds from sale of preferred stock		88,236		—		—		—		—		88,236
Net cash (used in) / provided by financing		163,694		(71,608)		—		—		—		92,086
Net increase (decrease) in cash		14,915		(3,945)		(8,822)		—		—		2,148
Cash
Beginning of period		100		12,448		9,325		20		—		21,893
End of period	$	15,015	$	8,503	$	503	$	20	$	—	$	24,041

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Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2015


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Cash flows from operating activities
Net income (loss)	$	(3,017)	$	56,535	$	(69,587)	$	(160)	$	5,587	$	(10,642)
Adjustments to reconcile net income (loss) to net cash provided by operating activities		(119,762)		(133,068)		357,958		160		(5,587)		99,701
Net cash (used in) / provided by operations		(122,779)		(76,533)		288,371		—		—		89,059
Cash flows from investing activities
Additions to oil and gas properties		—		—		(280,528)		—		—		(280,528)
Proceeds from sales of assets		—		—		37		—		—		37
Acquisition of other property, plant and equipment		—		—		(1,034)		—		—		(1,034)
Current period settlements of matured derivative contracts		—		103,858				—		—		103,858
Net cash (used in) / provided by investing		—		103,858		(281,525)		—		—		(177,667)
Cash flows from financing activities
Proceeds from issuance of long-term debt		—		75,000		—		—		—		75,000
Repayment under long-term debt		—		(335,000)		—		—		—		(335,000)
Proceeds from senior notes		—		236,475		—		—		—		236,475
Payment of debt issuance costs		—		(1,514)		—		—		—		(1,514)
Proceeds from sale of common stock, net of expense		122,779		—		—		—		—		122,779
Net cash (used in) / provided by financing		122,779		(25,039)		—		—		—		97,740
Net increase (decrease) in cash		—		2,286		6,846		—		—		9,132
Cash												—
Beginning of period		100		1,000		12,436		30		—		13,566
End of period	$	100	$	3,286	$	19,282	$	30	$	—	$	22,698

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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, 2015, filed on March 9, 2016 with the Securities and Exchange Commission, as well as 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, 2016, filed on May 6, 2016 with the Securities and Exchange Commission and our quarterly report on Form 10-Q for the quarter ended June 30, 2016, filed on August 5, 2016 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 and Arkoma basins, having concentrated our operations in the Anadarko basin for over 25 years and applied our knowledge to the Arkoma basin since 2011. We have drilled over 850 total wells as operator, including over 675 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 three distinct areas in the Texas Panhandle and Oklahoma:

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

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

the Arkoma Basin—targeting the Woodford shale formation.

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 and Woodford shale formations.

Third Quarter and Year-to-Date 2016 Highlights:

Average daily net production for the third quarter of 2016 of 18.6 MBoe/d

Completed two acquisitions in the third quarter of 2016, including transformative $136.5 million Merge Acquisition and bolt-on $26.3 million (net of closing adjustments) Anadarko Acquisition

Raised $152.3 million in net proceeds from common stock and convertible preferred stock issuance

Expect to deploy first rig on the properties acquired in the Merge Acquisition in December 2016

Increasing full year 2016 capital guidance to $110.0 million, primarily due to higher average working interest associated with Cleveland development program and expected Merge leasing

Borrowing base maintained at $425.0 million as a result of fall redetermination

Net loss for the third quarter of 2016 of $22.4 million and EBITDAX of $46.8 million

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Acquisitions

Merge Acquisition

On August 18, 2016, JEH entered into a definitive purchase and sale agreement with SCOOP Energy Company, LLC, an Oklahoma limited liability company, to acquire oil and gas properties located in the Merge area of the STACK/SCOOP (the “Merge”) play in Central Oklahoma (the “Merge Acquisition”). The oil and gas properties to be acquired in the Merge Acquisition principally consist of approximately 18,000 undeveloped net acres in Canadian, Grady and McClain Counties, Oklahoma. The Company closed the Merge Acquisition on September 22, 2016, for a closing price of approximately $136.5 million, subject to customary post-closing adjustments. The Company used proceeds from our equity offerings to fund the purchase.

Anadarko Acquisition

Updated Capital Expenditures Outlook

During the third quarter of 2016, the Company spent $29.3 million on capital expenditures excluding acquisitions, of which $28.4 million was drilling and completion capital and the remainder was related to maintenance capital and spending on non-operated wells, bringing total year-to-date 2016 capital expenditures excluding acquisitions to $53.1 million. The Company spent $163.6 million on acquisitions in the third quarter, bringing total capital expenditures including acquisitions for the third quarter of 2016 to $192.9 million and year-to-date capital expenditures including acquisitions to $216.7 million. The $163.6 million in capital spent on acquisitions includes the $136.5 million Merge Acquisition and the $26.3 million Anadarko Acquisition, which were both completed in the third quarter of 2016. On November 3, 2016, the Company announced a further revised 2016 capital expenditures program, increasing full year 2016 guidance (excluding acquisitions) to $110.0 million primarily due to higher average working interest associated with Cleveland development program and expected Merge leasing.

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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 September 30,						Nine Months Ended September 30,
production, sales price and average cost data)	2016		2015		Change		2016		2015		Change
Revenues:
Oil	$	15,817	$	26,926	$	(11,109)	$	45,239	$	93,591	$	(48,352)
Natural gas		9,580		11,822		(2,242)		21,237		36,925		(15,688)
NGLs		7,185		7,751		(566)		19,584		26,439		(6,855)
Total oil and gas		32,582		46,499		(13,917)		86,060		156,955		(70,895)
Other		771		653		118		2,295		2,210		85
Total operating revenues		33,353		47,152		(13,799)		88,355		159,165		(70,810)
Costs and expenses:
Lease operating		7,865		8,872		(1,007)		24,027		32,930		(8,903)
Production and ad valorem taxes		1,733		2,513		(780)		5,061		9,292		(4,231)
Exploration		998		5,556		(4,558)		1,237		6,184		(4,947)
Depletion, depreciation and amortization		36,550		52,766		(16,216)		116,449		156,151		(39,702)
Accretion of ARO liability		323		210		113		913		610		303
General and administrative		6,448		9,628		(3,180)		22,078		27,572		(5,494)
Other operating		—		—		—		—		4,188		(4,188)
Total costs and expenses		53,917		79,545		(25,628)		169,765		236,927		(67,162)
Operating income (loss)		(20,564)		(32,393)		11,829		(81,410)		(77,762)		(3,648)
Other income (expenses):
Interest expense		(12,792)		(16,722)		3,930		(40,397)		(47,553)		7,156
Gain on debt extinguishment		—		—		—		99,530		—		99,530
Net gain (loss) on commodity derivatives		4,014		90,483		(86,469)		(18,769)		111,714		(130,483)
Other income/(expense)		364		(7)		371		251		(1,631)		1,882
Total other income (expense)		(8,414)		73,754		(82,168)		40,615		62,530		(21,915)
Income (loss) before income tax		(28,978)		41,361		(70,339)		(40,795)		(15,232)		(25,563)
Income tax provision (benefit)		(6,549)		6,519		(13,068)		(8,234)		(4,590)		(3,644)
Net income (loss)		(22,429)		34,842		(57,271)		(32,561)		(10,642)		(21,919)
Net income (loss) attributable to non-controlling interests		(12,576)		21,604		(34,180)		(18,374)		(7,625)		(10,749)
Net income (loss) attributable to controlling interests	$	(9,853)	$	13,238	$	(23,091)	$	(14,187)	$	(3,017)	$	(11,170)
Dividends and accretion on preferred stock		(765)		—		(765)		(765)		—		(765)
Net income (loss) attributable to common shareholders	$	(10,618)	$	13,238	$	(23,856)	$	(14,952)	$	(3,017)	$	(11,935)

Net production volumes:
Oil (MBbls)		396		630		(234)		1,271		2,030		(759)
Natural gas (MMcf)		4,602		6,069		(1,467)		14,130		18,172		(4,042)
NGLs (MBbls)		549		682		(133)		1,633		1,946		(313)
Total (MBoe)		1,712		2,324		(612)		5,259		7,005		(1,746)
Average net (Boe/d)		18,609		25,261		(6,652)		19,193		25,659		(6,466)
Average sales price, unhedged:
Oil (per Bbl), unhedged	$	39.94	$	42.74	$	(2.80)	$	35.59	$	46.10	$	(10.51)
Natural gas (per Mcf), unhedged		2.08		1.95		0.13		1.50		2.03		(0.53)
NGLs (per Bbl), unhedged		13.09		11.37		1.72		11.99		13.59		(1.60)
Combined (per Boe), unhedged		19.03		20.01		(0.98)		16.36		22.41		(6.05)
Average sales price, hedged:
Oil (per Bbl), hedged	$	87.34	$	78.64	$	8.70	$	86.26	$	75.19	$	11.07
Natural gas (per Mcf), hedged		3.46		3.24		0.22		3.51		3.37		0.14
NGLs (per Bbl), hedged		17.54		24.28		(6.74)		17.40		26.21		(8.81)
Combined (per Boe), hedged		35.12		36.91		(1.79)		35.69		37.82		(2.13)
Average costs (per BOE):
Lease operating	$	4.59	$	3.82	$	0.77	$	4.57	$	4.70	$	(0.13)
Production and ad valorem taxes		1.01		1.08		(0.07)		0.96		1.33		(0.37)
Depletion, depreciation and amortization		21.35		22.70		(1.35)		22.14		22.29		(0.15)
General and administrative		3.77		4.14		(0.37)		4.20		3.94		0.26

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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 September 30,				Nine Months Ended September 30,
(in thousands of dollars)	2016		2015		2016		2015
Reconciliation of EBITDAX to net income
Net income (loss)	$	(22,429)	$	34,842	$	(32,561)	$	(10,642)
Interest expense		12,068		15,924		38,186		45,187
Exploration expense		998		5,556		1,237		6,184
Income taxes		(6,549)		6,519		(8,234)		(4,590)
Amortization of deferred financing costs		724		798		2,211		2,366
Depreciation and depletion		36,550		52,766		116,449		156,151
Accretion of ARO liability		323		210		913		610
Reduction of TRA liability		(260)		—		(422)		—
Other non-cash charges		116		418		1,227		1,178
Stock compensation expense		2,185		2,039		5,269		5,287
Deferred and other non-cash compensation expense		213		108		614		326
Net (gain) loss on derivative contracts		(4,014)		(90,483)		18,769		(111,714)
Current period settlements of matured derivative contracts		27,538		39,273		101,619		107,992
Amortization of deferred revenue		(587)		(493)		(1,828)		(1,521)
(Gain) loss on sale of assets		(69)		(16)		(68)		(10)
(Gain) on debt extinguishment		—		—		(99,530)		—
Stand-by rig costs		—		—		—		4,188
Financing expenses and other loan fees		25		22		298		2,323
EBITDAX	$	46,832	$	67,483	$	144,149	$	203,315

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

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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 computations of adjusted net income and adjusted earnings per share may not be comparable to other similarly titled measures of other companies.

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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 September 30,						Nine Months Ended September 30,
(in thousands except per share data)	2016			2015			2016			2015
Net income (loss)	$	(22,429)		$	34,842		$	(32,561)		$	(10,642)
Net (gain) loss on derivative contracts		(4,014)			(90,483)			18,769			(111,714)
Current period settlements of matured derivative contracts		27,538			39,273			101,619			107,992
Exploration		998			5,556			1,237			6,184
Non-cash stock compensation expense		2,185			2,039			5,269			5,287
Deferred and other non-cash compensation expense		213			108			614			326
(Gain) on debt extinguishment		—			—			(99,530)			—
Stand-by rig costs		—			—			—			4,188
Financing expenses		—			—			—			2,250
Reduction of TRA liability		(260)			—			(422)			—
Tax impact of adjusting items (1)		(5,374)			7,039			(5,705)			(2,233)
Change in valuation allowance		106			—			498			—
Adjusted net income (loss)		(1,037)			(1,626)			(10,212)			1,638
Adjusted net income (loss) attributable to non-controlling interests		(1,074)			(828)			(6,640)			1,566
Adjusted net income (loss) attributable to controlling interests		37			(798)			(3,572)			72
Dividends and accretion on preferred stock		(765)			—			(765)			—
Adjusted net income (loss) attributable to common shareholders	$	(728)		$	(798)		$	(4,337)		$	72

Earnings per share (basic and diluted)	$	(0.26)		$	0.44		$	(0.44)		$	(0.12)
Net (gain) loss on derivative contracts		(0.06)			(1.47)			0.27			(1.89)
Current period settlements of matured derivative contracts		0.38			0.64			1.53			1.79
Exploration		0.01			0.09			0.02			0.11
Non-cash stock compensation expense		0.03			0.03			0.08			0.09
Deferred and other non-cash compensation expense		—			—			0.01			0.01
(Gain) on debt extinguishment		—			—			(1.43)			—
Stand-by rig costs		—			—			—			0.06
Financing expenses		—			—			—			0.03
Reduction of TRA liability		—			—			(0.01)			—
Tax impact of adjusting items (1)		(0.12)			0.24			(0.17)			(0.08)
Change in valuation allowance		—			—			0.01			—
Adjusted earnings per share (basic and diluted)	$	(0.02)		$	(0.03)		$	(0.13)		$	0.00

Weighted average shares outstanding:
Basic		41,375			30,432			34,300			25,591
Diluted		41,375			30,432			34,300			25,591
Effective tax rate on net income (loss) attributable to controlling interests		35.5	%		39.7	%		35.5	%		39.7	%

(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.

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Results of Operations - Three months ended September 30, 2016 as compared to three months ended September 30, 2015

Operating revenues

Oil and gas sales. Oil and gas sales decreased $13.9 million, or 29.9%, to $32.6 million for the three months ended September 30, 2016, as compared to $46.5 million for the three months ended September 30, 2015. The decrease was attributable to the decline in production volumes ($14.1 million), which was offset by a slight increase in commodity prices ($0.2 million). The decrease in production volumes was driven by the temporary suspension of our drilling program. The average realized oil price, excluding the effects of commodity derivative instruments, decreased from $42.74 per Bbl for the three months ended September 30, 2015 to $39.94 per Bbl for the three months ended September 30, 2016, or 6.6%. The average realized natural gas price, excluding the effects of commodity derivative instruments, increased from $1.95 per Mcf for the three months ended September 30, 2015 to $2.08 per Mcf for the three months ended September 30, 2016, or 6.7%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increased from $11.37 per Bbl for the three months ended September 30, 2015 to $13.09 per Bbl for the three months ended September 30, 2016, or 15.1%. Average daily production decreased 26.3% to 18,609 Boe per day for the three months ended September 30, 2016 as compared to 25,261 Boe per day for the three months ended September 30, 2015.

Costs and expenses

Lease operating. Lease operating expenses decreased by $1.0 million, or 11.2%, to $7.9 million for the three months ended September 30, 2016, as compared to $8.9 million for the three months ended September 30, 2015. The decrease was principally attributable to reduction in post-completion costs driven by a temporary suspension of the drilling program, operational focus on reducing recurring operating expenses, such as optimizing the usage of compressors and rental equipment, and vendor price reductions. On a per unit basis, lease operating expenses increased $0.77 per Boe, or 20.2%, from $3.82 per Boe in the three months ended September 30, 2015 to $4.59 per Boe in the three months ended September 30, 2016.

Production and ad valorem taxes. Production and ad valorem taxes decreased by $0.8 million, or 32.0%, to $1.7 million for the three months ended September 30, 2016, as compared to $2.5 million for the three months ended September 30, 2015. The decrease was driven by a $0.3 million (16.7%) reduction in production taxes, which decreased in conjunction with the 29.9% decrease in oil and gas revenue. 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. Additionally, estimated ad valorem taxes decreased $0.5 million from $0.7 million for the three months ended September 30, 2015 to $0.2 million for the three months ended September 30, 2016, reflecting lower property assessments due to lower commodity prices. The average effective rate excluding the impact of ad valorem taxes increased from 4.0% for the three months ended September 30, 2015 to 4.7% for the three months ended September 30, 2016.

Exploration. Exploration expense decreased from $5.6 million for the three months ended September 30, 2015 to $1.0 million for the three months ended September 30, 2016. The Company recognized charges for lease abandonment of $0.9 million relating to certain leases that the Company decided during the third quarter of 2016 not to develop. No exploratory wells resulted in exploration expense during either year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased by $16.2 million, or 30.7%, to $36.6 million for the three months ended September 30, 2016, as compared to $52.8 million for the three months ended September 30, 2015. The decrease was primarily the result of lower production caused by a reduction in capital spending driven by a temporary suspension of the drilling program. On a per unit basis, depletion expense decreased $1.35 per Boe or 5.9% from $22.70 per Boe for the three months ended September 30, 2015 as compared to $21.35 per Boe for the three months ended September 30, 2016.

General and administrative. General and administrative expenses decreased by $3.2 million, or 33.3%, to $6.4 million for the three months ended September 30, 2016, as compared to $9.6 million for the three months ended September 30, 2015. The decrease in general and administrative expense was primarily attributable to staff and other cost reductions. Non-cash compensation expense increased $0.3 million from $2.1 million for the three months ended September 30, 2015 to $2.4 million for the three months ended September 30, 2016. On a per unit basis, general and administrative

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expenses, excluding non-cash items, decreased from $3.04 per Boe for the three months ended September 30, 2015 to $2.30 per Boe for the three months ended September 30, 2016.

Interest expense. Interest expense decreased by $3.9 million, or 23.4%, to $12.8 million for three months ended September 30, 2016, as compared to $16.7 million for the three months ended September 30, 2015. The decrease was driven by a reduction in the outstanding balance of the 2022 Notes and the 2023 Notes as a result of our debt extinguishments. During the three months ended September 30, 2016, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.29%, 6.75% and 9.25%, respectively. Average outstanding balances for the three months ended September 30, 2016 were $184.5 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 $4.0 million for the three months ended September 30, 2016, as compared to a net gain of $90.5 million for the three months ended September 30, 2015. The gain was primarily driven by lower average crude oil prices ($44.85 per barrel) for the three months ended September 30, 2016, as compared to the crude oil prices as of June 30, 2016 ($45.46 per barrel).

Other income (expense). Other income (expense) decreased by $0.4 million to net income of $0.4 million for the three months ended September 30, 2016, as compared to a net expense of less than $0.1 million for the three months ended September 30, 2015. Other income (expense) for the three months ended September 30, 2016 related to an increase in the TRA valuation allowance which resulted in income of $0.3 million.

Income taxes. The provision for federal and state income taxes for the three months ended September 30, 2016 was a benefit of $6.5 million resulting in a 22.6% effective tax rate as a percentage of our pre-tax book income for the quarter as compared to an expense of $6.5 million resulting in a 15.8% effective tax rate as a percentage of our pre-tax book income for the three months ended September 30, 2015. 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. See Note 10, “Income Taxes,” for further details.

Results of Operations - Nine months ended September 30, 2016 as compared to nine months ended September 30, 2015

Operating revenues

Oil and gas sales. Oil and gas sales decreased $70.9 million, or 45.2%, to $86.1 million for the nine months ended September 30, 2016, as compared to $157.0 million for the nine months ended September 30, 2015. The decrease was attributable to the decline in commodity prices ($34.1 million), as well as decreased production volumes ($36.8 million). The decrease in production volumes was driven by the temporary suspension of our drilling program. The average realized oil price, excluding the effects of commodity derivative instruments, decreased from $46.10 per Bbl for the nine months ended September 30, 2015 to $35.59 per Bbl for the nine months ended September 30, 2016, or 22.8%. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $2.03 per Mcf for the nine months ended September 30, 2015 to $1.50 per Mcf for the nine months ended September 30, 2016, or 26.1%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, decreased from $13.59 per Bbl for the nine months ended September 30, 2015 to $11.99 per Bbl for the nine months ended September 30, 2016, or 11.8%. Average daily production decreased 25.2% to 19,193 Boe per day for the nine months ended September 30, 2016 as compared to 25,659 Boe per day for the nine months ended September 30, 2015.

Costs and expenses

Lease operating. Lease operating expenses decreased by $8.9 million, or 27.1%, to $24.0 million for the nine months ended September 30, 2016, as compared to $32.9 million for the nine months ended September 30, 2015. The decrease was principally attributable to reduction in post-completion costs driven by a temporary suspension of the drilling program, operational focus on reducing recurring operating expenses, such as optimizing the usage of compressors and rental equipment, and vendor price reductions. On a per unit basis, lease operating expenses decreased $0.13 per Boe, or 2.8%, from $4.70 per Boe in the nine months ended September 30, 2015 to $4.57 per Boe in the nine months ended September 30, 2016.

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Production and ad valorem taxes. Production and ad valorem taxes decreased by $4.2 million, or 45.2%, to $5.1 million for the nine months ended September 30, 2016, as compared to $9.3 million for the nine months ended September 30, 2015. The decrease was driven by a $2.7 million (39.7%) reduction in production taxes, which decreased in conjunction with the 45.2% decrease in oil and gas revenue. 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. Additionally, estimated ad valorem taxes decreased $1.5 million from $2.5 million for the nine months ended September 30, 2015 to $1.0 million for the nine months ended September 30, 2016, reflecting lower property assessments due to lower commodity prices. The average effective rate excluding the impact of ad valorem taxes increased from 4.3% for the nine months ended September 30, 2015 to 4.8% for the nine months ended September 30, 2016.

Exploration. Exploration expense decreased from $6.2 million for the nine months ended September 30, 2015 to $1.2 million for the nine months ended September 30, 2016. The Company recognized charges for lease abandonment of $0.9 million relating to certain leases that the Company decided during 2016 not to develop. The remaining spending during 2016 primarily related to geological data and seismic processing associated with unproved acreage. No exploratory wells resulted in exploration expense during either year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased by $39.7 million, or 25.5%, to $116.4 million for the nine months ended September 30, 2016, as compared to $156.2 million for the nine months ended September 30, 2015. The decrease was primarily the result of lower production caused by a reduction in capital spending driven by a temporary suspension of the drilling program. On a per unit basis, depletion expense decreased $0.15 per Boe or 0.7% from $22.29 per Boe for the nine months ended September 30, 2015 as compared to $22.14 per Boe for the nine months ended September 30, 2016.

General and administrative. General and administrative expenses decreased by $5.5 million, or 19.9%, to $22.1 million for the nine months ended September 30, 2016, as compared to $27.6 million for the nine months ended September 30, 2015. The decrease in general and administrative expense was primarily attributable to staff and other cost reductions. Non-cash compensation expense increased $0.3 million from $5.6 million for the nine months ended September 30, 2015 to $5.9 million for the nine months ended September 30, 2016. On a per unit basis, general and administrative expenses, excluding non-cash items, decreased from $2.97 per Boe for the nine months ended September 30, 2015 to $2.85 per Boe for the nine months ended September 30, 2016.

Other operating expense. Other operating expense decreased from $4.2 million for the nine months ended September 30, 2015 to none for the nine months ended September 30, 2016. Expense for the nine months ended September 30, 2015 represents stand-by rig costs associated with the early termination of drilling rig contracts. There were no similar charges during 2016.

Interest expense. Interest expense decreased by $7.2 million, or 15.1%, to $40.4 million for nine months ended September 30, 2016, as compared to $47.6 million for the nine months ended September 30, 2015. The decrease was driven by a reduction in the outstanding balance of the 2022 Notes and the 2023 Notes as a result of our debt extinguishments. During the nine months ended September 30, 2016, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.38%, 6.75% and 9.25%, respectively. Average outstanding balances for the nine months ended September 30, 2016 were $170.9 million, $424.1 million and $171.9 million under the Revolver, the 2022 Notes and the 2023 Notes, respectively.

Gain on debt extinguishment. The gain on debt extinguishment of $99.5 million for the nine months ended September 30, 2016 was related to the purchase of an aggregate principal amount of $190.9 million of our senior unsecured notes for cash of $84.6 million. The company recognized accelerated amortization of debt issuance costs of $6.7 million associated with the cancellation. See Note 5, “Long-Term Debt,” for further details regarding the debt extinguishment. There were no similar gains during 2015.

Net gain (loss) on commodity derivatives. The net gain (loss) on commodity derivatives was a net loss of $18.8 million for the nine months ended September 30, 2016, as compared to a net gain of $111.7 million for the nine months ended September 30, 2015. The loss was driven by higher average crude oil and natural gas prices ($41.35 per barrel and $2.34 per Mcf, respectively) for the nine months ended September 30, 2016, as compared to the crude oil and natural gas prices as of December 31, 2015 ($37.13 per barrel and $2.28 per Mcf, respectively), as well as additional hedging activity during 2016.

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Other income (expense). Other income (expense) decreased by $1.9 million to net income of $0.3 million for the nine months ended September 30, 2016, as compared to a net expense of $1.6 million for the nine months ended September 30, 2015. Other income (expense) for the nine months ended September 30, 2016 related to an increase in the TRA valuation allowance which resulted in income of $0.4 million, offset by financing costs which resulted in expenses of $0.3 million. Other income (expense) for the nine months ended September 30, 2015 related to financing costs resulted in expenses of $2.4 million, partially offset by the receipt of a $0.7 million distribution of dividend income from our investment in Monarch Natural Gas Holdings, LLC.

Income taxes. The provision for federal and state income taxes for the nine months ended September 30, 2016 was a benefit of $8.2 million resulting in a 20.2% effective tax rate as a percentage of our pre-tax book income year-to-date as compared to a benefit of $4.6 million with a 30.1% effective tax rate as a percentage of our pre-tax book income for the nine months ended September 30, 2015. 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 change in effective tax rate was due primarily to the percentage of income allocated to the non-controlling interest and the impact of a change in enacted state tax rate during the nine months ended September 30, 2015. 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 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 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 September 30, 2016 reflects a positive working capital balance largely due to the value of our current commodity derivative assets as of this date. 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. Our borrowing base at September 30, 2016 was $425.0 million of which $143.0 million was utilized leaving an unused capacity of $282.0 million. The borrowing base was reaffirmed at this level during the semi-annual borrowing base re-determination effective October 24, 2016. 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 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 required under the Revolver 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

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As of September 30, 2016, our total leverage ratio is approximately 3.3x and our current ratio is approximately 4.1x, as calculated based on the requirements in our covenants. We are in compliance with all terms of our Revolver at September 30, 2016, and we expect to maintain compliance throughout 2016. 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 2016 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. If an event of default exists under the Revolver, the lenders will 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.

The Company routinely enters into oil and natural gas swap contracts as seller, thus resulting in a fixed price. As of October 28, 2016, the estimated mark-to-market value of the Company’s total hedge portfolio was approximately $96.8 million, incorporating strip pricing but excluding adjustments for credit risk. In early 2016, 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. Based on current contract terms, the gains will be recognized as the hedge contracts mature in 2018 and 2019. The estimated mark-to-market value of the Company’s realized gains as a result of these offsetting hedges were approximately $38.7 million and $8.4 million relating to the years ended December 31, 2018 and December 31, 2019, respectively, incorporating strip pricing as of October 28, 2016, but excluding adjustments for credit risk.

Our capital budget is primarily focused on the development of the Cleveland formation through exploitation and development, with spending to begin development of the recently acquired Merge acreage occurring late in the fourth quarter of 2016. The amount of capital we expend may fluctuate materially based on the market conditions for commodity prices and costs of drilling and completing wells, the economic returns being realized and the success of our drilling results as the year progresses.

On May 24, 2016, the Company and Jones Energy Holdings, LLC entered into an 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 nine months ended September 30, 2016, the Company sold approximately 0.5 million Class A Shares under the Equity Distribution Agreement for net proceeds of approximately $1.8 million ($2.1 million gross proceeds, net of approximately $0.3 million in commissions and professional services expenses). The Company used the net proceeds for general corporate purposes. At September 30, 2016, approximately $70.9 million in aggregate offering price remained available to be issued and sold under the Equity Distribution Agreement.

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,

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drilling and acquisition 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 nine months ended September 30, 2016 and 2015:


	Nine Months Ended September 30,
(in thousands of dollars)	2016		2015
Net cash provided by operating activities	$	14,909	$	89,059
Net cash (used in) investing activities		(104,847)		(177,667)
Net cash provided by financing activities		92,086		97,740
Net increase (decrease) in cash	$	2,148	$	9,132

Cash flow provided by operating activities

Net cash provided by operating activities was $14.9 million during the nine months ended September 30, 2016 as compared to net cash provided by operating activities of $89.1 million during the nine months ended September 30, 2015. The decrease in operating cash flows was primarily due to the $70.9 million decrease in oil and gas revenues for the nine months ended September 30, 2016 as compared to the nine months ended September 30, 2015, driven by declines in production volumes as a result of the temporary suspension of the drilling program, as well as declines in commodity prices.

Cash flow (used in) investing activities

Net cash used in investing activities was $104.9 million during the nine months ended September 30, 2016 as compared to net cash used in investing activities of $177.7 million during the nine months ended September 30, 2015. The increase in investing cash flow was primarily driven by the reduction in capital spending, resulting from a temporary suspension of the drilling program.

Cash flow provided by financing activities

Net cash provided by financing activities was $92.1 million during the nine months ended September 30, 2016 as compared to $97.7 million during the nine months ended September 30, 2015. The decrease in financing cash flows was primarily due to the purchase of an aggregate principal amount of $190.9 million of our senior unsecured notes for cash of $84.6 million. The Company used cash on hand and borrowings from its Revolver to fund the note purchases. Additionally, we paid cash tax distributions of approximately $10.1 million to Pre-IPO Owners. Borrowings under the Revolver, net of repayments, totaled $33.0 million during the nine months ended September 30, 2016. Cash flows provided by financing activities were also impacted by net equity offerings of $153.8 million.

Contractual Obligations

Based on information available as of this filing, we estimate that the total amount of tax distributions to JEH unitholders in 2016 will be approximately $46.4 million, including the approximately $20.0 million that has been paid to date. The tax distributions are made pro-rata to all holders of JEH Units, and would result in a $27.6 million distribution made to the Company, and an $18.8 million distribution made to Pre-IPO Owners. The 2016 tax distributions to date were the result of taxable income generated by our operations and debt extinguishment, and our current projections do not currently lead us to anticipate payment of such tax distribution obligations beyond the current year.

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, 2015.

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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, 2015.

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, 2015, 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 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 2016, and historically low commodity prices may exist for an extended period. In applying the prescribed impairment test under the successful efforts method at September 30, 2016, no impairment charge was indicated.

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, 2015 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 12-month period ended September 30, 2016 (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, 2015 would have decreased by approximately 2.6%. 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, 2016.

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;

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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 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 September 30, 2016 was a net asset of $97.1 million.

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 September 30, 2016, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.29%, 6.75% and 9.25%, respectively. During the nine months ended September 30, 2016, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.38%, 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 September 30, 2016 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.

Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of September 30, 2016 because of the material weakness in internal control over financial reporting described in our Annual Report on Form 10-K for the year ended December 31, 2015.

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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, 2015 included a report of management’s assessment regarding internal control over financial reporting.

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PART II—OTHER INFORMATIO N

Item 1. Legal Proceeding s

For a discussion of legal proceedings, see Note 14 “Commitments and Contingencies,” in the Notes to Consolidated 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, 2015, 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, 2015 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2016 and June 30, 2016. There have been no material changes in our risk factors from those described in our Annual Report or our Quarterly Reports, except as set forth below.

A significant portion of the value of the Merge Acquisition is associated with undeveloped acreage that is not held by production, will require substantial amounts of capital to develop and may not be economic.

Most of the acreage we acquired in the Merge Acquisition is undeveloped and will require substantial amounts of capital to fully develop, which we may not be able to fully fund or may require significant issuances or incurrence of equity or debt which may not be available to us or may only be available at a cost that does not allow us to achieve our plans, development schedule and production schedule associated with the acreage. We may also significantly change our development plans in response to commodities pricing. As a result, our investment in these areas may not achieve the production growth or returns we anticipate or may render development opportunities uneconomic, and we could incur material write-downs of unevaluated properties.

In addition, because most of the acreage we acquired in the Merge Acquisition is undeveloped, it is not held by production. Unless development or production, in accordance with the terms of the respective leases, is established, these leases will expire. If the acquired leases expire, we will lose our right to develop the properties. Our drilling and development plans for the area are subject to change based upon various factors, many of which are beyond our control. If we are unable to establish the development or production necessary to hold our leases, we may be forced to pay extension fees to prevent those leases from expiring. If our leases expire or we are forced to pay extension fees in order to maintain them, the areas may not be as economic as we anticipate and we may not realize the expected benefits of the acquisition.

We may fail to realize the benefits anticipated as a result of the Merge Acquisition or the Anadarko Acquisition.

There are a number of risks and uncertainties relating to the Merge Acquisition and the Anadarko Acquisition. The Merge Acquisition and the Anadarko Acquisition involve potential risks, including:

the failure to realize recoverable reserves;

regulatory compliance and permitting;

title issues or other unidentified or unforeseeable liabilities and costs;

the incurrence of liabilities or other compliance costs related to environmental or regulatory matters, including potential liabilities that may be imposed without regard to fault or the legality of conduct;

the diversion of management's attention from our existing properties; and

the incurrence of significant charges, such as asset devaluation or restructuring charges.

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If these risks or other unanticipated liabilities were to materialize, any desired benefits of the Merge Acquisition or the Anadarko Acquisition may not be fully realized, if at all, and our future financial performance and results of operations could be negatively impacted. We cannot assure you that we will realize value from the Merge Acquisition or the Anadarko Acquisition that equals or exceeds the consideration paid.

The Merge Acquisition and the Anadarko Acquisition may not achieve their intended results and may result in us assuming unanticipated liabilities. To date, we have conducted only limited diligence regarding the assets and liabilities we assumed in the Merge Acquisition and the Anadarko Acquisition. These risks are heightened with respect to the Merge Acquisition because it involves the acquisition of a material amount of undeveloped acreage relative to our current undeveloped acreage position.

We consummated the Merge Acquisition and the Anadarko Acquisition because we believe they will result in various benefits and opportunities. Achieving the anticipated benefits of each of the Merge Acquisition and the Anadarko Acquisition is subject to a number of risks and uncertainties. Prior to closing each of the Merge Acquisition and the Anadarko Acquisition, we only had the opportunity to conduct limited environmental and title due diligence. As a result, we may discover title defects or adverse environmental or other conditions of which we are currently unaware. Environmental, title and other problems could reduce the value of the properties to us, and, depending on the circumstances, we could have limited or no recourse to the Seller with respect to those problems. We assumed certain of the Seller's liabilities and are entitled to indemnification in connection with those liabilities in only limited circumstances and in limited amounts. We cannot assure that such potential remedies will be adequate for any liabilities we incur, and such liabilities could be significant.

The risks involved in the Merge Acquisition are heightened due to the size and location of the acquisition. The Merge Acquisition involved our acquisition of approximately 18,000 undeveloped net acres in Canadian, Grady and McClain Counties, Oklahoma, which is a material amount of undeveloped acreage relative to our approximately 27,248 undeveloped net acres as of December 31, 2015. In addition, the properties acquired in the Merge Acquisition are located in the Merge, which is an area in which we do not have previous drilling experience. As a result, the risk that our ability to efficiently and effectively develop and produce the properties acquired in the Merge Acquisition is heightened. If we are unable to efficiently and effectively develop and produce the properties acquired in the Merge Acquisition, the areas may not be as economic as we anticipate and we may not realize the expected benefits of the acquisition.

The anticipated future growth of our business will impose significant added responsibilities on management. The anticipated growth may place strain on our administrative and operational infrastructure. Our senior management's attention may be diverted from the management of daily operations to the integration of the Seller's business operations and the assets acquired in the Merge Acquisition and the Anadarko Acquisition. Our ability to manage our business and growth will require us to apply our operational, financial and management controls, reporting systems and procedures to the acquired business. We may also encounter risks, costs and expenses associated with any undisclosed or other unanticipated liabilities, and use more cash and other financial resources on integration and implementation activities than we anticipate. We may not be able to successfully integrate the Seller's operations into our existing operations, successfully manage this additional acreage or realize the expected economic benefits of the Merge Acquisition or the Anadarko Acquisition, which may have a material adverse effect on our business, financial condition and results of operations.

The development of the properties are subject to all of the risks and uncertainties associated with oil and gas activities as described in the "Risk Factors" section of our Annual Report on Form 10-K for the year ended December 31, 2015.

Our business requires substantial capital expenditures, and we may be unable to obtain needed capital or financing on satisfactory terms or at all.

Our exploration, exploitation, development and acquisition activities require substantial capital expenditures. Our total capital expenditures for 2015 were $200.1 million excluding the impact of asset retirement costs. On November 3, 2016, the Company announced a further revised 2016 capital expenditures program, increasing full year 2016 guidance (excluding acquisitions) to $110.0 million primarily due to higher average working interest associated with Cleveland development program and expected Merge leasing. Historically, we have funded development and operating activities primarily through a combination of equity capital raised from a private equity partner and public equity offerings, through borrowings under our Revolver, through the issuance of debt securities and through internal operating cash flows. We intend to finance the majority of our capital expenditures for the remainder of 2016, including capital

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expenditures related to the Merge Acquisition, with cash flows from operations and borrowings under our senior secured credit facility. Our capital expenditures have historically been greater than our cash flows from operations, and we expect our capital expenditures for the remainder of 2016 to continue to exceed our cash flows. If necessary, we may also access capital through proceeds from potential asset dispositions and the issuance of additional debt and equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

the estimated quantities of our oil, natural gas and NGL reserves;

the amount of oil, natural gas and NGLs we produce from existing wells;

the prices at which we sell our production;

any gains or losses from our hedging activities;

the costs of developing and producing our oil, natural gas and NGL reserves;

take-away capacity;

our ability to acquire, locate and produce new reserves;

the ability and willingness of banks to lend to us; and

our ability to access the equity and debt capital markets.

If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may have limited ability to obtain the additional capital necessary to conduct our operations at expected levels. Our senior secured credit facility and the indentures governing our 2022 Notes (as defined above) and 2023 Notes (as defined above) may restrict our ability to obtain new debt financing. We may not be able to obtain debt or equity financing on terms favorable to us, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a decline in our oil, natural gas and NGLs production or reserves, and in some areas a loss of properties.

In addition, our estimate of the required development capital for the Merge Acquisition may not be sufficient for the actual development capital needs of the Merge Acquisition. If our estimate of the targeted development capital was lower than the actual needs of the Merge Acquisition, we could be required to fund such additional development capital needs out of other operating cash flows or borrowings under our Revolver and through the capital markets.

External financing may be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under our senior secured credit facility and through the capital markets may not be available in the future. Without additional capital resources, we may be unable to pursue and consummate acquisition opportunities as they become available, and we may be forced to limit or defer our planned oil, natural gas and NGLs development program, which will adversely affect the recoverability and ultimate value of our oil, natural gas and NGLs properties, in turn negatively affecting our business, financial condition and results of operations.

The borrowing base under our senior secured credit facility is subject to redetermination and any reduction in the borrowing base may reduce our liquidity or result in our having to repay indebtedness under our senior secured credit facility earlier than anticipated.

We have experienced significant recent declines in our borrowing base under our senior secured credit facility as a result of redeterminations and we expect further significant declines. The current borrowing base under our senior secured credit facility is $425 million. On October 28, 2016, we had availability of approximately $282 million on our senior secured credit facility. Further redeterminations occur at least semi-annually. Redeterminations are based primarily on reserve reports using lender commodity price expectations at such time. JEH and the administrative agent (acting at the direction of lenders holding at least 66 2 / 3 % of the outstanding loans) may each request one unscheduled borrowing base redetermination between each scheduled redetermination. In addition, the lenders may elect to redetermine the borrowing base upon the occurrence of certain defaults under our material operating agreements or upon the cancellation or termination of certain of our joint development agreements. The borrowing base may also be reduced as a result of

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our issuance of unsecured notes, a continued or further reduction in the price or volume of our hedging positions or our consummation of significant asset sales. If current low commodity prices continue through such redetermination events, the borrowing base under our senior secured credit facility may be reduced.

Any reduction in the borrowing base will reduce our liquidity, and, if a borrowing base reduction results in the outstanding amount of obligations under our senior secured credit facility exceeding the borrowing base, we will be required to repay the deficiency within a short period of time. If alternate sources of capital are not available, any such reductions can also adversely affect our ability to fund our drilling program and development of our undeveloped properties, including those acquired in the Merge Acquisition, which in turn can limit our ability to replace or add reserves and maintain or grow our borrowing base, and could adversely affect our business, financial condition and results of operations.

Certain federal regulatory agencies, including the Office of the Comptroller of the Currency ("OCC"), the Federal Reserve, and the Federal Deposit Insurance Corp., have recently focused on oil and gas lenders' examinations and ratings of reserve-based loans, with a view towards encouraging such lenders to reduce their exposure to potentially substandard loans to oil and gas companies. In March 2016, the OCC issued an updated "Oil and Gas Production Lending" bank examination booklet, which details potential regulatory requirements related to reserve-based lending. Whether or not these regulatory agencies are successful in implementing stricter requirements related to reserve-based lending, oil and gas lenders may respond to these discussions by taking a more conservative approach in their lending practices, which could also adversely impact future borrowing base redeterminations under our senior secured credit facility.

Our issuance of Series A preferred stock may result in a substantial number of shares of our Class A common stock being issued upon its conversion, or as dividends and redemption payments in respect of the Series A preferred stock, which issuances could reduce the value of our Class A common stock.

In addition to the issuance of shares of Class A common stock upon conversion of shares of our Series A preferred stock, the terms of our convertible preferred stock permit us, subject to certain limitations, to issue shares of our Class A common stock in lieu of cash to satisfy payments of dividends and redemption prices with respect to the Series A preferred stock. The number of shares issued for such payments will be determined based on 95% of a five day average market value of such shares determined shortly before such payments, and could be substantial, especially during periods of significant declines in market prices of our Class A common stock.

The covenants applicable to our senior secured credit facility and the indentures governing our currently outstanding senior notes currently restrict, and any indentures and other financing agreements that we enter into in the future may restrict, our ability to pay cash dividends on our capital stock, including the Series A preferred stock. These limitations may cause us to be unable to pay dividends in cash on our Series A preferred stock unless we can obtain an amendment of such provisions or refinance amounts outstanding under those agreements. In most situations, however, we are permitted under our financing agreements to pay dividends in equity interests, including common stock, as permitted by the terms of the Series A preferred stock. Accordingly, dividends declared and paid in respect of the Series A preferred stock may be paid in Class A common stock and we will be restricted in the amount of dividends we are able to pay in cash, unless and until we obtain an amendment of our senior secured credit facility covenants. There is no assurance that we will obtain such an amendment. Issuance of shares of Class A common stock as dividends, upon the occurrence of conversion, including following a fundamental change, or upon redemption of the Series A preferred stock, will dilute ownership of the Class A common stock and accordingly may adversely affect its market value.

The Series A preferred stock may adversely affect the market price of our Class A common stock for other reasons.

The market price of our Class A common stock is likely to be influenced by the Series A preferred stock. For example, the market price of our Class A common stock could become more volatile and could be depressed by:

investors' anticipation of the potential resale in the market of a substantial number of additional shares of our Class A common stock received upon conversion of the Series A preferred stock;

possible sales of our Class A common stock by investors who view the Series A preferred shares as a more attractive means of equity participation in us than owning shares of our Class A common stock; and

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hedging or arbitrage trading activity that may develop involving the Series A preferred shares and our Class A common stock.

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 August 18, 2016, by and between Jones Energy Holdings, LLC and SCOOP Energy Company, LLC
3.1		Certificate of Designations of the 8.0% Series A Perpetual Convertible Preferred Stock, filed with the Secretary of State of the State of Delaware and effective August 25, 2016 (including form of stock certificate) (incorporated by reference herein to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on August 26, 2016)
4.1		Form of certificate for the 8.0% Series A Perpetual Convertible Preferred Stock (included as Exhibit A to Exhibit 3.1)
10.1*		Amendment No. 10 to Credit Agreement dated as of August 1, 2016, among Jones Energy Holdings, LLC, as borrower, Jones Energy, Inc., Jones Energy, LLC and Nosley Assets, LLC, as guarantors, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto
10.2		Fourth Amended and Restated Limited Liability Company Agreement of Jones Energy Holdings, LLC, dated as of August 25, 2016 (incorporated by reference herein to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on August 26, 2016)
10.3		Amendment No. 1 to Fourth Amended and Restated Limited Liability Company Agreement of Jones Energy Holdings, LLC, dated as of September 30, 2016 (incorporated by reference herein to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on October 6, 2016)
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: November 4, 2016	By:	/s/ Robert J. Brooks
	Name: Robert J. Brooks
	Title: Chief Financial Officer (Principal Financial Officer)

Signature Page to Form 10-Q (Q3 2016)

Execution Version

PURCHASE AND SALE AGREEMENT

by and between

SCOOP ENERGY COMPANY, LLC,

as Seller,

and

JONES ENERGY HOLDINGS, LLC,

as Buyer,

_________________________________________

Dated as of August 18 , 2016
_________________________________________

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TABLE OF CONTENTS

Definitions and References 1

Definitions 1

References; Construction 17

Purchase and Sale; Purchase Price 18

Title and Environmental Defects 18

Preferential Rights to Purchase; Consents to Assignment 25

Imbalance Volumes 27

Certain Upward Adjustments 27

Certain Downward Adjustments 27

Closing Date Estimates 28

Final Accounting 28

Payments 29

Seller’s Representations and Warranties 29

Organization, Good Standing, Etc. 29

Legal Requirements 29

No Breach 29

Litigation 30

Taxes 30

Compliance with Laws 30

Contracts 30

Environmental Proceedings 31

Authority 32

Broker’s or Finder’s Fees 32

Foreign Person 32

Capital Projects 32

Leases 32

Imbalance Volumes; Payments for Production 32

Preferential Purchase Rights 33

Required Consents 33

Bankruptcy; Insolvency 33

Outstanding Unit Proposals 33

Buyer’s Representations and Warranties 33

Organization, Good Standing, Etc. 33

Governmental Consent 34

Litigation 34

Broker’s or Finder’s Fees 34

Qualifications 34

Funding; Investment 34

Bankruptcy; Insolvency 35

Covenants 35

Access to Records 35

Access to Properties 36

Conduct of Business 37

Consents and Operations 39

Conditions 39

Additional Properties 39

Revenues Held For Benefit of the Other Party 39

Extension and Renewal of Expiring Leases 40

Limitations on Representations and Warranties 40

Taxes 42

Buyer’s Conditions Precedent 43

No Injunctions or Orders 43

No Legal Proceedings 43

Representations 43

Performance 43

Purchase Price Adjustments 44

Closing Deliverables 44

AKM Consent 44

Seller’s Conditions Precedent 44

No Injunctions or Orders 44

No Legal Proceedings 44

Representations 44

Performance 44

Title Defects and Environmental Defects 45

Closing Deliverables 45

AKM Consent 45

The Closing 45

Buyer’s Deliveries 45

Seller’s Deliveries 46

Post-Closing Adjustments 46

Post-Closing Deliveries 46

Costs and Expenses 47

Risk of Loss 47

Press Releases 47

Indemnification 47

Assumed Obligations 47

Seller’s Indemnification 47

Buyer’s Indemnification 48

Express Negligence 48

Indemnification Procedure 49

Defense 49

Certain Limitations on Indemnity Obligations 50

Exclusive Remedy 52

Satisfaction 52

Termination 52

Right to Terminate 52

Effect of Termination 53

Distribution of Deposit and Remedies upon Termination 53

Arbitration; Rules of Arbitration 56

Consolidation 57

Initiation; Selection of Arbitrators 57

Procedure 58

Location and Timing 58

Expenses; Award of Fees 58

Limitations 59

Enforcement; Remedies 59

No Third Party Beneficiaries 61

Cumulative Remedies 61

Counterparts; Facsimiles; Electronic Transmission 62

Joint Acknowledgment 63

Waiver of Jury Trial, Special Damages, etc 63

Possible Exchange 63

Mutuality 63

Schedules 64

Preparation of Agreement 64

Filings, Notices and Approvals 64

Nonrecourse to Others 64

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EXHIBITS AND SCHEDULES

EXHIBITS

Exhibit A Properties and Allocated Values

Exhibit B Form of Assignment, Bill of Sale and Conveyance

Exhibit C Form of Non-Foreign Status Certificate

Exhibit D Form of Closing Certificate

Exhibit E Form of Escrow Agreement

SCHEDULES

Schedule ‎1.1(a) Knowledge Persons (Buyer)

Schedule ‎1.1(b) Knowledge Persons (Seller)

Schedule ‎3.3 No Breaches

Schedule ‎3.4 Litigation

Schedule ‎3.5 Taxes

Schedule ‎3.7 Contracts

Schedule ‎3.8 Environmental Proceedings

Schedule ‎3.12 Capital Projects

Schedule ‎3.14 Imbalance Volumes; Payments for Production

Schedule ‎3.15 Preferential Purchase Rights

Schedule ‎3.16 Required Consents

Schedule ‎3.18 Outstanding Unit Proposals

Schedule ‎5.8.1 Extension or Renewal of Leases

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PURCHASE AND SALE AGREEMENT

This PURCHASE AND SALE AGREEMENT (this “ Agreement ”) is entered into this 16 th day of August, 2016 (“ Execution Date ”), between SCOOP ENERGY COMPANY, LLC , an Oklahoma limited liability company (“ Seller ”), and Jones Energy holdings, llc , a Delaware limited liability company (“ Buyer ”). Buyer and Seller are referred to herein, individually, as a “ Party ” and, collectively, as the “ Parties ”.

RECITALS

WHEREAS, Seller desires to sell and Buyer desires to purchase all of the Properties (as hereinafter defined); and

WHEREAS, the purchase and sale of the Properties will be consummated on the terms and conditions set forth in this Agreement;

NOW, THEREFORE, for and in consideration of the mutual covenants herein contained and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

AGREEMENT

1. Definitions and References . Capitalized terms used throughout this Agreement including the Recitals above and not defined elsewhere in this Agreement shall have the meanings given such terms in this Section ‎1.1 or in the Section referred to below

1.1.

Definitions . The following terms have the meanings given in this Section ‎1.1 or in the Section referred to below:

“ AAA ” means the American Arbitration Association.

“ AAA Rules ” has the meaning specified in Section ‎13.1 .

“ Accounting Referee ” means a nationally recognized accounting firm mutually agreed upon by the Parties, provided that such Accounting Referee has not performed any material work for either of the Parties or their respective Affiliates within the preceding five (5) year period.

“ Additional Interests ” has the meaning specified in Section 5.6 .

“ Affiliate ” means, with respect to any Person, any other Person that directly or indirectly (through one or more intermediaries or otherwise) Controls, is Controlled by, or is under common Control with the first Person.

“ Aggregate Defect Threshold ” has the meaning specified in Section ‎2.1.2 .

“ Agreement ” has the meaning specified in the introductory paragraph and includes the Schedules attached hereto.

27242226 1 Asset Purchase Agreement

“ AI Escrow Agent ” has the meaning specified in Section 5.6.1 .

“ AI Escrow Funds ” has the meaning specified in Section 5.6.1 .

“ AI Price ” has the meaning specified in Section 5.6.1 .

“ AKM Consent ” has the meaning specified in Section 3.2 .

“ Allocated Value ” means, with respect to any Property, the portion of the Purchase Price attributable to such Property as set forth on Exhibit A .

“ Arbitrable Dispute ” means (except for: (i) disputes involving Title Defects or Environmental Defects or any cure relating thereto, or involving Title Benefits, each of which will be resolved as provided in Section ‎2.1.11 , or (ii) any matters to be resolved by the Accounting Referee as provided in Section ‎2.7 ) any and all disputes, claims, counterclaims, demands, causes of action, controversies and other matters in question arising out of or relating to this Agreement or the alleged breach hereof, or in any way relating to matters that are the subject of this Agreement or the transactions contemplated hereby or the relationship between the Parties created by this Agreement, regardless of whether (a) allegedly extra-contractual in nature, (b) sounding in contract, tort or otherwise, (c) provided for by Law or otherwise, or (d) seeking damages or any other relief, whether at Law, in equity or otherwise.

“ Asset Taxes ” means ad valorem, property, excise, severance, production, sales, use, or similar Taxes (excluding, for the avoidance of doubt, any Income Taxes and Transfer Taxes) based upon or measured by the ownership or operation of the Conveyed Interests or the production of Hydrocarbons therefrom or the receipt of proceeds therefrom.

“ Assignment ” means the Assignment, Bill of Sale and Conveyance in substantially the same form attached hereto as Exhibit B .

“ Assumed Obligations ” means, other than Retained Obligations, all Liabilities of every kind and character, known or unknown, arising out of or in connection with, or attributable to or related to the Properties or to the ownership, use operation, maintenance or disposition thereof, regardless of whether arising, occurring, accruing or attributable to periods prior to, on or after the Effective Time, including, without limitation, Liabilities arising out of or in connection with or attributable to or related to any of the following: (a) the terms of all oil, gas and mineral leases, easements and similar agreements constituting part of the Properties, as well as the terms and provisions of all Contracts constituting part of the Properties including, without limitation, any Contracts entered into by Seller after the Effective Time and prior to Closing which are both attributable to, and constitute part of, the Properties and are entered into in compliance with Section ‎5.3 ; (b) Third Party claims, demands, violations, actions, assessments, penalties, fines, costs, expenses, obligations or other liabilities with respect to the ownership, operation or maintenance of any of the Properties; (c) Imbalance Volumes; (d) Taxes allocated to Buyer under Section 5.9 or Section 8.5 ; (e) the accounting for, failure to pay or

27242226 2 Asset Purchase Agreement

the incorrect payment to any royalty owner under the Leases or Lands attributable to the period that Hydrocarbons were produced and marketed from any Property from and after the Effective Time; (f) properly plugging, abandoning and decommissioning wells, flowlines, gathering lines or other facilities, equipment or other personal property or fixtures located on the Properties; and (g) restoring the surface of Leases or the Lands or any failure of the Properties or the ownership or operation thereof to comply with Environmental Laws, including any and all obligations to bring the Properties into compliance with applicable Environmental Laws (including conducting any remediation activities that may be required on or otherwise in connection with activities on the Properties).

“ Average NA Price ” has the meaning specified in Section 5.6 .

“ Basket ” has the meaning specified in Section ‎10.7.1 .

“ Business Day ” means any day other than Saturday or Sunday or a day on which banking institutions in Oklahoma City, Oklahoma are authorized by Law to close.

“ Buyer ” has the meaning specified in the introductory paragraph.

“ Buyer Indemnified Parties ” has the meaning specified in Section ‎10.2 .

“ Certificate ” means a certificate in substantially the form of Exhibit D .

“ Claimant ” has the meaning specified in Section ‎13.5 .

“ Closing ” means the closing and consummation of the transactions contemplated by this Agreement.

“ Closing Date ” means the date on which the Closing occurs, which will be September 22, 2016.

“ Closing Payment ” has the meaning specified in Section ‎2.6 .

“ Closing Statement ” has the meaning specified in Section ‎2.6 .

“ Confidentiality Agreement ” means that certain confidentiality agreement dated June 28, 2016 executed by the Parties or their Affiliates.

“ Consultant ” has the meaning specified in Section ‎2.1.11 .

“ Contracts ” has the meaning specified in the definition of Properties.

“ Control ” means the possession, directly or indirectly, of the power, directly or indirectly, to direct or cause the direction of the management or policies of the controlled Person, whether through the ownership of equity interests in or voting rights attributable to the equity interests in such Person, by contract or agency, by

27242226 3 Asset Purchase Agreement

the general partner of a Person that is a partnership, or otherwise; and “ Controls ” and “ Controlled ” have meanings correlative thereto.

“ Cure Period ” has the meaning specified in Section ‎2.1.10 .

“ Customary Post-Closing Consents ” has the meaning specified in the definition of Permitted Encumbrances.

“ Defect Disputes ” has the meaning specified in Section ‎2.1.11 .

“ Defect Notice ” means a written notice delivered to Seller on or before the Defect Notice Date specifying one or more defects associated with the Properties that Buyer asserts constitutes a Title Defect or Environmental Defect, which must include at a minimum (in order to be valid and considered timely delivered) a specific description of each such Title Defect or Environmental Defect, the basis for such assertion under the terms of this Agreement, the amount of the adjustment to the Purchase Price that Buyer asserts based on such Title Defect or Environmental Defect and its method of calculating such adjustment, together with all data and information in Buyer’s possession reasonably necessary for Seller to verify the existence of such Title Defect or Environmental Defect.

“ Defect Notice Date ” has the meaning specified in Section ‎2.1 .

“ Defensible Title ” means title deducible of record and/or provable title evidenced by documentation that, although not constituting perfect, merchantable or marketable title, can be successfully defended if challenged, which, immediately prior to the Closing pursuant to this Agreement and subject to Permitted Encumbrances:

(a)

with respect to a Lease or a Well , entitles Seller to receive throughout the productive life of such Well or Lease not less than the Net Revenue Interest set forth on Exhibit A in and to all Hydrocarbons produced and saved or sold from or allocated to the Target Formations of such Well or Lease , except for (i) decreases in connection with any operation in which the owner of such Lease or Well may elect to be a non-consenting co-owner after the Execution Date, (ii) decreases resulting from the establishment after the Execution Date of pools or units, (iii) decreases resulting from the reversion of interests to co-owners with operations in which such co-owners elected not to consent as shown on Exhibit A , (iv) resulting from actions by (or undertaken at the request of) Buyer, and (v) as otherwise shown on Exhibit A ;

(b)

with respect to a Lease , entitles Seller to not less than the respective number of Net Acres shown on Exhibit A for such Lease;

(c)

with respect to a Well, obligates Seller to bear a percentage of the costs and expenses for the maintenance, development, operation and the production relating to such Well (“ Working Interest ”), and throughout the productive

27242226 4 Asset Purchase Agreement

life of such Well, not greater than the Working Interest shown in Exhibit A with respect to the Target Formations of such Well, except (i) increases in such Working Interest that result in at least a proportionate increase in Seller’s Net Revenue Interest for such Well, (ii) increases resulting from contribution requirements with respect to defaults by co-owners under applicable operating agreements and shown on Exhibit A , or (iii) as otherwise shown on Exhibit A ; and

(d)

is free and clear of all Liens.

“ Deposit ” has the meaning specified in Section ‎2 .

“ Dollar ” means the United States of America dollar.

“ Easements ” has the meaning specified in the definition of Properties.

“ Effective Time ” means 11:59 p.m. Central Time on August 1, 2016.

“ Environmental Defect ” means a condition with respect to the Properties that would constitute a current violation of applicable Environmental Laws or that with notice or the passage of time, or both, would constitute a violation of Environmental Laws existing prior to the Closing Date on or under any Property that requires reporting, investigation, monitoring, removal, cleanup, remediation, restoration or correction under Environmental Laws.

“ Environmental Law ” means, as the same have been amended as of the Execution Date, the Comprehensive Environmental Response, Compensation and Liability Act, including the Superfund Amendments and Reauthorization Act of 1986, 42 U.S.C. § 9601 et seq .; the Resource Conservation and Recovery Act, including the Hazardous and Solid Waste Amendments Act of 1984, 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 .; the Safe Drinking Water Act, 42 U.S.C. §§ 300f through 300j; the Rivers and Harbors Act of 1899, 33 U.S.C. § 401 et seq .; and the Occupational Safety and Health Act, 29 U.S.C. § 651 et seq .; all similar Laws as of the Execution Date of any Governmental Authority having jurisdiction over the Property in question addressing health, safety, pollution or protection of the environment and the presence of Hazardous Materials and environmental conditions on, under, or about any of the Properties and all regulations implementing the foregoing that are applicable to the operation and maintenance of the Properties.

“ Escrow Agent ” has the meaning specified in Section ‎2 .

“ Escrow Agreement ” has the meaning specified in Section ‎2 .

27242226 5 Asset Purchase Agreement

“ Escrow Fund ” has the meaning specified in Section ‎2 .

“ Excluded Assets ” means:

(a)

Seller’s minute books, financial and income tax records and legal records (other than title records pertaining to the Properties), and all other business records that are related to the Excluded Assets or to the business generally of Seller or any of its Affiliates;

(b)

any existing or future refund of costs, Taxes or expenses borne by any of Seller, its Affiliates or its or their respective predecessors in title attributable to the period prior to the Effective Time or to any Excluded Assets;

(c)

to the extent that they do not relate to the Assumed Obligations for which Buyer is providing indemnification hereunder or are not assignable, all rights and interests of Seller or any of its Affiliates (i) under any policy or agreement of insurance or indemnity (including any rights, claims or causes of action of Seller and its Affiliates against Third Parties under any indemnities or hold harmless agreements and any indemnities received in connection with Seller’s or any of its Affiliates’ prior acquisition of any of the Properties) to the extent and only to the extent such rights and interests relate to the ownership or operation of the Properties prior to the Effective Time and (ii) under any bond;

(d)

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

(e)

all accounts receivable and audit rights arising under any of the applicable contracts or otherwise with respect to the Properties with respect any period prior to the Effective Time insofar as such audit rights relate to the Retained Obligations or to any of the Excluded Assets;

(f)

Geological and Geophysical Information to the extent Seller is prohibited from sharing by written agreement with a Third Party;

(g)

except to the extent included in the calculation of Net Revenue Interests set forth on Exhibit A , all mineral interests, royalty interests, overriding royalty interests and other non-expense bearing interests owned by Seller and all mineral interests, royalty interests, overriding royalty interests and other non-expense bearing interests owned by Affiliates of Seller;

(h)

all claims of Seller or any of its Affiliates for refunds of or loss carry forwards with respect to (i) Asset Taxes attributable to any period prior to the Effective Time, (ii) Income Taxes attributable to any period prior to the Closing Date, or (iii) any Taxes attributable to the Excluded Assets;

27242226 6 Asset Purchase Agreement

(i)

all “virtual courthouses” of Seller or any of its Affiliates, all of their respective exclusive use arrangements with title abstract facilities and all documents and instruments of Seller or any of its Affiliates that may be protected by an attorney-client privilege and all data that cannot be disclosed to Buyer as a result of confidentiality arrangements under agreements with Third Parties (other than title opinions and other title records relating to the Properties);

(j)

all surface fee interests, surface leasehold and other surface property interests (but excluding the Properties described in subpart (d) of the definition thereof), and all buildings, offices, improvements, appurtenances, field offices and yards;

(k)

automation systems including meters and related telemetry, licensed radio frequencies and associated communications infrastructure including towers, antennas, data links and network circuits, except any such items in which Seller owns an interest related to a Well which was charged to the joint account of the Working Interest owners in such Well;

(l)

all drilling rigs and related equipment, all work over rigs and related equipment, tools and other equipment, all vehicles, all other equipment, inventory, machinery, tools and other personal property;

(m)

all gathering lines, flow lines, gas lines, gas processing and gathering line compression facilities, tubing, pumps, motors, gauges, valves and other systems, machinery and equipment constituting part of or comprising gas gathering systems or assets, and all rights of way, easements and other contracts relating to the ownership, operation or maintenance of any of the foregoing, except to the extent set forth in sub-part (c) of “Properties” and except any such items in which Seller owns an interest related to a Well which was charged to the joint account of the Working Interest owners in such Well;

(n)

all claims, rights, demands, actions, judgments, damages, awards, fines, penalties, recoveries (including insurance proceeds), and settlements in favor of, and all other amounts and obligations owed to, Seller relating to the Properties or any damage to or destruction thereof, in each case, to the extent relating to the period prior to the Effective Time, and all proceeds received by Seller in respect of any of the foregoing regardless of when such proceeds are received, except, in each case, to the extent such matters do not relate to the Assumed Obligations for which Buyer is providing indemnification hereunder; and

(o)

any assets that are excluded pursuant to the provisions of this Agreement.

“ Execution Date ” has the meaning specified in the introductory paragraph.

27242226 7 Asset Purchase Agreement

“ Existing Credit Agreement ” means that certain Fourth Amended and Restated Term Loan and Guaranty Agreement by and among Oaktree SC AE SCOOP Holdings, LLC, as the Lender, American Energy – SCOOP, LLC, as the Borrower, and American Energy Anadarko Holdings, LLC and Aubrey K. McClendon as the Guarantors dated as of October 28, 2015.

“ Expiration Date ” has the meaning specified in Section ‎14.3 .

“ Final Statement ” has the meaning specified in Section ‎2.7 .

“ Fundamental Representations ” means the representations contained in Sections ‎3.1 , ‎3.2 , ‎3.5 , ‎3.9 , ‎3.10 , 3.11 , ‎3.17 , ‎4.1 , ‎4.2 , ‎4.4 , ‎4.8 , ‎4.9 and ‎4.10 .

“ GAAP ” means generally accepted accounting principles, consistently applied, as recognized by the U.S. Financial Accounting Standards Board (or any generally recognized successor). The requisite that such principles be consistently applied means that the accounting principles in a current period are comparable in all material respects to those applied in preceding periods.

“ Geological and Geophysical Information ” means data, core and fluid samples and other engineering, geological and/or geophysical studies (including seismic data, studies and information), and other similar information and records, in each case relating to the Properties.

“ Governmental Authority ” means any national, state, local, municipal or other government or division thereof; 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 or arbitrator.

“ Hazardous Materials ” means any waste, substance, product or other material (whether solid, liquid, gas or mixed), which is identified, listed, published or defined as a hazardous substance, hazardous waste, hazardous material, toxic substance, radioactive material or solid waste, including Hydrocarbons, oil or petroleum waste, or any other waste, pollutant or contaminant that is regulated, restricted or subject to reporting and recordkeeping under any Environmental Law.

“ Hydrocarbons ” means crude oil, natural gas, casinghead gas, condensate, natural gas liquids, and other liquid or gaseous hydrocarbons.

“ Imbalance Volumes ” means any well imbalance volumes at the wellhead between the amount of Hydrocarbons produced from a Well and allocable to Seller’s interest and the shares of production from the relevant Well to which Seller is entitled as adjusted by any setoffs that Seller may be entitled to under the terms of the gas purchase contracts and agency agreements related to the applicable pipeline.

“ Income Taxes ” means any income or franchise Taxes.

27242226 8 Asset Purchase Agreement

“ Individual Claim ” has the meaning specified in Section ‎10.7.1 .

“ Individual Defect Threshold ” has the meaning specified in Section ‎2.1.1 .

“ Interim Period ” means that period of time commencing at the Effective Time and ending on the Closing Date.

“ Knowledge ” of a fact or matter means the actual knowledge with respect to such fact or matter (at the time the representation is made), without investigation, of any of the following listed individuals: (a) with respect to Buyer, the individuals listed in Schedule ‎1.1(a) , and (b) with respect to Seller, the individuals listed in Schedule ‎1.1(b) .

“ Lands ” means the lands covered by the Leases and all lands pooled or unitized therewith.

“ Laws ” means any and all applicable laws, statutes, ordinances, permits, decrees, writs, injunctions, orders, codes, judgments, principles of common law, rules or regulations (including Environmental Laws) which are promulgated, issued or enacted by a Governmental Authority having jurisdiction.

“ Lease ” has the meaning specified in the definition of Properties.

“ Liabilities ” means any and all claims, demands causes of action, payments, charges, judgments, assessments, liabilities, losses, damages, diminution in value, debts, duties, obligations, violations, penalties, fines, costs, and/or expenses, including attorneys’ fees, legal or other expenses incurred in connection therewith, and including liabilities, costs, losses and damages for personal injury or death or property damage.

“ Lien ” means any lien, mortgage, security interest, pledge, charge, encumbrance or rights of a vendor under any title retention or other arrangements substantially equivalent thereto, but does not include any production payment, net profits interest, overriding royalty interest or similar interest.

“ Material Adverse Effect ” means any result, consequence, condition, occurrence, event, fact or matter which could reasonably be expected to, individually or in the aggregate, (a) materially adversely affect the Properties or the operations, rights, results of operations or the value of the Properties, taken as a whole, (b) materially impair the ability of Seller to own, hold, develop and operate the Properties, taken as a whole or (c) impair, prevent or materially delay Seller’s ability to perform its obligations under this Agreement or to consummate the transactions contemplated by this Agreement; provided , however , that, in any event, the following shall not be deemed to constitute, create or cause a Material Adverse Effect: (i) any changes, circumstances or effects that affect generally the oil and gas industry, such as fluctuations in the price of Hydrocarbons, or the financial or securities markets, or that result from international, national, regional, state or local economic conditions, from general developments or from other general economic or political conditions,

27242226 9 Asset Purchase Agreement

facts or circumstances, including changes in Tax policy or other fiscal conditions, that are not subject to the control of the relevant Party; (ii) changes, circumstances or effects that result from entering into this Agreement or from the transactions contemplated in this Agreement, or the public announcement thereof; (iii) changes, circumstances or effects that result from conditions or events resulting from civil unrest, an outbreak or escalation of hostilities (whether nationally or internationally), or the occurrence of any other calamity or crisis (whether nationally or internationally), including the occurrence of one or more terrorist attacks; (iv) matters that are cured or no longer exist by the earlier of Closing and the termination of this Agreement; (v) acts or failures to act of Governmental Authorities; or (vi) any change in Laws, and any interpretations thereof or in accounting rules (including GAAP) after the Execution Date.

“ Net Acres ” means, as to each parcel or tract of Land burdened by a Lease, the product of (a) the number of acres of land that are in such parcel or tract (i.e. gross acres), multiplied by (b) the lessor’s undivided interests in the Target Formations Hydrocarbons in the Lands burdened by such Lease, multiplied by (c) Seller’s undivided interest in such Lease (provided, however, if items (b) and (c) of this definition vary as to different areas within any tracts or parcels burdened by such Lease, a separate calculation shall be performed with respect to each such area) .

“ Net Revenue Interest ” (or “ NRI ”) means the decimal interest in and to all production of the Target Formations Hydrocarbons produced and saved or sold from or allocated to the relevant Well or Lease after giving effect to all valid lessors’ royalties, overriding royalties and/or other burdens upon, measurable or payable out of production or proceeds thereof.

“ NORM ” has the meaning specified in Section ‎5.9 .

“ Ordinary Course of Business ” means in the ordinary course of business consistent with past custom and practice.

“ Outside Date ” has the meaning specified in Section ‎11.1.2 .

“ Overhead Costs ” means: (a) for the period from the Effective Time through the earlier of the Closing date or September 30, 2016, an aggregate amount equal to $350,000.00; and (b) in the event the Closing has not occurred on or before September 30, 2016, $250,000.00 per calendar month thereafter (prorated for partial months), which represents overhead and administrative costs attributable to the Properties.

“ Party ” and “ Parties ” have the meanings specified in the introductory paragraph.

“ Permitted Encumbrances ” means:

(a)

royalties, overriding royalties and other burdens or encumbrances to the extent they do not, individually or in the aggregate, reduce Seller’s Net Revenue Interest or Net Acres in any Property from that shown on Exhibit

27242226 10 Asset Purchase Agreement

A or increase Seller’s Working Interest (without at least a proportionate corresponding increase in Seller’s Net Revenue Interest) in any Well from that described for Seller in Exhibit A ;

(b)

Liens for Taxes for which payment is not due or which are being contested in good faith by appropriate proceedings;

(c)

Liens of mechanics, materialmen, warehousemen, employees, contractors, landlords, vendors, and carriers and any other Liens arising by operation of Law which arise in the Ordinary Course of Business , for sums not yet due or which are being contested in good faith by appropriate proceedings;

(d)

the existence, terms and provisions of all oil, gas and mineral leases, operating agreements, unit agreements, unitization and pooling designations and declarations, and all of the other Contracts and Leases, in each case, to the extent they do not, individually or in the aggregate, (i) reduce Seller’s Net Revenue Interest or Net Acres below that shown in Exhibit A or increase Seller’s Working Interest in any Well above that shown in Exhibit A (without a corresponding and proportionate increase in the Net Revenue Interest), and (ii) materially detract from the value of, or interfere with the use, development or ownership of, any Property;

(e)

easements, servitudes, permits, rights-of-way, surface leases, and other rights and plat restrictions, and all zoning and planning laws, restrictive covenants and conditions, regulatory authority of Governmental Authorities, and building and other land use Laws and similar encumbrances;

(f)

all rights to consent by, required notices to, filings with or other actions by Governmental Authorities in connection with the sale, disposition, transfer or conveyance of federal, state, tribal, or other governmental oil and gas leases or interests therein or related thereto, where the same are customarily obtained subsequent to the assignment, disposition or transfer of such oil and gas leases or interests therein, or such operations (“ Customary Post-Closing Consents ”);

(g)

conventional rights of reassignment obligating the lessee to reassign or offer to reassign its interests in any lease prior to a release or abandonment of such lease;

(h)

required non-governmental Third Party consents to assignments which have been obtained or waived by the appropriate parties pursuant to Section ‎2.2 or which are not Required Consents or need not be obtained prior to an assignment, and PPRs which have been waived by the appropriate parties or for which the time period for asserting such rights has expired without the exercise of such rights; provided that Seller has complied with the provisions of Section ‎2.2 with respect to such PPRs;

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(i)

rights of tenants-in-common in and to the Properties or other rights of a common owner of any interest in rights-of-way, permits or easements held by Seller and such common owner as tenants in common or through common ownership;

(j)

all defects or irregularities, if any, affecting the Properties which do not, individually or in the aggregate, (i) adversely interfere in any material way with the present or future operation or use of the Properties subject thereto or affected thereby, (ii) reduce Seller’s Net Revenue Interest or Net Acres below that shown in Exhibit A or increase Seller’s Working Interest in any Well above that shown in Exhibit A (without a corresponding and proportionate increase in the Net Revenue Interest), and (iii) which would be accepted by a reasonably prudent and sophisticated buyer engaged in the business of owning, developing and operating oil and gas properties in the same geographical location with knowledge of all the facts and appreciation of their legal significance;

(k)

any matter that would not constitute a Title Defect under the terms of this Agreement (including matters described in the exceptions set forth within the definition of Title Defect); such Title Defects as Buyer may have waived (whether in writing or pursuant to the terms of this Agreement); and any Lien that is discharged, effective as of the Effective Time, by Seller or its Affiliates at or prior to Closing;

(l)

any provision in a Lease, surface lease, easement or other surface use agreement entered into prior to the Effective Time providing a Third Party with rights to an overriding royalty interest or other burdens or payments triggered by the use of the relevant surface property for drilling or other purposes, which do not, individually or in the aggregate, reduce Seller’s Net Revenue Interest or Net Acres below that shown in Exhibit A or increase Seller’s Working Interest in any Well above that shown in Exhibit A (without a corresponding and proportionate increase in the Net Revenue Interest); and

(m)

rights vested in or reserved to any Governmental Authority to regulate the Properties, to terminate any right, power, franchise, license or permit afforded by such Governmental Authority, or to purchase, condemn or expropriate any of the Properties.

“ Person ” means an individual, corporation, partnership, limited liability company, joint venture, association, joint stock company, trust, unincorporated organization or other entity or Governmental Authority.

“ PPR ” has the meaning specified in Section ‎2.2 .

“ Pre-Closing Acquisition Period ” has the meaning specified in Section 5.6 .

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“ Proceedings ” means any and all proceedings, suits and causes of action by or before any Governmental Authority, arbitrator or mediator, excluding, however, In the Matter of the Estate of Aubrey K. McClendon and proceedings relating thereto.

“ Properties ” means Seller’s right, title and interest, immediately prior to the Closing, in and to the following (but excluding the Excluded Assets), subject to the terms and reservations hereof:

(a)

the oil and gas leases, oil, gas and mineral leases (and subleases, other leaseholds, working interests and net revenue interests) owned by Seller and described on Exhibit A , whether producing or non-producing, in each case, subject to any depth limitations other than as to the Target Formations (collectively, the “ Leases ”);

(a)

all presently existing unitization, pooling and/or communitization agreements, declarations or designations and contractually, statutorily, judicially or administratively created drilling, spacing and/or production units, whether recorded or unrecorded, insofar as the same are attributable or allocated to the Real Property Interests, Lands, or Wells;

(a)

all Hydrocarbon wells located on the Lands including, without limitation, the oil, gas and other wells identified on Exhibit A (the “ Wells ”), whether such Wells are producing, operating, shut-in or abandoned, and the facilities and equipment associated or used in connection with the Wells, including gathering lines, flow lines, gas lines, gas processing and gathering line compression facilities, tubing, pumps, motors, gauges, valves and other systems, machinery and equipment constituting part of or comprising gas gathering systems or assets, and all rights of way, easements and other contracts relating to the ownership, operation or maintenance of any of the foregoing, and to the extent owned by Seller, all well logs for the Wells;

(b)

all presently existing and valid operating agreements, farmout and farmin agreements, unitization, pooling and communitization agreements, exploration agreements, area of mutual interest agreements, partnership and joint venture agreements and any other contracts, agreements and instruments, in each case, to the extent the above agreements cover, are attributable to or relate to the Lands or the Leases, including, without limitation, those contracts and agreements described on Schedule ‎3.7 (collectively, the “ Contracts ”); provided that “Contracts” shall exclude any master service agreements;

(c)

all Hydrocarbons in, on, under or produced from or attributable to the Leases or any interests pooled or unitized therewith from and after the Effective Time and the proceeds thereof;

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(d)

to the extent assignable, all easements, surface leases, subsurface leases, servitudes, permits, licenses and rights of way primarily used or held for use in connection with the ownership or operation of the Leases;

(e)

all rights, benefits and obligations arising from or in connection with any Imbalance Volumes as of the Effective Time;

(f)

all mineral interests, overriding royalty interests and lessor royalties owned by Seller to the extent included in the calculation of the Net Revenue Interest set forth on Exhibit A ;

(g)

to the extent owned by Seller, any Geological and Geophysical Information; and

(h)

the Records.

“ Purchase Price ” has the meaning specified in Section ‎2 .

“ Records ” means all of Seller’s records, data (including electronic data) and files related to the Properties, including Contract files, lease files, land files, maps, abstracts, title files, and Tax records, provided that “Records” does not include any Excluded Assets; provided , however , that Seller may retain copies of such Records as Seller has determined may be required for litigation, Tax, accounting and auditing purposes.

“ Required Consent ” means a consent by a Third Party that, if not obtained prior to the assignment of a Lease , automatically either (a) voids or nullifies the Assignment with respect to such Property, (b) terminates Seller’s interest in the Lease subject to such consent or (c) results in a breach that makes Buyer or Seller liable for a material amount of damages; provided , however , “Required Consent” does not include any consent which by its terms cannot be unreasonably withheld or any Customary Post-Closing Consent.

“ Respondent ” has the meaning specified in Section ‎13.5 .

“ Retained Obligations ” means those Liabilities of Seller: (a) arising out of, incident to or in connection with the Seller’s accounting for, failure to pay or the incorrect payment of (i) any and all royalties, overriding royalties, production payments, net profits interests 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 and (ii) amounts to any working interest owners (for the avoidance of doubt, including unleased mineral owners) in respect 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; (b) any Proceedings set forth on Schedule ‎3.4 (or any Proceedings that should have been listed on such Schedule); (c) Third Party claims, demands or other liabilities with respect to property damage, bodily injury or death arising from Seller’s operations on the Properties prior to the Closing Date;

27242226 14 Asset Purchase Agreement

(d) Seller’s disposal or transportation prior to the Effective Time of any Hazardous Materials that are attributable to Seller’s ownership or operation of the Properties at or to any location not on the Properties; or (e) Taxes allocated to Seller pursuant to Section 5.9 .

“ Seller ” has the meaning specified in the introductory paragraph.

“ Seller Indemnified Parties ” has the meaning specified in Section ‎10.3 .

“ Solvent ” means with regard to a Person and on a particular date that, at fair valuation, such Person’s assets are equal to or greater than the sum of all of such Person’s debts and liabilities, subordinated, contingent or otherwise, on such date, and that such Person is generally paying its debts as they become absolute and mature unless such debts or liabilities are subject of a bona fide dispute. The amount of contingent liabilities at any time shall be computed as the amount that, in the light of all the facts and circumstances existing at such time, represents the amount that can reasonably be expected to become an actual or matured liability as of that date.

“ Special Damages ” has the meaning specified in Section ‎14.16 .

“ Superior Transaction ” means a transaction involving the direct or indirect acquisition of the Properties at an acquisition price in excess of the Purchase Price.

“ Target Formations ” means (a) with respect to a Well listed on Exhibit A , the depths currently open to production from such Well as of the Execution Date, and (b) with respect to a Lease, that portion of the geological formations included within the depths described for such Lease on Exhibit A .

“ Taxes ” means taxes of any kind, levies, or other like assessments, customs, duties, imposts, charges or fees of any Governmental Authority, including income, gross receipts, ad valorem, value added, excise, real or personal property, asset, sales, use, royalty, license, payroll, transaction, capital, net worth and franchise taxes, withholding, employment, social security, workers compensation, utility, severance, production, unemployment compensation, occupation, premium, windfall profits, transfer and gains taxes or other governmental taxes, unclaimed property, or escheat obligations imposed or payable to the United States or any other Governmental Authority, and in each instance such term shall include any interest, penalties or additions to tax attributable to any such Tax, including penalties for the failure to file any tax return or report, and including any Liabilities in respect of any item described above, payable by reason of contract, assumption, transferee or successor liability, Treasury Regulations Section 1.1502-6(a) or any analogous or similar provision of law (or any predecessor or successor thereof), or having been a member of a combined or unitary group or otherwise, and in each case whether disputed or otherwise.

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

“ Third Party ” means any Person other than a Party or an Affiliate of a Party.

“ Title Benefit ” has the meaning specified in Section ‎2.1.9 .

“ Title Defect ” means, as to any Lease or Well, any condition that, if not cured, causes Seller’s title to such Lease or Well to be less than Defensible Title as of the Closing Date; provided , however , that, notwithstanding the foregoing, the following shall not be considered Title Defects:

(a)

defects based solely on lack of information in Seller’s files or references to a document that is not in Seller’s files;

(b)

defects arising out of lack of corporate or other entity authorization or a variation in corporate or entity name, unless Buyer provides evidence that the action was not authorized and resulted in a Third Party’s superior claim of title;

(c)

defects based on failure to record leases issued by any state or federal governmental body, or any assignments of such leases, in the real property, conveyance or other records of the county in which the Property is located and defects solely based on Tax assessment records, Tax payment records, or similar records (or the absence of such records);

(d)

defects based on a gap in Seller’s chain of title 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 the Defect Notice) and has resulted in another party’s superior claim of title and Seller cannot provide to Buyer curative documents with respect thereto that would be accepted by a reasonably prudent operator;

(e)

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

(f)

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, unless Buyer provides affirmative evidence that such failure or omission has resulted in another party’s superior claim of title;

(g)

defects as a consequence of cessation of production, insufficient production, failure to report production or report production timely, or failure to conduct operations on any of the Leases held by production, or lands pooled, communitized or unitized therewith, except to the extent that a claim for termination has been made by a lessor or other Third Party and Buyer is able to affirmatively establish (by means other than merely a lack of

27242226 16 Asset Purchase Agreement

available production records) that such matter occurred and that it has given rise to a right of the lessor or other Third Party to terminate the underlying lease (which documentation shall be included in the Defect Notice);

(h)

defects based on a legal description that includes the lessor’s mineral estate but describes a tract of land larger than that owned by the lessor;

(i)

Liens 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 which are not currently subject to foreclosure or other enforcement proceedings by the holder of the Lien;

(j)

defects arising out of prior oil and gas leases relating to the Leases or Lands that are not surrendered of record, or defects resulting from failure to record releases of liens, production payments or mortgages, in each case, that have expired by their own terms or the enforcement of which are barred by applicable statutes of limitation;

(k)

the absence of any lease amendment or consent by any royalty interest or mineral interest holder authorizing the pooling of any leasehold interest, royalty interest or mineral interest; and

(l)

defects to the extent affecting any depths or formations with respect to any Lease other than the Target Formations.

“ Transfer Taxes ” has the meaning specified in Section 5.9.2.

“ Working Interest ” has the meaning specified in the definition of Defensible Title.

15.2.

References; Construction . All references in this Agreement to Exhibits, Schedules, Sections, paragraphs, subsections and other subdivisions refer to the corresponding Exhibits, Schedules, Sections, paragraphs, subsections and other subdivisions of or to this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any Sections, subsections or other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement, and shall be disregarded in construing the language hereof. The words “this Agreement,” “herein,” “hereby,” “hereunder” and “hereof,” and words of similar import, refer to this Agreement as a whole and not to any particular subdivision unless expressly so limited. The words “this Section” and “this subsection,” and words of similar import, refer only to the Section or subsection hereof in which such words occur. A defined term has its defined meaning throughout this Agreement regardless of whether it appears before or after the place where it is defined. The word “or” is disjunctive but not necessarily exclusive, and has the inclusive meaning represented by the phrase “and/or” and the word “including” (in its various forms) means including without limitation. Examples are not to be construed to limit, expressly or by implication, the matter they illustrate. Each accounting term not defined herein, and each accounting term partly defined herein to the extent not defined, will have the meaning given to it under GAAP. All references to prices, values or

27242226 17 Asset Purchase Agreement

monetary amounts refer to Dollars. Pronouns in masculine, feminine or neuter genders shall be construed to state and include any other gender, and words, terms and titles (including terms defined herein) in the singular form shall be construed to include the plural and vice versa, unless the context otherwise requires. Exhibits and Schedules referred to herein are attached to and by this reference incorporated herein for all purposes.

2. Purchase and Sale; Purchase Price . At the Closing, and upon the terms and subject to the conditions of this Agreement, (a) Seller agrees to sell and convey to Buyer the Properties, and (b) Buyer agrees to purchase, accept and pay for the Properties and to assume the Assumed Obligations. In consideration for the sale of the Properties, Buyer will pay to Seller the purchase price of ONE HUNDRED THIRTY-SIX MILLION FOUR HUNDRED EIGHTY-FIVE THOUSAND TWO HUNDRED NINETY-THREE DOLLARS ($136,485,293.00), adjusted as set forth herein (the “ Purchase Price ”), in immediately available funds at Closing (pursuant to wire transfer instructions designated in advance by Seller to Buyer in writing) for the account of Seller. Within two (2) Business Days after the later of (i) the Execution Date or (ii) the execution and delivery of the Escrow Agreement by all parties thereto, Buyer will deliver an earnest money deposit to Wells Fargo Bank, National Association (the “ Escrow Agent ”) equal to fifteen percent (15%) of the unadjusted Purchase Price (the “ Deposit ”), and such amount, including any interest or other amounts earned thereon and less any disbursements therefrom in accordance with the Escrow Agreement (the “ Escrow Fund ”), is to be held in accordance with the terms of an Escrow Agreement substantially in the form of Exhibit E attached hereto (the “ Escrow Agreement ”). The Parties shall instruct the Escrow Agent to release the funds in accordance with Section 11.3 and the Escrow Agreement. The Purchase Price will be adjusted as set forth below in this Section ‎2 .

2.1.

Title and Environmental Defects . The Purchase Price will be (a) decreased only for those uncured Title Defects and uncured Environmental Defects that exceed, individually, the respective Individual Defect Thresholds and, collectively with all other uncured Title Defects and Environmental Defects that exceed the applicable Individual Defect Thresholds, the Aggregate Defect Threshold and (b) increased for Title Benefits, in each case, in accordance with this Section ‎2.1 . Buyer may deliver to Seller, on or before the Defect Notice Date, one or more Defect Notices (each meeting all of the requirements set forth in the definition thereof) specifying each defect associated with the Properties that Buyer asserts constitutes a Title Defect or an Environmental Defect. Any matters that may otherwise constitute Title Defects or Environmental Defects, but of which Seller has not been notified by Buyer pursuant to a valid Defect Notice by the Defect Notice Date, shall be deemed to have been waived by Buyer for all purposes. The term “ Defect Notice Date ” means 5:00 p.m. Central Time on September 15, 2016. All adjustments to the Purchase Price based on Title Defects and/or any breach of the special warranty contained in the Assignment (other than with respect to a Lien l (other than a Permitted Encumbrance) created by Seller that is liquidated in amount and constitutes a breach of Seller’s special warranty title contained in the Assignment) will be based on the Allocated Values attributable to the affected Properties. The defect amount with respect to a Title Defect shall be determined without duplication of any costs or losses included in another defect amount for Title Defects hereunder, or for which Buyer otherwise receives credit in the calculation of the Purchase

27242226 18 Asset Purchase Agreement

Price. In no event will the aggregate amount of Title Defect adjustments exceed the Allocated Value of a Property. Subject to Sectionº ‎2.1.10 and Section ‎2.1.11 , if the aggregate of all adjustments to the Purchase Price required under this Agreement in respect of a Property would equal or exceed the entire Allocated Value of such Property, then at Seller’s option (which option must be exercised by delivering written notice to Seller at least five (5) Business Days prior to Closing) and in lieu of such adjustments, Seller may exclude such Property from the purchase and sale hereunder, and such Property shall be an Excluded Asset and the Purchase Price will be reduced in an amount equal to the entire Allocated Value of such Property, and any Title Defects or Environmental Defects asserted as to such Property will not be considered for purposes of determining whether the Aggregate Defect Threshold has been met. Upon timely delivery of a Defect Notice of a Title Defect or Environmental Defect under this Section ‎2.1 , Buyer and Seller will in good faith negotiate the validity of the claim and the amount of any adjustment to the Purchase Price using the following criteria:

2.1.1

(a) No single Title Defect or Title Benefit with respect to: (i) a Well shall be taken into account unless the value of such defect or benefit is determined to be more than One Hundred Thousand Dollars ($100,000.00), and (ii) a Lease shall be taken into account unless the value of such defect or benefit is determined to be more than Ten Thousand Dollars ($10,000.00); and (b) no single Environmental Defect shall be taken into account unless the value of such defect is determined to be more than One Hundred Thousand Dollars ($100,000.00) (each such amount an “ Individual Defect Threshold ”), in which event the full amount of such defect or benefit shall be taken into account from the first Dollar. For the avoidance of doubt, the value of any single Environmental Defect that affects multiple Properties shall be aggregated for purposes of determining whether the applicable Individual Defect Threshold has been met.

2.1.2

No adjustment will be made to the Purchase Price for either uncured Title Defects or for uncured Environmental Defects unless the total of all such uncured Title Defects that, subject to Section ‎2.1.1 , exceed the Individual Defect Threshold for Title Defects and all such uncured Environmental Defects that exceed the Individual Defect Threshold for Environmental Defects exceeds three and one-half percent (3½%) of the unadjusted Purchase Price in the aggregate (the “ Aggregate Defect Threshold ”). In the event that the aggregate of such uncured Title Defects and such uncured Environmental Defects exceed the Aggregate Defect Threshold after offsetting any Title Benefits pursuant to Section ‎2.1.9 , the adjustment to the Purchase Price shall only be for the amount by which all such Title Defects and Environmental Defects (in excess of such Title Benefits) exceed the Aggregate Defect Threshold. Subject to Section ‎2.1.10 and Section ‎2.1.11 , with respect to any Environmental Defects for which an adjustment greater than the Allocated Value of the affected Property is claimed in good faith in Buyer’s Defect Notice, at either Party’s option (which option must be exercised by delivering written notice to the other Party at least two (2)

27242226 19 Asset Purchase Agreement

Business Days prior to Closing), such Party may elect to exclude the affected Property from the transactions contemplated hereby, and such Property shall be an Excluded Asset and the Purchase Price will be reduced by the Allocated Value of the affected Property.

2.1.3

If the adjustment is based on Seller owning a Net Revenue Interest in a Lease or Well which is less than the Net Revenue Interest shown on Exhibit A for such Lease or Well, then the downward adjustment shall be calculated by multiplying the Allocated Value for such Lease or Well on Exhibit A by a fraction, the numerator of which is an amount equal to the Net Revenue Interest shown on Exhibit A for such Lease or Well, less the Net Revenue Interest for such Lease or Well to which Seller is actually entitled taking the applicable Title Defect into account, and the denominator of which is the Net Revenue Interest shown on Exhibit A for such Lease or Well .

2.1.4

If the adjustment is based on Seller owning a Working Interest in a Well which is larger than the Working Interest shown for such Well on Exhibit A , but without a proportionate increase in the Net Revenue Interest for such Well, then the downward adjustment shall be calculated by determining the effective Net Revenue Interest that results from such larger Working Interest, determining what the Net Revenue Interest would be using such effective Net Revenue Interest and the Working Interest shown for such Property on Exhibit A and then calculating the adjustment in the manner set forth herein for adjustment based on reductions in the Net Revenue Interest.

2.1.5

If the adjustment is based on Seller owning fewer Net Acres in a Lease than those shown on Exhibit A for such Lease, then the downward adjustment shall be calculated by multiplying the Allocated Value shown for such Lease on Exhibit A by a fraction, the numerator of which is the number of Net Acres shown on Exhibit A for such Lease, less the number of Net Acres in such Lease to which Seller is actually entitled taking the applicable Title Defect into account, and the denominator of which is the number of Net Acres shown on Exhibit A for such Lease .

2.1.6

If the adjustment is based on a Lien or other monetary charge upon a Lease or Well (other than a Permitted Encumbrance) that is liquidated in amount, then the downward adjustment is the lesser of the amount necessary to remove such Lien or other monetary charge from the affected Lease or the Allocated Value of the affected Lease or Well, provided, however, that in the event the monetary charge upon Seller’s interest in such Lease or Well exceeds the Allocated Value, Buyer may elect to exclude the affected Lease or Well from the transactions contemplated hereby, and such Property shall be an Excluded Asset and the Purchase Price will be reduced by the Allocated Value of the affected Property.

2.1.7

If the adjustment is based on a liability to remediate or otherwise cure an Environmental Defect related to a Property, then the downward adjustment

27242226 20 Asset Purchase Agreement

is that portion for which Buyer would be liable after Closing of an amount equal to the lowest cost reasonably necessary for the remediation or correction or to otherwise cure such Environmental Defect (including all costs related to remediation, restoration, clean up, correction, removal, reporting, investigation and monitoring and any related criminal or civil fines, penalties and liabilities) in a manner that does not materially interfere with the use or operation of such Lease and that is consistent with applicable Environmental Law and prudent industry practices.

2.1.8

If the adjustment is based on an obligation, burden, or liability upon a Lease or Well for which Buyer’s economic detriment is not liquidated but can be estimated with reasonable certainty, then, subject to the other provisions hereof, the downward adjustment is the amount equal to the lesser of the amount of such economic detriment or the Allocated Value of such Lease or Well.

2.1.9

If Seller determines that the ownership of any Lease entitles Seller to: (a) a larger Net Revenue Interest than that set forth on Exhibit A for such Well or Lease; or (b) a greater number of Net Acres than the number of Net Acres set forth on Exhibit A for such Lease (each, a “ Title Benefit ”), then Seller shall notify Buyer of such Title Benefit in writing on or before the Defect Notice Date, which notice shall include a description of such Title Benefit, the Dollar value that Seller asserts is attributable to such Title Benefit and Seller’s method of calculating such amount, together with all data and information in Seller’s possession or control reasonably necessary for Buyer to verify the existence of the alleged Title Benefit. Seller shall be deemed to have conclusively waived any Title Benefit of which Seller fails to notify Buyer in the manner and by the date specified in the preceding sentence. The upward adjustment to the Purchase Price in respect of each Title Benefit shall be determined using the same principles as provided in this Section ‎2.1 with respect to Title Defects and any such adjustment shall only be to the extent that the aggregate of all Title Benefits that exceed the Individual Defect Thresholds exceed the Aggregate Defect Threshold.

2.1.10

If a Title Defect or an Environmental Defect is reasonably susceptible of being cured or remediated, as applicable, then Seller will provide notice to Buyer on or before five (5) days prior to the Closing Date stating whether or not Seller will attempt to cure such Title Defect or Environmental Defect. If Seller provides notice electing to attempt to cure such Title Defect or Environmental Defect, then Seller will have the right, but not the obligation, to attempt to cure such defect for a period of one hundred eighty (180) days following the Closing (the “ Cure Period ”) , provided, that such election shall not waive or be deemed to waive Seller’s right to dispute the existence of such alleged defect or the Purchase Price adjustment asserted with respect thereto. With respect to any alleged Title Defect Seller elects to cure or to which a Defect Dispute relates, (a) the Properties affected by such alleged Title Defect shall be conveyed to Buyer at Closing, (b) subject to the

27242226 21 Asset Purchase Agreement

applicable Individual Defect Threshold and the Aggregate Defect Threshold, the Purchase Price at Closing shall be reduced by the amount asserted by Buyer in the applicable Defect Notice attributable to such alleged Title Defect, and (c) Buyer shall pay to the Escrow Agent the amount set forth in Section ‎2.1.10(b) , such amount to be held by the Escrow Agent pursuant to the Escrow Agreement. After Closing, Buyer shall provide (or cause to be provided) to Seller and its representatives reasonable access to the Records during the Cure Period in connection with Seller’s efforts to cure such alleged Title Defects. With respect to any alleged Environmental Defect Seller elects to cure or to which a Defect Dispute relates, (x) the Properties affected by such alleged Environmental Defect shall be retained by Seller at Closing, (y) subject to the applicable Individual Defect Threshold and the Aggregate Defect Threshold, the Purchase Price shall be reduced by the Allocated Value of the applicable Property, and (z) Buyer shall pay to the Escrow Agent the amount set forth in Section ‎2.1.10(y) , such amount to be held by the Escrow Agent pursuant to the Escrow Agreement. If, at the expiration of the Cure Period, Seller has cured or partially cured any such Title Defect or Environmental Defect, then Buyer and Seller shall instruct the Escrow Agent to pay to Seller an amount equal to the value of the Title Defect or Environmental Defect (or in the event of a partial cure, the portion of the value of such Title Defect or Environmental Defect that corresponds to such partial cure), as applicable, that has been cured and Seller shall execute and deliver to Buyer an assignment (substantially in the same form as the Assignment) of any Properties affected by a cured Environmental Defect. If Seller fails to cure or partially cure any Environmental Defects or Title Defects such that the aggregate of any remaining amounts of all adjustments to the Purchase Price that Buyer in good faith asserts to remain with respect to such Title Defects and Environmental Defects exceeds the Allocated Value of the affected Property, then Seller or Buyer may elect to exclude such Property from the transactions contemplated hereby (or, if already conveyed to Buyer, Buyer will execute and deliver to Seller an assignment (in substantially the same form as the Assignment) of such Property), such Property shall be an Excluded Asset and the Parties shall instruct the Escrow Agent to pay to Buyer an amount equal to the amount previously paid to the Escrow Agent with respect to such Title Defects and Environmental Defects for such Property. If the Parties dispute whether or the extent to which a Title Defect or Environmental Defect has been cured or the amount due to the Party as a result thereof, then the matter shall be resolved in the manner described in Section ‎2.1.11 , and the amounts held by the Escrow Agent that are attributable to such Title Defect or Environmental Defect shall not be released until such matter is finally resolved in accordance therewith.

2.1.11

Seller and Buyer shall attempt in good faith to agree upon all Title Benefits, Title Defects, Environmental Defects, curative, and Purchase Price adjustments with respect thereto, on or before the Closing (or, with respect to any Title Defects or Environmental Defects that Seller has elected to cure,

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by the end of the Cure Period). If, at the Closing (or, with respect to any Title Defects or Environmental Defects that Seller has elected to cure, at the end of the Cure Period), there is still a dispute between Seller and Buyer involving: (a) Title Defects, (b) Title Benefits, (c) Environmental Defects, (d) the cure of a Title Defect or Environmental Defect, or (e) the value attributable to Title Defects, Title Benefits, or Environmental Defects or the adjustment to the Purchase Price with respect thereto (collectively, “ Defect Disputes ”), then Seller and Buyer shall each have until the date that is ninety (90) days after the end of the Cure Period to submit the dispute to an expert for determination as provided in this Section ‎2.1.11 following written notice from one Party to the other Party that such Party is initiating dispute resolution in accordance with this Section ‎2.1.11 , such notice to describe in reasonable detail the nature and specifics of the dispute. Buyer, with respect to Title Defects and Environmental Defects, and Seller, with respect to Title Benefits, shall be deemed to have conclusively waived any unresolved Title Defect or Environmental Defect dispute, or any unresolved Title Benefit dispute, with respect to which the applicable Party has not delivered a Dispute Notice to the other Party on or before the date that is ninety (90) days after the end of the Cure Period. The applicable disputes shall be consolidated to the extent practicable and resolved through the binding dispute resolution process set forth in this Section ‎2.1.11 . Title dispute matters to be resolved under this Section ‎2.1.11 shall be submitted to a mutually agreed lawyer in the energy industry in the State of Oklahoma with not less than seven (7) years’ experience in oil and gas title issues selected by Seller and Buyer, and environmental dispute matters to be resolved under this Section ‎2.1.11 shall be submitted to a mutually agreed, suitably qualified environmental expert in the energy industry with experience in environmental issues selected by Seller and Buyer (each such title attorney or environmental expert hereinafter, a “ Consultant ”). In the event Seller and Buyer are unable to agree on a single Consultant within thirty (30) days after receipt of the initiating notice, Seller will appoint one Consultant and Buyer will appoint one Consultant within twenty (20) Business Days thereafter and the two Consultants so appointed will appoint a third Consultant within thirty (30) days after the second Consultant is appointed. If the two Consultants are unable to agree on a third Consultant within such thirty (30) day period, then a third Consultant shall be selected by the AAA office in Dallas, Texas consistent with the selection criteria set forth in this Section and with due regard given to input from the Parties and the other Consultants. Any Consultant appointed pursuant to this Agreement (y) shall not have worked as an employee of or performed other material work for any Party or its Affiliates within the preceding five (5) year period or have any financial interest in the dispute (except publicly traded securities with respect to any Party or its Affiliates), and (z) shall agree in writing to keep strictly confidential the specifics and existence of the dispute as well as all proprietary records of the Parties reviewed by the Consultants in the process of resolving such dispute. The mutually agreed Consultant

27242226 23 Asset Purchase Agreement

or the three Consultants so appointed will resolve such matter. The costs and expenses of each Consultant shall be paid fifty percent (50%) by Seller and fifty percent (50%) by Buyer. Buyer and Seller shall each present to the Consultant(s), with a simultaneous copy to the other Party, a single written statement of its position on the defect, benefit, or dispute in question, together with a copy of this Agreement and any supporting material that such Party desires to furnish, not later than ten (10) Business Days after appointment of the Consultant(s). In making their determination, the Consultant(s) shall be bound by the terms of this Agreement and, without any additional or supplemental submittals by either Buyer or Seller, may consider available legal and industry matters as in their opinion are necessary or appropriate to make a proper determination. Within sixty (60) days following the submission of such written statements to the Consultant(s), applying the principles set forth in this Section ‎2.1 , the Consultant(s) shall make a determination of the matter submitted based solely on the single written statement of each Party. The decision of the Consultant(s) shall be in writing and conclusive and binding on Seller and Buyer and shall be enforceable against the Parties in any court of competent jurisdiction. Within five (5) days of the final decision by the Consultant(s), Buyer and Seller shall instruct the Escrow Agent to pay to Seller and/or Buyer, as applicable, an amount equal to the amounts awarded to each Party by the Consultant(s). Seller shall execute and deliver to Buyer an assignment (substantially in the same form as the Assignment) of any Properties affected by an applicable Environmental Defect; provided , however , that if the Consultant(s) determines the Purchase Price adjustment that would have been attributable to any Environmental Defects or Title Defects in the aggregate exceeds the Allocated Value of the affected Property, then Seller or Buyer may elect to exclude such Property from the transactions contemplated hereby (or, if already conveyed to Buyer, Buyer will execute and deliver to Seller an assignment (in substantially the same form as the Assignment) of such Property) and such Property shall be an Excluded Asset. The Consultant(s) shall act as experts for the limited purpose of determining the specific title or environmental dispute presented to them, shall not act as arbitrators, shall not consider, hear or decide any matters except the specific title or environmental disputes presented to them and shall not award legal fees, damages, interest or penalties (including punitive or exemplary damages, lost profits, consequential, special or indirect damages) to either Buyer or Seller. The Consultants shall not have the powers of the arbitrators under Section ‎13 and shall not consider any matters that are Arbitrable Disputes. In addition, the Consultant(s) shall agree in writing to keep strictly confidential the specifics and existence of any matters submitted as well as all proprietary records of the Parties, if any, reviewed by the Consultant(s) in the process of resolving such disputes.

2.1.12

Notwithstanding anything to the contrary in this Agreement, except for special warranty of title provided by Seller in the Assignment, Buyer’s

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termination rights set forth in Section ‎11.1 and for the indemnity provided under Section ‎10.2.1 as it relates to breaches of the representations in Sections ‎3.8 and 3.13 , constitutes the sole and exclusive remedy that Buyer shall have against the Seller Indemnified Parties with respect to any matter or circumstance relating to either (a) title to the Properties or (b) Environmental Laws, the release of Hazardous Materials into the environment, or the protection of the environment or health. Except to the limited extent necessary to enforce the terms of Section ‎2.1 , the special warranty of title provided by Seller in the Assignment, Buyer’s termination rights set forth in Section ‎11.1 and the indemnity provided under Section ‎10.2.1 as it relates to breaches of the representations in Sections ‎3.8 and 3.13 , Buyer (on behalf of itself, its Affiliates and their respective insurers and successors in interest) hereby releases, discharges and waives 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 Indemnified Parties with respect to any matter or circumstance relating to either (i) title to the Properties or (ii) Environmental Laws, the release of materials into the environment, or the protection of the environment 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 OR GROSS NEGLIGENCE), STRICT LIABILITY OR OTHER LEGAL FAULT OF THE SELLER INDEMNIFIED PARTIES . Except for the special warranty of title provided by Seller in the Assignment, Buyer acknowledges that Seller has not made and will not make any representation or warranty regarding any matter or circumstance relating to title to the Properties and, except as expressly provided in Section ‎3.8 , Buyer acknowledges that Seller has not made and will not make any representation or warranty regarding any matter or circumstance relating to the release of materials into the environment or protection of the environment or health, and that nothing in Section ‎3 or otherwise shall be construed as such a representation or warranty.

2.2.

Preferential Rights to Purchase; Consents to Assignment . Within ten (10) Business Days after the Execution Date, Seller shall provide any required notifications of a preferential purchase right, right of first refusal or other agreement which gives a Third Party a right to purchase a Property (or any part thereof) (“ PPR ”), requesting waivers thereof, in connection with the transactions contemplated hereby. Within ten (10) Business Days after the Execution Date, Seller will send letters seeking applicable consents pertaining to the transactions contemplated hereby, including Required Consents, but excluding Customary Post-Closing Consents. Seller will thereafter use its commercially reasonable efforts (at no cost to Seller) to ensure that all Required Consents are promptly granted, and Buyer (at no cost to Buyer) will provide any reasonable assistance requested by Seller to ensure that waivers and consents are promptly granted. Notwithstanding anything to the contrary contained herein, Seller shall have no liability to Buyer for failure to obtain such consents or waivers.

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2.2.1

If, as of the Closing Date, a holder of a PPR has notified Seller that it elects to exercise its PPR with respect to the Properties to which its PPR applies (determined by and in accordance with the agreement under which the PPR arises), then the Properties covered by that PPR will not be sold to Buyer (subject to the remaining provisions in this Section ‎2.2 ), and the Purchase Price will be reduced by the Allocated Value of the Properties subject to such PPR. Seller shall be entitled to all proceeds paid by any Person exercising a PPR prior to Closing. If, as of the Closing Date, the PPR has not been exercised or waived and the time for exercising such PPR has not expired, the Properties covered by that PPR will be sold to Buyer subject to any rights of the holder of the PPR and no adjustment to the Purchase Price will be made with respect thereto and, in the event the holder of any such PPR thereafter exercises such PPR, Buyer will comply with all of the terms thereof and, as may be required by the terms of the PPR, convey the applicable Properties to the holder of the PPR and be entitled to the proceeds paid by such holder with respect thereto. If, as of the Closing Date, a holder of a Required Consent has not yet delivered such Required Consent and the time for granting such consent has not expired, then the Properties covered by that Required Consent will not be conveyed to Buyer at Closing and the Purchase Price will be reduced by the Allocated Value of the Properties (or portions thereof) subject to such Required Consent.

2.2.2

If Properties have been excluded at the Closing due to a pre-Closing exercise of a PPR and if for any reason the purchase and sale of the Properties covered by the PPR are not or cannot be consummated with the holder of the PPR that exercised its PPR, then Seller shall so notify Buyer and, within ten (10) Business Days after Buyer’s receipt of such notice, Seller shall sell, assign, and convey to Buyer and Buyer shall purchase and accept from Seller such Properties pursuant to the terms of this Agreement and for the Allocated Value of such Property, subject to adjustments in accordance with Sections ‎2.4 and ‎2.5 . If Properties have been excluded at the Closing due to a failure to obtain a Required Consent in accordance with Section ‎2.2.1 , and if a Required Consent is received or deemed received pursuant to the terms of the underlying agreement within six (6) months after the Closing Date, then Seller shall so notify Buyer and, within ten (10) Business Days after Buyer’s receipt of such notice, Seller shall sell, assign, and convey to Buyer and Buyer shall purchase and accept from Seller such Properties pursuant to the terms of this Agreement and for the Allocated Value of such Property, subject to adjustments in accordance with Sections ‎2.4 and ‎2.5 .

2.2.3

Properties permanently excluded pursuant to this Section ‎2.2 will not be deemed to be affected by Title Defects or be subject to Section ‎2.1 and the Allocated Value of such excluded properties shall not be applied toward the Aggregate Defect Threshold.

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2.3.

Imbalance Volumes . The Purchase Price will be adjusted upward or downward, as applicable, by the net mcf of Seller’s aggregate Imbalance Volumes as of the Effective Time as set forth on Schedule ‎3.14 multiplied by $2.00 per mcf (upward for underage and downward for overage).

2.4.

Certain Upward Adjustments . The Purchase Price shall be increased by the following (without duplication): (a) the value of all merchantable allowable oil or other liquid Hydrocarbons owned by Seller in storage above the pipeline connection at the Effective Time that is credited to the Properties in accordance with gauging and other customary industry procedures, such value to be the actual price paid or, if not yet sold, the current market price at the Effective Time, less gravity adjustments deducted by the purchaser of such oil or other liquid Hydrocarbons; (b) the value of all pipeline line pack at the Effective Time that is credited to the Properties, such value to be the current market price at the Effective Time; (c) the amount of all expenditures incurred in accordance with the relevant operating or unit agreement, in connection with the ownership, operation and maintenance of the Properties (including capital expenditures, rentals, overhead, royalties, prepayments, operating, drilling and completion costs and other charges and expenses billed under applicable operating agreements and Taxes) attributable to Seller’s interest in the Properties for the period at or after the Effective Time, provided that no upward adjustment made pursuant to this Section ‎2.4(c) shall affect Buyers’ liability with respect to Assumed Obligations; (d) the amount of any and all prepaid utilities, rentals, deposits and any other prepays applicable to the period on or after the Effective Time that are attributable to the Properties; (e) the amount of any Taxes paid or borne by Seller (including as a reduction in proceeds received) for which Buyer is responsible under Section 5.9 ; (f) the Overhead Costs; and (g) any other amount provided for in this Agreement or agreed upon by Buyers and Seller; provided that, notwithstanding anything to the contrary contained herein, there shall be no adjustment pursuant to this Section ‎2.4 for any amounts spent or costs incurred by Seller (i) pursuant to Section ‎5.8 or (ii) from or after the Effective Time to extend or renew the term of any Leases.

2.5.

Certain Downward Adjustments . The Purchase Price shall be decreased by the following (without duplication): (a) the amount of any proceeds received and retained by Seller from the sale of Hydrocarbons produced from and after the Effective Time from the Properties (net of royalties and other burdens, including Taxes), less applicable marketing fees; provided, that on oil the amount shall be the amount paid by the purchaser to Seller actually received by Seller net of applicable marketing fees; (b) the amount equal to all unpaid Taxes based upon or measured by the ownership of the Properties that accrue to or are chargeable against the Properties in accordance with GAAP prior to the Effective Time but which will be paid by Buyer, which amount shall, to the extent not actually assessed or known, be computed based upon such Taxes for the immediately preceding calendar year; (c) the amount determined pursuant to Section ‎5.8.2 , if any; and (d) any other amount provided for in this Agreement or agreed upon by Buyer and Seller. For the avoidance of doubt, the Parties agree that all Asset Taxes for calendar year 2016

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constitute an Assumed Obligation and are being allocated pursuant to Section ‎5.10 of this Agreement.

2.6.

Closing Date Estimates . On or before two (2) Business Days prior to the Closing Date, Seller (in consultation with Buyer) will prepare, in accordance with the provisions of this Agreement, and deliver to Buyer, using the best information available to Seller, a statement (the “ Closing Statement ”) setting forth each adjustment to the Purchase Price required under this Agreement and showing the calculation of such adjustments. The Closing Statement will be used to adjust the Purchase Price at Closing (the Purchase Price as adjusted at Closing and less the Deposit, the “ Closing Payment ”). Any final adjustments, if necessary, will be made pursuant to Section ‎2.7 of this Agreement.

2.7.

Final Accounting . On or before one hundred twenty (120) days after the Closing Date, Seller (with the cooperation of Buyer) will prepare, in accordance with the provisions of this Agreement, and deliver to Buyer, a post-closing statement setting forth a detailed calculation of all final adjustments to the Purchase Price which takes into account all such adjustments provided in this Agreement (the “ Final Statement ”). If Buyer disputes any items in or the accuracy and completeness of the Final Statement, then as soon as reasonably practicable, but in no event later than thirty (30) days after its receipt of the Final Statement, Buyer will deliver to Seller a written exception report containing any changes Buyer proposes to be made to the Final Statement. If Buyer fails to deliver such exception report to Seller within that period, then the Final Statement as delivered by Seller will be deemed to be true and correct, binding upon and not subject to dispute by either Party. If Buyer delivers a timely exception report, then as soon as reasonably practicable, but in no event later than thirty (30) days after Seller receives Buyer’s exception report, the Parties will meet and undertake to agree on the final post-Closing adjustments to the Purchase Price. If the Parties fail to agree on the final post-Closing adjustments within sixty (60) days after Seller’s receipt of Buyer’s exception report, either Buyer or Seller will be entitled to submit the dispute for resolution by the Accounting Referee. The cost of the Accounting Referee shall be paid fifty percent (50%) by Seller and fifty percent (50%) by Buyer. Buyer and Seller shall each present to the Accounting Referee, with a simultaneous copy to the other Party, a single written statement of its position on the dispute in question, together with a copy of this Agreement, the Closing Statement, the proposed Final Statement, and Buyer’s written exception report and any supporting material that such Party desires to furnish, not later than ten (10) Business Days after appointment of the Accounting Referee. In making its determination, the Accounting Referee shall be bound by the terms of this Agreement and, without any additional or supplemental submittals by either Party, may consider such other accounting and financial standards matters as in its opinion are necessary or appropriate to make a proper determination. The Parties shall direct the Accounting Referee to resolve the disputes within thirty (30) days after receipt of the written statements submitted for review and to render a decision in writing based upon such written statements. The Accounting Referee shall act as an expert for the limited purpose of determining the specific Final Statement dispute presented

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to it, shall not act as an arbitrator, shall not consider, hear or decide any matters except the specific adjustment disputes presented to it and shall not award legal fees, damages, interest or penalties (including punitive or exemplary damages, lost profits, consequential, special or indirect damages) to Buyer or Seller. The Accounting Referee shall not have the powers of the arbitrators under Section 13 and shall not consider any matters that are Arbitrable Disputes. In addition, the Accounting Referee shall agree in writing to keep strictly confidential the specifics and existence of any matters submitted as well as all proprietary records of the Parties, if any, reviewed by the Accounting Referee in the process of resolving such disputes. Upon agreement of the Parties to the adjustments to the Final Statement, or upon resolution of such adjustments by the Accounting Referee, as the case may be, the Final Statement (as adjusted pursuant to such agreement or resolution by the Accounting Referee) will be deemed final, conclusive and binding on the Parties, without right of appeal, and the aggregate amount due to either Buyer or Seller pursuant to such Final Statement will be paid in accordance with Section ‎2.8 .

2.8.

Payments . Payments to be made following the Closing under this Section ‎2 shall be made by wire transfer of immediately available funds within five (5) Business Days after the final determination is made that such payments are due and payable (pursuant to wire transfer instructions designated in advance by the receiving Party to the paying Party in writing) for the account of the receiving Party.

3. Seller’s Representations and Warranties . Buyer acknowledges that Seller does not operate any of the Properties and to the extent that any of Seller’s representations or warranties in the Section 3 relate to the operation or contracting normally conducted by the operator of oil and gas properties, each and every such representation and warranty shall be deemed to be qualified by the phrase “to Seller’s Knowledge without inquiry to any operator of the Properties.” Subject to the foregoing, Seller represents and warrants to Buyer as of the Execution Date as follows:

3.1.

Organization, Good Standing, Etc . Seller is a limited liability company duly formed, validly existing and in good standing under the Laws of the State of Oklahoma. Seller is duly qualified and/or licensed, as may be required, and in good standing in the State of Oklahoma.

3.2.

Legal Requirements . Seller has all requisite power to own the Properties. No consent, approval, or authorization of, or designation, or filing with, any Governmental Authority is required on the part of Seller in connection with the valid execution and delivery of this Agreement or the consummation of transactions contemplated hereby, except any Customary Post-Closing Consents and the consent, approval or authorization of the transactions contemplated by this Agreement by the applicable Governmental Authority having jurisdiction over that portion of the Seller’s parent company owned by Aubrey K. McClendon at his death (the “ AKM Consent ”).

3.3.

No Breach . Except as disclosed in Schedule ‎3.3 , the execution, delivery, performance and consummation of this Agreement do not and will not: (a) violate,

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conflict with or constitute a default or an event that, with notice or lapse of time or both, would be a default, breach, or violation under any term or provision of the Articles of Organization or any other governing document of Seller or any instrument, agreement, contract, commitment, license, promissory note, conditional sales contract, indenture, mortgage, deed of trust, lease or other agreement, instrument or arrangement to which Seller is a party or by which Seller or Seller’s interest in any of the Properties is bound; (b) violate, conflict with or constitute a breach of any Law applicable to Seller or by which Seller or its interest in any of the Properties is bound; or (c) except with respect to Permitted Encumbrances, result in the creation, imposition or continuation of any Lien on or affecting Seller’ interest in the Properties.

3.4.

Litigation . Except as disclosed in Schedule ‎3.4 , (a) there are no Proceedings pending, or, to Seller’s Knowledge, threatened in writing against Seller involving its interest in the Properties, and (b) there are no Proceedings pending, or to Seller’s Knowledge, threatened before or by any Governmental Authority, arbitrator or mediator questioning the validity of or seeking to prevent the consummation of this Agreement or any other action taken or to be taken in connection herewith.

3.5.

Taxes . Except as disclosed in Schedule 3.5 , (a) to Seller’s Knowledge, all Asset Taxes payable by Seller which are based on or measured by the purchase or ownership of property comprising the Properties and any Asset Taxes with respect to which a lien could attach to the Properties have been timely paid when due and are not in arrears, (b) Seller has not received notice of any pending claim which remains outstanding for Asset Taxes with respect to the Properties, (c) to Seller’s Knowledge, there is no pending audit or examination by any Governmental Authority for Asset Taxes with respect to the Properties, and (d) none of Seller’s interests in the Properties are deemed by agreement or applicable Law to be held by a partnership for federal income tax purposes.

3.6.

Compliance with Laws . To Seller’s Knowledge, the Properties have been operated in material compliance with the provisions and requirements of all applicable Laws (other than Environmental Laws), except for prior instances of non-compliance that have been fully and finally resolved to the satisfaction of all Governmental Authorities with jurisdiction over such matters.

3.7.

Contracts . To Seller’s Knowledge, Seller has described in Schedule ‎3.7 all of the following Contracts in Seller’s possession as of the Execution Date: (a) all Contracts that can reasonably be expected to result in an aggregate revenue to or aggregate payments by the owner of the Properties of Two Hundred Thousand Dollars ($200,000) or more during any calendar year during the term of the Contract; (b) all executory farmout, exploration, development, participation, joint operating, area of mutual interest, non-competition, purchase and/or acquisition agreements of which any terms remain executory which materially affect any of the Properties (excluding oil, gas and mineral leases); (c) contracts for the balancing, gathering, treatment, processing, storage or transportation of Hydrocarbons, which are not, by the terms thereof, subject to termination without penalty upon thirty (30)

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days or less notice, (d) indentures, mortgages or deeds of trust, loans, credit or note purchase agreements, sale-lease back agreements, guaranties, bonds, letters of credit or similar financial agreements that constitute a Lien upon the Properties that will not be satisfied or released at or before the Closing Date, (e) any Contract that constitutes a lease under which Seller is the lessor or the lessee of real or personal property that cannot be terminated by Seller without penalty upon sixty (60) days or less notice and which involves an annual base rental of more than Two Hundred Thousand Dollars ($200,000); (f) any surface use contract, surface lease, easement or other surface use agreement (excluding the leases comprising the Leases and easements in effect at the time of Seller’s acquisition of the applicable Properties) relating to the Properties providing a Third Party with rights to material burdens or payments (other than customary surface damage provisions providing for remediation of, or indemnification for, damages to the surface) triggered by the use of the relevant surface property for drilling or other purposes, (g) all Contracts with Affiliates of Seller which will be binding on the Properties after Closing; (h) any Contract that constitutes a partnership agreement, joint venture agreement or similar Contract; and (i) any pooling, unitization and/or communitization agreements, declarations and/or orders or pre-pooling agreements or similar instruments pertaining to or affecting the Properties. To the extent such contracts are in Seller’s possession, Seller has made available to Buyer prior to the Execution Date true, correct and complete copies of each of the contracts listed on Schedule 3.7 , together with all amendments thereto, in Seller’s possession, provided, however, that to the extent Seller is not a party to any such contracts Seller does not make any representation that such contracts remain unchanged, modified or amended. To Seller’s Knowledge, the contracts listed in Schedule ‎3.7 affecting Seller’s interest in the Properties are in full force and effect and no party thereto is in default or breach thereunder. Seller has not received written notice of the exercise of any termination of any contract listed in Schedule ‎3.7 .

3.8.

Environmental Proceedings . Insofar as it pertains to the Properties, except as set forth in Schedule ‎3.8 :

3.8.1

To Seller’s Knowledge, (a) the Properties and the operation thereof are in material compliance with Environmental Law; (b) there are no Proceedings against Seller or its Affiliates relating to an alleged or actual breach of Environmental Laws on or with respect to the Properties; (c) Seller has not received written notice of any material release, spill, disposal, event, condition or circumstance concerning any of the Properties that materially interferes with or prevents compliance with Environmental Law; and (d) Seller has not received any written notice of any environmental, health or safety claim, demand, filing, investigation, administrative proceeding, or other Proceeding relating to the Properties or notice of any alleged or actual violation or non-compliance with any Environmental Law.

3.8.2

Without limiting Seller’s representations and warranties hereunder, Buyer understands that NORM, asbestos, mercury, polychlorinated biphenyls, drilling fluids and chemicals, and produced waters and Hydrocarbons may

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be present in or on the Properties or equipment in quantities typical for oilfield or gas operations in the areas in which the Properties are located.

3.9.

Authority . Except for the AKM Consent, Seller has taken all necessary action to authorize the execution, delivery and performance of this Agreement and has adequate power, authority and legal right to enter into, execute, deliver and perform this Agreement and the Assignment and to consummate the transactions contemplated hereby. This Agreement is legal, valid and binding with respect to Seller and is enforceable in accordance with its terms, except as the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditors’ rights generally.

3.10.

Broker’s or Finder’s Fees . Seller has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees in respect of the transactions contemplated by this Agreement for which Buyer will have any responsibility whatsoever.

3.11.

Foreign Person . The Seller is not a “foreign person” or an entity disregarded as separate from a “foreign person” within the meaning of Section 1445 of the Internal Revenue Code.

3.12.

Capital Projects . Except as set forth in Schedule ‎3.12 , as of the Execution Date there are no outstanding authorizations for expenditures or other binding capital commitments that are binding on the Properties and that Seller reasonably anticipates will be due within one hundred eighty (180) days after Closing and require expenditure by the owner of the Properties after the Closing Date exceeding individually Two Hundred Thousand Dollars ($200,000.00) (net to Buyer’s interest).

3.13.

Leases . To Seller’s Knowledge, the applicable operator has timely and properly paid all accrued bonuses, delay rentals, minimum royalties, and royalties due with respect to Seller’s interest in the Leases, in each case, in accordance with the Leases and applicable Law. Neither Seller, nor to Seller’s Knowledge, any other party to any Lease is in material breach or default with respect to any of its obligations under any Leases. Schedule 3.13 contains a true, correct and complete list of the expiration date of each of the Leases that will expire on or before August 1, 2017 (unless extended by the drilling of a well or continued production in paying quantities or are subject to a right of extension based on the terms of such Lease).

3.14.

Imbalance Volumes; Payments for Production . To Seller’s Knowledge, Schedule ‎3.14 sets forth all Imbalance Volumes associated with the Properties as of the Effective Time. Except as set forth on Schedule ‎3.14 , Seller is not obligated by virtue of a take-or-pay payment, advance payment, or other similar payment (other than royalties, overriding royalties, similar arrangements established in the Leases), to deliver Hydrocarbons, or proceeds from the sale thereof, attributable to Seller’s interest in the Properties at some future time without receiving payment therefor at or after the time of delivery.

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3.15.

Preferential Purchase Rights . Except as set forth in Schedule ‎3.15 attached hereto, to the Seller’s Knowledge, there are no preferential rights to purchase any of the Properties that are applicable to the transfer of the Properties in connection with the transactions contemplated hereby.

3.16.

Required Consents . Except for the preferential purchase rights set forth in Schedule ‎3.15 , if any, and Customary Post-Closing Consents, to the Seller’s Knowledge, Schedule ‎3.16 lists all Required Consents applicable in connection with the transfer of the Properties to Buyer in accordance with the terms and conditions of this Agreement.

3.17.

Bankruptcy; Insolvency . There are no bankruptcy, reorganization or arrangement proceedings pending, being contemplated by or to Seller’s Knowledge threatened against Seller or any Affiliate of Seller. Seller is and will be Solvent as of the Closing Date and the transactions contemplated by this Agreement will not render Seller not Solvent. By entering into this Agreement and consummating the transactions contemplated hereby, Seller does not intend to incur, and does not believe that it will incur, debts that will be beyond Seller’s ability to pay as such debts mature or that the sum of Seller’s debts will exceed the fair valuation of its assets. Seller is not entering into the transactions contemplated by this Agreement or incurring any obligation pursuant to this Agreement with the intent to hinder, delay or defraud any creditor to which Seller is indebted on the Closing Date or any creditor to which Seller may become indebted after the Closing Date. Seller’s disposition of the Properties was subject to a marketed process with the assistance of a third party investment bank.

3.18.

Outstanding Unit Proposals . Schedule 3.18 sets forth all outstanding proposals to establish or amend any pooling or spacing units with respect to the Properties of which Seller has received written notice.

4. Buyer’s Representations and Warranties . Buyer represents and warrants to Seller as follows:

4.1.

Organization, Good Standing, Etc . Buyer is a limited liability company duly formed, validly existing and in good standing under the laws of the State of Delaware. Buyer has the limited liability company power and authority to acquire and own the Properties and to conduct business in the State of Oklahoma.

4.2.

Powers . Buyer is duly authorized and empowered to execute, deliver and perform this Agreement and to consummate the transactions contemplated hereby. Neither the certificate of formation nor the operating agreement or other governing document of Buyer, nor any other instrument to which Buyer is a party or is bound, nor any court order or governmental law, rule or regulation, will be violated by Buyer’s execution and consummation of this Agreement.

4.3.

No Restriction . Buyer is not subject to any order, judgment or decree, or the subject of any litigation, claim or Proceeding, pending or threatened or any other restriction

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of any kind or character specific to Buyer, which would affect Buyer’s ability to carry out the transactions contemplated by this Agreement.

4.4.

Authorization . Buyer has taken all necessary action to authorize the execution, delivery and performance of this Agreement and has adequate power, authority and legal right to enter into, execute, deliver and perform this Agreement and the Assignment and to consummate the transactions contemplated hereby. This Agreement is legal, valid and binding with respect to Buyer and is enforceable in accordance with its terms, except as the enforceability thereof may be limited by bankruptcy, insolvency or similar laws affecting creditors’ rights generally.

4.5.

No Breach . The execution, delivery, performance, and consummation of this Agreement and the transactions contemplated hereby do not and will not: (a) violate any provision of the certificate of formation or any other governing document of Buyer; or (b) breach or violate, or result (with the giving of notice or the lapse of time or both) in the breach, violation, acceleration or termination of, any contract, indenture, Lien, note, lease, agreement, license or Law to which Buyer is subject or by which any of its assets are bound or subject, except, with respect to any such breach, violation, acceleration or termination which would not reasonably be expected to prevent the consummation of the transactions contemplated hereby by Buyer or result in Seller incurring any loss or liability therefrom.

4.6.

Governmental Consent . No consent, approval, or authorization of, or designation, or filing with, any Governmental Authority is required on the part of Buyer in connection with the valid execution and delivery of this Agreement or the consummation of transactions contemplated hereby, except any Customary Post-Closing Consents.

4.7.

Litigation . There are no Proceedings pending or, to Buyer’s Knowledge, threatened in writing against Buyer questioning the validity of or seeking to prevent the consummation of this Agreement or any other action taken or to be taken in connection herewith, or which would have a material adverse effect on Buyer or its ability to consummate the transactions contemplated hereby.

4.8.

Broker’s or Finder’s Fees . Buyer has not incurred any liability, contingent or otherwise, for brokers’ or finders’ fees in respect of the transactions contemplated by this Agreement for which Seller will have any responsibility whatsoever.

4.9.

Qualifications . Buyer is qualified with all applicable Governmental Authorities to own the Properties.

4.10.

Funding; Investment . Buyer has available (through cash on hand or existing credit arrangements, arrangements with its Affiliates or otherwise) all of the funds necessary for the acquisition of all of the Properties pursuant to this Agreement, as and when needed, and to perform its obligations under this Agreement. Buyer is experienced in and knowledgeable about the oil and gas business and the evaluation, acquisition, ownership and operation of oil and gas properties, and

27242226 34 Asset Purchase Agreement

Buyer is aware of the risks of such investments. Buyer acknowledges that neither Seller nor any of its Affiliates or representatives have made any representation or warranty, expressed or implied, including, without limitation, as to the accuracy or completeness of any information regarding the Properties, except as expressly set forth in this Agreement, the Seller’s Certificate or in the Assignment, and Seller shall have no liability to Buyer or any of Buyer’s successors or assigns for its reliance on any information regarding Seller or the Properties that is not contained in this Agreement. In making its decision to enter into this Agreement and to consummate the transactions contemplated hereby, except for the express representations and warranties of Seller set forth in Section ‎3 and the special warranty of title set forth in the Assignment, Buyer has relied solely on its own independent investigation and evaluation of the Properties and the advice of its own legal, Tax, economic, environmental, engineering, geological and geophysical advisors and not on any comments, statements, projections or other material made or given by any representative, consultant or advisor of Seller or any Affiliate or representative of Seller. Buyer is an “accredited investor”, as such term is defined in Regulation D of the Securities Act of 1933, as amended, and Buyer is acquiring the Properties for its own account and not with the intent to make any distribution of undivided interests thereof which would violate any applicable Laws.

4.11.

Bankruptcy; Insolvency . There are no bankruptcy, reorganization or arrangement proceedings pending, being contemplated by or to Buyer’s Knowledge threatened against Buyer or any Affiliate of Buyer. Buyer is and will be Solvent as of the Closing Date and the transactions contemplated by this Agreement will not render Buyer not Solvent. Buyer is not entering into the transactions contemplated by this Agreement or incurring any obligation pursuant to this Agreement with the intent to hinder, delay or defraud any creditor to which Buyer is indebted.

5. Covenants . The Parties hereby covenant and agree to perform the following:

5.1.

Access to Records . Insofar as related to the Properties or the ownership thereof, during the period from the Execution Date to the Closing Date, Seller will give to Buyer and to its agents and representatives, reasonable access to all of the Records of Seller and its Affiliates and Seller will cause its officers and employees to furnish to Buyer and to Buyer’s agents and representatives such other information with respect to the Properties as Buyer or its agents and representatives may, from time to time, reasonably request; provided , however , (a) any such investigation will be conducted in such manner as not to interfere unreasonably with the operation of the business of Seller, and (b) Seller shall not be required to provide any of the foregoing information to the extent that Seller is prohibited by any Third Party agreement from sharing such information with Buyer, and for which no consent to share such information with Buyer is obtained following reasonable efforts to obtain (at no cost to Seller) such consent. All information or data provided or made available by Seller shall be held by Buyer as confidential information or data and Buyer shall not use any of the same except in connection with the transactions set forth in this Agreement. In the event this Agreement is terminated prior to the Closing, Buyer shall return to Seller (or certify the destruction of) all copies of all

27242226 35 Asset Purchase Agreement

such information and data to the extent required by the Confidentiality Agreement. If the Closing should occur, the foregoing confidentiality restriction on Buyer, including the Confidentiality Agreement, shall terminate (except as to (a) such portion of the Properties that are not conveyed to Buyer (or are retained by or reconveyed to Seller after the Closing) pursuant to the provisions of this Agreement, (b) Excluded Assets and (c) information to the extent related to the assets or business of Seller or its Affiliates other than the Properties conveyed to Buyer).

5.2.

Access to Properties . Subject to the terms of this Section ‎5.2 and to obtaining any required consents of Third Parties (including operators of the Wells), during the period from the Execution Date to the Defect Notice Date, Seller will use Seller’s reasonable efforts to cause the operators of the Wells to grant Buyer access for Buyer to conduct, at its sole cost and expense, such examinations and investigations as it may choose to conduct with respect to the Properties in order to determine whether any Environmental Defects exist; provided that Buyer shall not conduct any sampling, boring drilling or invasive activities or any Phase II environmental investigations or examinations with respect to any of the Properties without the prior written consent of Seller, which consent may be granted or withheld by Seller in its sole discretion; provided , however , that if Buyer reasonably requests access to conduct a Phase II environmental investigation or examination and Seller denies Buyer consent to conduct such Phase II environmental investigation or examination, then Buyer may, in its sole election, elect to exclude such affected Property from the transactions contemplated under this Agreement (and, other than with respect to this sentence, such Properties shall be deemed “Excluded Assets” hereunder), and the Purchase Price shall be reduced by the Allocated Value of such Properties excluded and deemed Excluded Assets hereunder. The following covenants shall survive Closing or termination of this Agreement:

5.2.1

In connection with any such examination or investigation, (a) Buyer shall notify Seller in writing at least two (2) Business Days prior to such examination or investigation of a Property and coordinate the conduct of such examination or investigation with Seller’s representatives (and Seller or its designee shall have the right to accompany Buyer and its representatives whenever on site at any Property), (b) such examination or investigation shall be conducted during normal business hours and in a manner not to unreasonably interfere with the normal operation of the Properties or the business of Seller, and (c) Buyer shall, and shall cause all of its representatives to, comply with all applicable Laws and abide by Seller’s and the operator’s safety rules, regulations and operating policies while conducting its due diligence evaluation of the Properties and, to the extent required by any Third-Party operator, execute and deliver any required bonding agreement of such Third-Party operator or maintain insurance as may be required by any operator, in each case before conducting Buyer’s assessment on such Property.

27242226 36 Asset Purchase Agreement

5.2.2

Buyer acknowledges that any entry into Seller’s or its Affiliates’ offices or onto the Properties shall be at Buyer’s sole risk and, subject to the terms hereof, that none of the Seller Indemnified Parties shall be liable in any way for any injury, loss or damage arising out of such entry that may occur to Buyer or any of their respective representatives pursuant to this Agreement. In connection with the granting of such access, Buyer represents that it is adequately insured and Buyer hereby fully waives, releases and agrees to defend, indemnify and hold harmless all of the Seller Indemnified Parties from and against any and all liabilities, damages, costs, losses and expenses arising from or in any way related to the access afforded to Buyer hereunder or the activities of Buyer or any of its employees, agents, contractors or representatives in connection with such examinations or investigations, even if such liabilities, damages, costs, losses or expenses arise out of or result from, solely or in part, the sole, active, passive, concurrent or comparative negligence, strict liability or other fault or violation of Law of or by a member of the Seller Indemnified Parties, excepting only liabilities actually resulting on the account of the gross negligence or willful misconduct of the Seller Indemnified Parties. This waiver, release, and indemnity by Buyer shall survive termination of this Agreement .

5.2.3

If this Agreement is terminated by either Party, Buyer agrees to promptly provide Seller, but in no case less than five (5) days after such termination, copies of all environmental reports and environmental test results prepared by or for Buyer and/or any of its representatives which contain environmental data collected or generated from Buyer’s environmental due diligence with respect to the Properties (including any drafts thereof). None of Buyer, any of Buyer’s representatives, or Seller shall be deemed by Seller’s or its Affiliates’ receipt of said documents, or otherwise, to have made any representation or warranty, expressed, implied or statutory, as to the condition of the Properties or to the accuracy of said documents or the information contained therein.

5.3.

Conduct of Business . From the Execution Date until Closing, except as required in the event of an emergency to protect life, property or the environment, as required by Law or permit, as specifically contemplated by this Agreement or with the prior written consent of Buyer (not to be unreasonably withheld, conditioned or delayed):

5.3.1

Seller shall operate its business with respect to the Properties in the ordinary course of business and in compliance with Law, and without limiting the generality of the foregoing and the exceptions noted in Section ‎5.3 , shall:

(a)

fulfill in all material respects all contractual or other covenants, obligations and conditions imposed upon Seller with respect to the

27242226 37 Asset Purchase Agreement

Properties, including payment of delay rentals and any and all other payments required ;

(b)

maintain insurance coverage on the Properties in the amounts and of the types presently in force and not make any election to be excluded from any coverage provided by an operator for the joint account pursuant to a joint operating agreement or similar agreement;

(c)

to the extent Seller receives written notice thereof, promptly provide Buyer with written notice of (i) any Proceedings that affect the Properties, (ii) any proposal from a Third Party to engage in any material transaction (e.g., a farmout) or operations with respect to the Properties, or (iii) any proposal to establish or amend any pools or units with respect to the Properties; and

(d)

use commercially reasonable efforts to maintain and keep the Leases in full force and effect.

5.3.2

(a)

convey, encumber, abandon or otherwise dispose of any part of the Properties other than the sale of Hydrocarbons in the ordinary course of business or in accordance with applicable PPRs;

(b)

grant any PPR or consent (including any Required Consent) with respect to Seller’s interest in the Properties; and

(c)

(i) enter into any agreement, contract or commitment which, if entered into prior to the Execution Date, would be required to be listed in a Schedule attached to this Agreement, (ii) materially amend or change the terms of any Contract or commitment affecting the Properties to which Seller is a party or (iii) knowingly and voluntarily waive any material rights under any Contract affecting the Properties, in each case, without first consulting with Buyer and attempting in good faith to reach a mutual agreement regarding such matter;

(d)

(i) propose any new drilling, reworking, or similar operations with respect to the Properties or (ii) elect to participate or not to participate in any new drilling, reworking or similar operation reasonably anticipated to require future capital expenditures by the new owner of the Property to be incurred, in each case, without first consulting with Buyer and attempting in good faith to reach a mutual agreement regarding such matter;

27242226 38 Asset Purchase Agreement

(e)

enter into any agreement, contract or commitment to (i) establish or amend any pools or units with respect to the Properties or (ii) engage in any acreage swaps or similar transactions with respect to the Properties;

(f)

voluntarily abandon any of the Properties other than as commercially reasonable or as required pursuant to the terms of a Lease or by applicable Law; and

(g)

agree to take any action or actions prohibited by any of the provisions in this Section ‎5.3.2 .

5.4.

Consents and Operations . From and after the date of this Agreement, Seller will use reasonable efforts to obtain the Required Consents and each of the Parties will use reasonable efforts to obtain any other approvals that may be required of it in order to consummate the transactions contemplated by this Agreement. Seller shall submit as soon as practicable, but in no event prior to, or later than three (3) Business Days after the public announcement of the transaction contemplated by this Agreement by Buyer, filings with the Governmental Authority appropriate to request the AKM Consent and shall use its reasonable efforts to obtain the AKM Consent. In addition, Seller shall use its reasonable efforts to (i) resolve as promptly as practicable such objections, if any, as may be asserted by any Person or Governmental Authority with respect to the transactions contemplated by this Agreement or such Governmental Authority’s granting of the AKM Consent and (ii) obtain from Wilmington Trust, National Association, a consent or agreement not to object to the AKM Consent.

5.5.

Conditions . Each of Buyer and Seller will use its respective reasonable commercial efforts to cause the conditions and agreements in Sections ‎6, ‎7 and ‎8 of this Agreement that are to be satisfied or performed by it to be satisfied and performed, whether prior to or after the Closing.

5.6.

Additional Properties . If, during the period between the Execution Date and the date ten (10) days prior to the Closing Date (the “ Pre-Closing Acquisition Period ”), Seller or any of its Affiliates acquires any oil, gas and mineral leases within the general geographic area where the Properties are located, then Seller shall give Buyer written notice on or before the earlier of the tenth day following such acquisition and the expiration of the Pre-Closing Acquisition Period, of such acquisition together with a copy of the recorded conveyance into Seller or its Affiliate of such oil, gas and mineral leases (the “ Additional Interests ”) and all other information reasonably requested by Buyer and available to Seller. Following receipt of such notice and prior to the Closing, Buyer and Seller shall negotiate in good faith regarding the terms and conditions for including all of some of the Additional Interests in the transaction contemplated by this Agreement.

5.7.

Revenues Held For Benefit of the Other Party . Following the Closing, in the event either (a) Buyer receives production or other revenues attributable to any of the

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Properties for any periods prior to the Effective Time which is not accounted for in the Closing Statement or the Final Statement or (b) Seller receives production or other revenues attributable to any of the Properties for any periods after the Effective Time which is not accounted for in the Closing Statement or the Final Statement, the receiving Party will hold such revenues for the exclusive benefit of the Party entitled thereto and, if not taken into account for purposes of the Closing Statement or the Final Statement, will pay any such amounts due to such Party within thirty (30) days after receipt.

5.8.

Extension and Renewal of Expiring Leases .

5.8.1

From and after the Execution Date, Seller shall (i) timely and properly exercise the option to extend the term of the Leases set forth on Scheduleº‎5.8.1 or (ii) with respect to the Leases set forth on Schedule ‎5.8.1 which do not contain an option to extend their term, Seller shall use Seller’s reasonable efforts to enter into a replacement lease replacing it on substantially the same terms, with the same lessor or its lawful successor and covering the same lands covered by such Lease. Seller shall bear and pay for all costs of any such lease extensions or replacement leases and no such payments or costs hereunder shall result in an upward adjustment to the Purchase Price.

5.8.2

If, as of the Closing Date, any Lease on Schedule ‎5.8.1 that will expire prior to December 31, 2016 has not been extended or replaced pursuant to Section ‎5.8.1 , the Purchase Price shall be reduced by the Allocated Value of such Lease as set forth on Schedule ‎5.8.1 , such Lease shall not be conveyed to Buyer at Closing and such reduction shall not be subject to the Defect Deductible. For the avoidance of doubt, there shall be no Title Benefit with respect to any actions taken pursuant to this Section ‎5.8 . Notwithstanding anything in this Section 5.8 to the contrary, the Parties agree that Seller will have the sole and exclusive right during the Cure Period to renew, extend or replace any Lease on Schedule ‎5.8.1 and in the event Seller is successful in renewing, extending or replacing any Lease on Schedule ‎5.8.1 Seller shall deliver notice thereof to Buyer and within five (5) Business Days thereafter Seller will deliver Buyer an Assignment of each such Lease and, provided that Seller has, at such time, Defensible Title to such Lease, Buyer will simultaneously pay Seller the Allocated Value of each Lease on Schedule ‎5.8.1 which has been renewed, extended or replaced.

5.9.

Limitations on Representations and Warranties . Except for the express and specific representations and warranties set forth in Section ‎3 of this Agreement, Seller’s Certificate, or the Special Warranty contained in the Assignment, Buyer acknowledges that none of Seller or any other member of the Seller Indemnified Parties has made, and Seller hereby expressly disclaims and negates, and

27242226 40 Asset Purchase Agreement

Buyer hereby expressly waives, any representation or warranty, express, implied, at common law, by statute or otherwise.

Except for the express and specific representations and warranties set forth in Section ‎3 of this Agreement, Seller’s Certificate, or the Special Warranty contained in the Assignment , and without limiting the generality of the foregoing, Seller expressly disclaims and negates, and Buyer hereby waives, any representation or warranty, express, implied, at common law, by statute or otherwise, as to any of the following: (a) the contents, character, accuracy, completeness or materiality of records, information, data or other materials (written or oral) now, heretofore or hereafter furnished to Buyer or any Buyer Indemnified Party by or on behalf of Seller or any Seller Indemnified Party, including any information memorandum, reports, brochures, charts or statements prepared by Seller, any Seller Indemnified Party or any Third Party with respect to the Properties; (b) the contents, character or nature of any report of any petroleum engineering consultant, or any engineering, geological or seismic data or interpretation, relating to the Properties; (c) any estimates of the value of, or future revenues generated by, the Properties; (d) production rates, recompletion opportunities, decline rates, gas balancing information, or the quality, quantity, volume, or recoverability of the reserves of Hydrocarbons, if any, attributable to the Properties or Seller’s interest therein; (e) title to any of the Properties; (f) maintenance, repair, condition, quality, suitability, marketability, merchantability, or fitness for a particular purpose of the Properties; (g) any rights of purchasers under appropriate statutes to claim diminution of consideration or return of the Purchase Price; (h) any implied or express warranty of freedom from defects, whether known or unknown, (i) any and all implied warranties existing under applicable Law; and (j) the environmental or other condition of the Properties, including, without limitation, any implied or express warranty regarding Environmental Laws, the release of substances, wastes or materials into the environment, or protection of the environment or of human health, safety, or natural resources. It is the express intention of Buyer and Seller that, Except for the express and specific representations and warranties set forth in Section ‎3 of this Agreement, Seller’s Certificate, or the Special Warranty contained in the Assignment , the Properties are being accepted by Buyer, “as is, where is, with all faults and defects” and in their present condition and state of repair, and Buyer has made or will make prior to closing any and all such inspections as Buyer deems appropriate.

Buyer acknowledges that the Properties have been used for exploration, development, and production of oil and gas and that

27242226 41 Asset Purchase Agreement

equipment and sites included in the Properties may contain asbestos, naturally occurring radioactive material (“ NORM ”) or other Hazardous Materials. NORM may affix or attach itself to the inside of wells, materials, and equipment as scale, or in other forms. The wells, materials, and equipment located on the Properties may contain NORM and other wastes or Hazardous Materials. NORM containing material and/or other wastes or Hazardous Materials may have come in contact with various environmental media, including air, water, soils or sediment. Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of environmental media, wastes, asbestos, norm and other Hazardous Materials from the Properties. NORM shall not constitute the basis of an Environmental Defect claim or a purchase price adjustment under Section ‎2.1 .

Seller and Buyer agree that, to the extent required by applicable Law to be effective, the disclaimers of certain representations and warranties contained in this Section ‎5.9 are “conspicuous” disclaimers for purposes of any applicable Law, rule or order.

5.10.

Taxes .

5.10.1

For Tax purposes, Buyer and Seller shall use commercially reasonable efforts to agree to an allocation schedule setting forth the fair market values of the Properties as of the Closing Date within thirty (30) days following the date of the Final Statement. Buyer and Seller shall report the purchase and sale of the Properties consistently with any such agreed allocation schedule unless otherwise required by applicable Law.

5.10.2

Seller shall be allocated and bear: (a) all Income Taxes for any period or portion thereof ending prior to the Closing Date, and (b) all Asset Taxes for any period or portion thereof ending prior to the Effective Time. Seller shall not be allocated or bear any Taxes based upon or related to recording, transfer, stamp, conveyance, sales, documentary or similar Taxes, assessments or charges levied in connection with the sale of the Properties (collectively, “ Transfer Taxes ”), which shall be borne entirely by Buyer. Buyer shall be allocated and bear: (i) all Transfer Taxes, (ii) all Income Taxes for any period or portion thereof ending from and after the Closing Date, and (iii) all Asset Taxes for any period or portion thereof ending from and after the Effective Time.

5.10.3

(i) Taxes that are attributable to the severance or production of Hydrocarbons shall be allocated to the period in which the severance or production giving rise to such Taxes occurred, (ii) Taxes that are based upon or related to income or receipts or imposed on a transactional basis (other than such Taxes described in clause (i)), shall be allocated to the period in which the transaction giving rise to such Taxes occurred, and (iii) Taxes

27242226 42 Asset Purchase Agreement

that are ad valorem, property or other Taxes imposed on a periodic basis pertaining to a period that begins before and ends after the Effective Time shall be allocated by prorating each such Tax based on the number of days in the applicable period that occur before the date on which the Effective Time occurs, on the one hand, and the number of days in such period that occur on or after the date on which the Effective Time occurs, on the other hand. For purposes of clause (iii) of the preceding sentence, the period for such Taxes shall begin on the date on which ownership of the applicable Property gives rise to liability for the particular Tax and shall end on the day before the next such date.

5.10.4

The Parties shall cooperate fully, as and to the extent reasonably requested by the other Party, in connection with the filing of Tax Returns and any audit, litigation, or other proceeding with respect to Taxes relating to the Properties.

6. Buyer’s Conditions Precedent . The obligation of Buyer to consummate the transactions contemplated by this Agreement is subject to the satisfaction or waiver in writing by Buyer (subject to applicable Laws) on or prior to the Closing Date of each of the following conditions precedent:

6.1.

No Injunctions or Orders . No preliminary or permanent injunction or other order will have been issued (and remain in force) by any Governmental Authority having appropriate jurisdiction preventing consummation of the transactions contemplated by this Agreement.

6.2.

No Legal Proceedings . No Proceeding will have been commenced by any Third Party against Seller, Buyer or any of their respective Affiliates, associates, officers or directors seeking to restrain, enjoin, prevent or challenge the transactions contemplated by this Agreement or seeking material damages arising from the transactions contemplated by this Agreement.

6.3.

Representations . All representations and warranties of Seller contained herein (a) that are qualified by the term “material” or contain terms such as “material adverse change,” “material adverse effect” or other terms or Dollar amounts of similar import or effect (whether or not capitalized) shall be true and correct as of the Closing Date as though such representations and warranties were made at such time (except to the extent that a representation specifically relates to an earlier date, in which case as of such earlier date), and (b) that are not so qualified shall be true and correct in all material respects as of the Closing Date as though such representations and warranties were made at such time (except to the extent that a representation specifically relates to an earlier date, in which case as of such earlier date).

6.4.

Performance . Seller will have performed or satisfied in all material respects on or prior to the Closing Date all obligations, covenants and agreements contained in this Agreement to be performed or complied with by Seller on or prior to the Closing Date.

27242226 43 Asset Purchase Agreement

6.5.

Purchase Price Adjustments . The sum of the aggregate amount of all Purchase Price adjustments (i) pursuant to Sections ‎2.2 and ‎5.2 and (ii) asserted by Buyer with respect to Title Defects and Environmental Defects (without giving effect to the Aggregate Defect Threshold or Sections ‎2.1.10 or ‎2.1.11 ) that were properly asserted pursuant to validly and timely delivered Defect Notices ( less that aggregate amount of all Purchase Price adjustments asserted by Seller in respect of Title Benefits that were properly asserted pursuant to validly and timely delivered notices of Title Benefits without giving effect to the Aggregate Defect Threshold), shall be no more than twenty percent (20%) of the unadjusted Purchase Price.

6.6.

Closing Deliverables . Seller shall have delivered (or be ready, willing and able to deliver at Closing) to Buyer the documents and other items required to be delivered by Seller under Section ‎8.2 .

6.7.

AKM Consent . Seller shall have obtained and provided evidence satisfactory to Buyer that the AKM Consent, which shall be in a form reasonably satisfactory to Buyer, has been obtained.

7. Seller’s Conditions Precedent . The obligation of Seller to consummate the transactions contemplated by this Agreement is subject to the satisfaction or waiver in writing by Seller (subject to applicable Laws) on or prior to the Closing Date of each of the following conditions precedent:

7.1.

7.2.

7.3.

Representations . All representations and warranties of Buyer contained herein (a) that are qualified by the term “material” or contain terms such as “material adverse change,” “material adverse effect” or other terms or Dollar amounts of similar import or effect (whether or not capitalized) shall be true and correct as of the Closing Date as though such representations and warranties were made at such time (except to the extent that a representation specifically relates to an earlier date, in which case as of such earlier date), and (b) that are not so qualified shall be true and correct in all material respects as of the Closing Date as though such representations and warranties were made at such time (except to the extent that a representation specifically relates to an earlier date, in which case as of such earlier date).

7.4.

Performance . Buyer will have performed or satisfied in all material respects on or prior to the Closing Date all obligations, covenants and agreements contained in

27242226 44 Asset Purchase Agreement

this Agreement to be performed or complied with by Buyer on or prior to the Closing Date.

7.5.

Title Defects and Environmental Defects . The sum of the aggregate amount of all Purchase Price adjustments (i) pursuant to Sections ‎2.2 and ‎5.2 and (ii) asserted by Buyer with respect to Title Defects and Environmental Defects (without giving effect to the Aggregate Defect Threshold or Sections ‎2.1.10 or ‎2.1.11 ) that were properly asserted pursuant to validly and timely delivered Defect Notices ( less that aggregate amount of all Purchase Price adjustments asserted by Seller in respect of Title Benefits that were properly asserted pursuant to validly and timely delivered notices of Title Benefits without giving effect to the Aggregate Defect Threshold), shall be no more than twenty percent (20%) of the unadjusted Purchase Price.

7.6.

Closing Deliverables . Buyer shall have delivered (or be ready, willing and able to deliver at Closing) to Seller the documents and other items, including the Closing Payment, required to be delivered by Buyer under Section ‎8.1 .

7.7.

AKM Consent . Seller shall have received the AKM Consent, which shall be in a form reasonably satisfactory to Seller.

8. The Closing . Subject to the terms and conditions hereof, unless extended as provided herein, the Closing will take place at 10:00 a.m. Central Time on the Closing Date, and will be conducted electronically (by fax, email or other electronic means) to the extent reasonably possible, but if necessary shall take place in the offices of Seller at 301 NW 63 rd Street, Suite 400, Oklahoma City, Oklahoma 73116 (or if all conditions in Sections ‎6 and ‎7 to be satisfied or waived prior to the Closing have not yet been satisfied or waived on such date, within two (2) Business Days after such conditions have been satisfied or waived, subject to the rights of the Parties under Section ‎11 ), at which Closing the documents and payments referred to in Sections ‎8.1 and ‎8.2 (or otherwise required by this Agreement to be delivered at the Closing) shall be exchanged by the Parties. When completed, the Closing shall be deemed to have occurred at 12:01 a.m. Central Time on the Closing Date. Unless otherwise agreed, all transactions at the Closing shall be deemed to have occurred simultaneously.

8.1.

Buyer’s Deliveries . At the Closing, and subject to the simultaneous performance by Seller of its obligations under Section ‎8.2 , Buyer will deliver or cause to be delivered to Seller the following items, unless waived in writing by Seller:

8.1.1

Purchase Price . The Closing Payment;

8.1.2

Certificate . Buyer’s Certificate executed by an authorized officer of Buyer.

8.1.3

Assignments . An original counterpart of the Assignment for each County in which any of the Properties are located, executed by an authorized officer of Buyer covering all of the Properties (other than those Properties to be excluded in accordance with the terms hereof) in recordable form;

8.1.4

Closing Statement . An original counterpart of the Closing Statement executed by an authorized officer of Buyer;

27242226 45 Asset Purchase Agreement

8.1.5

Escrow . A duly executed release instruction to cause the Escrow Agent to pay Seller an amount, if any, equal to the Deposit; and

8.1.6

Additional Documents . Such additional documents as might be reasonably requested by Seller and are reasonably required to consummate the transactions contemplated by this Agreement.

8.2.

Seller’s Deliveries . At the Closing, and subject to the simultaneous performance by Buyer of its obligations under Section ‎8.1 , Seller will deliver or cause to be delivered to Buyer the following items, unless waived in writing by the Buyer:

8.2.1

Assignments . An original counterpart of the Assignment for each County in which any of the Properties are located, executed by an authorized officer of Seller covering all of the Properties (other than those Properties to be excluded in accordance with the terms hereof) in recordable form;

8.2.2

Certificate . Seller’s Certificate executed by an authorized officer of Seller;

8.2.3

Non-Foreign Status Certificate . The Non-Foreign Status Certificate in substantially in the form attached hereto as Exhibit C executed by an authorized officer of Seller;

8.2.4

Releases . Releases, in form and substance reasonably acceptable to Buyer, of all Liens created by Seller or any of its Affiliates to secure indebtedness for borrowed money covering any of the Properties, including under the Existing Credit Agreement, in sufficient counterparts to facilitate recording in each county in which the Properties are located, as applicable, or (for terminations of financing statements) filing in the central filing system in Oklahoma County, Oklahoma;

8.2.5

Closing Statement . An original counterpart of the Closing Statement executed by an authorized officer of Seller;

8.2.6

Escrow . A duly executed release instruction to cause the Escrow Agent to pay Seller an amount, if any, equal to the Deposit; and

8.2.7

Additional Documents . Such additional documents as might be reasonably requested by Buyer and are reasonably required to consummate the transactions contemplated by this Agreement.

8.3.

Post-Closing Adjustments . Buyer and Seller agree that the Purchase Price may be further adjusted after the Closing Date in accordance with the provisions of Section ‎2 of this Agreement.

8.4.

Post-Closing Deliveries . Seller shall make the Records in Seller’s possession or control available to Buyer for pickup from Seller’s offices during normal business hours promptly after Closing, but no later than thirty (30) days after the Closing Date.

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8.5.

Costs and Expenses . Except as otherwise expressly provided herein, Seller will pay Seller’s attorney fees and other expenses, including any fees referred to in Section ‎3.10 ; and Buyer will pay Buyer’s attorney fees and other expenses, including any fees referred to in Section ‎4.8 , and the recording costs for the Assignments. Buyer will pay (or reimburse Seller for) all Transfer Taxes. The Parties agree to cooperate with each other in demonstrating that the requirements for exemptions from any of Transfer Taxes, if any, have been met.

8.6.

Risk of Loss . As of the consummation of the Closing, beneficial ownership and the risk of loss of the Properties will pass from Seller to Buyer effective from and after the Effective Time.

9. Press Releases . Until Closing, no Party shall make any press release or other public announcements concerning this transaction without the consent of the other Party, which consent shall not be unreasonably withheld, provided, however, that, notwithstanding the foregoing, any filings required to be made by Seller or its equity holders with the applicable Governmental Authority with respect to obtaining the AKM Consent will not violate the terms and provisions of this Section 9 . Any Party desiring to make a public announcement shall first give the other Party forty-eight (48) hours written notification of its desire to make such a public announcement. The written notification shall include (a) a request for consent to make the announcement, and (b) a written draft of the text of such public announcement. Notwithstanding the foregoing, nothing contained herein shall prohibit any Party (or its Affiliate) from issuing or making a public announcement or other statement if such Party (or its Affiliate) deems it necessary to do so in order to comply with any applicable Law, or the rules of any stock exchange upon which the Party’s (or its Affiliate’s) capital stock is traded, or in connection with Buyer’s (or its Affiliate’s) financing activities, provided that in the event the disclosure is a public announcement or other statement, such Party provides the other Party with a written draft of the text of such public announcement at least forty-eight (48) hours prior to issuing or making such announcement and, upon request of the other Party, omits any references to the other Party’s identity in such public announcement.

10. Indemnification . Upon and after the Closing of the transactions contemplated by this Agreement, the Parties will indemnify each other as follows:

10.1.

Assumed Obligations . Upon the Closing, Buyer will assume (and, upon delivery by Seller of the Assignment, Buyer shall be deemed to have assumed) and hereby agrees to fulfill, perform, pay and discharge, all of the Assumed Obligations.

10.2.

Seller’s Indemnification . From and after Closing, subject to the limitations set forth Sections ‎10 , ‎14.3 , ‎14.16 and elsewhere in this Agreement, Seller shall be responsible for, pay on a current basis, and defend, indemnify, reimburse, hold harmless and release Buyer, its Affiliates, and all of its and their respective equity holders, directors, partners, members, managers, officers, representatives, agents and employees (“ Buyer Indemnified Parties ”) for, from and against any and all Liabilities (including interest, reasonable legal fees, and expenses of litigation and attorneys’ fees in enforcing this indemnity) incurred, suffered, paid by or resulting to any of the Buyer Indemnified Parties and which results from, arises out of or in connection with, is based upon, or exists by reason of:

27242226 47 Asset Purchase Agreement

10.2.1

any breach of or default by Seller of any representation or warranty of Seller set forth in this Agreement (or brought down in the Certificate signed by Seller) (in each case, with respect to the calculation of any Liabilities resulting therefrom, but not with respect to determining whether a breach has occurred, determined without regard to any materiality, Material Adverse Effect or other similar qualification contained in such representation or warranty);

10.2.2

any failure by the Seller to perform any covenant or obligation of Seller set forth in this Agreement which is not cured as provided in Section ‎12 of this Agreement; or

10.2.3

any Retained Obligations; or

10.2.4

any of the Excluded Assets.

10.3.

Buyer’s Indemnification . From and after Closing, subject to the limitations set forth in this Sections ‎10 , ‎14.3 , ‎14.16 and elsewhere in this Agreement, Buyer shall be responsible for, pay or caused to be paid on a current basis, and defend, indemnify, reimburse, hold harmless and release Seller, its Affiliates, and all of its and their respective equity holders, directors, partners, members, managers, officers, representatives, agents and employees (“ Seller Indemnified Parties ”) for, from and against any and all Liabilities (including interest, reasonable legal fees, and expenses of litigation and attorneys’ fees in enforcing this indemnity) incurred, suffered, paid by or resulting to any of the Seller Indemnified Parties and which results from, arises out of or in connection with, is based upon, or exists by reason of:

10.3.1

any breach of or default by Buyer of any representation or warranty of Buyer set forth in this Agreement (as brought down in the Certificate signed by Buyer) or any failure by Buyer to perform any covenant or obligation of Buyer set forth in this Agreement which is not cured as provided in Section ‎12 of this Agreement; or

10.3.2

any of the Assumed Obligations.

10.4.

Express Negligence . Without limiting or enlarging the scope of the indemnification, defense, hold harmless, release and assumption provisions set forth in this Agreement, to the fullest extent permitted by Law, an indemnified Person shall be entitled to indemnification hereunder in accordance with the terms of Sections ‎5.2.2 , ‎10.2 or ‎10.3 , regardless of any pre-existing condition or whether the act, occurrence or circumstance giving rise to any such indemnification obligation sounds in contract, tort or otherwise, or is the result of the sole, active, passive, concurrent or comparative negligence, strict liability, breach of duty (statutory or otherwise), or other fault or violation of any Law of or by any such indemnified

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Person, provided that no such indemnification shall be applicable to the extent of any gross negligence or willful misconduct of the indemnified Person.

10.5.

Indemnification Procedure . If any indemnified party discovers or otherwise becomes aware of an indemnification claim arising under this Agreement, such party will give written notice to the indemnifying Party, including the specific details of and specific basis under this Agreement for its claim and an estimate of the amount, if reasonably estimable, of the Liabilities that have been or may be sustained by the Indemnified Party, and may thereafter exercise any remedies available to such indemnified party under this Agreement; provided , however , the failure of any indemnified party to give notice as provided herein will not relieve the indemnifying Party of any obligations hereunder, to the extent the indemnifying Party is not materially prejudiced thereby. In the event that the claim for indemnification is based upon an inaccuracy or breach of a representation, warranty, covenant or agreement, the claim notice shall specify the representation, warranty, covenant or agreement that was inaccurate or breached. Further, promptly after receipt by an indemnified party hereunder of written notice of the commencement of any action or proceeding with respect to which a claim for indemnification may be made against any indemnifying Party, the indemnified party will give written notice to the indemnifying Party of the commencement of such action, accompanied by a copy of all papers, if any, served with respect to the action or proceeding; provided , however , the failure of any indemnified party to give notice as provided herein will not relieve the indemnifying Party of any obligations hereunder, to the extent the indemnifying Party is not materially prejudiced thereby.

10.6.

Defense . If any action is brought against an indemnified party, the indemnifying Party will be entitled to participate in and to assume the defense thereof to the extent that it may wish, and after notice from the indemnifying Party to such indemnified party of the indemnifying Party’s election to assume the defense thereof, the indemnifying Party shall not be liable to such indemnified party for any legal or other expenses subsequently incurred by the latter in connection with the defense thereof unless the indemnifying Party has failed to assume and diligently prosecute the defense of such claim. Notwithstanding any of the foregoing to the contrary, the indemnified party will be entitled to select its own counsel and assume the defense of any action brought against it if the indemnifying Party fails to assume or diligently prosecute such defense, the expenses of such defense to be paid by the indemnifying Party. As a condition to the indemnifying Party’s obligations hereunder, the indemnified party will in good faith cooperate with and assist the indemnifying Party in the prosecution or defense of such indemnified claim at no unreasonable expense to the indemnified party. No indemnifying Party shall consent to entry of any judgment or enter into any settlement with respect to a claim either (a) without the consent of the indemnified party, which consent shall not be unreasonably withheld, or (b) unless such judgment or settlement includes as an unconditional term thereof the giving by the claimant or plaintiff to such indemnified party of a release from all liability with respect to such claim. No

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indemnified party shall consent to entry of any judgment or enter into any settlement of any such action, the defense of which has been assumed by an indemnifying Party, without the consent of such indemnifying Party, which consent shall not be unreasonably withheld.

10.7.

Certain Limitations on Indemnity Obligations .

10.7.1

No claim of Buyer or the Buyer Indemnified Parties pursuant to Section ‎10.2.1 shall be made hereunder (and Seller shall not be required to indemnify the Buyer Indemnified Parties) unless the amount of such claim exceeds an amount equal to One Hundred Thousand Dollars $100,000 (each an “ Individual Claim ”). In addition, no claim of Buyer or the Buyer Indemnified Parties pursuant to Section ‎10.2.1 shall be made hereunder (and Seller shall not be required to indemnify the Buyer Indemnified Parties) until the total of all Individual Claims exceeds three percent (3%) of the unadjusted Purchase Price (the “ Basket ”). If the total amount of all of Buyer’s or the Buyer Indemnified Parties’ Individual Claims exceeds the Basket, then Seller’s obligations under Section ‎10.2.1 shall be limited to the amount by which the aggregate amount of such Individual Claims exceeds the Basket. The limitations in this Section ‎10.7.1 shall not limit or apply any to claims for breach of any Fundamental Representation of Seller.

10.7.2

In no event will Seller’s aggregate liability under Section ‎10.2.1 exceed ten percent (10%) of the unadjusted Purchase Price, except with respect to any claims for breaches of Fundamental Representations of Seller. In no event shall Seller’s aggregate liability to Buyer (a) under Section 10.2.2 of this Agreement, (b) for breaches of Fundamental Representations of Seller or (c) otherwise in connection with the transactions contemplated hereby exceed an amount equal to the final adjusted Purchase Price.

10.7.3

The amount of any indemnification provided under Section ‎10.2 or ‎10.3 shall be net of any amounts actually recoverable by the indemnified party under any insurance policies.

10.7.4

Notwithstanding anything stated herein to the contrary: (a) neither Party will have any liability to the other Party or such other Party’s indemnified parties under this Section ‎10 with respect to any item for which an adjustment has already been made to the Purchase Price under the terms of this Agreement to the extent of such adjustment; and (b) except as it relates to a breach of the special warranty of title in the Assignment or a breach of the representations and warranties contained in Sections ‎3.8 , Seller will have no liability to Buyer or the Buyer Indemnified Parties under this Section ‎10 for any matter (including any breach of the other representations or warranties under Section ‎3 ) which constitutes a Title Defect or an Environmental Defect. Claims for Title Defects or Environmental Defects, whether or not resulting in a Purchase Price adjustment because the applicable Aggregate Defect Threshold is not exceeded, are not subject to

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the terms of this Section ‎10 , may not be claimed under this Section ‎10 , may not be included for purposes of determining whether the limitations set forth in this Section ‎10.7 have been met and may not be included in the Basket for purposes of the limitations set forth in this Section ‎10.7 .

10.7.5

Notwithstanding anything else to the contrary herein, the Parties agree that adjustments to the Purchase Price as provided for in Section ‎ 2 are not subject to the terms of this Section ‎10 . In addition, Seller and Buyer specifically agree that Buyer will not have any right to pursue a claim under the special warranty of title in the Assignment with respect to any matters that were raised by Buyer as a Title Defect under Section ‎2.1 of this Agreement.

10.7.6

Notwithstanding anything to the contrary contained in this Agreement, if either Buyer or Seller elects to proceed with the Closing with actual knowledge by such Party of any failure of any condition to be satisfied in its favor or the breach of any representation, warranty, agreement or covenant by the other Party or of the facts giving rise to any such breach, then the condition that is unsatisfied or the representation, warranty, agreement or covenant which is breached will be deemed waived by such Party, and such Party shall be deemed to fully release and forever discharge the other Party on account of any and all Liabilities, known or unknown, with respect to such condition, representation, warranty, agreement or covenant.

10.7.7

Any indemnity payments made by a Party pursuant to this Section ‎10 shall be treated as an adjustment to the Purchase Price for federal, state and local income tax purposes unless otherwise required by applicable Law.

10.7.8

Buyer and Seller acknowledge that, following 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 herein or for any other claim arising in connection with or with respect to the transactions contemplated by this Agreement. As the payment of money shall be adequate compensation, following the Closing, Buyer and Seller waive any right to rescind this Agreement or any of the transactions contemplated hereby.

10.7.9

Any claim for indemnity under this Section ‎10 by any indemnified party must be brought and administered by the respective Party to this Agreement. No indemnified party other than Seller and Buyer shall have any rights against either Seller or Buyer under the terms of this Section ‎10 except as may be exercised on its behalf by Buyer or Seller, as applicable, pursuant to this Section ‎10.7.9 . Each of Seller and Buyer may elect to exercise or not exercise indemnification rights under this Section ‎10 on behalf of the other indemnified Persons affiliated with it in its sole discretion and shall

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have no liability to any such other indemnified Person for any action or inaction under this Section.

10.8.

Exclusive Remedy . Notwithstanding anything to the contrary contained in this Agreement, from and after Closing, Sections ‎5.2.2 , ‎10.2 and ‎10.3 contain the Parties’ sole and exclusive remedies against each other with respect to any breaches of representations, warranties, covenants or agreements of the Parties contained in Section ‎3 , Section ‎4 or Section ‎5 of this Agreement and the affirmations of such representations, warranties, covenants and agreements contained in the Certificate delivered by each Party at Closing. Except for (a) the remedies contained in Sections ‎5.2.2 , ‎10.2 and ‎10.3 , (b) subject to the terms hereof, any other remedies available to the Parties at Law or in equity for breaches of provisions of this Agreement other than Section ‎3 , Section ‎4 or Section ‎5 , and (c) subject to the terms hereof, the remedies available at Law or in equity for breaches of the special warranty contained in the Assignment, effective as of Closing, each Party hereby releases, remises and forever discharges the other Party and the other Party’s Affiliates and all such Persons’ stockholders, members, partners, officers, directors, employees, agents, advisors and representatives from any and all Liabilities whatsoever, in Law or in equity, known or unknown, which such Party might now or subsequently may have, based on, relating to or arising out of or in connection with this Agreement, the transactions contemplated hereby, the ownership, use or operation of any of the Properties prior to the Closing, or the condition, quality, status or nature of any of the Properties prior to Closing, including rights to contribution, cost recovery or other claims under any Environmental Law, breaches of statutory or implied warranties, nuisance or other tort actions, right to punitive damages, common Law rights of contribution, and rights under insurance maintained by the other Party or its Affiliates .

10.9.

Satisfaction . Any Liabilities payable to a Buyer Indemnified Party pursuant to Section 10 shall be satisfied: (a) from the Escrow Fund; and (b) to the extent the amount of such Liabilities exceeds the amounts available to the Buyer Indemnified Party in the Escrow Fund, from the Seller.

11. Termination . The Parties agree that this Agreement is subject to termination as follows:

11.1.

Right to Terminate . Subject to Sections ‎11.2 and ‎11.3 , this Agreement may be terminated (except for the provisions referenced in Section ‎11.2 ) at any time prior to the consummation of the Closing as follows:

11.1.1

by mutual written consent of Seller and Buyer;

11.1.2

by Buyer, (i) if Seller has materially breached this Agreement and such breach causes any of the conditions to Closing set forth in Section ‎6 not to be satisfied (or, if prior to Closing, is of such a magnitude or effect that it

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will not be possible for such condition to be satisfied); provided , however , that in the case of a breach that is capable of being cured, Seller shall have until the earlier of the Outside Date and the date that is ten (10) days following receipt of such notice to attempt to cure the breach and the termination under this Section ‎11.1.2 shall not become effective unless Seller fails to cure such breach prior to the end of such period or (ii) after September 22, 2016, if the court has denied approval of the AKM Consent on or before September 22, 2016;

11.1.3

by Seller, if Buyer has materially breached this Agreement and such breach causes any of the conditions to Closing set forth in Section ‎7 not to be satisfied (or, if prior to Closing, is of such a magnitude or effect that it will not be possible for such condition to be satisfied); provided , however , that in the case of a breach that is capable of being cured, Buyer shall have until the earlier of the Outside Date and the date that is ten (10) days following receipt of such notice to attempt to cure the breach and the termination under this Section ‎11.1.3 shall not become effective unless Buyer fails to cure such breach prior to the end of such period; or

11.1.4

by Seller, if Buyer fails to pay the Deposit within two Business Days after the Execution Date; or

11.1.5

by Seller or Buyer, if the Closing shall not have occurred on or before October 31, 2016 (the “ Outside Date ”), provided that such failure does not result primarily from the terminating Party’s material breach of its representations, warranties or covenants contained in this Agreement;

provided , however , neither Seller nor Buyer shall have the right to terminate this Agreement pursuant to Section ‎11.1.2 or Section ‎11.1.3 if such Party or any of its Affiliates is at such time in material breach of any of its representations, warranties or covenants contained in this Agreement.

11.2.

Effect of Termination . In the event of termination, written notice thereof will be given to the other Party specifying the provision pursuant to which such termination is made. Except as specifically provided in Section ‎11.3 , with five (5) Business Days following the termination of this Agreement the Deposit will be refunded to Buyer. If this Agreement is terminated in accordance with Section ‎11.1 , then the provisions contained in this Section ‎11.2 and in Sections ‎1.2 , ‎5.2.2 , 5.2.3 , ‎5.9 , ‎8.5 , ‎9 , ‎12 , ‎13 , ‎14.1 , ‎14.2 , ‎14.5 through ‎14.16 , ‎14.18 , ‎14.19 , ‎14.20 and ‎14.22 , and such defined terms in Section ‎1.1 as may be required to give meaning to such sections, shall survive termination of this Agreement. No termination of this Agreement under Section ‎11 shall relieve any Party of liability for breach of this Agreement arising prior to such termination.

11.3.

Distribution of Deposit and Remedies upon Termination .

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11.3.1

If the Closing occurs, the Escrow Fund shall remain with the Escrow Agent pursuant to the Escrow Agreement and used to satisfy any claims for indemnification by any Buyer Indemnified Party pursuant to Section 10.2 . Except to the extent of the amount of any unresolved pending claims pursuant to Section 10.2 , Seller and Buyer shall instruct the Escrow Agent to release the entire balance of the Escrow Fund to Seller on the date six (6) months after the Closing Date.

11.3.2

If this Agreement is terminated by Seller pursuant to Section ‎11.1.3 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, then subject to Seller’s exercise of its rights under Section 11.3.4 , Buyer and Seller shall instruct the Escrow Agent to pay to Seller the Deposit as liquidated damages as Seller’s sole and exclusive remedy for any breach or failure to perform by Buyer under this Agreement. Seller and Buyer agree that, in the event Seller receives the Deposit as liquidated damages pursuant to this Section 11.3.2 , the amount of the Deposit is a reasonable estimate due to the difficulty and inconvenience of measuring actual damages and the uncertainty thereof, and Seller and Buyer 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 Buyer. Upon such termination, Seller shall be free immediately to enjoy all rights of ownership of the Properties and to sell, transfer, encumber or otherwise dispose of the Properties to any Person without any restriction under this Agreement.

11.3.3

If this Agreement is terminated by Buyer pursuant to Section ‎11.1.2(i) and Buyer 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 Buyer’s election, either (a) Buyer and Seller shall instruct the Escrow Agent to pay the Deposit to Buyer and Buyer shall be entitled to seek monetary damages available at Law from Seller for Seller’s applicable breach of this Agreement (limited to 15% of the unadjusted Purchase Price) or (b) pursuant to Section 11.3.4 , the Deposit will remain in escrow with the Escrow Agent and Buyer shall be entitled to seek specific performance as provided in Section ‎11.3.4 .

11.3.4

In lieu of termination of this Agreement, if either Party 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 such Party shall be entitled to specific performance of this Agreement, it being specifically agreed that monetary damages will not be sufficient to compensate such Party if such Party determines the same in its sole discretion. If a Party elects to seek specific performance of this Agreement, the Deposit shall be held by the Escrow Agent until a non-appealable final judgment or award on such Party’s claim for specific

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performance is rendered, at which time the Parties shall instruct the Escrow Agent to distribute the Deposit as provided in the judgment or award resolving the specific performance claim or shall be applied as provided in Section ‎2 .

11.3.5

If this Agreement terminates for reasons other than those set forth in Section ‎11.1.2(i) or Section ‎11.1.3 , then (a) Buyer and Seller shall instruct the Escrow Agent to pay the Deposit to Buyer, free of any claims by Seller or any other Person with respect thereto, and (b) except as otherwise provided in Section 11.3.6 , neither Party shall have any further liability hereunder of any nature whatsoever to the other Party.

11.3.6

If this Agreement terminates for any reason other than those set forth in Section 11.1.1 , Section Error! Reference source not found. ‎11.1.3 , or Section 11.1.4 , and Seller directly or indirectly receives an indication of interest for a Superior Transaction prior to the date of termination of this Agreement and enters into an agreement representing a Superior Transaction within six (6) months of such termination (whether or not with the party submitting such indication of interest), then unless Buyer has terminated under Section 11.1.2(i) and elected to enforce its rights under Section 11.3.3 , Seller shall, upon the closing of the transaction contemplated by such agreement, pay to Buyer the amount of Five Million Dollars ($5,000,000.00) as a break-up fee constituting liquidated damages and as Buyer’s sole and exclusive remedy in connection with any such termination in lieu of all other recourse against Seller including monetary damages and specific performance. Seller and Buyer agree that, in the event Buyer receives such break-up fee pursuant to this Section ‎11.3.6 , ( i ) such amount is a reasonable estimate due to the difficulty and inconvenience of measuring actual damages and the uncertainty thereof, and Seller and Buyer agree that such amount would be a reasonable estimate of Buyer’s loss and ( ii ) Buyer shall not be entitled to seek the remedies provided for in Section ‎11.3.3 (other than right to receive the return of the Deposit). If this Agreement terminates for any reason other than those set forth in Section 11.1.1 , Section Error! Reference source not found. ‎11.1.3 , or Section 11.1.4 , the provisions of this Section ‎11.3.6 shall survive termination of this Agreement .

12. Default . If either Party fails to perform any material obligation contained in this Agreement that is to be performed at or prior to Closing, and Closing has not yet occurred, then the Party claiming default will serve written notice to the other Party specifying the nature of such default and demanding performance. If such a material default by Seller has not been cured within the sooner of ten (10) days after receipt of such default notice or the date specified in Section ‎11.1.5 above, and each of the conditions contained in Section ‎7 has been either fulfilled in all material respects or waived in writing (other than conditions pertaining to the execution and delivery of documents and payment of monies by Buyer the fulfillment of which is expressly provided to occur at the Closing, and conditions not satisfied as a consequence of acts or omissions of Seller

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or its Affiliates), Buyer will be entitled to exercise all of the remedies provided in Section ‎11.3.3 by reason of such default, including termination of this Agreement pursuant to Section ‎11 . If such a material default by Buyer has not been cured within the sooner of ten (10) days after receipt of such default notice or the date specified in Section ‎11.1.5 above, and each of the conditions contained in Section ‎6 has been either fulfilled in all material respects or waived in writing (other than conditions pertaining to the execution and delivery of documents the fulfillment of which is expressly provided to occur at the Closing, and conditions not satisfied as a consequence of acts or omissions of Buyer or its Affiliates), Seller will be entitled to exercise all of the remedies provided in Section ‎11.3.1 by reason of such default, including, without limitation, termination of this Agreement pursuant to Section ‎11 .

13. Arbitration . Except with respect to disputes involving Title Defects, Environmental Defects, or any cure relating thereto or any Final Statement matters or other matters to be resolved by the Consultants or Accounting Referee, which will be resolved as provided in Sections ‎2.1.11 or ‎2.7 , unless expressly provided otherwise in this Agreement, any and all Arbitrable Disputes must be resolved through the use of binding arbitration in accordance with the procedures specified in this Section ‎13 .

13.1.

Negotiation . The Parties shall attempt to resolve any Arbitrable Dispute promptly by negotiation between executives who have authority to settle the controversy and who are at a comparable or higher level of management than the persons who have been involved in the negotiation of this Agreement. Either Party may give the other Party written notice of any Arbitrable Dispute not resolved in the normal course of business. Within fifteen (15) days after delivery of the notice, the receiving Party shall submit to the other a written response. The notice and response shall include (a) a statement of that Party’s position and a summary of arguments supporting that position, and (b) the name and title of the executive who will represent that Party and of any other person who will accompany the executive. Within thirty (30) days after delivery of the initial notice, the executives of both Parties shall meet at a mutually acceptable time and place, and thereafter continue to meet as often as they reasonably deem necessary, to use their good faith and reasonable efforts to attempt to resolve the Arbitrable Dispute. All negotiations pursuant to this clause shall be confidential and shall be treated as compromise and settlement negotiations for purposes of applicable rules of evidence.

13.2.

Mediation . If the Arbitrable Dispute has not been resolved by negotiation as provided in Section ‎13.1 within sixty (60) days after delivery of the initial notice of negotiation, or if the Parties failed to meet within thirty (30) days after delivery of such notice, the Parties shall endeavor to settle the dispute by mediation under the AAA Commercial Mediation Procedure then currently in effect. Either Buyer or Seller may ask AAA to select a mediator or the Parties may mutually agree on a mediator.

13.3.

Arbitration; Rules of Arbitration . Except as otherwise provided herein, if any Arbitrable Dispute has not been resolved under the provisions of Section ‎13.2 within sixty (60) days after request for mediation has been submitted to AAA, then, at the request of Buyer or Seller, an Arbitrable Dispute shall be submitted to binding

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arbitration in accordance with the AAA Commercial Arbitration Rules then in effect (the “ AAA Rules ”), as supplemented to the extent necessary to determine any procedural appeal questions by the Federal Arbitration Act (Title 9 of the United States Code); provided , however , that if there is no mediation under Section ‎13.2 because any Party will not participate in mediation as provided therein, the other Party may initiate arbitration at any time within sixty (60) days following a Party’s refusal to participate in mediation under such Section. If there is any inconsistency between this Section ‎13 and the Commercial Arbitration Rules or the Federal Arbitration Act, the terms of this Section ‎13 shall control the rights and obligations of the Parties.

13.4.

Consolidation . If there is more than one (1) Arbitrable Dispute that involves the same facts and Parties as the facts and Parties with respect to which arbitration has been initiated pursuant to this Agreement, such disputes shall be consolidated into the first arbitration initiated pursuant to this Agreement, provided that disputes regarding Title Defects, Environmental Defects or any cure relating thereto or any Final Statement matters or other matters to be resolved by the Consultants or Accounting Referee shall not be consolidated with an Arbitrable Dispute under this Section ‎13 .

13.5.

Initiation; Selection of Arbitrators . Arbitration may be initiated by a Party (“ Claimant ”) serving written notice on the other Party (“ Respondent ”) that the Claimant has referred the Arbitrable Dispute to binding arbitration. Claimant’s notice initiating binding arbitration must describe in reasonable detail the nature of the Arbitrable Dispute and the facts and circumstances relating thereto and identify the arbitrator Claimant has appointed. Respondent shall respond to Claimant within thirty (30) days after receipt of Claimant’s notice, identifying the arbitrator Respondent has appointed. All arbitrators must (a) be neutral parties who have never been officers, directors or employees of the Parties or any of their Affiliates, or have performed material work for either of the Parties or its Affiliates within the preceding five (5) year period, and (b) agree in writing to keep strictly confidential the specifics and existence of the dispute as well as all proprietary records of the Parties reviewed by the arbitrators in the process of resolving such dispute. Unless expressly provided otherwise in this Agreement arbitrators must have a formal education or training in the area of dispute resolution and must have not less than seven (7) years’ experience as a lawyer in the energy industry with experience in exploration, contracts and production issues. The two (2) arbitrators so chosen shall select a third arbitrator within thirty (30) days after the second arbitrator has been appointed, consistent with the selection criteria above and with due regard given to input from the Parties. If either the Respondent fails to name its Party-appointed arbitrator within the time permitted, or if the two arbitrators are unable to agree on a third arbitrator within thirty (30) days from the date the second arbitrator has been appointed, then the missing arbitrator(s) shall be selected by the AAA with due regard given to the selection criteria above and input from the Parties and other arbitrators. The Parties acknowledge that each Party may have confidential communications with its Party-appointed arbitrator concerning that arbitrator’s selection. The AAA shall select the missing arbitrator(s) not later than ninety (90)

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days from initiation of arbitration. In the event the AAA should fail to select the third arbitrator within ninety (90) days from initiation of arbitration, then any Party may petition the Chief United States District Judge for the Western District of Oklahoma, to select the third arbitrator. Such selection shall be consistent with the selection criteria above and with due regard given to input from the Parties and other arbitrators.

13.6.

Procedure . The arbitration shall proceed under the AAA Rules and shall be governed by the Federal Arbitration Act, 9 U.S.C. Section 1, et. seq. The arbitrators may, in their discretion, limit or expand discovery in any arbitration proceeding. The Parties expressly covenant and agree to be bound by the decision of the arbitrators as a final determination of the matter in dispute, and a judgment thereon may be entered in any court of competent jurisdiction. In rendering the award the arbitrators shall abide by (a) the terms and conditions of this Agreement including, without limitation, any and all restrictions, prohibitions or limitations on damages or remedies set forth in this Agreement and (b) the law of the State of Oklahoma. The arbitrators shall not have jurisdiction or authority to add to, detract from or alter in any way the provisions of this Agreement. The arbitrators may award equitable relief, such as specific performance, as well as monetary damages for any Party’s breach of such Party’s obligations under this Agreement, but in no event may the arbitrators’ award indirect, consequential, exemplary or punitive damages or damages for lost profits.

13.7.

Location and Timing . The arbitration shall take place in Oklahoma City, Oklahoma and commence within sixty (60) days after the selection of the third arbitrator, unless delayed by order of the arbitrators. The hearing shall be based upon written position papers submitted by each Party within fifteen (15) days after the selection of the third arbitrator, stating such Party’s proposed resolution of the dispute. The Parties and the arbitrators should proceed diligently and in good faith in order that the award may be made as promptly as possible. The arbitrators shall determine the Arbitrable Disputes and render a final award on or before thirty (30) days following the completion of the hearing. The arbitrators’ decision shall be in writing and set forth the reasons for the award.

13.8.

Expenses; Award of Fees . The arbitration panel may apportion the costs of arbitration between or among the Parties in such manner as it deems reasonable, taking into account the circumstances of the Arbitrable Dispute, the conduct of the Parties and the result of arbitration. The arbitration panel shall be empowered and directed to enter an award by default against any Party to the arbitration who declines to pay when required by the arbitration panel its share of such fees and costs. In addition, the arbitration panel, shall be entitled to award to a Party such Party’s reasonable attorney’s fees and expert fees, as determined by the arbitration panel considering those factors mentioned in the first sentence of this Section ‎13.8 , incurred in connection with such Party’s preparation for and participation in the arbitration.

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13.9.

Limitations . All statutes of limitations and defenses based upon passage of time applicable to any Arbitrable Dispute (including any counterclaim or setoff) shall be interrupted by the initiating of the dispute resolution process pursuant to this Section ‎13 and suspended while any of the dispute resolution processes described in this Section ‎13 is pending. The terms hereof shall not create or limit any obligations of a Party to defend, indemnify or hold harmless another Party against court proceedings or other claims.

13.10.

Enforcement; Remedies . Prior to the appointment of the third arbitrator a Party may, notwithstanding any other provision of this Agreement, seek temporary injunctive relief from any court of competent jurisdiction, provided that the Party seeking such relief shall (if arbitration has not already been commenced) simultaneously commence the dispute resolution process set forth in this Section ‎13 . Such court-ordered relief shall not continue more than ten (10) days after the appointment of the arbitrators and in no event for longer than ninety (90) days. Except as provided in the Federal Arbitration Act, the decision of the arbitrators shall be binding on and non-appealable by the Parties. Each Party agrees that any arbitration award against it may be enforced in any court of competent jurisdiction and that any Party may authorize any such court to enter judgment on the arbitrators’ decisions. Without prejudice to such provisional remedies as may be available under the jurisdiction of a court and in order to prevent irreparable harm, the arbitral tribunal shall have full authority to grant provisional remedies and to direct the parties to request that any court modify or vacate any temporary or preliminary relief issued by such court or grant permanent injunctive or other equitable relief.

14. Miscellaneous . It is further agreed as follows:

14.1.

Time . This Agreement contains a number of dates and times by which performance or the exercise of rights is due, and the Parties intend that each and every such date and time be the firm and final date and time, as agreed. For this reason, each Party hereby waives and relinquishes any right it might otherwise have to challenge its failure to meet any performance or rights election date applicable to it on the basis that its late action constitutes substantial performance, to require the other Party to show prejudice, or on any equitable grounds. Without limiting the foregoing, time is of the essence of this Agreement. If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) shall be the next day which is a Business Day.

14.2.

Notices . All notices and communications required or permitted under this Agreement shall be in writing addressed as indicated below, and any communication or delivery hereunder shall be deemed to have been duly delivered upon the earliest of: (a) actual receipt by the Party to be notified; (b) if sent by U.S. certified mail, postage prepaid, return receipt requested, then the date shown as

27242226 59 Asset Purchase Agreement

received on the return notice; (c) if by email, then upon an affirmative reply by email by the intended recipient that such email was received, provided that if such email is received after 5:00 pm local time of such recipient, such email will be deemed to have been received on the following Business Day; or (d) if by Federal Express overnight delivery (or other reputable overnight delivery service), the date shown on the notice of delivery. Addresses for all such notices and communication shall be as follows:

To Seller:	SCOOP Energy Company, LLC 301 NW 63 rd Street, Suite 400 Oklahoma City, Oklahoma 73116 Attention: Scott R. Mueller Telephone:(405) 418-8080 Email: scott.mueller@aep-lp.com
With a copy to:	SCOOP Energy Company, LLC 301 NW 63 rd Street, Suite 400 Oklahoma City, Oklahoma 73116 Attention: Thomas J. Blalock Telephone: (405) 608-5727 Email: tom.blalock@aep-lp.com
To Buyer:	Jones Energy Holdings, LLC 807 Las Cimas Parkway Austin, Texas 78746 Attention: Mike S. McConnell Telephone: (512) 493-4299 Email: mmcconnell@jonesenergy.com
With a copy to:	Baker Botts L.L.P. 98 San Jacinto Blvd. Suite 1500 Austin, Texas 78701-4078 Attention: Mike Bengtson Telephone: (512) 322-2661 Email: mike.bengtson@bakerbotts.com

Either Party may, upon written notice to the other Party, change the address(es) and person(s) to whom such communications are to be directed.

14.3.

Survival . Except as otherwise expressly provided in the applicable Section of this Agreement, (a) the Fundamental Representations and the representations corresponding thereto in any certificate delivered in connection with this Agreement (together with the indemnification rights with respect to such representations) will survive the Execution Date for the period thirty (30) days following the expiration of the applicable statute of limitations and shall thereafter be of no further force or effect, (b) covenants of the Parties contained in this Agreement shall survive until fully performed, and (c) all of the other

27242226 60 Asset Purchase Agreement

representations and warranties of the Parties contained in this Agreement or in any certificate delivered in connection with this Agreement will survive the Execution Date for a period of twelve (12) months and shall thereafter be of no further force or effect (as to each of (a), (b) and (c) above, the “ Expiration Date ”); provided , however , any representation, warranty or covenant as to which a claim shall have been asserted prior to the Expiration Date shall survive until such claim and the indemnity claim with respect thereto are resolved. Notwithstanding the foregoing, the Indemnities in Sections ‎5.2.2 , ‎10.2.3 , 10.2.4 and ‎10.3.2 shall survive the Closing without time limit. The special warranty of title set forth in the Assignment will survive the Closing Date for a period of two (2) years and shall thereafter be of no further force or effect except that any claim under such special warranty of title which has been asserted prior to the end of such two (2) years period shall survive until such claim with respect thereto is resolved. The intended effect of termination of (a) representations, warranties and covenants (and the indemnification rights with respect thereto) and (b) the special warranty of title is to bar, from and after the date of termination, any claim or cause of action based on the alleged inaccuracy of such representation or breach of such warranty, or with regard to claims for indemnity with respect thereto or with respect to such special warranty of title. Subject to the limitations set forth in this Section, the provisions of this Agreement shall survive the delivery of the Assignment at Closing, unless otherwise indicated.

14.4.

Cooperation . Prior to termination of this Agreement and at all times following the consummation of this Agreement, the Parties agree to execute and deliver, or cause to be executed and delivered, such documents and do, or cause to be done, such other acts and things as might reasonably be requested by any Party to this Agreement to assure that the benefits of this Agreement are realized by the Parties .

14.5.

No Third Party Beneficiaries . Except for the indemnification rights of the Seller Indemnified Parties and the Buyer Indemnified Parties under Sections ‎5.2.2 and ‎10 , nothing in this Agreement, express or implied, is intended to confer upon anyone, other than the Parties hereto and their respective successors and assigns, any rights or remedies under or by reason of this Agreement or to constitute any Person a third party beneficiary of this Agreement.

14.6.

Cumulative Remedies . Subject to the other provisions hereof, no failure on the part of any Party to this Agreement to exercise and no delay in exercising any right hereunder will operate as a waiver thereof, nor will any single or partial exercise by any Party hereto of any right hereunder preclude any other or further right of exercise thereof or the exercise of any other right.

14.7.

Choice of Law . This Agreement will be interpreted, construed and enforced in accordance with the laws of the State of Oklahoma, without giving effect to any rules or principles of conflicts of law that might otherwise refer to the laws of another jurisdiction.

14.8.

Entire Agreement . This Agreement (including, for purposes of certainty, the Exhibits and Schedules attached hereto), the Assignment and other documents to

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be executed hereunder and 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.

14.9.

Assignment . Except as contemplated in Section ‎14.17 , it is agreed that no Party may assign such Party’s rights nor delegate such Party’s duties under this Agreement without the express written consent of the other Party to this Agreement, and no such assignment under Section ‎14.17 shall be deemed to have released the assigning Party from any of its obligations under this Agreement; provided that Buyer, subject to Buyer remaining liable for the performance of its obligations under this Agreement, may direct that the Properties be assigned to one of its subsidiaries at the Closing.

14.10.

Amendment . Neither this Agreement nor any of the provisions hereof can be changed, waived, discharged or terminated, except by an instrument in writing signed by the Party against whom enforcement of the change, waiver, discharge or termination is sought.

14.11.

Severability . If any clause or provision of this Agreement is illegal, invalid or unenforceable under any present or future Law or public policy, the remainder of this Agreement will not be affected thereby. It is the intention of the Parties that if any such provision is held to be illegal, invalid or unenforceable, there will be added in lieu thereof a provision as similar in terms to such provisions as is possible to make such provision legal, valid and enforceable.

14.12.

Attorney Fees . If any Party institutes an Proceeding against any other Party relating to the provisions of this Agreement, including arbitration, the Party to such action or proceeding which does not prevail will reimburse the prevailing Party therein (regardless of whether the prevailing Party is the plaintiff or the defendant in such action or proceeding) for the reasonable expenses of attorneys’ fees and disbursements incurred by the prevailing Party.

14.13.

Waiver . Waiver of performance of any obligation or term contained in this Agreement by any Party, or waiver by one Party of the other’s default hereunder will not operate as a waiver of performance of any other obligation or term of this Agreement or a future waiver of the same obligation or a waiver of any future default.

14.14.

Counterparts; Facsimiles; Electronic Transmission . This Agreement may be executed in multiple counterparts, each of which will be an original instrument, but all of which will constitute one agreement. The execution and delivery of this Agreement by any Party may be evidenced by facsimile or other electronic transmission (including scanned documents delivered by email), which shall be binding upon all Parties.

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14.15.

Joint Acknowledgment . This written Agreement represents the final agreement between the Parties and may not be contradicted by evidence of prior, contemporaneous or subsequent oral agreements of the Parties.

14.16.

Waiver of Jury Trial, Special Damages, etc . Each of Buyer and Seller hereby knowingly, voluntarily, intentionally and irrevocably (a) waives, to the maximum extent not prohibited by Law, any right it may have to a trial by a jury in respect of any litigation based hereon, or directly or indirectly at any time arising out of, under or in connection with this Agreement or any transaction contemplated hereby or associated herewith, (b) waives, to the maximum extent not prohibited by Law, any right it may have to claim or recover in any such Proceeding any “ Special Damages ,” as defined below, and (c) acknowledges that it has been induced to enter into this Agreement and the transactions contemplated hereby by, among other things, the mutual waivers and certifications contained in this Section, in each case it being the express intent, understanding, and agreement of the Parties that such waivers are to be given the fullest effect, notwithstanding the negligence (whether sole, joint or concurrent), strict liability or other legal fault of any Party. As used in this Section, “Special Damages” means all special, exemplary, punitive, consequential, indirect, remote and speculative damages (regardless of how named, and including loss of profit, loss of revenue, loss of production or reserves, or any other incidental damages), but does not include any payments or funds which a Party has expressly promised to pay or deliver to the other Party or any claims of any Person for which one Party has agreed to indemnify the other Party under this agreement.

14.17.

Possible Exchange . Each of Buyer and Seller reserve the right to structure the transaction contemplated under the terms of this Agreement as a non-simultaneous like-kind exchange pursuant to §1031 of the Internal Revenue Code of 1986, as amended, and its implementing regulations. In connection with effectuating a non-simultaneous like-kind exchange, each Party reserves the right, at or prior to Closing, to assign its rights under this Agreement to a Qualified Intermediary (as that term is defined in §1.1031(k)-1(g)(4)(v) of the Treasury Regulations) or to a Qualified Exchange Accommodation Titleholder (as that term is defined in Revenue Procedure 2000-37). In addition, should a Party choose to structure the transaction provided under the terms of this Agreement as a non-simultaneous like-kind exchange, the other Party agrees to execute all documents reasonably necessary to effectuate the non-simultaneous like-kind exchange.

14.18.

Mutuality . The Parties acknowledge and declare that this Agreement is the result of extensive negotiations between them. Accordingly, if there is any ambiguity in this Agreement, there shall be no presumption that this instrument was prepared solely by either Party.

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14.19.

Schedules . The inclusion of any information (including dollar amounts) in any section of the disclosure Schedules hereto shall not be deemed to be an admission or acknowledgment by Seller that such information is required to be listed on such Schedule or is material to or outside the Ordinary Course of Business of Seller. The information contained in this Agreement, the Exhibits and the Schedules hereto is disclosed solely for purposes of this Agreement, and no information contained herein or therein shall be deemed to be an admission by any Party hereto to any Third Party of any matter whatsoever (including any violation of a legal requirement or breach of contract). Matters disclosed in each Schedule shall qualify the representation and warranty in which such Schedule is referenced and any other representation or warranty to which the matters disclosed reasonably relate.

14.20.

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

14.21.

Filings, Notices and Approvals . Promptly after the Closing, Buyer shall (a) record the Assignments of the Properties and all state/federal assignments delivered at Closing in all applicable real property records and/or, if applicable, all state or federal agencies and (b) actively pursue the approval of all Customary Post-Closing Consents from applicable Governmental Authorities of the Assignment of the Properties transferred to Buyer at Closing. Buyer obligates itself to take any and all action required by any Governmental Authority in order to obtain such approval, including the posting of any and all bonds or other security that may be required in excess of its existing lease, pipeline or area-wide bonds.

14.22.

Nonrecourse to Others . The Parties further agree that, notwithstanding anything to the contrary set forth in this Agreement and subject to the other limitations on liability set forth in this Agreement, Buyer’s sole recourse for any and all loss, damage, claim, liability, expense or other obligations arising under this Agreement or any of the documents or transactions relating thereto shall be solely to Seller and neither Buyer nor the Buyer Indemnified Parties will have any recourse to Seller’s Affiliates or any of the Seller Indemnified Parties.

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SIGNATURE PAGES FOLLOW]

27242226 64 Asset Purchase Agreement

IN WITNESS WHEREOF, Seller has executed this Agreement on the Execution Date.

S eller :

SCOOP ENERGY COMPANY, LLC , an Oklahoma limited liability company

By: /s/ Scott R. Mueller

Name: Scott R. Mueller

Title: Chief Financial Officer

Seller’s Signature Page to Purchase and Sale Agreement

IN WITNESS WHEREOF, Buyer has executed this Agreement on the Execution Date.

B uyer :

JONES ENERGY HOLDINGS, LLC ,

a Delaware corporation

By: /s/ Jonny Jones

Name: Jonny Jones

Title: CEO

Buyer’s Signature Page to Purchase and Sale Agreement

Exhibit 10.1

Execution Version

AMENDMENT NO. 10 TO CREDIT AGREEMENT

This AMENDMENT NO. 10 TO CREDIT AGREEMENT (this “ Agreement ”) dated as of August 1, 2016 (the “ Effective Date ”), is among Jones Energy Holdings, LLC, a Delaware limited liability company (the “ Borrower ”), Jones Energy, Inc., a Delaware corporation and the parent company of the Borrower (“ Jones Parent ”), the undersigned subsidiaries of the Borrower as guarantors (together with Jones Parent, collectively, the “ Guarantors ”), the Lenders (as defined below) and Wells Fargo Bank, N.A. (“ Wells Fargo ”), in its capacity as administrative agent for the Lenders (in such capacity, the “ Administrative Agent ”).

RECITALS

A. The Borrower is party to that certain Credit Agreement dated as of December 31, 2009 among the Borrower, the financial institutions party thereto from time to time as lenders (the “ Lenders ”) and the Administrative Agent, as heretofore amended (as so amended, the “ Credit Agreement ”).

B. The parties hereto wish to, subject to the terms and conditions of this Agreement, (i) redetermine the Borrowing Base and (ii) amend the Credit Agreement as provided herein.

NOW THEREFORE, in consideration of the premises and the mutual covenants, representations and warranties contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

Section 1. Defined Terms . As used in this Agreement, each of the terms defined in the opening paragraph and the Recitals above shall have the meanings assigned to such terms therein. Unless otherwise specifically defined herein, each term defined in the Credit Agreement, as amended hereby, and used herein without definition shall have the meaning assigned to such term in the Credit Agreement, as amended hereby.

Section 2. Other Definitional Provisions . Article, Section, Schedule, and Exhibit references are to Articles and Sections of and Schedules and Exhibits to this Agreement, unless otherwise specified. The words “hereof”, “herein”, and “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement. The term “including” means “including, without limitation,”. Paragraph headings have been inserted in this Agreement as a matter of convenience for reference only and it is agreed that such paragraph headings are not a part of this Agreement and shall not be used in the interpretation of any provision of this Agreement.

Section 3. Decrease in the Borrowing Base .

(a) Subject to the terms of this Agreement, as of the Effective Date, the Borrowing Base shall be set at $425,000,000 and, subject to the provisions set forth below, such Borrowing Base shall remain in effect at that level until the effective date of the next Borrowing Base redetermination made in accordance with the terms of the Credit Agreement, as amended hereby. The parties hereto further agree that, if the EOG Acquisition (as defined in Exhibit A attached

hereto) shall not have been consummated on or prior to August 31, 2016, the Borrowing Base shall automatically be reduced to $410,000,000 effective as of August 31, 2016 unless the Borrowing Base has been reduced to an amount less than $410,000,000 pursuant to the terms of the Credit Agreement, as amended hereby.

(b) The parties hereto acknowledge and agree that the Borrowing Base redetermination set forth in this Section 3 shall be and be deemed to be the Scheduled Redetermination of the Borrowing Base under Section 2.07(b) of the Credit Agreement for spring 2016. Each Lender’s Applicable Percentage of the resulting Borrowing Base, after giving effect to the redetermination of the Borrowing Base set forth in this Section 3 , is set forth in Annex I attached hereto.

Section 4. Amendments to Credit Agreement .

(a) The Credit Agreement (other than the exhibits and schedules thereto) is hereby amended and restated in its entirety as set forth in Exhibit A attached hereto.

(b) Exhibit B to the Credit Agreement is hereby amended and restated in its entirety and replaced with Exhibit B attached hereto.

Section 5. Credit Parties Representations and Warranties . Each Credit Party represents and warrants that: (a) after giving effect to this Agreement, the representations and warranties of the Borrower and the Guarantors contained in the Credit Agreement, as amended hereby, and the other Loan Documents are true and correct in all material respects (except that such materiality qualifier shall not be applicable to any such representation or warranty that already is qualified or modified by materiality in the text thereof) on and as of the Effective Date as if made on as and as of such date except to the extent that any such representation or warranty expressly relates solely to an earlier date, in which case such representation or warranty is true and correct in all material respects (except that such materiality qualifier shall not be applicable to any representation or warranty that already is qualified or modified by materiality in the text thereof) as of such earlier date; (b) after giving effect to this Agreement, no Event of Default has occurred and is continuing; (c) the execution, delivery and performance of this Agreement are within the limited liability company power and authority of such Credit Party and have been duly authorized by appropriate limited liability company action and proceedings; (d) this Agreement constitutes the legal, valid, and binding obligation of such Credit Party enforceable in accordance with its terms, except as limited by applicable bankruptcy, insolvency, reorganization, moratorium, or similar laws affecting the rights of creditors generally and general principles of equity; (e) there are no governmental or other third party consents, licenses and approvals required in connection with the execution, delivery, performance, validity and enforceability of this Agreement; and (f) the Liens under the Security Instruments are valid and subsisting and secure the Indebtedness (as such Indebtedness may be increased as a result of the transactions contemplated hereby).

Section 6. Conditions to Effectiveness . This Agreement shall become effective on the Effective Date and enforceable against the parties hereto upon the occurrence of the following conditions precedent:

(a) The Administrative Agent, the Arranger and the Lenders shall have received, to the extent invoiced, reimbursement or payment of all reasonable out-of-pocket expenses required to be reimbursed or paid by the Borrower under the Credit Agreement (including, without limitation, the reasonable fees and expenses of Bracewell LLP, as special counsel to the Administrative Agent).

(b) The Administrative Agent shall have received a certificate of the Secretary or an Assistant Secretary of the Borrower and each Guarantor each setting forth resolutions of its board of directors or other appropriate governing body with respect to the authorization of the Borrower or such Guarantor to execute and deliver the Loan Documents to which it is a party and to enter into the transactions contemplated in those documents, the officers of the Borrower or such Guarantor (y) who are authorized to sign the Loan Documents to which the Borrower or such Guarantor is a party and (z) who will, until replaced by another officer or officers duly authorized for that purpose, act as its representative for the purposes of signing documents and giving notices and other communications in connection with this Agreement and the transactions contemplated hereby, specimen signatures of such authorized officers, and the Organizational Documents of the Borrower and such Guarantor, certified as being true and complete, or if applicable, certifying that there has been no change thereto since the date of a previously-delivered certificate of the Secretary or an Assistant Secretary of the Borrower or such Guarantor. The Administrative Agent and the Lenders may conclusively rely on such certificate until the Administrative Agent receives notice in writing from the Borrower to the contrary.

(c) The Administrative Agent shall have received certificates of the appropriate State agencies with respect to the existence and qualification of the Borrower and each Guarantor in its jurisdiction of formation.

(d) The Administrative Agent shall have received from each party hereto counterparts (in such number as may be requested by the Administrative Agent) of this Agreement signed on behalf of such party.

Section 7. Acknowledgments and Agreements .

(a) The Borrower acknowledges that on the date hereof all outstanding Indebtedness is payable in accordance with its terms and the Borrower waives any defense, offset, counterclaim or recoupment with respect thereto.

(b) The Administrative Agent, the Issuing Bank, and the Lenders hereby expressly reserve all of their rights, remedies, and claims under the Loan Documents, as amended hereby. This Agreement shall not constitute a waiver or relinquishment of (i) any Default or Event of Default under any of the Loan Documents, as amended hereby, (ii) any of the agreements, terms or conditions contained in any of the Loan Documents, as amended hereby, (iii) any rights or remedies of the Administrative Agent, the Issuing Bank, or any Lender with respect to the Loan Documents, as amended hereby, or (iv) the rights of the Administrative Agent, the Issuing Bank, or any Lender to collect the full amounts owing to them under the Loan Documents, as amended hereby.

(c) The Borrower, each Guarantor, the Administrative Agent, the Issuing Bank and each Lender do hereby adopt, ratify, and confirm the Credit Agreement, as amended hereby, and acknowledge and agree that the Credit Agreement, as amended hereby, is and remains in full force and effect, and the Borrower and each Guarantor acknowledge and agree that their respective liabilities and obligations under the Credit Agreement, as amended hereby, the Guarantee and Collateral Agreement, and the other Loan Documents are not impaired in any respect by this Agreement.

(d) From and after the Effective Date, all references to the Credit Agreement in the Loan Documents shall mean the Credit Agreement, as amended by this Agreement. This Agreement is a Loan Document for the purposes of the provisions of the other Loan Documents.

Section 8. Reaffirmation of the Guaranty . Each Guarantor hereby ratifies, confirms, acknowledges and agrees that its obligations under the Guarantee and Collateral Agreement are in full force and effect and that such Guarantor continues to unconditionally and irrevocably guarantee the full and punctual payment, when due, whether at stated maturity or earlier by acceleration or otherwise, of all of the Obligations (as defined in the Guarantee and Collateral Agreement), as such Obligations may have been amended by this Agreement, and its execution and delivery of this Agreement does not indicate or establish an approval or consent requirement by such Guarantor under the Guarantee and Collateral Agreement in connection with the execution and delivery of amendments, consents or waivers to the Credit Agreement, the Notes or any of the other Loan Documents.

Section 9. Counterparts . This Agreement may be signed in any number of counterparts, each of which shall be an original and all of which, taken together, constitute a single instrument. This Agreement may be executed by facsimile or PDF electronic mail signature, and all such signatures shall be effective as originals.

Section 10. Successors and Assigns . This Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted pursuant to the Credit Agreement.

Section 11. Severability . Any provision of this Agreement held to be invalid, illegal or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such invalidity, illegality or unenforceability without affecting the validity, legality and enforceability of the remaining provisions hereof, and the invalidity of a particular provision in a particular jurisdiction shall not invalidate such provision in any other jurisdiction.

Section 12. Governing Law . This Agreement shall be deemed to be a contract made under and shall be governed by and construed in accordance with the laws of the State of Texas.

Section 13. Entire Agreement . THIS AGREEMENT, THE CREDIT AGREEMENT AS AMENDED BY THIS AGREEMENT, THE NOTES, AND THE OTHER LOAN DOCUMENTS CONSTITUTE THE ENTIRE UNDERSTANDING AMONG THE PARTIES HERETO WITH RESPECT TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ANY PRIOR AGREEMENTS, WRITTEN OR ORAL, WITH RESPECT THERETO.

THERE ARE NO UNWRITTEN ORAL AGREEMENTS AMONG THE PARTIES.

[SIGNATURES BEGIN ON NEXT PAGE]

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized as of the day and year first above written.

BORROWER:	JONES ENERGY HOLDINGS, LLC


	By:	/s/ Robert J. Brooks
		Robert J. Brooks
		Executive Vice President, Chief Financial
		Officer, Secretary and Treasurer

GUARANTORS:	JONES ENERGY, INC.
	JONES ENERGY, LLC
	NOSLEY ASSETS, LLC


	Each by:	/s/ Robert J. Brooks
		Robert J. Brooks
		Executive Vice President, Chief
		Financial Officer, Secretary
		and Treasurer

Signature Page to