Jones Energy (JONEQ) 10-Q 2015 Q3 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended September 30, 2015

or

oTRANSITION 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 x    No o

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 x    No o

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 o	Accelerated filer x
Non-accelerated filer o	Smaller reporting company o
(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  o  No  x

On October 30, 2015, the Registrant had 30,519,153 shares of Class A common stock outstanding and 31,273,130 shares of Class B common stock outstanding.

JONES ENERGY, INC.

TABLE OF CONTENTS

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	27
Item 3. Quantitative and Qualitative Disclosures About Market Risk	34
Item 4. Controls and Procedures	35
PART II—OTHER INFORMATION	37
Item 1. Legal Proceedings	37
Item 1A. Risk Factors	37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3. Defaults Upon Senior Securities	37
Item 4. Mine Safety Disclosures	37
Item 5. Other Information	37
Item 6. Exhibits	37
SIGNATURES	38

i

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, our ability to take advantage of additional working interest capture, our ability to increase capital spending in connection with leasing and additional working interest capture, our ability to mitigate commodity price risk through our hedging program, and our ability to successfully execute our 2015 development plan and guidance for the fourth quarter and full year 2015. 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 oil, natural gas liquids, and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, customers’ elections to reject ethane and include it as part of the natural gas stream for the remainder of 2015, 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.

ii

PART 1—FINANCIAL INFORMATION

Item 1. Financial Statements

Jones Energy, Inc.

Consolidated Balance Sheets (Unaudited)

	September 30,			December 31,
(in thousands of dollars)	2015			2014
Assets
Current assets
Cash	$	22,698		$	13,566
Restricted cash	277			149
Accounts receivable, net
Oil and gas sales	26,610			51,482
Joint interest owners	13,978			41,761
Other	13,932			12,512
Commodity derivative assets	117,186			121,519
Other current assets	2,498			3,374
Total current assets	197,179			244,363
Oil and gas properties, net, at cost under the successful efforts method	1,665,732			1,638,860
Other property, plant and equipment, net	4,136			4,048
Commodity derivative assets	95,102			87,055
Other assets	18,751			20,352
Deferred tax assets	1,135			171
Total assets	$	1,982,035		$	1,994,849
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	47,300		$	136,337
Oil and gas sales payable	42,145			70,469
Accrued liabilities	32,182			19,401
Commodity derivative liabilities	20			—
Deferred tax liabilities	470			718
Asset retirement obligations	3,311			3,074
Total current liabilities	125,428			229,999
Long-term debt	100,000			360,000
Senior notes	737,487			500,000
Deferred revenue	11,856			13,377
Commodity derivative liabilities	—			28
Asset retirement obligations	12,260			10,536
Liability under tax receivable agreement	40,009			803
Deferred tax liabilities	21,896			26,756
Total liabilities	1,048,936			1,141,499
Commitments and contingencies (Note 8)
Stockholders’ equity
Class A common stock, $0.001 par value; 30,531,278 shares issued and 30,508,676 shares outstanding at September 30, 2015 and 12,672,260 shares issued and 12,649,658 shares outstanding at December 31, 2014	31			13
Class B common stock, $0.001 par value; 31,283,607 shares issued and outstanding at September 30, 2015 and 36,719,499 shares issued and outstanding at December 31, 2014	31			37
Treasury stock, at cost: 22,602 shares at September 30, 2015 and December 31, 2014	(358		)	(358		)
Additional paid-in-capital	361,355			178,763
Retained earnings	35,933			38,950
Stockholders’ equity	396,992			217,405
Non-controlling interest	536,107			635,945
Total stockholders’ equity	933,099			853,350
Total liabilities and stockholders’ equity	$	1,982,035		$	1,994,849

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

1

Jones Energy, Inc.

Consolidated Statements of Operations (Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands of dollars except per share data)	2015			(Restated) 2014			2015			(Restated) 2014
Operating revenues
Oil and gas sales	$	46,499		$	99,707		$	156,955		$	303,370
Other revenues	653			639			2,210			1,610
Total operating revenues	47,152			100,346			159,165			304,980
Operating costs and expenses
Lease operating	8,872			11,183			32,930			30,306
Production and ad valorem taxes	2,513			5,044			9,292			18,248
Exploration	5,556			266			6,184			3,278
Depletion, depreciation and amortization	52,766			50,491			156,151			137,490
Accretion of ARO liability	210			206			610			573
General and administrative	9,628			6,925			27,572			18,723
Other operating	—			—			4,188			—
Total operating expenses	79,545			74,115			236,927			208,618
Operating income (loss)	(32,393		)	26,231			(77,762		)	96,362
Other income (expense)
Interest expense	(16,722		)	(11,849		)	(47,553		)	(34,659		)
Net gain (loss) on commodity derivatives	90,483			41,163			111,714			(9,785		)
Other income (expense)	(7		)	30			(1,631		)	97
Other income (expense), net	73,754			29,344			62,530			(44,347		)
Income (loss) before income tax	41,361			55,575			(15,232		)	52,015
Income tax provision (benefit)	6,519			5,550			(4,590		)	5,736
Net income (loss)	34,842			50,025			(10,642		)	46,279
Net income (loss) attributable to non-controlling interests	21,604			40,893			(7,625		)	37,835
Net income (loss) attributable to controlling interests	$	13,238		$	9,132		$	(3,017	)	$	8,444
Earnings (loss) per share:
Basic	$	0.44		$	0.73		$	(0.12	)	$	0.68
Diluted	$	0.44		$	0.73		$	(0.12	)	$	0.68
Weighted average shares outstanding:
Basic	30,432			12,508			25,591			12,503
Diluted	30,432			12,573			25,591			12,540

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

2

Jones Energy, Inc.

Consolidated Statement of Changes In Stockholders’ Equity (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, 2014	12,622	$	13	36,719		$	37		23	$	(358	)	$	178,763	$	38,950		$	635,945		$	853,350
Sale of common stock	12,263	12		—		—			—	—			123,189		—			—			123,201
Exchange of Class B shares for Class A shares	5,436	6		(5,436	)	(6		)	—	—			54,116		—			(92,213		)	(38,097		)
Stock-compensation expense	—	—		—		—			—	—			5,287		—			—			5,287
Vested restricted shares	121	—		—		—			—	—			—		—			—			—
Net income (loss)	—	—		—		—			—	—			—		(3,017		)	(7,625		)	(10,642		)
Balance at September 30, 2015	30,442	$	31	31,283		$	31		23	$	(358	)	$	361,355	$	35,933		$	536,107		$	933,099

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

3

Jones Energy, Inc.

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended September 30,
(in thousands of dollars)	2015			(Restated) 2014
Cash flows from operating activities
Net income (loss)	$	(10,642	)	$	46,279
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Exploration (dry hole and lease abandonment)	5,250			2,952
Depletion, depreciation, and amortization	156,151			137,490
Accretion of ARO liability	610			573
Amortization of debt issuance costs	3,379			6,129
Stock compensation expense	5,287			2,707
Other non-cash compensation expense	326			380
Amortization of deferred revenue	(1,521		)	(862		)
(Gain) loss on commodity derivatives	(111,714		)	9,785
(Gain) loss on sales of assets	(10		)	(97		)
Deferred income tax provision	(4,590		)	5,823
Other - net	1,178			241
Changes in assets and liabilities
Accounts receivable	54,244			(4,961		)
Other assets	848			631
Accrued interest expense	9,577			16,611
Accounts payable and accrued liabilities	(19,184		)	28,151
Net cash provided by operations	89,189			251,832
Cash flows from investing activities
Additions to oil and gas properties	(280,528		)	(343,405		)
Net adjustments to purchase price of properties acquired	—			15,709
Proceeds from sales of assets	37			99
Acquisition of other property, plant and equipment	(1,034		)	(1,196		)
Current period settlements of matured derivative contracts	103,858			(14,228		)
Change in restricted cash	(129		)	(52		)
Net cash used in investing	(177,796		)	(343,073		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	75,000			80,000
Repayment under long-term debt	(335,000		)	(468,000		)
Proceeds from senior notes	236,475			500,000
Purchases of treasury stock	—			(358		)
Payment of debt issuance costs	(1,514		)	(11,431		)
Proceeds from sale of common stock	122,778			—
Net cash provided by financing	97,739			100,211
Net increase in cash	9,132			8,970
Cash
Beginning of period	13,566			23,820
End of period	$	22,698		$	32,790
Supplemental disclosure of cash flow information
Cash paid for interest	$	34,594		$	10,787
Change in accrued additions to oil and gas properties	(94,552		)	58,501
Current additions to ARO	1,355			1,205

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

4

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (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 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 a result of the IPO and as of October 30, 2015, the Pre-IPO owners had 74.7% and 50.6%, respectively, of the total economic interest in JEH, but with no voting rights or management power over JEH, resulting in the Company reporting this ownership interest as a non-controlling interest.

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 Anadarko and Arkoma basins of Texas and Oklahoma, and are owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas.

Restatement of Previously Issued Financial Statements

In conjunction with our 2014 year-end audit and the preparation of our annual Form 10-K, we identified an error in our previously issued 2014 quarterly financial statements which would have been material to such statements if not restated. We recorded the adjustments on a quarterly basis in the prior periods. The Consolidated Statement of Operations for the three and nine months ended September 30, 2014 were restated to record $2.6 million and $7.0 million, respectively, of additional depletion, depreciation and amortization expense and net income was reduced by $2.2 million and $6.2 million accordingly. The impact of the restatement to the three and nine month periods ended September 30, 2014 are summarized in the table below:

	Three Months EndedSeptember 30, 2014				Nine Months EndedSeptember 30, 2014
(in thousands)	As Reported		As Restated		As Reported		As Restated
Oil and gas properties	$	1,533,704	$	1,526,735	$	1,533,704	$	1,526,735
Depletion, depreciation and amortization	$	47,965	$	50,491	$	130,521	$	137,490
Operating income	$	28,757	$	26,231	$	103,331	$	96,362
Net income (loss)	$	52,230	$	50,025	$	52,434	$	46,279
Net income (loss) attributable to non-controlling interests	$	42,701	$	40,893	$	42,879	$	37,835
Net income (loss) attributable to controlling interests	$	9,529	$	9,132	$	9,555	$	8,444
Basic earnings (loss) per share	$	0.76	$	0.73	$	0.76	$	0.68
Diluted earnings (loss) per share	$	0.76	$	0.73	$	0.76	$	0.68

5

Revision of Previously Issued Financial Statements

During the first quarter of 2015, we identified an error in our previously issued Form 10-K for the year ended December 31, 2014 related to the over accrual for production taxes which would have been material to the first quarter and could be material to projected 2015 annual results if recorded as an out of period adjustment in such period. Therefore we will revise our Consolidated Statement of Operations for the year and quarter ended December 31, 2014 in the December 31, 2015 Form 10-K to reduce Production Taxes by $1.6 million and increase Income Tax Provision by $0.1 million related to an accrual for production taxes that was not properly reversed at December 31, 2014. As a result, net income will be increased for the year and quarter ended December 31, 2014 by $1.5 million, resulting in an increase in earnings per share of $0.02. The balance sheet impacts of the revision, which are reflected in this Form 10-Q, are included in the table below. This revision had no impact on our net cash provided by operations in our Consolidated Statement of Cash Flows for the nine months ended September 30, 2014. We have determined that this error is not material to the consolidated financial statements of any prior period presented.

In addition, we identified an error in our previously issued Form 10-K for the year ended December 31, 2014 related to the exchange of Class B shares for Class A shares. Therefore we revised our Consolidated Balance Sheet and Statement of Changes in Stockholders’ Equity for the year ended December 31, 2014 as noted in the table below. This revision had no impact on Class A or Class B shares outstanding at December 31, 2014. We have determined that this error is not material to the consolidated financial statements of any prior period presented.

	December 31, 2014				Exchange of Class B			December 31, 2014
	As Reported		Production tax		shares			As Revised
Accounts Receivable, Oil and gas sales	$	49,861	$	1,621				$	51,482
Deferred tax liabilities	$	26,612	$	144				$	26,756
Additional paid in capital	$	177,133			$	1,630		$	178,763
Retained earnings	$	38,682	$	268				$	38,950
Non-controlling interest	$	636,366	$	1,209	$	(1,630	)	$	635,945

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”). All significant intercompany transactions and balances have been eliminated in consolidation. The financial statements reported for September 30, 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. These reclassifications include the reclassification of ad valorem taxes of $0.1 million and $3.3 million from Lease Operating Expense to Production and Ad Valorem Taxes in the Consolidated Statement of Operations for the three and nine months ended September 30, 2014, respectively.

These interim financial statements have not been audited. However, in the opinion of management, all adjustments necessary for a fair statement of the financial statements have been included. As these are interim financial statements, they do not include all disclosures required for financial statements prepared in conformity with GAAP. Interim period results are not necessarily indicative of results of operations or cash flows for a full year.

These consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Accordingly, they do not include all disclosures required by GAAP and 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, 2014.

Use of Estimates

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent liabilities, and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from these estimates. Changes in estimates are recorded prospectively.

Significant assumptions are required in the valuation of proved and unproved oil and natural gas reserves, which affect the Company’s estimates of depletion expense, impairment, and the allocation of value in our business combinations. Significant

6

assumptions are also required in the Company’s estimates of the net gain or loss on commodity derivative assets and liabilities, fair value associated with business combinations, and asset retirement obligations (“ARO”).

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, 2015 and December 31, 2014:

	September 30,			December 31,
(in thousands of dollars)	2015			2014
Mineral interests in properties
Unproved	$	74,639		$	94,526
Proved	1,025,630			1,001,194
Wells and equipment and related facilities	1,276,980			1,094,202
	2,377,249			2,189,922
Less: Accumulated depletion and impairment	(711,517		)	(551,062		)
Net oil and gas properties	$	1,665,732		$	1,638,860

Costs to acquire mineral interests in oil and natural gas properties are capitalized. Costs to drill and equip development wells and the related asset retirement costs are capitalized. The costs to drill and equip exploratory wells are capitalized pending determination of whether the Company has discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are charged to expense. In some circumstances, it may be uncertain whether proved commercial reserves have been found when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the anticipated reserve quantity is sufficient to justify its completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. During the nine months ended September 30, 2015 we had no material capitalized costs associated with exploratory wells.

The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. The Company did not capitalize any interest during the nine months ended September 30, 2015 as no projects lasted more than six months. Depletion of oil and gas properties amounted to $52.5 million and $155.3 million for the three and nine months ended September 30, 2015, respectively, and $50.3 million and $136.7 million for the three and nine months ended September 30, 2014, respectively.

Other Property, Plant and Equipment

Other property, plant and equipment consisted of the following at September 30, 2015 and December 31, 2014:

	September 30,			December 31,
(in thousands of dollars)	2015			2014
Leasehold improvements	$	1,208		$	1,218
Furniture, fixtures, computers and software	4,075			3,727
Vehicles	1,537			988
Aircraft	910			910
Other	249			219
	7,979			7,062
Less: Accumulated depreciation and amortization	(3,843		)	(3,014		)
Net other property, plant and equipment	$	4,136		$	4,048

Other property, plant and equipment is depreciated on a straight-line basis over the estimated useful lives of the property, plant and equipment, which range from three years to ten years. Depreciation and amortization of other property, plant and equipment amounted to $0.3 million and $0.9 million during the three and nine months ended September 30, 2015, respectively, and $0.2 million and $0.8 million during the three and nine months ended September 30, 2014, respectively.

7

Commodity Derivatives

The Company records its commodity derivative instruments on the Consolidated Balance Sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized currently in earnings, unless specific hedge accounting criteria are met. During the nine month periods ended September 30, 2015 and 2014, the Company elected not to designate any of its commodity price risk management activities as cash-flow or fair value hedges. The changes in the fair values of outstanding financial instruments are recognized as gains or losses in the period of change. Although the Company does not designate its commodity derivative instruments as cash-flow hedges, management uses those instruments to reduce the Company’s exposure to fluctuations in commodity prices related to its natural gas and oil production.

Net gains and losses, at fair value, are included on the Consolidated Balance Sheet as current or noncurrent assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of commodity derivative contracts are recorded in earnings as they occur and are included in the Other Income (Expense) caption on the Consolidated Statement of Operations. See Note 3, “Fair Value Measurement,” for disclosure about the fair values of commodity derivative instruments.

Asset Retirement Obligations

The Company’s asset retirement obligations consist of future plugging and abandonment expenses on oil and natural gas properties.

A summary of the Company’s ARO for the nine months ended September 30, 2015 is as follows:

(in thousands of dollars)
Balance at December 31, 2014	$	13,610
Liabilities incurred	1,355
Accretion of ARO liability	610
Liabilities settled	(19		)
Change in estimate	15
Balance at September 30, 2015	15,571
Less: Current portion of ARO	(3,311		)
Total long-term ARO at September 30, 2015	$	12,260

Tax Receivable Agreement

In connection with the IPO, the Company entered into a Tax Receivable Agreement (the “TRA”) which obligates the Company to make payments to certain current and former owners equal to 85% of the applicable cash savings that the Company realizes as a result of tax attributes arising from exchanges of JEH Units and shares of the Company’s Class B common stock held by those owners for shares of the Company’s Class A common stock. The Company will retain the benefit of the remaining 15% of these tax savings.

As a result of exchanges made through September 30, 2015, the Company has accrued future tax benefits of $47.1 million and has accounted for this amount as a reduction of deferred tax liabilities on its consolidated balance sheet. As of September 30, 2015, the Company has recorded a liability of $40.0 million associated with its future obligations under the TRA. The actual amount and timing of payments to be made under the TRA will depend upon a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers, and the portion of the Company’s payments under the TRA constituting imputed interest. 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, 2015, the Company has made no payments under the TRA and does not anticipate making a payment under the TRA in 2015.

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Stock Compensation

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”). The management unit grants awarded prior to the initial filing of the IPO registration statement in March 2013 had a dual vesting schedule. Grants awarded after the filing of the initial IPO registration statement have a single vesting structure with equal annual installments and were valued at the IPO price, adjusted for equivalent shares. In connection with the IPO, both the vested and unvested management units were converted into the right to receive an indirect interest in JEH Units and shares of Class B common stock.

Under the Jones Energy, Inc. 2013 Omnibus Incentive Plan (the “LTIP”), established in conjunction with the Company’s IPO, the Company reserved 3,850,000 shares of Class A common stock for director and employee stock-based compensation awards.

The Company granted performance unit and restricted stock unit awards to certain officers and employees under the LTIP during 2014 and 2015. The fair value of the performance units was based on the grant date fair value (using a Monte Carlo simulation model) and is expensed on a straight-line basis over the applicable three-year performance period. The number of shares of Class A common stock issuable upon vesting of the performance unit awards ranges from zero to 200% based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. The fair value of the restricted stock unit awards was 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.

The Company granted each of the outside members of the Board of Directors shares of restricted Class A common stock under the LTIP in 2014 and 2015. The fair value of the restricted stock grants was 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.

Refer to Note 6, “Stock-based Compensation,” for additional information regarding director and employee stock-based compensation awards.

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers,” which creates a new topic in the ASC, topic 606, “Revenue from Contracts with Customers.” This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14 which deferred the effective date of ASU 2014-09 by one year. The amendments are now effective for interim and annual reporting periods beginning after December 15, 2018 and may be applied on either a full or modified retrospective basis. Early adoption is permitted. We are currently evaluating the effect that the adoption of Update 2014-09 and Update 2015-14 will have on our financial statements.

In August 2014, the FASB issued ASU No. 2014-15, “Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.” This ASU requires management to evaluate whether there are conditions or events that raise substantial doubt about an entity’s ability to continue as a “going concern” and to provide disclosures when certain criteria are met. Substantial doubt exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as they become due within one year after the date that the financial statements are issued (or available to be issued). The amendments are effective for interim and annual reporting periods beginning after December 15, 2016. Early adoption is permitted. We do not expect the adoption of these disclosures to have a significant impact on the Company’s consolidated financial statements.

In January 2015, the FASB issued 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. The Company does not expect the adoption of this guidance to have a material impact on its 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

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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) (“Update 2015-15”), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 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. We are currently evaluating the effect that the adoption of Update 2015-03 and Update 2015-15 will have on our financial statements.

3.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 price hedge contracts. The Company utilizes valuation techniques that maximize the use of observable inputs, where available. If listed market prices or quotes are not published, fair value is determined based upon a market quote, adjusted by other market-based or independently sourced market data, such as trading volume, historical commodity volatility, and counterparty-specific considerations. These adjustments may include amounts to reflect counterparty credit quality, the time value of money, and the liquidity of the market.

Counterparty credit valuation adjustments are necessary when the market price of an instrument is not indicative of the fair value as a result of the credit quality of the counterparty. Generally, market quotes assume that all counterparties have low default rates and equal credit quality. Therefore, an adjustment may be necessary to reflect the quality of a specific counterparty to determine the fair value of the instrument. The Company currently has all derivative positions placed and held by members of its lending group, which have high credit quality.

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. The Company does not classify any of its financial instruments as Level 1.
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.

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The financial instruments carried at fair value as of September 30, 2015 and December 31, 2014, by consolidated balance sheet caption and by valuation hierarchy as described above, are as follows:

	September 30, 2015
(in thousands of dollars)	Fair Value Measurements
Commodity Derivative Instruments	(Level 1)		(Level 2)			(Level 3)		Total
Current assets	$	—	$	116,377		$	809	$	117,186
Long-term assets	—		94,827			275		95,102
Current liabilities	—		(20		)	—		(20		)
Long-term liabilities	—		—			—		—

	December 31, 2014
(in thousands of dollars)	Fair Value Measurements
Commodity Derivative Instruments	(Level 1)		(Level 2)		(Level 3)			Total
Current assets	$	—	$	120,604	$	915		$	121,519
Long-term assets	—		85,162		1,893			87,055
Current liabilities	—		—		—			—
Long-term liabilities	—		—		(28		)	(28		)

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, 2015.

(in thousands of dollars) Commodity Derivative	Quantitative Information About Level 3 Fair Value Measurements
Instruments	Fair Value		Valuation Technique	Unobservable Input	Range
Natural gas liquid swaps	$	1,084	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures prices	$8.09 - $59.78 per barrel

Significant increases/decreases in natural gas liquid futures 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, 2015. 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, 2014, net	$	2,780
Purchases	(17		)
Settlements	(750		)
Transfers to Level 2	(1,115		)
Transfers to Level 3	—
Changes in fair value	186
Balance at September 30, 2015, net	$	1,084

Transfers from Level 3 to Level 2 represent the Company’s natural gas liquid and gas basis swaps for which observable forward curve pricing information has become readily available.

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Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments which may not be recorded at fair value in the consolidated financial statements:

	September 30, 2015				December 31, 2014
(in thousands of dollars)	Principal Amount		Fair Value		Principal Amount		Fair Value
Debt:
Revolver	$	100,000	$	100,000	$	360,000	$	360,000
2022 Notes	500,000		399,690		500,000		384,375
2023 Notes	250,000		232,345		—		—

The Revolver (as defined in Note 5) is categorized as Level 3 in the valuation hierarchy as the debt is not publicly traded and no observable market exists to determine the fair value; however, the carrying value of the Revolver approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to the Company for those periods.

The fair value of the 2022 Notes (as defined in Note 5) is based on pricing that is readily available in the public market. Accordingly, the 2022 Notes are classified as Level 1 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities and is actively traded.

The fair value of the 2023 Notes (as defined in Note 5) is based on indicative pricing that is available in the public market. Accordingly, the 2023 Notes are classified as Level 2 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities but is not actively traded.

The Company reviews its oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a 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. The Company assessed its proved and unproved properties for impairment as of September 30, 2015 and no impairment charges were recorded. However, future price declines, or a period of sustained low commodity prices, could result in a significant impairment charge in future periods. Furthermore, in addition to commodity prices, our production rates, levels of proved reserves, future development costs, and other factors affect our impairment analyses and may lead to an impairment charge in future periods.

4.Commodity Derivative Instruments

The Company had various commodity derivatives in place as of September 30, 2015 and December 31, 2014, as follows:

Hedging Positions

	September 30, 2015
								Weighted			Final
		Low			High			Average			Expiration
Oil swaps	Exercise price	$	54.53		$	100.87		$	79.73
	Barrels per month	54,000			197,357			103,522			June 2019
Natural gas swaps	Exercise price	$	2.82		$	6.45		$	4.27
	mmbtu per month	450,000			1,640,000			1,076,575			June 2019
Basis swaps	Contract differential	$	(0.39	)	$	(0.11	)	$	(0.25	)
	mmbtu per month	320,000			750,000			538,333			March 2016
Natural gas liquids swaps	Exercise price	$	8.09		$	95.24		$	34.08
	Barrels per month	2,000			145,000			61,407			December 2017

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	December 31, 2014
								Weighted			Final
		Low			High			Average			Expiration
Oil swaps	Exercise price	$	75.05		$	100.95		$	84.20
	Barrels per month	45,000			184,054			113,852			December 2018
Natural gas swaps	Exercise price	$	3.37		$	6.45		$	4.40
	mmbtu per month	710,000			1,772,584			1,175,275			December 2018
Basis swaps	Contract differential	$	(0.39	)	$	(0.11	)	$	(0.21	)
	mmbtu per month	320,000			980,000			716,667			March 2016
Natural gas liquids swaps	Exercise price	$	8.09		$	95.24		$	42.46
	Barrels per month	2,000			143,000			50,444			December 2017

The Company recognized net gains on derivative instruments of $90.5 million and net gains of $111.7 million for the three and nine months ended September 30, 2015, respectively, and net gains on derivative instruments of $41.2 million and net losses of $9.8 million for the three and nine months ended September 30, 2014, respectively.

Offsetting Assets and Liabilities

As of September 30, 2015, the counterparties to our commodity derivative contracts consisted of seven financial institutions. All of our counterparties or their affiliates are also lenders under our credit facility. Therefore, 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 which are netted on our Consolidated Balance Sheet as of September 30, 2015 and December 31, 2014:

(in thousands)	Gross Amounts of Recognized Assets / Liabilities			Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets / Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet		Net Amount
September 30, 2015
Commodity derivative contracts
Assets	$	213,019		$	(731	)	$	212,288		$	—	$	212,288
Liabilities	(751		)	731			(20		)	—		(20		)
December 31, 2014
Commodity derivative contracts
Assets	$	208,646		$	(72	)	$	208,574		$	—	$	208,574
Liabilities	(100		)	72			(28		)	—		(28		)

5.Long-Term Debt

Senior Unsecured Notes

Senior notes consisted of the following at September 30, 2015 and December 31, 2014:

(in thousands of dollars)	September 30,2015			December 31, 2014
2022 Notes	$	500,000		$	500,000
2023 Notes	250,000			—
Total principal amount	750,000			500,000
Less: unamortized discount	(12,513		)	—
Total carrying amount	$	737,487		$	500,000

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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 (together 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 ($160.0 million), a portion of the outstanding borrowings under the Revolver ($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. As of September 30, 2015, the Company had $16.9 million in interest accrued related to the 2022 Notes. Total interest expense related to the 2022 Notes amounted to $8.4 million and $25.3 million for the three and nine months ended September 30, 2015, respectively.

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. As of September 30, 2015, the Company had $1.0 million in interest accrued related to the 2023 Notes. Total interest expense related to the 2023 Notes amounted to $5.8 million and $13.9 million for the three and nine months ended September 30, 2015, respectively.

The 2022 and 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of its significant subsidiaries. The 2022 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 and 2023 Notes are substantially similar and contain covenants that, among other things, limit the ability of the Company to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or other payments from the Company’s restricted subsidiaries to the Company, consolidate, merge or transfer all of the Company’s assets, engage in transactions with affiliates or create unrestricted subsidiaries. However, many of these covenants will be suspended if the Notes are rated investment grade.

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”), each of which have been or were amended periodically. 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, increase the borrowing base under the Revolver from $550.0 million to $625.0 million until the next redetermination thereof, and 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 million during the semi-annual borrowing base re-determination.

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 redetermined by the lenders at least semi-annually on or about April 1 and October 1 of each year. 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, 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. For the three and nine months ended September 30, 2014, the average interest rates under the Revolver were 2.17% and 2.54%, respectively, on average outstanding balances of $261.0 million and $334.6 million, respectively.

Total interest and commitment fees under the Revolver were $1.0 million and $4.0 million for the three and nine months ended September 30, 2015 and $1.8 million and $6.7 million for the three and nine months ended September 30, 2014. Total interest and commitment fees under the Term Loan were $3.6 million for the nine months ended September 30, 2014. No interest and commitment fees were incurred under the Term Loan for the three months ended September 30, 2014. $3.8 million in

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unamortized deferred financing costs were written off to interest expense during the nine months ended September 30, 2014 in connection with the repayment of the Term Loan.

We are subject to certain covenants under the Revolver which include, but are not limited to, restrictions on asset sales, distributions to members, and incurrence of additional indebtedness, and financial covenants which require the maintenance of certain financial ratios, including a maximum leverage ratio and a minimum current ratio. The Company was in compliance with these covenants at September 30, 2015.

6.Stock-based Compensation

Management Unit Awards

Prior to the IPO, JEH granted management units to certain officers and employees under a previously existing management incentive plan. 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. No new JEH Units or shares of Class B common stock are created upon a vesting event. 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. Grants listed below reflect the transfer of JEH units that occurred upon forfeiture.

The following table summarizes information related to the vesting of JEH Units as of September 30, 2015:

	JEH Units		Weighted Average Grant Date Fair Value per Share
Unvested at January 1, 2015	274,385		$	15.00
Granted	1,909		15.00
Forfeited	(1,909	)	15.00
Vested	(76,319	)	15.00
Unvested at September 30, 2015	198,066		$	15.00

Stock compensation expense associated with the JEH Units was $0.3 million and $0.9 million for the three and nine months ended September 30, 2015, respectively, and $0.4 million and $1.2 million for the three and nine months ended September 30, 2014, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

Restricted Stock Unit Awards

The Company has outstanding restricted stock unit awards granted to certain officers and employees of the Company. The fair value of the restricted stock unit awards was 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.

The following table summarizes information related to the total number of units awarded to officers and employees as of September 30, 2015:

	Restricted Stock Unit Awards		Weighted Average Grant Date Fair Value per Share
Unvested at January 1, 2015	324,897		$	17.33
Granted	567,689		9.63
Forfeited	(10,108	)	14.82
Vested	(93,842	)	17.11
Unvested at September 30, 2015	788,636		$	11.84

Stock compensation expense associated with the employee restricted stock unit awards was $0.9 million and $2.1 million for the three and nine months ended September 30, 2015, respectively, and $0.4 million and $0.6 million for the three and nine months ended September 30, 2014, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

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Performance Unit Awards

The Company has outstanding performance unit awards granted to certain officers of the Company. Upon the completion of the applicable three-year performance period, each officer will vest in a number of performance units. The percent of awarded performance units in which each officer vests at such time 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 unit is exchangeable for one share of the Company’s Class A common stock. The grant date fair value of the performance units was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance units earned. The fair value of the performance units is expensed on a straight-line basis over the applicable three-year performance period.

The following table summarizes information related to the total number of units awarded to the officers as of September 30, 2015:

	PerformanceUnit Awards	Weighted AverageGrant Date Fair Valueper Share
Unvested at January 1, 2015	192,998	$	21.65
Granted	361,422	10.27
Forfeited	—	—
Vested	—	—
Unvested at September 30, 2015	554,420	$	14.23

Stock compensation expense associated with the performance unit awards was $0.7 million and $1.7 million for the three and nine months ended September 30, 2015, respectively, and $0.4 million and $0.6 million for the three and nine months ended September 30, 2014, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

Restricted Stock Awards

The Company has outstanding restricted stock awards granted to non-employee members of the Board of Directors. 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, 2015:

	Restricted Stock Awards		Weighted Average Grant Date Fair Value per Share
Unvested at January 1, 2015	27,430		$	18.77
Granted	67,380		7.30
Forfeited	—		—
Vested	(27,430	)	18.77
Unvested at September 30, 2015	67,380		7.30

Stock compensation expense associated with the Board of Directors awards was $0.1 million and $0.4 million for the three and nine months ended September 30, 2015, respectively, and $0.1 million and $0.3 million for the three and nine months ended September 30, 2014, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

7.Earnings (loss) 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

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issued by the Company in conjunction with stock awards that have been granted to directors and employees. In accordance with ASC 260, Earnings Per Share, awards of nonvested shares shall be 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 ended September 30, 2015, 788,636 restricted stock units, 67,380 shares of restricted stock, and 554,420 performance units were excluded from the calculation as they would have had an anti-dilutive effect. The following is a calculation of the basic and diluted weighted-average number of shares of Class A common stock outstanding and EPS for the three and nine months ended September 30, 2015 and September 30, 2014.

	Three Months Ended September 30				Nine Months Ended September 30
(in thousands, except per share data)	2015		2014(Restated)		2015			2014(Restated)
Income (numerator):
Net income (loss) attributable to controlling interests	$	13,238	$	9,132	$	(3,017	)	$	8,444
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock - basic	30,432		12,508		25,591			12,503
Weighted-average number of shares of Class A common stock - diluted	30,432		12,573		25,591			12,540
Earnings (loss) per share:
Basic	$	0.44	$	0.73	$	(0.12	)	$	0.68
Diluted	$	0.44	$	0.73	$	(0.12	)	$	0.68

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, 2015 due to the change in weighted-average shares outstanding.

8.Commitments and Contingencies

The Company is subject to legal proceedings and claims that arise in the ordinary course of its business. The Company believes that the final disposition of such matters will not have a material adverse effect on its financial position, results of operations, or liquidity.

9.Income Taxes

Following its IPO, the Company began recording federal and state income tax liabilities associated with its status as a corporation. Prior to the IPO, the Company only recorded a provision for Texas franchise tax as the Company’s taxable income or loss was includable in the income tax returns of the individual partners and members. The Company will recognize 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 for the three and nine months ended September 30, 2015 was 15.8% and 30.1%, 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’s income tax provision was an expense of $6.5 million and a benefit of $4.6 million for the three and nine months ended September 30, 2015, respectively, and an expense of $5.5 million and $5.7 million for the three and nine months ended September 30, 2014, respectively. See the table below for 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)	2015			(Restated) 2014		2015			(Restated) 2014
Jones Energy, Inc.	$	7,157		$	4,954	$	(3,195	)	$	4,739
Non-controlling interest	(638		)	596		(1,395		)	997
Total tax provision (benefit)	$	6,519		$	5,550	$	(4,590	)	$	5,736

The Company had deferred tax assets for its federal and state loss carryforwards at September 30, 2015 recorded in non-current 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, 2015, management determined that a valuation allowance was not required for the tax loss carryforwards as they are expected to be fully utilized before expiration.

17

10.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. and two immaterial subsidiaries) and certain future subsidiaries, including any future subsidiaries that guarantee any indebtedness under the Revolver. Each subsidiary guarantor is 100% owned by JEH, and all guarantees are full and unconditional, subject to customary exceptions pursuant to the indentures governing our 2022 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, 2015, the Company held approximately 49.4% of the economic interest in JEH, with the remaining 50.6% economic interest held by a group of investors that owned interests in JEH prior to the Company’s IPO (the “Existing Owners”). The Existing 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. 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.

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

The Existing Owners have the right, pursuant to the terms of an Exchange Agreement by and among the Company, JEH and each of the Existing Owners, 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.

18

Jones Energy, Inc.

Condensed Consolidating Balance Sheet

September 30, 2015

(in thousands of dollars)	JEI (Parent)			Issuers		Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	3,286	$	19,282	$	30		$	—		$	22,698
Restricted cash	—			—		277		—			—			277
Accounts receivable, net
Oil and gas sales	—			—		26,610		—			—			26,610
Joint interest owners	—			—		13,978		—			—			13,978
Other	154			12,922		856		—			—			13,932
Commodity derivative assets	—			117,186		—		—			—			117,186
Other current assets	—			579		1,919		—			—			2,498
Intercompany receivable	10,437			1,141,786		—		—			(1,152,223		)	—
Total current assets	10,691			1,275,759		62,922		30			(1,152,223		)	197,179
Oil and gas properties, net, at cost under the successful efforts method	—			—		1,665,732		—			—			1,665,732
Other property, plant and equipment, net	—			—		3,408		728			—			4,136
Commodity derivative assets	—			95,102		—		—			—			95,102
Other assets	—			18,499		252		—			—			18,751
Deferred tax assets	1,135			—		—		—			—			1,135
Investment in subsidiaries	443,322			—		—		—			(443,322		)	—
Total assets	$	455,148		$	1,389,360	$	1,732,314	$	758		$	(1,595,545	)	$	1,982,035
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	—		$	178	$	47,122	$	—		$	—		$	47,300
Oil and gas sales payable	—			—		42,145		—			—			42,145
Accrued liabilities	—			18,233		13,949		—			—			32,182
Commodity derivative liabilities	—			20		—		—			—			20
Deferred tax liabilities	—			470		—		—			—			470
Asset retirement obligations	—			—		3,311		—			—			3,311
Intercompany payable	—			—		1,369,031		2,420			(1,371,451		)	—
Total current liabilities	—			18,901		1,475,558		2,420			(1,371,451		)	125,428
Long-term debt	—			100,000		—		—			—			100,000
Senior notes	—			737,487		—		—			—			737,487
Deferred revenue	—			11,856		—		—			—			11,856
Asset retirement obligations	—			—		12,260		—			—			12,260
Liability under tax receivable agreement	40,009			—		—		—			—			40,009
Deferred tax liabilities	18,147			3,749		—		—			—			21,896
Total liabilities	58,156			871,993		1,487,818		2,420			(1,371,451		)	1,048,936
Stockholders’ / members’ equity
Members’ equity	—			517,367		244,496		(1,662		)	(760,201		)	—
Class A common stock, $0.001 par value; 30,531,278 shares issued and 30,508,676 shares outstanding	31			—		—		—			—			31
Class B common stock, $0.001 par value; 31,283,607 shares issued and outstanding	31			—		—		—			—			31
Treasury stock, at cost; 22,602 shares	(358		)	—		—		—			—			(358		)
Additional paid-in-capital	361,355			—		—		—			—			361,355
Retained earnings	35,933			—		—		—			—			35,933
Stockholders’ equity	396,992			517,367		244,496		(1,662		)	(760,201		)	396,992
Non-controlling interest	—			—		—		—			536,107			536,107
Total stockholders’ equity	396,992			517,367		244,496		(1,662		)	(224,094		)	933,099
Total liabilities and stockholders’ equity	$	455,148		$	1,389,360	$	1,732,314	$	758		$	(1,595,545	)	$	1,982,035

19

Jones Energy, Inc.

Condensed Consolidating Balance Sheet

December 31, 2014

(in thousands of dollars)	JEI(Parent)			Issuers		Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	1,000	$	12,436	$	30		$	—		$	13,566
Restricted Cash	—			—		149		—			—			149
Accounts receivable, net
Oil and gas sales	—			—		51,482		—			—			51,482
Joint interest owners	—			—		41,761		—			—			41,761
Other	102			8,788		3,622		—			—			12,512
Commodity derivative assets	—			121,519		—		—			—			121,519
Other current assets	—			451		2,923		—			—			3,374
Intercompany receivable	4,576			1,203,978		—		—			(1,208,554		)	—
Total current assets	4,778			1,335,736		112,373		30			(1,208,554		)	244,363
Oil and gas properties, net, at cost under the successful efforts method	—			—		1,638,860		—			—			1,638,860
Other property, plant and equipment, net	—			—		3,252		796			—			4,048
Commodity derivative assets	—			87,055		—		—			—			87,055
Other assets	—			20,098		254		—			—			20,352
Deferred tax assets	171			—		—		—			—			171
Investment in subsidiaries	233,496			—		—		—			(233,496		)	—
Total assets	$	238,445		$	1,442,889	$	1,754,739	$	826		$	(1,442,050	)	$	1,994,849
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	—		$	288	$	136,049	$	—		$	—		$	136,337
Oil and gas sales payable	—			—		70,469		—			—			70,469
Accrued liabilities	—			8,914		10,487		—			—			19,401
Deferred tax liabilities	—			718		—		—			—			718
Asset retirement obligations	—			—		3,074		—			—			3,074
Intercompany payable	—			—		1,210,042		2,328			(1,212,370		)	—
Total current liabilities	—			9,920		1,430,121		2,328			(1,212,370		)	229,999
Long-term debt	—			360,000		—		—			—			360,000
Senior notes	—			500,000		—		—			—			500,000
Deferred revenue	—			13,377		—		—			—			13,377
Commodity derivative liabilities	—			28		—		—			—			28
Asset retirement obligations	—			—		10,536		—			—			10,536
Liability under tax receivable agreement	803			—		—		—			—			803
Deferred tax liabilities	20,237			6,519		—		—			—			26,756
Total liabilities	21,040			889,844		1,440,657		2,328			(1,212,370		)	1,141,499
Stockholders’ / members’ equity
Members’ equity	—			553,045		314,082		(1,502		)	(865,625		)	—
Class A common stock, $0.001 par value; 12,672,260 shares issued and 12,649,658 shares outstanding	13			—		—		—			—			13
Class B common stock, $0.001 par value; 36,719,499 shares issued and 36,719,499 shares outstanding	37			—		—		—			—			37
Treasury stock, at cost: 22,602 shares	(358		)	—		—		—			—			(358		)
Additional paid-in-capital	178,763			—		—		—			—			178,763
Retained earnings	38,950			—		—		—			—			38,950
Stockholders’equity	217,405			553,045		314,082		(1,502		)	(865,625		)	217,405
Non-controlling interest	—			—		—		—			635,945			635,945
Total stockholders’ equity	217,405			553,045		314,082		(1,502		)	(229,680		)	853,350
Total liabilities and stockholders’ equity	$	238,445		$	1,442,889	$	1,754,739	$	826		$	(1,442,050	)	$	1,994,849

20

Jones Energy, Inc.

Condensed Consolidating Statement of Operations and Comprehensive Income

Nine Months Ended September 30, 2015

(in thousands)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor 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 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	(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	)

21

Jones Energy, Inc.

Condensed Consolidating Statement of Operations and Comprehensive Income

Three Months Ended September 30, 2015

(in thousands)	JEI (Parent)		Issuers			Guarantor Subsidiaries			Non- Guarantor 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 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	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

22

Jones Energy, Inc.

Condensed Consolidating Statement of Operations and Comprehensive Income

Nine Months Ended September 30, 2014

(in thousands)	JEI (Parent)		Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—	$	—		$	303,370		$	—		$	—		$	303,370
Other revenues	—		862			748			—			—			1,610
Total operating revenues	—		862			304,118			—			—			304,980
Operating costs and expenses
Lease operating	—		—			30,306			—			—			30,306
Production and ad valorem taxes	—		—			18,248			—			—			18,248
Exploration	—		—			3,278			—			—			3,278
Depletion, depreciation and amortization	—		—			137,422			68			—			137,490
Accretion of ARO liability	—		—			573			—			—			573
General and administrative	—		3,403			15,253			67			—			18,723
Total operating expenses	—		3,403			205,080			135			—			208,618
Operating income (loss)	—		(2,541		)	99,038			(135		)	—			96,362
Other income (expense)
Interest expense	—		(33,662		)	(997		)	—			—			(34,659		)
Net gain on commodity derivatives	—		(9,785		)	—			—			—			(9,785		)
Other income (expense)	—		—			97			—			—			97
Other income (expense), net	—		(43,447		)	(900		)	—			—			(44,347		)
Income (loss) before income tax	—		(45,988		)	98,138			(135		)	—			52,015
Equity interest in income	12,963		—			—			—			(12,963		)	—
Income tax provision	4,519		1,217			—			—			—			5,736
Net income (loss)	8,444		(47,205		)	98,138			(135		)	(12,963		)	46,279
Net income (loss) attributable to non-controlling interests	—		—			—			—			37,835			37,835
Net income (loss) attributable to controlling interests	$	8,444	$	—		$	—		$	—		$	—		$	8,444

23

Jones Energy, Inc.

Condensed Consolidating Statement of Operations and Comprehensive Income

Three Months Ended September 30, 2014

(in thousands)	JEI (Parent)		Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—	$	—		$	99,707		$	—		$	—		$	99,707
Other revenues	—		336			303			—			—			639
Total operating revenues	—		336			100,010			—			—			100,346
Operating costs and expenses
Lease operating	—		—			11,183			—			—			11,183
Production and ad valorem taxes	—		—			5,044			—			—			5,044
Exploration	—		—			266			—			—			266
Depletion, depreciation and amortization	—		—			50,468			23			—			50,491
Accretion of ARO liability	—		—			206			—			—			206
General and administrative	—		83			6,820			22			—			6,925
Total operating expenses	—		83			73,987			45			—			74,115
Operating income (loss)	—		253			26,023			(45		)	—			26,231
Other income (expense)
Interest expense	—		(11,028		)	(821		)	—			—			(11,849		)
Net gain on commodity derivatives	—		41,163			—			—			—			41,163
Other income (expense)	—		—			30			—			—			30
Other income (expense), net	—		30,135			(791		)	—			—			29,344
Income (loss) before income tax	—		30,388			25,232			(45		)	—			55,575
Equity interest in income	13,954		—			—			—			(13,954		)	—
Income tax provision	4,822		728			—			—			—			5,550
Net income (loss)	9,132		29,660			25,232			(45		)	(13,954		)	50,025
Net income (loss) attributable to non-controlling interests	—		—			—			—			40,893			40,893
Net income (loss) attributable to controlling interests	$	9,132	$	—		$	—		$	—		$	—		$	9,132

24

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2015

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor 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	(119,761		)	(133,068		)	358,087			160			(5,587		)	99,831
Net cash (used in) / provided by operations	(122,778		)	(76,533		)	288,500			—			—			89,189
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
Change in restricted cash	—			—			(129		)	—			—			(129		)
Net cash (used in) / provided by investing	—			103,858			(281,654		)	—			—			(177,796		)
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	122,778			—			—			—			—			122,778
Net cash (used in) / provided by financing	122,778			(25,039		)	—			—			—			97,739
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

25

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2014

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	8,444		$	(47,205	)	$	98,138		$	(135	)	$	(12,963	)	$	46,279
Adjustments to reconcile net income (loss) to net cash provided by operating activities	(8,086		)	(43,930		)	244,471			135			12,963			205,553
Net cash (used in) / provided by operations	358			(91,135		)	342,609			—			—			251,832
Cash flows from investing activities
Additions to oil and gas properties	—			—			(343,405		)	—			—			(343,405		)
Net adjustments to purchase price of properties acquired	—			—			15,709			—			—			15,709
Proceeds from sales of assets	—			—			99			—			—			99
Acquisition of other property, plant and equipment	—			—			(1,196		)	—			—			(1,196		)
Current period settlements of matured derivative contracts	—			(14,228		)	—			—			—			(14,228		)
Change in restricted cash	—			—			(52		)	—			—			(52		)
Net cash (used in) / provided by investing	—			(14,228		)	(328,845		)	—			—			(343,073		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	—			80,000			—			—			—			80,000
Repayment under long-term debt	—			(468,000		)	—			—			—			(468,000		)
Proceeds from senior notes	—			500,000			—			—			—			500,000
Payment of debt issuance costs	—			(11,431		)	—			—			—			(11,431		)
Purchase of treasury stock	(358		)	—			—			—			—			(358		)
Net cash (used in) / provided by financing	(358		)	100,569			—			—			—			100,211
Net increase (decrease) in cash	—			(4,794		)	13,764			—			—			8,970
Cash
Beginning of period	100			6,000			17,650			70			—			23,820
End of period	$	100		$	1,206		$	31,414		$	70		$	—		$	32,790

26

Item 2. Management’s Discussion and Analysis 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, 2014, filed on March 6, 2015 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, 2015, filed on May 8, 2015 with the Securities and Exchange Commission and our quarterly report on Form 10-Q for the quarter ended June 30, 2015, filed on August 7, 2015 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 Anadarko and Arkoma basins 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 825 total wells, including over 640 horizontal wells, since our formation and delivered compelling rates of return over various commodity price cycles. Our operations are focused on horizontal drilling and completions within two distinct basins in the Texas Panhandle and Oklahoma:

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

·the Arkoma Basin—targeting the Woodford shale formation.

We optimize returns through a disciplined emphasis on controlling costs and promoting operational efficiencies, and we believe we are recognized as one of the lowest cost drilling and completion operators in the Cleveland and Woodford shale formations.

Third Quarter 2015 Highlights:

·Average daily net production for the quarter was 25.3 MBoe/d;

·Reduced 2015 capital budget from $240 million to $220 million on September 9, 2015; announcing additional reduction to $210 million;

·Completed senior secured credit facility redetermination with borrowing base set at $510 million; liquidity of $420 million as of October 31, 2015; and

·Acquired nearly 10,000 net acres in the Cleveland through leasing for approximately $3 million.

Updated Capital Expenditures Outlook

In our Annual Report on Form 10-K for the year ended December 31, 2014, we provided an overview of our 2015 capital expenditures budget, which was approximately $210 million, of which $190 million was expected to be used to drill and complete wells. The updated outlook provided as of July 31, 2015 for our capital expenditures for the full year 2015 reflected total projected capital expenditures of $240 million, incorporating additional working interests and leasing. On September 9, 2015 the Company further revised the full year capital expenditures budget to $220 million.  The Company now expects capital expenditures of $210 million for the full year 2015.

27

Results of Operations

The following table summarizes our revenues, expenses and production data for the periods indicated.

(in thousands of dollars except for production, sales price	Three Months Ended September 30,									Nine Months Ended September 30,
and average cost data)	2015			2014			Change			2015			2014			Change
Revenues:
Oil	$	26,926		$	60,553		$	(33,627	)	$	93,591		$	179,004		$	(85,413	)
Natural gas	11,822			19,338			(7,516		)	36,925			64,017			(27,092		)
NGLs	7,751			19,816			(12,065		)	26,439			60,349			(33,910		)
Total oil and gas	46,499			99,707			(53,208		)	156,955			303,370			(146,415		)
Other	653			639			14			2,210			1,610			600
Total operating revenues	47,152			100,346			(53,194		)	159,165			304,980			(145,815		)
Costs and expenses:
Lease operating	8,872			11,183			(2,311		)	32,930			30,306			2,624
Production and ad valorem taxes	2,513			5,044			(2,531		)	9,292			18,248			(8,956		)
Exploration	5,556			266			5,290			6,184			3,278			2,906
Depletion, depreciation and amortization	52,766			50,491			2,275			156,151			137,490			18,661
Accretion of ARO liability	210			206			4			610			573			37
General and administrative	9,628			6,925			2,703			27,572			18,723			8,849
Other operating	—			—			—			4,188			—			4,188
Total costs and expenses	79,545			74,115			5,430			236,927			208,618			28,309
Operating income (loss)	(32,393		)	26,231			(58,624		)	(77,762		)	96,362			(174,124		)
Other income (expenses):
Interest expense	(16,722		)	(11,849		)	(4,873		)	(47,553		)	(34,659		)	(12,894		)
Net gain (loss) on commodity derivatives	90,483			41,163			49,320			111,714			(9,785		)	121,499
Other income (expense)	(7		)	30			(37		)	(1,631		)	97			(1,728		)
Total other income (expense)	73,754			29,344			44,410			62,530			(44,347		)	106,877
Income (loss) before income tax	41,361			55,575			(14,214		)	(15,232		)	52,015			(67,247		)
Income tax provision	6,519			5,550			969			(4,590		)	5,736			(10,326		)
Net income (loss)	34,842			50,025			(15,183		)	(10,642		)	46,279			(56,921		)
Net income (loss) attributable to non-controlling interests	21,604			40,893			(19,289		)	(7,625		)	37,835			(45,460		)
Net income (loss) attributable to controlling interests	$	13,238		$	9,132		$	4,106		$	(3,017	)	$	8,444		$	(11,461	)
Net production volumes:
Oil (MBbls)	630			639			(9		)	2,030			1,869			161
Natural gas (MMcf)	6,069			5,812			257			18,172			16,371			1,801
NGLs (MBbls)	682			644			38			1,946			1,733			213
Total (MBoe)	2,324			2,252			72			7,005			6,331			674
Average net (Boe/d)	25,261			24,478			783			25,659			23,190			2,469
Average sales price, unhedged:
Oil (per Bbl), unhedged	$	42.74		$	94.76		$	(52.02	)	$	46.10		$	95.78		$	(49.68	)
Natural gas (per Mcf), unhedged	1.95			3.33			(1.38		)	2.03			3.91			(1.88		)
NGLs (per Bbl), unhedged	11.37			30.77			(19.40		)	13.59			34.82			(21.23		)
Combined (per Boe), unhedged	20.01			44.27			(24.26		)	22.41			47.92			(25.51		)
Average sales price, hedged:
Oil (per Bbl), hedged	$	78.64		$	90.80		$	(12.16	)	$	75.19		$	89.51		$	(14.32	)
Natural gas (per Mcf), hedged	3.24			3.82			(0.58		)	3.37			4.06			(0.69		)
NGLs (per Bbl), hedged	24.28			30.27			(5.99		)	26.21			32.74			(6.53		)
Combined (per Boe), hedged	36.91			44.27			(7.36		)	37.82			45.88			(8.06		)
Average costs (per Boe):
Lease operating	$	3.82		$	4.97		$	(1.15	)	$	4.70		$	4.79		$	(0.09	)
Production and ad valorem taxes	1.08			2.24			(1.16		)	1.33			2.88			(1.55		)
Depletion, depreciation and amortization	22.70			22.42			0.28			22.29			21.72			0.57
General and administrative	4.14			3.08			1.06			3.94			2.96			0.98

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, however, we may modify our definition of EBITDAX in the future. 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 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 non-recurring 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:

28

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands of dollars)	2015			2014			2015			2014
Reconciliation of EBITDAX to net income
Net income (loss)	$	34,842		$	50,025		$	(10,642	)	$	46,279
Interest expense	15,924			11,002			45,187			28,530
Exploration	5,556			266			6,184			3,278
Income taxes	6,519			5,550			(4,590		)	5,736
Amortization of deferred financing costs	798			847			2,366			2,368
Depreciation and depletion	52,766			50,491			156,151			137,490
Accretion of ARO liability	210			206			610			573
Other non-cash charges	418			201			1,178			241
Stock compensation expense	2,039			1,321			5,287			2,707
Other non-cash compensation expense	108			127			326			380
Net (gain) loss on commodity derivatives	(90,483		)	(41,163		)	(111,714		)	9,785
Current period settlements of matured derivative contracts	39,273			285			107,992			(12,610		)
Amortization of deferred revenue	(493		)	(336		)	(1,521		)	(862		)
(Gain) loss on sales of assets	(16		)	(30		)	(10		)	(97		)
Stand-by rig costs	—			—			4,188			—
Financing expenses and other loan fees	22			—			2,323			3,761
EBITDAX	$	67,483		$	78,792		$	203,315		$	227,559

Adjusted Net Income is a supplemental non GAAP financial measure that is 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 items, including gains or losses on commodity derivative instruments not yet settled, impairment of oil and gas properties, and non-cash compensation expense, and certain unusual or non-recurring items. We believe adjusted net income is useful to investors because it provides readers with a more meaningful measure of our profitability before recording certain items for which the timing or amount cannot be reasonably determined. However, this measure is 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 may not be comparable to other similarly titled measures of other companies. The following tables provide a reconciliation of net income (loss) as determined in accordance with GAAP to adjusted net income for the periods indicated:

	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands of dollars, except per share data)	2015			2014			2015			2014
Net income (loss)	$	34,842		$	50,025		$	(10,642	)	$	46,279
Net (gain) loss on commodity derivatives	(90,483		)	(41,163		)	(111,714		)	9,785
Current period settlements of matured derivative contracts	39,273			285			107,992			(12,610		)
Exploration	5,556			266			6,184			3,278
Non-cash stock compensation expense	2,039			1,321			5,287			2,707
Other non-cash compensation expense	108			127			326			380
Stand-by rig costs	—			—			4,188			—
Financing expenses	—			—			2,250			3,761
Tax impact(1)	7,039			3,440			(2,233		)	(744		)
Adjusted net income (loss)	(1,626		)	14,301			1,638			52,836
Adjusted net income (loss) attributable to non-controlling interests	(828		)	11,668			1,566			43,218
Adjusted net income (loss) attributable to controlling interests	$	(798	)	$	2,633		$	72		$	9,618

29

	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
Earnings (loss) per share (basic and diluted)	$	0.44		$	0.73		$	(0.12	)	$	0.68
Net (gain) loss on commodity derivatives	(1.47		)	(0.83		)	(1.89		)	0.20
Current period settlements of matured derivative contracts	0.64			—			1.79			(0.26		)
Exploration	0.09			0.01			0.11			0.06
Non-cash stock compensation expense	0.03			0.03			0.09			0.06
Other non-cash compensation expense	—			—			0.01			0.01
Stand-by rig costs	—			—			0.06			—
Financing expenses	—			—			0.03			0.08
Tax impact(1)	0.24			0.27			(0.08		)	(0.06		)
Adjusted earnings (loss) per share (basic and diluted)	$	(0.03	)	$	0.21		$	(0.00	)	$	0.77
Effective tax rate on net income (loss) attributable to controlling interests	39.7		%	36.4		%	39.7		%	36.4		%

(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.

Results of Operations - Three months ended September 30, 2015 as compared to three months ended September 30, 2014

Operating revenues

Oil and gas sales. Oil and gas sales decreased $53.2 million, or 53.4%, to $46.5 million for the three months ended September 30, 2015, as compared to $99.7 million for the three months ended September 30, 2014. The decrease is attributable to decreases in average prices for all products, partially offset by increases in production. The average realized oil price, excluding the effects of commodity derivative instruments, decreased from $94.76 per Bbl for the three months ended September 30, 2014 to $42.74 per Bbl for the three months ended September 30, 2015, or 54.9%. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $3.33 per Mcf for the three months ended September 30, 2014 to $1.95 per Mcf for the three months ended September 30, 2015, or 41.4%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, decreased from $30.77 per Bbl for the three months ended September 30, 2014 to $11.37 per Bbl for the three months ended September 30, 2015, or 63.0%. Partially offsetting the decrease in prices, average daily production increased 3.2% to 25,261 Boe per day for the three months ended September 30, 2015 as compared to 24,478 Boe per day for the three months ended September 30, 2014. The increase in production was driven by the year-over-year increase in producing wells due to continued drilling activity as well as changes in completion techniques.

Costs and expenses

Lease operating. Lease operating expenses decreased $2.3 million, or 20.5%, to $8.9 million for the three months ended September 30, 2015, as compared to $11.2 million for the three months ended September 30, 2014. The decrease in lease operating expenses is principally attributable to an operational focus on reducing post-completion costs, such as limiting the length of time rental equipment and flow-back hands are on-site, and by reducing recurring operating expenses, such as optimizing the usage of compressors and chemicals. On a per unit basis, lease operating expenses decreased $1.15 per Boe, or 23.1%, from $4.97 per Boe in the three months ended September 30, 2014 to $3.82 per Boe in the three months ended September 30, 2015.

Production and ad valorem taxes. Production and ad valorem taxes decreased by $2.5 million, or 50.0%, to $2.5 million for the three months ended September 30, 2015, as compared to $5.0 million for the three months ended September 30, 2014. Overall, production and ad valorem taxes decreased in conjunction with the decrease in oil and gas revenues. Estimated ad valorem taxes accounted for $1.0 million of the decrease from $1.7 million for the three months ended September 30, 2014 to $0.7 million for the three months ended September 30, 2015, reflecting lower property assessments due to lower commodity prices. The average effective rate excluding the impact of ad valorem taxes increased from 3.3% for the three months ended September 30, 2014 to 4.0% for the three months ended September 30, 2015. 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.

30

Exploration.  Exploration expense increased $5.3 million from $0.3 million for the three months ended September 30, 2014 to $5.6 million for the three months ended September 30, 2015. The Company recognized charges for lease abandonment of $5.3 million relating to certain leases that the Company decided during the third quarter of 2015 not to develop.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $2.3 million, or 4.6%, to $52.8 million for the three months ended September 30, 2015, as compared to $50.5 million for the three months ended September 30, 2014. The increase was primarily the result of continued drilling activity. On a per unit basis, depletion expense increased $0.28 per Boe or 1.2% from $22.42 per Boe for the three months ended September 30, 2014 as compared to $22.70 per Boe for the three months September 30, 2015.

General and administrative. General and administrative expenses increased by $2.7 million, or 39.1%, to $9.6 million for the three months ended September 30, 2015, as compared to $6.9 million for the three months ended September 30, 2014. Salary and compensation accounted for $1.8 million of the increase, attributable to increases in headcount and to accrued compensation expense associated with our incentive programs. The remainder of the increase was primarily attributable to increases in professional fees including higher accounting, legal and other fees associated with the Company’s financing activities and status as a new public entity. Excluding non-cash compensation expense, general and administrative expense increased $0.79, on a per unit basis, from $2.43 per Boe for the three months ended September 30, 2014 to $3.22 for the three months ended September 30, 2015.

Interest expense. Interest expense increased by $4.9 million, or 41.5%, to $16.7 million for the three months ended September 30, 2015, as compared to $11.8 million for the three months ended September 30, 2014. The increase is driven by the issuance of the 2023 Notes on February 23, 2015.

Net gain (loss) on commodity derivatives. The gain (loss) on commodity derivatives was a net gain of $90.5 million for the three months ended September 30, 2015. The gain was driven by lower average crude oil, natural gas, and NGL prices ($46.49 per barrel, $2.76 per Mcf, and $17.37 per barrel, respectively) for the three months ended September 30, 2015, as compared to the crude oil, natural gas, and NGL prices as of June 30, 2015 ($59.48 per barrel, $2.80 per Mcf, and $17.72 per barrel, respectively).

Income taxes. The provision for federal and state income taxes for the three months ended September 30, 2015 was an expense of $6.5 million as compared to an expense of $5.6 million for the three months ended September 30, 2014. 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.

Results of Operations - Nine months ended September 30, 2015 as compared to nine months ended September 30, 2014

Operating revenues

Oil and gas sales. Oil and gas sales decreased $146.4 million, or 48.3%, to $157.0 million for the nine months ended September 30, 2015, as compared to $303.4 million for the nine months ended September 30, 2014. The decrease is attributable to decreases in average prices for all products, partially offset by increases in production. The average realized oil price, excluding the effects of commodity derivative instruments, decreased from $95.78 per Bbl for the nine months ended September 30, 2014 to $46.10 per Bbl for the nine months ended September 30, 2015, or 51.9%. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $3.91 per Mcf for the nine months ended September 30, 2014 to $2.03 per Mcf for the nine months ended September 30, 2015, or 48.1%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, decreased from $34.82 per Bbl for the nine months ended September 30, 2014 to $13.59 per Bbl for the nine months ended September 30, 2015, or 61.0%. Partially offsetting the decrease in prices, average daily production increased 10.6% to 25,659 Boe per day for the nine months ended September 30, 2015 as compared to 23,190 Boe per day for the nine months ended September 30, 2014. The increase in production was driven by the year-over-year increase in producing wells due to continued drilling activity as well as changes in completion techniques.

Costs and expenses

Lease operating. Lease operating expenses increased $2.6 million, or 8.6%, to $32.9 million for the nine months ended September 30, 2015, as compared to $30.3 million for the nine months ended September 30, 2014. The increase in lease operating expenses is primarily attributable to the increase in production volumes and number of producing wells. On a per unit basis, lease operating expenses decreased $0.09 per Boe, or 1.9%, from $4.79 per Boe in the nine months ended September 30, 2014 to $4.70 per Boe in the nine months ended September 30, 2015.

Production and ad valorem taxes. Production and ad valorem taxes decreased by $8.9 million, or 48.9%, to $9.3 million for the nine months ended September 30, 2015, as compared to $18.2 million for the nine months ended September 30, 2014. Overall, production

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and ad valorem taxes decreased in conjunction with the decrease in oil and gas revenues. Estimated ad valorem taxes accounted for $0.8 million of the decrease from $3.3 million for the nine months ended September 30, 2014 to $2.5 million for the nine months ended September 30, 2015, reflecting lower property assessments due to lower commodity prices. The average effective rate excluding the impact of ad valorem taxes decreased from 4.9% for the nine months ended September 30, 2014 to 4.3% for the nine months ended September 30, 2015. 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.

Exploration. Exploration expense increased $2.9 million from $3.3 million for the nine months ended September 30, 2014 to $6.2 million for the nine months ended September 30, 2015. In 2015, the Company recognized charges for lease abandonment of $5.3 million relating to certain leases that the Company does not plan to develop. In 2014, the Company recognized the drilling cost of $3.0 million associated with an unsuccessful exploratory well.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $18.7 million, or 13.6%, to $156.2 million for the nine months ended September 30, 2015, as compared to $137.5 million for the nine months ended September 30, 2014. The increase was primarily the result of continued drilling activity. On a per unit basis, depletion expense increased $0.57 per Boe or 2.6% from $21.72 per Boe for the nine months ended September 30, 2014 as compared to $22.29 per Boe for the nine months ended September 30, 2015.

General and administrative. General and administrative expenses increased by $8.9 million, or 47.6%, to $27.6 million for the nine months ended September 30, 2015, as compared to $18.7 million for the nine months ended September 30, 2014. Salary and compensation accounted for $5.8 million of the increase, attributable to increases in headcount and to accrued compensation expense associated with our incentive programs. The remainder of the increase was primarily attributable to increases in professional fees including higher accounting, legal and other fees associated with the Company’s financing activities and status as a new public entity. Excluding non-cash compensation expense, general and administrative expense increased $0.66, on a per unit basis, from $2.47 per Boe for the nine months ended September 30, 2014 to $3.13 for the nine months ended September 30, 2015.

Other operating expense. Other operating expense of $4.2 million for the nine months ended September 30, 2015 represents stand-by rig costs associated with the charges assessed on early termination of drilling rig contracts. This is a non-recurring charge for which all costs have been recognized as of September 30, 2015.

Interest expense. Interest expense increased by $12.9 million, or 37.2%, to $47.6 million for the nine months ended September 30, 2015 as compared to $34.7 million for the nine months ended September 30, 2014. The increase is driven by the issuance of the 2022 Notes and 2023 Notes on April 1, 2014 and February 23, 2015, respectively.

Net gain (loss) on commodity derivatives. The gain (loss) on commodity derivatives was a net gain of $111.7 million for the nine months ended September 30, 2015. The gain was driven by lower average crude oil and natural gas prices ($51.01 per barrel and $2.80 per Mcf, respectively) for the nine months ended September 30, 2015, as compared to the crude oil and natural gas prices as of December 31, 2014 ($53.45 per barrel and $3.14 per Mcf, respectively).

Other income/ (expense). Other income/(expense) for the nine months ended September 30, 2015 was a net expense of $1.6 million. 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, 2015 was a benefit of $4.6 million as compared to an expense of $5.7 million for the nine months ended September 30, 2014. 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.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been private and public equity sales and debt offerings, 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 future 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 senior secured revolving credit facility, 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, 2015 reflects a positive working capital balance largely due to

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the net asset value of our commodity derivatives and the reduction in accounts payable. 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. Our borrowing base at September 30, 2015 was $562.5 million, of which $100.0 million was utilized and $462.5 million was available. Effective October 8, 2015, the borrowing base under the Revolver was reduced to $510 million by our lenders as a result of the semi-annual borrowing base re-determination.

On February 23, 2015, the Company sold $250.0 million in aggregate principal amount of 9.25% senior unsecured notes due 2023 (or the “2023 Notes”) in a private placement to affiliates of GSO Capital Partners LP and Magnetar Capital LLC. The Company used the 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 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. The foregoing description of the 2023 Notes does not purport to be complete and is qualified in its entirety by reference to the full text of the Indenture pursuant to which the 2023 Notes were issued and the Registration Rights Agreement related thereto, which were filed with the Quarterly Report on Form 10-Q for the period ended June 30, 2015  as Exhibits 4.1 and 4.2, respectively, and are incorporated herein by reference.

On February 17, 2015, we completed the issuance and sale of 7,500,000 shares of Class A common stock to the public at a price of $10.25 per share under our registration statement on Form S-3, which we refer to as the Public Equity Offering. On February 23, 2015, we completed the sale of an aggregate of $50.0 million of Class A common stock to certain affiliates of GSO Capital Partners LP and Magnetar Capital LLC in a direct placement of registered shares under our registration statement on Form S-3, which we refer to as the Private Equity Offering.

The sum of these capital transactions enabled the Company to substantially improve its near-term liquidity. The combination of cash on hand and availability under the Revolver was approximately $485 million at September 30, 2015.

Our capital budget is primarily focused on the development of the Cleveland formation through exploitation and development. The amount of capital we expend may fluctuate materially based on market conditions, the economic returns being realized and the success of our drilling results.

The amount, timing and allocation of capital expenditures are largely discretionary and within management’s control. If oil and gas prices decline below our acceptable levels or costs increase 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 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 consistently monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, 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, 2015 and 2014:

	Nine Months Ended September 30,
(in thousands of dollars)	2015			2014
Net cash provided by operating activities	$	89,189		$	251,832
Net cash used in investing activities	(177,796		)	(343,073		)
Net cash provided by financing activities	97,739			100,211
Net increase in cash	$	9,132		$	8,970

Cash flow provided by operating activities

Net cash provided by operating activities was $89.2 million during the nine months ended September 30, 2015 as compared to net cash provided by operating activities of $251.8 million during the nine months ended September 30, 2014. The decrease in operating cash flows was primarily due to the $146.4 million decrease in oil and gas revenues for the nine months ended September 30, 2015 as compared to the nine months ended September 30, 2014, driven by declines in prices for all products.

Cash flow used in investing activities

Net cash used in investing activities was $177.8 million during the nine months ended September 30, 2015 as compared to net cash used in investing activities of $343.1 million during the nine months ended September 30, 2014. The decrease was primarily driven by

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a decrease in capital expenditures as a result of our decreased drilling program from eleven rigs at September 30, 2014 to three rigs running at September 30, 2015.

Cash flow provided by financing activities

Net cash provided by financing activities was $97.7 million during the nine months ended September 30, 2015 as compared to net cash provided by financing activities of $100.2 million during the nine months ended September 30, 2014. The increase in cash flows provided by financing activities was primarily due to net equity offerings of $122.8 million and borrowings of $236.5 million under the 2023 Notes, offset by repayments net of advances of $260 million on the Revolver during the nine months ended September 30, 2015.

Contractual Obligations

Other than the stand-by rig costs related to the termination of certain drilling contracts, there have been no material changes in our contractual obligations as reported in our Annual Report on Form 10-K for the year ended December 31, 2014.

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.

Item 3. Quantitative and Qualitative Disclosures 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, 2014, 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 over the latter half of 2014 and during 2015.  In applying the prescribed impairment test under the successful efforts method at September 30, 2015, no impairment charge was indicated.  The undiscounted cash flows of our proved properties are greater than the carrying cost of those properties, but the difference has narrowed significantly since 2014. Future price declines, or a period of sustained low commodity prices, could result in a significant impairment charge in future periods. Furthermore, in addition to commodity prices, our production rates, levels of proved reserves, future development and operating costs, and other factors affect our impairment analyses and may lead to an impairment charge in future periods.

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, 2014 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, 2015 (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, 2014 would have decreased by approximately 34%. 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, 2015.

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, new leasing, purchases and sales of leases, drilling

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and operating cost changes, technological advances, new geological or geophysical data or other economic factors. As all of these factors are inherently estimates and inter-dependent, the actual 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. 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.

Commodity price risk and hedges

Our principal market risk exposure is to crude 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 crude oil and regional spot prices for natural gas and NGLs. We have used, and expect to continue to use, crude 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 crude oil, natural gas and NGL derivative contracts at September 30, 2015 was a net asset of $212.3 million.

Counterparty and customer credit risk

Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we drill. We are also subject to credit risk due to concentration of our crude oil and natural gas receivables with several significant customers. The inability or failure of these significant customers to meet their obligations or their insolvency or liquidation may adversely affect our financial results. In addition, our crude oil, natural gas, and NGL derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. While we do not typically require our partners, customers and counterparties to post collateral, and we do not have a formal process in place to evaluate and assess the credit standing of our partners or customers for oil and gas receivables and the counterparties on our derivative instruments, we do evaluate the credit standing of such parties as we deem appropriate under the circumstances. This evaluation may include reviewing a party’s credit rating, latest financial information and, in the case of a customer with which we have receivables, their historical payment record, and undertaking the due diligence necessary to determine creditworthiness. The counterparties on our derivative instruments currently in place are lenders under the revolving credit facility with investment grade ratings.

Interest rate risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness. The terms of the Revolver provide for interest on borrowings at a floating rate equal to prime, LIBOR or the 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. During the three and nine months ended September 30, 2015, borrowings under the senior secured revolving credit facility bore interest at a weighted average rate of 2.31% and 2.40%, respectively.

Item 4. Controls and Procedures

Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting during the quarter ended September 30, 2015 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, 2015 because of the material weakness in internal control over financial reporting described in our Annual Report.

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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, 2014 included a report of management’s assessment regarding internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of legal proceedings, see Note 8 to the Consolidated Financial Statements 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 Factors

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, 2014, 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.

There have been no material changes in our risk factors from those described in our Annual Report. For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our Annual Report.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits

Exhibit No.	Description
31.1*	Rule 13a-14(a)/15d-14(a) Certification of Jonny Jones (Principal Executive Officer).
31.2*	Rule 13a-14(a)/15d-14(a) Certification of Robert J. Brooks (Principal Financial Officer).
32.1**	Section 1350 Certification of Jonny Jones (Principal Executive Officer).
32.2**	Section 1350 Certification of Robert J. Brooks (Principal Financial Officer).
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

* - filed herewith

** - furnished herewith

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SIGNATURES

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

	Jones Energy, Inc.
	(registrant)
Date: November 6, 2015	By:	/s/ Robert J. Brooks
		Name:	Robert J. Brooks
		Title:	Chief Financial Officer (Principal Financial Officer)

Signature Page to Form 10-Q (Q3 2015)

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