Table of Contents
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

 
FORM 10-Q
 
(Mark One)
 
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the Quarterly Period Ended September 30, 2017
 
or
 
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission file number 001-36006
 
Jones Energy, Inc.
(Exact name of registrant as specified in its charter)
 
Delaware	 	1311	 	80-0907968	
(State or other Jurisdiction of	 	(Primary Standard Industrial	 	(IRS Employer	
Incorporation or Organization)	 	Classification Code Number)	 	Identification Number)	
 
807 Las Cimas Parkway, Suite 350
Austin, Texas 78746
(512) 328-2953
 (Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)
 
Robert J. Brooks
807 Las Cimas Parkway, Suite 350
Austin, Texas 78746
(512) 328-2953
(Address, including zip code, and telephone number, including area code, of Agent for service)

 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes  ☒     No  ☐
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  ☒     No  ☐
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer ☐	 	Accelerated filer ☒	
 	 	 	
Non-accelerated filer ☐	 	Smaller reporting company ☐	
(Do not check if a smaller reporting company)	 	 	
 	 	 	
Emerging growth company ☒	
 
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☒ 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  ☐  No  ☒

 
On November 1, 2017, the Registrant had 87,043,604 shares of Class A common stock outstanding and 11,028,964 shares of Class B common stock outstanding.

 

Table of Contents

JONES ENERGY, INC.
TABLE OF CONTENTS
 
PART 1—FINANCIAL INFORMATION  	
1	
 	 	
Item 1. Financial Statements  	
1	
 	 	
Unaudited Consolidated Financial Statements  	
1	
 	 	
Balance Sheets  	
1	
 	 	
Statements of Operations  	
2	
 	 	
Statement of Changes in Stockholders’ Equity  	
3	
 	 	
Statements of Cash Flows  	
4	
 	 	
Notes to the Consolidated Financial Statements  	
5	
 	 	
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations  	
43	
 	 	
Item 3. Quantitative and Qualitative Disclosures About Market Risk  	
54	
 	 	
Item 4. Controls and Procedures  	
56	
 	 	
PART II—OTHER INFORMATION  	
56	
 	 	
Item 1. Legal Proceedings  	
56	
 	 	
Item 1A. Risk Factors  	
57	
 	 	
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds  	
58	
 	 	
Item 3. Defaults upon Senior Securities  	
58	
 	 	
Item 4. Mine Safety Disclosures  	
58	
 	 	
Item 5. Other Information  	
58	
 	 	
Item 6. Exhibits  	
58	
 	 	
SIGNATURES  	
59	

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this report that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this report specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, our expectations regarding our ability to drill the recently acquired acreage in the Merge, our potential decrease in capital spending if profitability or cash flows are lower than anticipated, our ability to mitigate commodity price risk through our hedging program, JEH’s obligations to pay cash distributions, expectations regarding litigation, our belief that we will be able to identify and prioritize projects with the greatest expected returns, our ability to amend our senior secured revolving credit facility to modify certain financial covenants, our expectations regarding our working capital balance and our ability to borrow to manage it, and our ability to successfully execute our 2017 development plan. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include, but are not limited to, changes in prices for oil, natural gas liquids, and natural gas prices, weather, including its impact on oil and natural gas demand and weather-related delays on operations, the amount, nature and timing of planned capital expenditures, availability and method of funding acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, customers’ elections to reject ethane and include it as part of the natural gas stream, ability to fund our 2017 capital expenditure budget, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company’s business and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the SEC.
 
Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

 

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PART 1—FINANCIAL INFORMATIO  N
Item 1. Financial Statement  s
Jones Energy, Inc.
Consolidated Balance Sheet  s (Unaudited)

 	 	 	 	 	 	 	 	
 	 	September 30, 	 	December 31, 	 	
(in thousands of dollars)	    	2017	    	2016	 	
Assets	 	   	 	 	   	 	 	
Current assets	 	 	 	 	 	 	 	
Cash	 	$	5,478	 	$	34,642	 	
Accounts receivable, net	 	 	 	 	 	 	 	
Oil and gas sales	 	 	29,136	 	 	26,568	 	
Joint interest owners	 	 	17,533	 	 	5,267	 	
Other	 	 	3,870	 	 	6,061	 	
Commodity derivative assets	 	 	7,590	 	 	24,100	 	
Other current assets	 	 	10,391	 	 	2,684	 	
Total current assets	 	 	73,998	 	 	99,322	 	
Oil and gas properties, net, at cost under the successful efforts method	 	 	1,578,739	 	 	1,743,588	 	
Other property, plant and equipment, net	 	 	2,565	 	 	2,996	 	
Commodity derivative assets	 	 	1,608	 	 	34,744	 	
Other assets	 	 	4,668	 	 	6,050	 	
Total assets	 	$	1,661,578	 	$	1,886,700	 	
Liabilities and Stockholders' Equity	 	 	 	 	 	 	 	
Current liabilities	 	 	 	 	 	 	 	
Trade accounts payable	 	$	67,550	 	$	36,527	 	
Oil and gas sales payable	 	 	21,510	 	 	28,339	 	
Accrued liabilities	 	 	24,472	 	 	25,707	 	
Commodity derivative liabilities	 	 	15,696	 	 	14,650	 	
Other current liabilities	 	 	3,224	 	 	2,584	 	
Total current liabilities	 	 	132,452	 	 	107,807	 	
Long-term debt	 	 	698,740	 	 	724,009	 	
Deferred revenue	 	 	5,632	 	 	7,049	 	
Commodity derivative liabilities	 	 	5,355	 	 	1,209	 	
Asset retirement obligations	 	 	19,239	 	 	19,458	 	
Liability under tax receivable agreement	 	 	55,096	 	 	43,045	 	
Other liabilities	 	 	1,010	 	 	792	 	
Deferred tax liabilities	 	 	2,732	 	 	2,905	 	
Total liabilities	 	 	920,256	 	 	906,274	 	
Commitments and contingencies (Note 15)	 	 	 	 	 	 	 	
Mezzanine equity	 	 	 	 	 	 	 	
Series A preferred stock, $0.001 par value; 1,839,995 shares issued and outstanding at September 30, 2017 and 1,840,000 shares issued and outstanding at December 31, 2016	 	 	89,413	 	 	88,975	 	
Stockholders' equity	 	 	 	 	 	 	 	
Class A common stock, $0.001 par value; 74,376,391 shares issued and 74,353,789 shares outstanding at September 30, 2017 and 57,048,076 shares issued and 57,025,474 shares outstanding at December 31, 2016	 	 	74	 	 	57	 	
Class B common stock, $0.001 par value; 23,718,779 shares issued and outstanding at September 30, 2017 and 29,832,098 shares issued and outstanding at December 31, 2016	 	 	24	 	 	30	 	
Treasury stock, at cost: 22,602 shares at September 30, 2017 and December 31, 2016	 	 	(358)	 	 	(358)	 	
Additional paid-in-capital	 	 	534,499	 	 	447,137	 	
Retained (deficit) / earnings	 	 	(181,226)	 	 	(8,652)	 	
Stockholders' equity	 	 	353,013	 	 	438,214	 	
Non-controlling interest	 	 	298,896	 	 	453,237	 	
Total stockholders’ equity	 	 	651,909	 	 	891,451	 	
Total liabilities and stockholders' equity	 	$	1,661,578	 	$	1,886,700	 	

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

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

 	 	Three months ended September 30, 	 	Nine months ended September 30, 	 	
(in thousands of dollars except per share data)	    	2017	    	2016	    	2017	    	2016	 	
Operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas sales	 	$	43,636	 	$	32,582	 	$	132,427	 	$	86,060	 	
Other revenues	 	 	566	 	 	771	 	 	1,634	 	 	2,295	 	
Total operating revenues	 	 	44,202	 	 	33,353	 	 	134,061	 	 	88,355	 	
Operating costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating	 	 	9,458	 	 	7,865	 	 	27,689	 	 	24,027	 	
Production and ad valorem taxes	 	 	2,757	 	 	1,733	 	 	4,641	 	 	5,061	 	
Exploration	 	 	1,969	 	 	998	 	 	11,638	 	 	1,237	 	
Depletion, depreciation and amortization	 	 	46,353	 	 	36,550	 	 	127,343	 	 	116,449	 	
Impairment of oil and gas properties	 	 	 —	 	 	 —	 	 	148,016	 	 	 —	 	
Accretion of ARO liability	 	 	253	 	 	323	 	 	720	 	 	913	 	
General and administrative	 	 	7,819	 	 	6,448	 	 	24,493	 	 	22,078	 	
Total operating expenses	 	 	68,609	 	 	53,917	 	 	344,540	 	 	169,765	 	
Operating income (loss)	 	 	(24,407)	 	 	(20,564)	 	 	(210,479)	 	 	(81,410)	 	
Other income (expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	 	 	(12,817)	 	 	(12,792)	 	 	(38,381)	 	 	(40,397)	 	
Gain on debt extinguishment	 	 	 —	 	 	 —	 	 	 —	 	 	99,530	 	
Net gain (loss) on commodity derivatives	 	 	(32,539)	 	 	4,014	 	 	11,308	 	 	(18,769)	 	
Other income (expense)	 	 	(13,692)	 	 	364	 	 	14,389	 	 	251	 	
Other income (expense), net	 	 	(59,048)	 	 	(8,414)	 	 	(12,684)	 	 	40,615	 	
Income (loss) before income tax	 	 	(83,455)	 	 	(28,978)	 	 	(223,163)	 	 	(40,795)	 	
Income tax provision (benefit)	 	 	(492)	 	 	(6,549)	 	 	(2,707)	 	 	(8,234)	 	
Net income (loss)	 	 	(82,963)	 	 	(22,429)	 	 	(220,456)	 	 	(32,561)	 	
Net income (loss) attributable to non-controlling interests	 	 	(18,157)	 	 	(12,576)	 	 	(72,047)	 	 	(18,374)	 	
Net income (loss) attributable to controlling interests	 	$	(64,806)	 	$	(9,853)	 	$	(148,409)	 	$	(14,187)	 	
Dividends and accretion on preferred stock	 	 	(1,966)	 	 	(765)	 	 	(5,959)	 	 	(765)	 	
Net income (loss) attributable to common shareholders	 	$	(66,772)	 	$	(10,618)	 	$	(154,368)	 	$	(14,952)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) per share (1)  :	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic - Net income (loss) attributable to common shareholders	 	$	(0.91)	 	$	(0.24)	 	$	(2.30)	 	$	(0.40)	 	
Diluted - Net income (loss) attributable to common shareholders	 	$	(0.91)	 	$	(0.24)	 	$	(2.30)	 	$	(0.40)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average Class A shares outstanding (1)  :	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	73,089	 	 	44,993	 	 	67,029	 	 	37,299	 	
Diluted	 	 	73,089	 	 	44,993	 	 	67,029	 	 	37,299	 	

	(1)		All share and earnings per share information presented has been recast to retrospectively adjust for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 12, “Stockholders’ and Mezzanine equity”, distributed on March 31, 2017.	
 
The accompanying notes are an integral part of these consolidated financial statements.

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

 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Common Stock	 	Treasury Stock	 	Additional	 	Retained	 	 	 	 	Total	 	
 	 	Class A	 	Class B	 	Class A	 	Paid-in-	 	(Deficit)/	 	Non-controlling	 	Stockholders'	 	
(amounts in thousands)	    	Shares	    	Value	    	Shares	    	Value	    	Shares	    	Value	    	Capital	    	Earnings	    	Interest	    	Equity	 	
Balance at December 31, 2016	 	
57,025	 	$	
57	 	
29,832	 	$	
30	 	
23	 	$	
(358)	 	$	
447,137	 	$	
(8,652)	 	$	
453,237	 	$	891,451	 	
Cumulative effect of adoption of ASU 2016-09	 	 —	 	 	 —	 	 —	 	 	 —	 	 —	 	 	 —	 	 	706	 	 	(706)	 	 	 —	 	 	 —	 	
Stock-compensation expense	 	759	 	 	 1	 	 —	 	 	 —	 	 —	 	 	 —	 	 	5,239	 	 	 —	 	 	 —	 	 	5,240	 	
Cash tax distribution	 	 —	 	 	 —	 	 —	 	 	 —	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(562)	 	 	(562)	 	
Sale of common stock	 	3,716	 	 	 3	 	 —	 	 	 —	 	 —	 	 	 —	 	 	8,329	 	 	 —	 	 	 —	 	 	8,332	 	
Stock dividends on common stock	 	5,000	 	 	 5	 	 —	 	 	 —	 	 —	 	 	 —	 	 	17,495	 	 	(17,500)	 	 	 —	 	 	 —	 	
Exchange of Class B shares for Class A shares	 	6,113	 	 	 6	 	(6,113)	 	 	(6)	 	 —	 	 	 —	 	 	53,441	 	 	 —	 	 	(81,732)	 	 	(28,291)	 	
Dividends and accretion on preferred stock	 	1,740	 	 	 2	 	 —	 	 	 —	 	 —	 	 	 —	 	 	2,152	 	 	(5,959)	 	 	 —	 	 	(3,805)	 	
Net income (loss)	 	 —	 	 	 —	 	 —	 	 	 —	 	 —	 	 	 —	 	 	 —	 	 	(148,409)	 	 	(72,047)	 	 	(220,456)	 	
Balance at September 30, 2017	 	74,353	 	$	74	 	23,719	 	$	24	 	23	 	$	(358)	 	$	534,499	 	$	(181,226)	 	$	298,896	 	$	651,909	 	
 
The accompanying notes are an integral part of these consolidated financial statements.

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

 	 	 	 	 	 	 	 	
 	 	Nine months ended September 30, 	 	
(in thousands of   dollars)	 	2017	 	2016	 	
Cash flows from operating activities	 	   	                     	 	   	                     	 	
Net income (loss)	 	$	(220,456)	 	$	(32,561)	 	
Adjustments to reconcile net income (loss) to net cash provided by
operating activities	 	 	 	 	 	 	 	
Depletion, depreciation, and amortization	 	 	
127,343	 	 	
116,449	 	
Exploration (dry hole and lease abandonment)	 	 	8,680	 	 	945	 	
Impairment of oil and gas properties	 	 	148,016	 	 	 —	 	
Accretion of ARO liability	 	 	720	 	 	913	 	
Amortization of debt issuance costs	 	 	2,930	 	 	3,083	 	
Stock compensation expense	 	 	5,702	 	 	5,269	 	
Deferred and other non-cash compensation expense	 	 	335	 	 	614	 	
Amortization of deferred revenue	 	 	(1,417)	 	 	(1,828)	 	
(Gain) loss on commodity derivatives	 	 	(11,308)	 	 	18,769	 	
(Gain) loss on sales of assets	 	 	131	 	 	(68)	 	
(Gain) on debt extinguishment	 	 	 —	 	 	(99,530)	 	
Deferred income tax provision	 	 	80	 	 	(11,824)	 	
Change in liability under tax receivable agreement	 	 	(15,831)	 	 	(422)	 	
Other - net	 	 	1,892	 	 	1,227	 	
Changes in operating assets and liabilities	 	 	 	 	 	 	 	
Accounts receivable	 	 	(15,070)	 	 	8,964	 	
Other assets	 	 	(8,238)	 	 	(466)	 	
Accrued interest expense	 	 	2,028	 	 	(1,050)	 	
Accounts payable and accrued liabilities	 	 	15,888	 	 	6,425	 	
Net cash provided by operations	 	 	
41,425	 	 	
14,909	 	
Cash flows from investing activities	 	 	 	 	 	 	 	
Additions to oil and gas properties	 	 	(179,152)	 	 	(212,419)	 	
Net adjustments to purchase price of properties acquired	 	 	2,391	 	 	 —	 	
Proceeds from sales of assets	 	 	60,422	 	 	1,615	 	
Acquisition of other property, plant and equipment	 	 	(603)	 	 	(194)	 	
Current period settlements of matured derivative contracts	 	 	69,412	 	 	106,151	 	
Net cash (used in) investing	 	 	(47,530)	 	 	(104,847)	 	
Cash flows from financing activities	 	 	 	 	 	 	 	
Proceeds from issuance of long-term debt	 	 	102,000	 	 	75,000	 	
Repayment of long-term debt	 	 	(129,000)	 	 	(42,000)	 	
Purchase of senior notes	 	 	 —	 	 	(84,589)	 	
Payment of cash dividends on preferred stock	 	 	(3,367)	 	 	 —	 	
Net distributions paid to JEH unitholders	 	 	(562)	 	 	(10,109)	 	
Net payments for share based compensation	 	 	(462)	 	 	 —	 	
Proceeds from sale of common stock	 	 	8,332	 	 	65,548	 	
Proceeds from sale of preferred stock	 	 	 —	 	 	88,236	 	
Net cash (used in) / provided by financing	 	 	(23,059)	 	 	92,086	 	
Net increase (decrease) in cash	 	 	
(29,164)	 	 	
2,148	 	
Cash	 	 	 	 	 	 	 	
Beginning of period	 	 	34,642	 	 	21,893	 	
End of period	 	$	5,478	 	$	24,041	 	
Supplemental disclosure of cash flow information	 	 	 	 	 	 	 	
Cash paid for interest	 	$	33,736	 	$	38,380	 	
Change in accrued additions to oil and gas properties	 	 	7,982	 	 	9,031	 	
Asset retirement obligations incurred, including changes in estimate	 	 	437	 	 	6,785	 	
 
The accompanying notes are an integral part of these consolidated financial statements.

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Jones Energy, Inc.
Notes to the Consolidated Financial Statement  s (Unaudited)
 
1.        Organization and Description of Business
 
Organization
 
Jones Energy, Inc. (the “Company”) was formed in March 2013 as a Delaware corporation to become a publicly-traded entity and the holding company of Jones Energy Holdings, LLC (“JEH”). As the sole managing member of JEH, the Company is responsible for all operational, management and administrative decisions relating to JEH’s business and consolidates the financial results of JEH and its subsidiaries.
 
JEH was formed as a Delaware limited liability company on December 16, 2009 through investments made by the Jones family, certain members of management and through private equity funds managed by Metalmark Capital, among others. JEH acts as a holding company of operating subsidiaries that own and operate assets that are used in the exploration, development, production and acquisition of oil and natural gas properties.
 
The Company’s certificate of incorporation authorizes two classes of common stock, Class A common stock and Class B common stock. The Class B common stock is held by the remaining owners of JEH prior to the initial public offering (“IPO”) of the Company (collectively, the “Class B shareholders”) and can be exchanged (together with a corresponding number of common units representing membership interests in JEH (“JEH Units”)) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. The Class B common stock has no economic rights but entitles its holders to one vote on all matters to be voted on by the Company’s stockholders generally. As of September 30, 2017, the Company held 74,353,789 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 23,718,779 JEH Units are held by the Class B shareholders. The Class B shareholders have no voting rights with respect to their economic interest in JEH, resulting in the Company reporting this ownership interest as a non-controlling interest.
 
The Company’s certificate of incorporation also authorizes the Board of Directors of the Company to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by the Board of Directors of the Company and may differ from those of any and all other series at any time outstanding.
 
On August 25, 2016, the Company issued 1,840,000 shares of its 8.0% Series A Perpetual Convertible Preferred Stock, par value $0.001 per share (the “Series A preferred stock”), pursuant to a registered public offering at $50 per share. See Note 12, “Stockholders’ and Mezzanine equity”.
 
Description of Business
 
The Company is engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States, spanning areas of Texas and Oklahoma. The Company’s assets are located within the Eastern Anadarko basin, targeting the liquids rich Woodford shale and Meramec formations in the Merge area of the STACK/SCOOP, and the Western Anadarko basin, targeting the liquids rich Cleveland, Granite Wash, Tonkawa and Marmaton formations, and are owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas.

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

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

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adoption date. Adoption did not have a material impact on the financial position, cash flows or results of operations.
 
To be adopted in a future period:
 
In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which creates a new topic in the Accounting Standards Codification (“ASC”), topic 606, “Revenue from Contracts with Customers.” This standard sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09 by one year. The amendments are now effective for interim and annual reporting periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis. Early adoption is permitted.
 
The Company is in the process of comparing our current revenue recognition policies to the new requirements for each of our revenue categories based upon review of our current contracts by product category and homogenous groupings. To date, our analysis of these homogenous groupings does not indicate any significant change to our current revenue recognition methodology, although we do expect some changes in presentation of gross revenues and expenses upon adoption of the standard; such costs are currently offset against revenues. Our evaluation is not yet complete, and we have not fully concluded on the overall impacts of adopting the new requirements. In addition to changes in the presentation of the Company’s Consolidated Statement of Operations, we expect to expand disclosures related to revenue recognition. The Company will continue to further evaluate the effect that the adoption of Update 2014-09 and Update 2015-14 will have on our financial statements and disclosures. We anticipate adoption of Update 2014-09 and Update 2015-14 effective as of January 1, 2018 applied on a modified retrospective basis.
 
In February 2016, the FASB issued ASU 2016-02, “Leases” (Topic 842). This amendment requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases. We anticipate adoption of ASU 2016-02 effective as of January 1, 2019.
 
In August 2017, the FASB issued ASU 2017-12, “Derivatives and Hedging” (Topic 815). The amendments in this update apply to any entity that elects to apply hedge accounting in accordance with current GAAP. This standard expands an entity’s ability to apply hedge accounting for nonfinancial and financial risk components and allows for a simplified approach for fair value hedging of interest rate risk. The standard also eliminates the need to separately measure and report hedge ineffectiveness and generally requires the entire change in fair value of a hedging instrument to be presented in the same income statement line as the hedged item. Additionally, the standard simplifies the hedge documentation and effectiveness assessment requirements under the previous guidance. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the impacts of the amendment to our financial statements and accounting practices for hedging, as well as our anticipated adoption date which would occur either on or before January 1, 2019.

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3.        Revision of Previously Issued Financial Statements
 
During the preparation of the closing of our Arkoma divestiture (as defined in Note 4) in the third quarter 2017, it was determined that the carrying value of the Arkoma Assets (as defined in Note 4) were overstated resulting in a $13.9 million overstatement of the Impairment of oil and gas properties upon the change in classification of the Held for sale assets (as defined in Note 4) at June 30, 2017. This error also resulted in a $2.3 million understatement of the Liability under the tax receivable agreement.  These errors resulted in the misstatement of our previously issued financial statements relating to the period ended June 30, 2017.
 
The following table presents the effect of the errors on our Consolidated Balance Sheet:

 	 	June 30, 2017	 	 	 	 	
(in thousands of dollars)	    	As corrected	 	As filed	 	Change	 	
Assets	 	   	 	 	   	 	 	   	 	 	
Current assets	 	 	 	 	 	 	 	 	 	 	
Other current assets	 	$	11,198	 	$	11,381	 	$	(183)	 	
Total current assets	 	 	101,524	 	 	101,707	 	 	(183)	 	
Oil and gas properties, net, at cost under the successful efforts method	 	 	1,559,861	 	 	1,545,991	 	 	13,870	 	
Total assets	 	$	1,739,706	 	$	1,726,019	 	$	13,687	 	
Liabilities and Stockholders' Equity	 	 	 	 	 	 	 	 	 	 	
Liability under tax receivable agreement	 	$	14,140	 	$	11,807	 	$	2,333	 	
Total liabilities	 	 	889,081	 	 	886,748	 	 	2,333	 	
Stockholders' equity	 	 	 	 	 	 	 	 	 	 	
Retained (deficit) / earnings	 	 	(114,454)	 	 	(121,477)	 	 	7,023	 	
Stockholders' equity	 	 	362,675	 	 	355,652	 	 	7,023	 	
Non-controlling interest	 	 	398,662	 	 	394,331	 	 	4,331	 	
Total stockholders’ equity	 	 	761,337	 	 	749,983	 	 	11,354	 	
Total liabilities and stockholders' equity	 	$	1,739,706	 	$	1,726,019	 	$	13,687	 	

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The following tables separately present the effect of the errors on our Consolidated Statement of Operations for the three and six-month periods:

 	 	Three months ended June 30, 2017	 	 	 	 	
(in thousands of dollars except per share data)	    	As corrected	    	As filed	    	Change	    	
Operating costs and expenses	 	 	 	 	 	 	 	 	 	 	
Impairment of oil and gas properties	 	$	148,016	 	$	161,886	 	$	(13,870)	 	
Total operating expenses	 	 	221,191	 	 	235,061	 	 	(13,870)	 	
Operating income (loss)	 	 	(172,565)	 	 	(186,435)	 	 	13,870	 	
Other income (expense)	 	 	 	 	 	 	 	 	 	 	
Other income (expense)	 	 	27,501	 	 	29,834	 	 	(2,333)	 	
Other income (expense), net	 	 	36,351	 	 	38,684	 	 	(2,333)	 	
Income (loss) before income tax	 	 	(136,214)	 	 	(147,751)	 	 	11,537	 	
Income tax provision (benefit)	 	 	(2,236)	 	 	(2,419)	 	 	183	 	
Net income (loss)	 	 	(133,978)	 	 	(145,332)	 	 	11,354	 	
Net income (loss) attributable to non-controlling interests	 	 	(51,762)	 	 	(56,093)	 	 	4,331	 	
Net income (loss) attributable to controlling interests	 	$	(82,216)	 	$	(89,239)	 	$	7,023	 	
Net income (loss) attributable to common shareholders	 	$	(84,182)	 	$	(91,205)	 	$	7,023	 	
 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) per share (1)  :	 	 	 	 	 	 	 	 	 	 	
Basic - Net income (loss) attributable to common shareholders	 	$	(1.28)	 	$	(1.39)	 	$	0.11	 	
Diluted - Net income (loss) attributable to common shareholders	 	$	(1.28)	 	$	(1.39)	 	$	0.11	 	
 	 	 	 	 	 	 	 	 	 	 	
Weighted average Class A shares outstanding (1)  :	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	65,681	 	 	65,681	 	 	 —	 	
Diluted	 	 	65,681	 	 	65,681	 	 	 —	 	

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 	 	Six months ended June 30, 2017	 	 	 	 	
(in thousands of dollars except per share data)	    	As corrected	    	As filed	    	Change	 	
Operating costs and expenses	 	 	 	 	 	 	 	 	 	 	
Impairment of oil and gas properties	 	$	148,016	 	$	161,886	 	$	(13,870)	 	
Total operating expenses	 	 	275,931	 	 	289,801	 	 	(13,870)	 	
Operating income (loss)	 	 	(186,072)	 	 	(199,942)	 	 	13,870	 	
Other income (expense)	 	 	 	 	 	 	 	 	 	 	
Other income (expense)	 	 	28,081	 	 	30,414	 	 	(2,333)	 	
Other income (expense), net	 	 	46,364	 	 	48,697	 	 	(2,333)	 	
Income (loss) before income tax	 	 	(139,708)	 	 	(151,245)	 	 	11,537	 	
Income tax provision (benefit)	 	 	(2,215)	 	 	(2,398)	 	 	183	 	
Net income (loss)	 	 	(137,493)	 	 	(148,847)	 	 	11,354	 	
Net income (loss) attributable to non-controlling interests	 	 	(53,890)	 	 	(58,221)	 	 	4,331	 	
Net income (loss) attributable to controlling interests	 	$	(83,603)	 	$	(90,626)	 	$	7,023	 	
Net income (loss) attributable to common shareholders	 	$	(87,596)	 	$	(94,619)	 	$	7,023	 	
 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) per share (1)  :	 	 	 	 	 	 	 	 	 	 	
Basic - Net income (loss) attributable to common shareholders	 	$	(1.37)	 	$	(1.48)	 	$	0.11	 	
Diluted - Net income (loss) attributable to common shareholders	 	$	(1.37)	 	$	(1.48)	 	$	0.11	 	
 	 	 	 	 	 	 	 	 	 	 	
Weighted average Class A shares outstanding (1)  :	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	63,948	 	 	63,948	 	 	 —	 	
Diluted	 	 	63,948	 	 	63,948	 	 	 —	 	
________________________________________
(1) All share and earnings per share information presented has been recast to retrospectively adjust for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 12, “Stockholders’ and Mezzanine equity”, distributed on March 31, 2017.
 
The following table presents the effect of the errors on our Statement of Changes in Stockholders’ Equity:

 	 	Six months ended June 30, 2017	 	
 	 	Retained	 	 	 	 	Total	 	
 	 	(Deficit)/	 	Non-controlling	 	Stockholders'	 	
(amounts in thousands)	    	Earnings	    	Interest	    	Equity	 	
As corrected - Net income (loss)	 	$	(83,603)	 	$	(53,890)	 	$	(137,493)	 	
As filed - Net income (loss)	 	$	(90,626)	 	$	(58,221)	 	 	(148,847)	 	
Change - Net income (loss)	 	$	7,023	 	$	4,331	 	$	11,354	 	
 	 	 	 	 	 	 	 	 	 	 	
As corrected - Balance at June 30, 2017	 	$	(114,454)	 	$	398,662	 	$	761,337	 	
As filed - Balance at June 30, 2017	 	$	(121,477)	 	$	394,331	 	$	749,983	 	
Change - Balance at June 30, 2017	 	$	7,023	 	$	4,331	 	$	11,354	 	

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The following table presents the effect of the errors on our Consolidated Statements of Cash Flows:

 	 	Six months ended  June 30, 2017	 	 	 	 	
(in thousands of   dollars)	 	As corrected	 	As filed	 	Change	 	
Cash flows from operating activities	 	   	                     	 	   	                     	 	   	 	 	
Net income (loss)	 	$	(137,493)	 	$	(148,847)	 	$	11,354	 	
Adjustments to reconcile net income (loss) to net cash provided by operating activities	 	 	 	 	 	 	 	 	 	 	
Impairment of oil and gas properties	 	 	148,016	 	 	161,886	 	 	(13,870)	 	
Change in liability under tax receivable agreement	 	 	(28,266)	 	 	(30,599)	 	 	2,333	 	
Changes in operating assets and liabilities	 	 	 	 	 	 	 	 	 	 	
Other assets	 	 	(12,407)	 	 	(12,590)	 	 	183	 	
Net cash provided by operations	 	 	
21,478	 	 	
21,478	 	 	 —	 	
Net increase (decrease) in cash	 	 	
(28,388)	 	 	
(28,388)	 	 	 —	 	
Cash	 	 	 	 	 	 	 	 	 	 	
Beginning of period	 	 	34,642	 	 	34,642	 	 	 —	 	
End of period	 	$	6,254	 	$	6,254	 	$	 —	 	
 
We assessed the materiality of the errors on prior periods’ financial statements in accordance with SEC Staff Accounting Bulletin (“SAB”) Topic 1.M, Materiality, codified in ASC Topic 250, Presentation of Financial Statements, (“ASC 250”) and concluded that the errors were not material to any prior periods. The Company will revise our Consolidated Statement of Operations for the three and six-month periods ended June 30, 2017 and our Consolidated Statements of Cash Flows for the six months ended June 30, 2017 in future filings to correct the errors.
 
4.        Acquisitions and Divestitures
 
During the nine months ended September 30, 2017 and the year ended December 31, 2016, the Company entered into several purchase and sale agreements, as described below.
 
Merge Acquisition
 
On September 22, 2016, JEH acquired oil and gas properties located in the Merge area of the STACK/SCOOP (the “Merge”) play in Central Oklahoma (the “Merge Acquisition”) from SCOOP Energy Company, LLC for cash consideration of $134.4 million, net of the final working capital settlement of $2.4 million received in the first quarter of 2017. The oil and gas properties acquired in the Merge Acquisition, on a closed and funded basis, principally consist of 16,975 undeveloped net acres in Canadian, Grady and McClain Counties, Oklahoma. This transaction has been accounted for as an asset acquisition. The Company used proceeds from our equity offerings to fund the purchase. See Note 12, “Stockholders’ and Mezzanine equity”.
 
Anadarko Acquisition
 
On August 25, 2016, JEH acquired producing and undeveloped oil and gas assets in the Western Anadarko basin (the “Anadarko Acquisition”) for final consideration of $25.9 million. This transaction was accounted for as a business combination. The Company allocated $32.3 million to “Oil and gas properties,” with $3.0 million allocated to “Unproved” properties, $17.0 million allocated to “Proved” properties, and $12.3 million allocated to “Wells and equipment and related facilities”, based on the respective fair values of the assets acquired. Additionally, the Company allocated $6.4 million to our ARO liability associated with those proved properties. As of September 30, 2017, the measurement-period has closed. The Anadarko Acquisition did not result in a significant impact to revenues or net income and as such, pro forma financial information is not included. The Company funded the Anadarko Acquisition with cash on hand.
 
The assets acquired in the Anadarko Acquisition included interests in 174 wells, 59% of which were operated by the company, and approximately 25,000 net acres in Lipscomb and Ochiltree Counties in the Texas Panhandle. As of the closing date, the acquired acreage was producing approximately 900 barrels of oil equivalent per day.

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Arkoma Divestiture
 
On August 1, 2017, JEH closed its previously announced agreement to sell its Arkoma Basin properties (the “Arkoma Assets”) for a purchase price of $65.0 million, prior to customary effective date adjustments of $7.3 million, and subject to customary post-close adjustments (the “Arkoma Divestiture”). JEH may also receive up to $2.5 million in contingent payments based on natural gas prices. No amounts have been recorded related to this contingent payment as of September 30, 2017.
 
As of June 30, 2017, the Arkoma Assets and related liabilities (the “Held for sale assets”) were classified as held for sale due to the pending Arkoma Divestiture. Upon the classification change occurring on June 30, 2017, the Company ceased recording depletion on the Held for sale assets. Based on the Company’s sales price, the Company recognized an estimated impairment charge of $148.0 million at June 30, 2017 which has been included in Impairment of oil and gas properties on the Company’s Consolidated Statement of Operations.

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

 	 	September 30, 	 	December 31, 	 	
(in thousands of dollars)	    	2017	    	2016	 	
Mineral interests in properties	 	   	 	 	   	 	 	
Unproved	 	$	190,722	 	$	213,153	 	
Proved	 	 	882,386	 	 	1,054,683	 	
Wells and equipment and related facilities	 	 	1,375,932	 	 	1,395,291	 	
 	 	 	2,449,040	 	 	2,663,127	 	
Less: Accumulated depletion and impairment	 	 	(870,301)	 	 	(919,539)	 	
Net oil and gas properties	 	$	1,578,739	 	$	1,743,588	 	
 
There were no exploratory wells drilled during the nine months ended September 30, 2017 or 2016. As such, no associated costs were capitalized and no exploratory wells resulted in exploration expense during either period.
 
The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. During the three and nine months ended September 30, 2017, the Company capitalized $0.1 million and $0.3 million, respectively, associated with such in progress projects. The Company did not capitalize any interest during the three and nine months ended September 30, 2016 as no projects lasted more than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.
 
Depletion of oil and gas properties amounted to $46.1 million and $126.6 million for the three and nine months ended September 30, 2017, respectively, and $36.3 million and $115.6 million for the three and nine months ended September 30, 2016, respectively.
 
The Company continues to monitor its proved and unproved properties for impairment. No impairments of proved or unproved properties were recorded as a result of our standard impairment assessment during the nine months ended September 30, 2017 or 2016. However, as noted in Note 4, “Acquisitions and Divestitures - Arkoma Divestiture,” the Company recognized an impairment charge of $148.0 million during the nine months ended September 30, 2017 resulting from the sale of the Arkoma Assets.

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Other Property, Plant and Equipment
 
Other property, plant and equipment consisted of the following at September 30, 2017 and December 31, 2016:

 	 	September 30, 	 	December 31, 	 	
(in thousands of dollars)	    	2017	    	2016	 	
Leasehold improvements	 	$	1,186	 	$	1,213	 	
Furniture, fixtures, computers and software	 	 	4,391	 	 	4,170	 	
Vehicles	 	 	1,768	 	 	1,677	 	
Aircraft	 	 	910	 	 	910	 	
Other	 	 	211	 	 	284	 	
 	 	 	8,466	 	 	8,254	 	
Less: Accumulated depreciation and amortization	 	 	(5,901)	 	 	(5,258)	 	
Net other property, plant and equipment	 	$	2,565	 	$	2,996	 	
 
Depreciation and amortization of other property, plant and equipment amounted to $0.3 million and $0.8 million for the three and nine months ended September 30, 2017, respectively, and $0.3 million and $0.9 million for the three and nine months ended September 30, 2016, respectively.

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

(in thousands of dollars)	    	September 30, 2017	    	December 31, 2016	 	
Revolver	 	$	151,000	 	$	178,000	 	
2022 Notes	 	 	409,148	 	 	409,148	 	
2023 Notes	 	 	150,000	 	 	150,000	 	
Total principal amount	 	 	710,148	 	 	737,148	 	
Less: unamortized discount	 	 	(5,481)	 	 	(6,240)	 	
Less: debt issuance costs, net	 	 	(5,927)	 	 	(6,899)	 	
Total carrying amount	 	$	698,740	 	$	724,009	 	
 
Senior Unsecured Notes
 
On April 1, 2014, JEH and Jones Energy Finance Corp., JEH’s wholly owned subsidiary formed for the sole purpose of co-issuing certain of JEH’s debt (collectively, the “Issuers”), sold $500.0 million in aggregate principal amount of the Issuers’ 6.75% senior notes due 2022 (the “2022 Notes”). The Company used the net proceeds from the issuance of the 2022 Notes to repay certain indebtedness and for working capital and general corporate purposes. The 2022 Notes bear interest at a rate of 6.75% per year, payable semi-annually on April 1 and October 1 of each year beginning October 1, 2014. The 2022 Notes were registered in March 2015.
 
On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of 9.25% senior notes due 2023 (the “2023 Notes”) in a private placement to affiliates of GSO Capital Partners LP and Magnetar Capital LLC. The 2023 Notes were issued at a discounted price equal to 94.59% of the principal amount. The Company used the $236.5 million net proceeds from the issuance of the 2023 Notes to repay outstanding borrowings under the Revolver (as defined below) and for working capital and general corporate purposes. The 2023 Notes bear interest at a rate of 9.25% per year, payable semi-annually on March 15 and September 15 of each year beginning September 15, 2015. The 2023 Notes were registered in February 2016.
 
During 2016, the Company purchased an aggregate principal amount of $190.9 million of its senior unsecured notes through several open-market and privately negotiated purchases. The Company purchased $90.9 million principal amount of its 2022 Notes for $38.1 million, and $100.0 million principal amount of its 2023 Notes for $46.5 million, in each case excluding accrued interest and including any associated fees. The Company used cash on hand and borrowings from its Revolver to fund the note purchases. In conjunction with the extinguishment of this debt, JEH recognized cancellation of debt income of $99.5 million for the twelve months ended December 31, 2016, on a pre-tax basis. This income is recorded in Gain on debt extinguishment on the Company’s

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Consolidated Statement of Operations. Of the Company’s total repurchases, $20.3 million principal amount of its 2022 Notes were not cancelled and are available for future reissuance, subject to applicable securities laws.
 
The 2022 Notes and 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of its significant subsidiaries. The 2022 Notes and 2023 Notes will be senior in right of payment to any future subordinated indebtedness of the Issuers.
 
The Company may redeem the 2022 Notes at any time on or after April 1, 2017 and the 2023 Notes at any time on or after March 15, 2018 at a declining redemption price set forth in the respective indentures, plus accrued and unpaid interest.
 
The indentures governing the 2022 Notes and 2023 Notes are substantially identical and contain covenants that, among other things, limit the ability of the Company to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or other payments from the Company’s restricted subsidiaries to the Company, consolidate, merge or transfer all of the Company’s assets, engage in transactions with affiliates or create unrestricted subsidiaries. If at any time when the 2022 Notes or 2023 Notes are rated investment grade and no default or event of default (as defined in the indenture) has occurred and is continuing, many of the foregoing covenants pertaining to the 2022 Notes or 2023 Notes, as applicable, will be suspended. If the ratings on the 2022 Notes or 2023 Notes, as applicable, were to decline subsequently to below investment grade, the suspended covenants would be reinstated.
 
As of September 30, 2017, the Company was in compliance with the indentures governing the 2022 Notes and 2023 Notes.
 
Other Long-Term Debt
 
The Company has a Senior Secured Revolving Credit Facility (the “Revolver”) with a syndicate of banks. On May 15, 2017 at its bi-annual redetermination, the borrowing base under the Revolver was reaffirmed at $425.0 million. Upon closing of the Arkoma Divestiture on August 1, 2017, the Company’s borrowing base was reduced to $375.0 million, where it remained as of September 30, 2017. The Company’s oil and gas properties are pledged as collateral to secure its obligations under the Revolver.
 
The terms of the Revolver require the Company to make periodic payments of interest on the loans outstanding thereunder, with all outstanding principal and interest under the Revolver due on the maturity date. The Revolver is subject to a borrowing base, which limits the amount of borrowings which may be drawn thereunder. The borrowing base will be re-determined by the lenders at least semi-annually on or about April 1 and October 1 of each year, with such re-determination based primarily on reserve reports using lender commodity price expectations at such time. Any reduction in the borrowing base will reduce our liquidity, and, if the reduction results in the outstanding amount under our Revolver exceeding the borrowing base, we will be required to repay the deficiency within a short period of time.
 
Interest on the Revolver is calculated, at the Company’s option, at either (a) the London Interbank Offered (“LIBO”) rate for the applicable interest period plus a margin of 1.50% to 2.50% based on the level of borrowing base utilization at such time or (b) the greatest of the federal funds rate plus 0.50%, the one month adjusted LIBO rate plus 1.00%, or the prime rate announced by Wells Fargo Bank, N.A. in effect on such day, in each case plus a margin of 0.50% to 1.50% based on the level of borrowing base utilization at such time. For the three and nine months ended September 30, 2017, the average interest rates under the Revolver were 3.12% and 2.84%, respectively, on average outstanding balances of $172.9 million and $187.5 million, respectively. For the three and nine months ended September 30, 2016, the average interest rates under the Revolver were 2.29% and 2.38%, respectively, on average outstanding balances of $184.5 million and $170.9 million, respectively.
 
Total interest and commitment fees under the Revolver were $1.6 million and $4.7 million for the three and nine months ended September 30, 2017, respectively, and $1.3 million and $4.0 million for the three and nine months ended September 30, 2016, respectively.

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Jones Energy, Inc. and its consolidated subsidiaries are subject to certain covenants under the Revolver, including the requirement to maintain the following financial ratios:
 
	·		a total leverage ratio, consisting of consolidated debt to EBITDAX, of not greater than 4.00 to 1.00 as of the last day of any fiscal quarter; and	
 
	·		a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.00 to 1.00 as of the last day of any fiscal quarter.	
 
As of September 30, 2017, our total leverage ratio was 3.90 to 1.00 and our current ratio was 2.49 to 1.00, as calculated based on the requirements in our covenants. We were in compliance with all terms of our Revolver at September 30, 2017.
 
If an event of default exists under the Revolver, the lenders would be able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change of control, as defined in the Revolver.
 
Going Concern Assessment and Management’s Plans
 
Pursuant to the FASB ASU 2014-15, the Company has assessed its ability to continue as a going concern for a period of one year from the date of the issuance of these financial statements. Substantial doubt about an entity’s ability to continue as a going concern 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 from the financial statement issuance date. As discussed above in “Other Long-Term Debt”, the Company has an obligation to maintain certain financial ratios in accordance with our covenants under the Revolver. Specifically, we are required to maintain a total leverage ratio of not greater than 4.00 to 1.00 and a current ratio of not less than 1.00 to 1.00, each as of the last day of any fiscal quarter. As of September 30, 2017, we were in compliance with all terms of our Revolver, with a total leverage ratio of 3.90 to 1.00 and a current ratio of 2.49 to 1.00. However, based on current projections, we expect to breach the total leverage ratio under our Revolver beginning with the next measurement date of December 31, 2017.
 
Management has initiated negotiations with our lenders under the Revolver to, among other things, modify or suspend the financial covenant requirements discussed above, thereby suspending our need to comply with the total leverage ratio for a specified period of time. We expect negotiations with our lenders will be finalized in advance of our next financial ratio measurement date of December 31, 2017. However, there can be no assurances that the requisite lenders under our Revolver approve any such amendment.
 
Any failure to comply with the conditions and covenants in our Revolver that is not waived by our lenders or otherwise cured could lead to a termination of our Revolver, acceleration of all amounts due under our Revolver, or trigger cross default provisions under other financing arrangements. These factors raise substantial doubt about the Company’s ability to continue as a going concern.
 
7.        Derivative Instruments and Hedging Activities
 
The Company uses derivative instruments to mitigate volatility in commodity prices. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our hedging positions.

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The following tables summarize our hedging positions as of September 30, 2017:
 
Hedging Positions

 	 	September 30, 2017	 	
 	    	 	    	 	 	    	 	 	    	Weighted	    	Final	 	
 	 	 	 	Low	 	High	 	Average	 	Expiration	 	
Oil swaps	 	Exercise price	 	$	44.60	 	$	85.60	 	$	51.97	 	December 2020	 	
 	 	Offset exercise price	 	$	42.00	 	$	42.00	 	$	42.00	 	 	 	
 	 	Net barrels per month	 	 	55,000	 	 	216,000	 	 	116,462	 	 	 	
Natural gas swaps	 	Exercise price	 	$	2.76	 	$	4.57	 	$	2.98	 	December 2020	 	
 	 	Net MMbtu per month	 	 	700,000	 	 	1,890,000	 	 	1,169,231	 	 	 	
Natural gas liquids swaps	 	Exercise price	 	$	18.06	 	$	72.52	 	$	29.08	 	December 2018	 	
 	 	Barrels per month	 	 	130,000	 	 	145,000	 	 	139,333	 	 	 	
Natural gas basis swaps	 	Exercise price	 	$	(0.50)	 	$	(0.30)	 	$	(0.39)	 	March 2019	 	
 	 	Net MMbtu per month	 	 	300,000	 	 	800,000	 	 	564,706	 	 	 	
Oil collars	 	Puts (floors)	 	$	45.00	 	$	50.00	 	$	48.52	 	December 2019	 	
 	 	Calls (ceilings)	 	$	56.60	 	$	61.00	 	$	59.64	 	 	 	
 	 	Net barrels per month	 	 	65,000	 	 	73,000	 	 	67,500	 	 	 	
Natural gas collars	 	Puts (floors)	 	$	2.55	 	$	2.55	 	$	2.55	 	December 2019	 	
 	 	Calls (ceilings)	 	$	3.08	 	$	3.41	 	$	3.19	 	 	 	
 	 	Net barrels per month	 	 	950,000	 	 	1,050,000	 	 	990,833	 	 	 	
 
The Company recognized net losses on derivative instruments of $32.5 million and net gains of $11.3 million for the three and nine months ended September 30, 2017, respectively. The Company recognized net gains on derivative instruments of $4.0 million and net losses of $18.8 million for the three and nine months ended September 30, 2016, respectively.
 
The Company routinely enters into oil and natural gas swap contracts as seller, thus resulting in a fixed price. During 2016 and 2017, the Company realized certain mark-to-market gains associated with oil and natural gas hedges the Company had in place for years 2018 and 2019. The gains were effectively realized by purchasing, as opposed to selling, oil and natural gas swap contracts for an equal volume that was associated with the initial hedge transaction. Therefore, as prices fluctuate, the loss (or gain) on any single contract in 2018 and 2019 will be offset by an equal gain (or loss). This essentially leaves the underlying production open to fluctuations in market prices. Based on the original contract terms of these purchased swaps, the gains would be recognized as the hedge contracts mature in 2018 and 2019. See further discussion below. Information related to these purchased oil and natural gas swap contracts is presented in the table above as the “offset exercise price”, and the volumes in the table above are presented “net” of such purchased oil and natural gas swap contracts.
 
During the three and nine months ended September 30, 2017, the Company unwound its realized 2018 and 2019 hedges resulting in approximately $14.8 million and $42.8 million, respectively, of recognized gains which have been included in Net gain (loss) on commodity derivatives on the Company’s Consolidated Statement of Operations.
 
Offsetting Assets and Liabilities
 
As of September 30, 2017, the counterparties to our commodity derivative contracts consisted of seven financial institutions. All of our counterparties or their affiliates are also lenders under the Revolver. We are not generally required to post additional collateral under our derivative agreements.
 
Our derivative agreements contain set-off provisions that state that in the event of default or early termination, any obligation owed by the defaulting party may be offset against any obligation owed to the defaulting party.

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The following table presents information about our commodity derivative contracts that are netted on our Consolidated Balance Sheet as of September 30, 2017 and December 31, 2016:

 	    	 	 	    	 	 	    	Net Amounts	    	 	 	    	 	 	 	
 	 	 	 	 	Gross	 	of Assets /	 	Gross Amounts	 	 	 	 	
 	 	Gross Amounts	 	Amounts	 	Liabilities	 	Not	 	 	 	 	
 	 	of Recognized	 	Offset in the	 	Presented in	 	Offset in the	 	 	 	 	
 	 	Assets /	 	Balance	 	the Balance	 	Balance	 	 	 	 	
(in thousands of dollars)	 	Liabilities	 	Sheet	 	Sheet	 	Sheet	 	Net Amount	 	
September 30, 2017	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivative contracts	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Assets	 	$	18,805	 	$	(9,607)	 	$	9,198	 	$	 —	 	$	9,198	 	
Liabilities	 	 	(30,658)	 	 	9,607	 	 	(21,051)	 	 	 —	 	 	(21,051)	 	
December 31, 2016	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Commodity derivative contracts	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Assets	 	$	79,649	 	$	(20,805)	 	$	58,844	 	$	 —	 	$	58,844	 	
Liabilities	 	 	(36,664)	 	 	20,805	 	 	(15,859)	 	 	 —	 	 	(15,859)	 	

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

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Level 2  Pricing inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, as of the reporting date. Contracts that are not traded on a recognized exchange or are tied to pricing transactions for which forward curve pricing is readily available are classified as Level 2 instruments. These include natural gas, crude oil and some natural gas liquids price swaps and natural gas basis swaps.
 
Level 3  Pricing inputs include significant inputs that are generally unobservable from objective sources. The Company classifies natural gas liquid swaps and basis swaps for which future pricing is not readily available as Level 3. The Company obtains estimates from independent third parties for its open positions and subjects those to the credit adjustment criteria described above.
 
The financial instruments carried at fair value as of September 30, 2017 and December 31, 2016, by consolidated balance sheet caption and by valuation hierarchy, as described above are as follows:

(in thousands of dollars)	 	September 30, 2017	 	
 	 	Fair Value Measurements Using	 	
Commodity Price Hedges	    	(Level 1)	    	    (Level 2)    	    	   (Level 3)   	    	   Total   	 	
Current assets	 	$	 —	 	$	7,590	 	$	 —	 	$	7,590	 	
Long-term assets (1)	 	 	 —	 	 	(344)	 	 	1,952	 	 	1,608	 	
Current liabilities	 	 	 —	 	 	14,587	 	 	1,109	 	 	15,696	 	
Long-term liabilities	 	 	 —	 	 	4,250	 	 	1,105	 	 	5,355	 	

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

	(1)		Level 2 long-term assets are negative as a result of the netting of our commodity derivatives reflected on our Consolidated Balance Sheet as of September 30, 2017. Our agreements include set-off provisions, as noted in Note 7, “Derivative Instruments and Hedging Activities - Offsetting Assets and Liabilities”.	
	(2)		Level 3 long-term assets are negative as a result of the netting of our commodity derivatives reflected on our Consolidated Balance Sheet as of December 31, 2016. Our agreements include set-off provisions, as noted in Note 7, “Derivative Instruments and Hedging Activities - Offsetting Assets and Liabilities”.	

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

 	 	Quantitative Information About Level 3 Fair Value Measurements	 	
 	    	Fair Value	    	 	    	Unobservable	    	 	 	
Commodity Price Hedges	 	(000’s)	 	Valuation Technique	 	Input	 	Range	 	
Natural gas liquid swaps	 	$	(1,266)	 	Use a discounted cash flow approach using inputs including forward price statements from counterparties	 	Natural gas liquid futures	 	$22.89 - $23.94 per barrel	 	
Crude oil collars	 	$	1,988	 	Use a discounted option model approach using inputs including interpolated volatilities for certain settlement months where market volatility quotes were unavailable for the option strike price	 	Market volatility quotes at the option strike for certain settlement months in 2019	 	$45.00 - $61.00 per barrel	 	
Natural gas collars	 	$	(984)	 	Use a discounted option model approach using inputs including interpolated volatilities for certain settlement months where market volatility quotes were unavailable for the option strike price	 	Market volatility quotes at the option strike for certain settlement months in 2019	 	$2.55 - $3.41 per barrel	 	
 
Significant increases/decreases in natural gas liquid prices in isolation would result in a significantly lower/higher fair value measurement. The following table presents the changes in the Level 3 financial instruments for the nine months ended September 30, 2017. Changes in fair value of Level 3 instruments represent changes in gains and losses for the periods that are reported in other income (expense). New contracts entered into during the year are generally entered into at no cost with changes in fair value from the date of agreement representing the entire fair value of the instrument. Transfers between levels are evaluated at the end of the reporting period.
 
The following table summarizes the Company’s commodity derivative contract activity involving Level 3 instruments during the nine months ended September 30, 2017:

(in thousands of dollars)	    	 	 	 	
Balance at December 31, 2016, net	 	$	(2,971)	 	
Purchases	 	 	(775)	 	
Settlements	 	 	1,115	 	
Transfers to Level 2	 	 	 —	 	
Transfers to Level 3	 	 	 —	 	
Changes in fair value	 	 	2,369	 	
Balance at September 30, 2017, net	 	$	(262)	 	

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

 	 	September 30, 2017	 	December 31, 2016	 	
 	 	Principal	 	 	 	 	Principal	 	 	 	 	
(in thousands of dollars)	    	Amount	    	Fair Value	    	Amount	    	Fair Value	 	
Debt:	 	   	 	 	   	 	 	   	 	 	   	 	 	
Revolver	 	$	151,000	 	$	151,000	 	$	178,000	 	$	178,000	 	
2022 Notes	 	 	409,148	 	 	338,496	 	 	409,148	 	 	393,150	 	
2023 Notes	 	 	150,000	 	 	124,560	 	 	150,000	 	 	153,375	 	
 
The Revolver (as defined in Note 6) 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 6) 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 6) 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.
 
9.        Asset Retirement Obligations
 
A summary of the Company’s Asset Retirement Obligations (“ARO”) for the nine months ended September 30, 2017 is as follows:

(in thousands of dollars)	    	 	 	
Balance at December 31, 2016	 	$	20,058	 	
Liabilities incurred	 	 	698	 	
Accretion of ARO liability	 	 	720	 	
Liabilities settled due to sale of related properties	 	 	(1,202)	 	
Liabilities settled due to plugging and abandonment	 	 	(174)	 	
Change in estimate	 	 	(261)	 	
Total ARO balance at September 30, 2017	 	 	19,839	 	
Less: Current portion of ARO	 	 	(600)	 	
Total long-term ARO at September 30, 2017	 	$	19,239	 	

10.        Stock-based Compensation
 
Management Unit Awards
 
Effective January 1, 2010, JEH implemented a management incentive plan that provided indirect awards of membership interests in JEH to members of senior management (“Management Units”). These awards had various vesting schedules, and a portion of the Management Units vested in a lump sum at the IPO date. In connection with the IPO, both the vested and unvested Management Units were converted into the right to receive JEH Units and shares of Class B common stock. The JEH Units (together with a corresponding number of shares of Class B common stock) will become exchangeable under this plan into a like number of shares of Class A common stock upon vesting or forfeiture. No new Management Units have been awarded since the IPO and no new JEH Units or shares of Class B common stock are created upon a vesting event. Grants listed below reflect the transfer of JEH Units that occurred upon forfeiture.

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

 	    	 	    	Weighted Average	 	
 	 	 	 	Grant Date Fair Value	 	
 	 	JEH Units	 	per Share	 	
Unvested at December 31, 2016	 	90,762	 	$	15.00	 	
Granted	 	 —	 	 	 —	 	
Forfeited	 	 —	 	 	 —	 	
Vested	 	(45,381)	 	 	15.00	 	
Unvested at September 30, 2017	 	45,381	 	$	15.00	 	
 
Stock compensation expense associated with the Management Units was $0.1 million and $0.5 million for the three and nine months ended September 30, 2017, respectively, and $0.2 million and $1.0 million for the three and nine months ended September 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.
 
2013 Omnibus Incentive Plan
 
Under the Amended and Restated Jones Energy, Inc. 2013 Omnibus Incentive Plan (the “LTIP”), established in conjunction with the Company’s IPO and restated on May 4, 2016 following approval by the Company’s stockholders, the Company has reserved a total of 8,185,771 shares of Class A common stock for non-employee director, consultant, and employee stock-based compensation awards, as adjusted for the effects of the Special Stock Dividend and the preferred stock dividends paid in shares, as described in Note 12 “Stockholders’ and Mezzanine equity”.
 
The Company granted (i) performance share unit and restricted stock unit awards to certain officers and employees and (ii) restricted shares of Class A common stock to the Company’s non-employee directors under the LTIP during 2014, 2015, 2016 and 2017. During 2016 and 2017, the Company also granted performance unit awards to certain members of the senior management team under the LTIP.
 
All share and earnings per share information presented for awards made under the LTIP has been recast to retrospectively adjust for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 12, “Stockholders’ and Mezzanine equity”, distributed on March 31, 2017.
 
Restricted Stock Unit Awards
 
The Company has outstanding restricted stock unit awards granted to certain officers and employees of the Company under the LTIP. The fair value of the restricted stock unit awards is based on the value of the Company’s Class A common stock on the date of grant and is expensed on a straight-line basis over the applicable vesting period, which is typically three years.
 
The following table summarizes information related to the total number of units awarded to officers and employees as of September 30, 2017:

 	    	Restricted	    	Weighted Average	 	
 	 	Stock Unit	 	Grant Date Fair Value	 	
 	 	Awards	 	per Share	 	
Unvested at December 31, 2016	 	1,359,142	 	$	5.60	 	
Adjustment (1)	 	72,871	 	 	 —	 	
Granted	 	2,394,290	 	 	2.32	 	
Forfeited	 	(174,703)	 	 	3.22	 	
Vested	 	(577,729)	 	 	6.68	 	
Unvested at September 30, 2017	 	3,073,871	 	$	2.93	 	

	(1)		Increase of 0.002195 units for each unvested restricted stock unit awards at the time of the Company’s May 15, 2017 preferred stock dividend for the portion of such dividend paid in shares of the Company’s Class A common stock and of 0.021931 units for each unvested restricted stock unit award at the time of the	

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Company’s August 15, 2017 preferred stock dividend paid entirely in shares of the Company’s Class A common stock, as described in Note 12 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards. This increase is in addition to the adjustment for the effects of the Special Stock Dividend previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.	
 
Stock compensation expense associated with the employee restricted stock unit awards was $1.1 million and $3.1 million for the three and nine months ended September 30, 2017, respectively, and $1.0 million and $2.0 million for the three and nine months ended September 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.
 
Performance Share Unit Awards
 
The Company has outstanding performance share unit awards granted to certain members of the senior management team of the Company under the LTIP. Prior to the second quarter of 2016, the performance share unit awards were described in the Company’s filings as performance unit awards. During the second quarter of 2016, the Company created a new class of equity award, described below as a performance unit award, that is settled in cash rather than shares of the Company’s Class A common stock. As a result, references to performance unit awards in the Company’s filings prior to the second quarter of 2016 refer to this description of performance share unit awards.
 
Upon the completion of the applicable three-year performance period, each recipient may vest in a number of performance share units. The percent of awarded performance share units in which each recipient vests at such time, if any, will range from 0% to 200% based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. Each vested performance share unit is exchangeable for one share of the Company’s Class A common stock. The grant date fair value of the performance share units was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned. The fair value of the performance share units is expensed on a straight-line basis over the applicable three-year performance period.
 
The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the performance share unit awards granted during the nine months ended September 30, 2017:

 	 	2017	 	
 	 	Performance	 	
 	 	Share	 	
 	 	Unit Awards	 	
Forecast period (years)	 	
2.71	    	
Risk-free interest rate	 	
1.34	%  	
Jones stock price volatility	 	
78.93	%  	
 
For the performance share units granted during the nine months ended September 30, 2017, the Monte Carlo simulation model resulted in approximately 29% of performance share units expected to be earned.
 
The following table summarizes information related to the total number of performance share units awarded to the senior management team as of September 30, 2017:

 	    	Performance	    	Weighted Average	 	
 	 	Share Unit	 	Grant Date Fair Value	 	
 	 	Awards	 	per Share	 	
Unvested at December 31, 2016	 	942,073	 	$	6.25	 	
Adjustment (1)	 	35,912	 	 	 —	 	
Granted	 	519,562	 	 	2.24	 	
Forfeited	 	(23,552)	 	 	9.42	 	
Vested	 	 —	 	 	 —	 	
Unvested at September 30, 2017	 	1,473,995	 	$	4.64	 	

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	(1)		Increase of 0.002195 units for each unvested performance share unit award at the time of the Company’s May 15, 2017 preferred stock dividend for the portion of such dividend paid in shares of the Company’s Class A common stock and of 0.021931 units for each unvested performance share unit award at the time of the Company’s August 15, 2017 preferred stock dividend paid entirely in shares of the Company’s Class A common stock, as described in Note 12 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards. This increase is in addition to the adjustment for the effects of the Special Stock Dividend previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.	
 
Stock compensation expense associated with the performance share unit awards was $0.7 million and $1.7 million for the three and nine months ended September 30, 2017, respectively, and $0.8 million and $1.9 million for the three and nine months ended September 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.
 
Performance Unit Awards
 
The value of awarded performance units in which each recipient vests at such time, if any, will range from $0.00 to $200.00 per performance unit based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. For accounting purposes, the performance units are treated as a liability award with the liability being re-measured at the end of each reporting period. Therefore, the expense associated with these awards is subject to volatility until the payout is finally determined at the end of the performance period. The value of the performance units was determined using a Monte Carlo simulation model, as of the grant date, which resulted in an estimated final value upon vesting of $0.4 and $1.3 million for awards made during 2017 and 2016, respectively. The fair value measured as of September 30, 2017 was $0.8 million.
 
The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the performance unit awards granted during the nine months ended September 30, 2017:

 	 	2017	 	
 	 	Performance	 	
 	 	Unit Awards	 	
Forecast period (years)	 	
2.71	    	
Risk-free interest rate	 	
1.34	%  	
Jones stock price volatility	 	
78.93	%  	
 
For the performance units granted during the nine months ended September 30, 2017, the Monte Carlo simulation
model resulted in an expected payout of $28.25 per performance unit as of the grant date.
 
Stock compensation expense associated with the performance unit awards was an expense of less than $0.1 million for the three and nine months ended September 30, 2017, respectively and $0.1 million and $0.2 million for the three and nine months ended September 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. As of September 30, 2017, unrecognized compensation expense of $0.5 million related to the performance unit awards, subject to re-measurement and adjustment for the change in estimated final value as of the end of each reporting period, and is expected to be recognized over the remaining weighted average service period of 1.7 years.
 
Restricted Stock Awards
 
The Company has outstanding restricted stock awards granted to the non-employee members of the Board of Directors of the Company under the LTIP. The restricted stock will vest upon the director serving as a director of the Company for a one-year service period in accordance with the terms of the award. The fair value of the awards was based on the price of the Company’s Class A common stock on the date of grant.

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

 	    	 	    	Weighted Average	 	
 	 	Restricted	 	Grant Date Fair Value	 	
 	 	Stock   Awards	 	per Share	 	
Unvested at December 31, 2016	 	152,050	 	$	3.68	 	
Adjustment (1)	 	3,948	 	 	 —	 	
Granted	 	180,000	 	 	2.25	 	
Forfeited	 	 —	 	 	 —	 	
Vested	 	(152,050)	 	 	3.68	 	
Unvested at September 30, 2017	 	183,948	 	$	2.20	 	
 
	(1)		Increase of 0.021931 units for each unvested performance share unit award at the time of the Company’s August 15, 2017 preferred stock dividend paid entirely in shares of the Company’s Class A common stock, as described in Note 12 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards. This increase is in addition to the adjustment for the effects of the Special Stock Dividend previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.	
 
Stock compensation expense associated with awards to the members of the Board of Directors was $0.1 million and $0.4 million for the three and nine months ended September 30, 2017, respectively, and $0.1 million and $0.4 million for the three and nine months ended September 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.
 
11.       Income Taxes
 
The Company records federal and state income tax liabilities associated with its status as a corporation. The Company recognizes a tax liability on its share of pre-tax book income, exclusive of the non-controlling interest. JEH is not subject to income tax at the federal level and only recognizes Texas franchise tax expense.
 
The Company’s effective tax rate was 0.6% and 1.2% for the three and nine months ended September 30, 2017, respectively, and 22.6% and 20.2% for the three and nine months ended September 30, 2016, respectively. The effective tax rate reduction is primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets. The effective rate differs from the statutory rate of 35% due to net income allocated to the non-controlling interest, percentage depletion, state income taxes, the valuation allowance recorded against deferred tax assets, and other permanent differences between book and tax accounting.
 
The Company’s income tax provision was a benefit of $0.5 million and $2.7 million for the three and nine months ended September 30, 2017, respectively, and a benefit of $6.5 million and $8.2 million for the three and nine months ended September 30, 2016, respectively.
 
The following table summarizes information related to the allocation of the income tax provision between the controlling and non-controlling interests:

 	 	Three Months Ended September 30, 	 	Nine Months Ended September 30, 	 	
(in thousands of dollars)	    	2017	    	2016	    	2017	    	2016	 	
Jones Energy, Inc.	 	$	(495)	 	$	(6,254)	 	$	(2,711)	 	$	(7,900)	 	
Non-controlling interest	 	 	 3	 	 	(295)	 	 	 4	 	 	(334)	 	
Income tax provision (benefit)	 	$	(492)	 	$	(6,549)	 	$	(2,707)	 	$	(8,234)	 	
 
The Company had deferred tax assets for its federal and state net operating loss carry forwards at September 30, 2017 recorded in its deferred taxes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of September 30, 2017, we have a valuation allowance of $5.4 million as a result of management’s assessment of the realizability of federal and state deferred tax assets.
 
Internal Revenue Code ("IRC") Section 382 addresses corporate shareholder changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change as

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defined under the IRC. The Company experienced an ownership change within the meaning of IRC Section 382 during the third quarter that will subject a portion of the Company’s net operating loss carryforwards and other tax attributes to an IRC Section 382 limitation in future periods.
 
Tax Receivable Agreement
 
In connection with the IPO, the Company entered into a Tax Receivable Agreement (the “TRA”) which obligates the Company to make payments to certain current and former owners equal to 85% of the applicable cash savings that the Company realizes as a result of tax attributes arising from exchanges of JEH Units and shares of the Company’s Class B common stock held by those owners for shares of the Company’s Class A common stock. The Company will retain the benefit of the remaining 15% of these tax savings. At the time of an exchange, the company records a liability to reflect the future payments under the TRA.
 
The actual amount and timing of payments to be made under the TRA will depend upon a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers, and the portion of the Company’s payments under the TRA constituting imputed interest. As of September 30, 2017 and December 31, 2016, the Company had a gross TRA liability of $60.7 million and $45.7 million, respectively. As a result of the valuation allowance recorded against the Company’s deferred tax assets associated with prior exchanges, the TRA liability was reduced, as the payment of the TRA liability is dependent on the realizability of the associated deferred tax assets. As of September 30, 2017 and December 31, 2016, the amount of the TRA liability was reduced by $4.9 million and $2.7 million, respectively, as a result of the valuation allowance recorded against the Company’s deferred tax assets. To the extent the Company does not realize all of the tax benefits in future years or in the event of a change in future tax rates, this liability may change.
 
As of September 30, 2017 and December 31, 2016, the Company had recorded a net TRA liability of $55.8 million and $43.0 million, respectively, for the estimated payments that will be made to the Class B shareholders who have exchanged shares, after adjusting for the TRA liability reduction, along with corresponding deferred tax assets, net of valuation allowances, of $65.7 million and $50.6 million, respectively, as a result of the increase in tax basis from such shares exchanged by current and former Class B shareholders.
 
As of September 30, 2017, the Company had not made any significant payments under the TRA to Class B shareholders who have exchanged JEH Units and Class B common stock for Class A common stock. The Company anticipates making a payment of approximately $0.6 million under the TRA with respect to cash savings that the Company will realize on its 2016 tax returns as a result of tax attributes arising from prior exchanges, to be paid in the first quarter of 2018.
 
Cash Tax Distributions
 
The holders of JEH Units, including the Company, incur U.S. federal, state and local income taxes on their share of any taxable income of JEH. Under the terms of its operating agreement, JEH is generally required to make quarterly pro-rata cash tax distributions to its unitholders (including us) based on income allocated to its unitholders through the end of each relevant quarter, as adjusted to take into account good faith projections by the Company of taxable income or loss for the remainder of the calendar year, to the extent JEH has cash available for such distributions and subject to certain other restrictions.
 
A Special Committee of the Board of Directors comprised solely of directors who do not have a direct or indirect interest in such distribution approved, and JEH made, aggregate cash tax distributions during the three and nine months ended September 30, 2017 of $0.0 million and $1.7 million, respectively. Distributions during the year were made pro-rata to all members of JEH, and included a $1.1 million payment to the Company and a $0.6 million payment to JEH unitholders other than the Company. During the three and nine months ended September 30, 2016 the Company made aggregate cash tax distributions of $0.0 million and $20.0 million to its unitholders towards its total 2016 projected tax distribution obligation. The distributions were made pro-rata to all members of JEH, and included a $9.9 million payment to the Company, and a $10.1 million payment to JEH unitholders other than the Company. All tax distributions were paid as a result of JEH’s 2016 taxable income.

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12.      Stockholders’ and Mezzanine equity
 
Stockholders’ equity is comprised of two classes of common stock, Class A common stock and Class B common stock. The Class B common stock is held by the owners of JEH prior to the Company’s IPO and can be exchanged (together with a corresponding number of units representing membership interests in JEH Units) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. The Class B common stock has no economic rights but entitles its holders to one vote on all matters to be voted on by the Company’s stockholders generally.
 
The Company has classified the Series A preferred stock as mezzanine equity based upon the terms and conditions that contain various redemption and conversion features. For a description of these features, please see below under “—Offering of 8.0% Series A Perpetual Convertible Preferred Stock.”
 
Equity Distribution Agreement
 
On May 24, 2016, the Company and JEH entered into an Equity Distribution Agreement (“Equity Distribution Agreement”) with Citigroup Global Markets Inc. and Wells Fargo Securities, LLC (each, a “Manager” and collectively, the “Managers”). Pursuant to the terms of the Equity Distribution Agreement, the Company may sell from time to time through the Managers, as the Company’s sales agents, the Company’s Class A common stock having an aggregate offering price of up to $73.0 million (the “Class A Shares”). Under the terms of the Equity Distribution Agreement, the Company may also sell Class A Shares from time to time to any Manager as principal for its own account at a price to be agreed upon at the time of sale. Any sale of Class A Shares to a Manager as principal would be pursuant to the terms of a separate terms agreement between the Company and such Manager. Sales of the Class A Shares, if any, will be made by means of ordinary brokers’ transactions, to or through a market maker or directly on or through an electronic communication network, a “dark pool” or any similar market venue, or as otherwise agreed by the Company and one or more of the Managers.
 
During the nine months ended September 30, 2017, the Company sold approximately 3.7 million Class A Shares under the Equity Distribution Agreement for net proceeds of approximately $8.4 million ($8.7 million gross proceeds, net of approximately $0.3 million in commissions and professional services expenses). During the three months ended September 30, 2017, the Company did not sell any Class A Shares under the Equity Distribution Agreement. The Company used the net proceeds from the sale of shares under the Equity Distribution Agreement for general corporate purposes. As of September 30, 2017, approximately $62.2 million in aggregate offering proceeds remained available to be issued and sold under the Equity Distribution Agreement.
 
Offering of Class A Common Stock
 
On August 26, 2016, the Company issued 21,000,000 shares of Class A common stock pursuant to an underwritten public offering, and on September 12, 2016 the Company issued an additional 3,150,000 shares of Class A common stock in connection with the exercise of the underwriters’ over-allotment option. The total net proceeds (after underwriters’ discounts and commissions, but before estimated expenses) of the offering, including the exercise of the over-allotment option, was $64.0 million.
 
Offering of 8.0% Series A Perpetual Convertible Preferred Stock
 
On August 26, 2016, the Company issued 1,840,000 shares of Series A preferred stock pursuant to an underwritten public offering for total net proceeds (after underwriters’ discounts and commissions but before expenses) of $88.3 million.
 
Holders of Series A preferred stock are entitled to receive, when as and if declared by the Company’s Board of Directors, cumulative dividends at the rate of 8.0% per annum (the “dividend rate”) per share on the $50.00 liquidation preference per share of the Series A Preferred Stock, payable quarterly in arrears on February 15, May 15, August 15 and November 15 of each year, beginning on November 15, 2016. Dividends may be paid in cash or, subject to certain limitations, in Class A common stock, or a combination thereof.

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Under the terms of the Series A preferred stock, the Company’s ability to declare or pay dividends or make distributions on, or purchase, redeem or otherwise acquire for consideration, shares of the Company’s Class A common stock, or any junior stock or parity stock currently outstanding or issued in the future, will be subject to certain restrictions in the event that the Company does not pay in full or declare and set aside for payment in full all accrued and unpaid dividends on the Series A preferred stock (including certain unpaid excess cash payment amounts excused from payment as a dividend due to restrictions in credit facilities or other indebtedness or legal requirements (“Unpaid Excess Cash Payment Amounts”)).
 
Each share of Series A preferred stock has a liquidation preference of $50.00 per share and is convertible, at the holder’s option at any time, into approximately 17.0683 shares of Class A common stock after adjusting the conversion ratio for the effects of the Special Stock Dividend, as defined in Note 12, “Stockholders’ and Mezzanine equity”, (which is equivalent to a conversion price of approximately $2.93 per share after adjusting for the effects of the Special Stock Dividend), subject to specified further adjustments and limitations as set forth in the certificate of designations for the Series A preferred stock. Based on the adjusted conversion rate and the full exercise of the Preferred Stock Underwriters’ over-allotment option, approximately 31.4 million shares of Class A common stock would be issuable upon conversion of all the Series A preferred stock.
 
On or after August 15, 2021, the Company may, at its option, give notice of its election to cause all outstanding shares of Series A preferred stock to be automatically converted into shares of Class A common stock at the conversion rate, if the closing sale price of the Class A common stock equals or exceeds 175% of the conversion price for at least 20 trading days in a period of 30 consecutive trading days.
 
On August 15, 2024 (the “designated redemption date”), each holder of Series A preferred stock may require us to redeem any or all Series A preferred stock held by such holder outstanding on the designated redemption date at a redemption price equal to a liquidation preference of $50.00 per share plus all accrued dividends on the shares up to but excluding the designated redemption date that have not been paid plus any Unpaid Excess Cash Payment Amounts (the “redemption price”). At our option, the redemption price may be paid in cash or, subject to certain limitations, in Class A common stock, or a combination thereof.
 
Except as required by law or the Company’s certificate of incorporation, which includes the certificate of designations for the Series A preferred stock, the holders of Series A preferred stock have no voting rights (other than with respect to certain matters regarding the Series A preferred stock or when dividends payable on the Series A preferred stock have not been paid for an aggregate of six quarterly dividend periods, or more, whether or not consecutive, as provided in the certificate of designations for the Series A preferred stock).
 
The Series A preferred stock is classified as mezzanine equity on the Company’s Consolidated Balance Sheet and is not listed on a national stock exchange.
 
A summary of the Company’s Mezzanine equity for the nine months ended September 30, 2017 is as follows:

(in thousands of dollars)	    	 	 	    	
Mezzanine equity at December 31, 2016	 	$	88,975	 	
Dividends on preferred stock, net	 	 	 —	 	
Accretion on preferred stock	 	 	438	 	
Mezzanine equity at September 30, 2017	 	$	89,413	 	
 
Preferred Stock Dividends
 
On January 19, 2017, the Company’s Board of Directors declared a quarterly cash dividend per share equal to 8.0% based on the liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock. This dividend is for the period beginning on the last payment date of November 15, 2016 through February 14, 2017 and was paid in cash on February 15, 2017 to shareholders of record as of February 1, 2017.
 
On April 17, 2017, the Company’s Board of Directors declared a quarterly dividend per share equal to 8.0% based on the liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock. On May 15, 2017, the dividend was paid in a combination of cash and the Company’s Class A

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common stock, with the cash component equal to $0.83 per share and the stock component equal to $0.17 per share. The price per share of the Class A common stock used to determine the number of shares issued was equal to 95% of the average volume-weighted average price per share for each day during the five-consecutive day trading period ending immediately prior to the payment date. This dividend was for the period beginning on the last payment date of February 15, 2017 through May 14, 2017 to shareholders of record as of May 1, 2017.
 
On July 13, 2017, the Company’s Board of Directors declared a quarterly dividend per share equal to 8.0% based on the liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock. On August 15, 2017, the dividend was paid entirely in shares of Class A common stock. The price per share of the Class A common stock used to determine the number of shares issued was equal to 95% of the average volume-weighted average price per share for each day during the 5-consecutive day trading period ending immediately prior to the payment date. This dividend was for the period beginning on the last payment date of May 15, 2017 through August 14, 2017 to shareholders of record as of August 1, 2017.
 
Special Stock Dividend
 
On March 31, 2017, the Company paid a stock dividend (the “Special Stock Dividend”) of 0.087423 shares of the Class A common stock to holders of record as of March 15, 2017. From time-to-time, JEH makes cash distributions to the holders of JEH Units to cover tax obligations that may occur as a result of any net taxable income of JEH allocable to holders of JEH Units. As a holder of JEH Units, the Company has received such cash distributions from JEH in excess of the amount required to satisfy the Company’s associated tax obligations. As a result, the Company used the excess cash of approximately $17.5 million in the aggregate to acquire newly-issued JEH Units from JEH.
 
The Special Stock Dividend was distributed in order to equalize the number of shares of Class A common stock outstanding to the number of JEH Units held by the Company, and the aggregate number of shares of Class A common stock issued in the Special Stock Dividend equaled the number of additional JEH Units the Company purchased from JEH. The Company purchased 4,999,927 JEH Units at a price of $3.50 per share, which is the volume weighted average price per share of the Class A common stock for the five trading days ended February 28, 2017. Immaterial cash payments were made in lieu of fractional shares. The comparative earnings per share information has been recast to retrospectively adjust for the effects of the Special Stock Dividend.

13.      Earnings per Share
 
Basic earnings per share (“EPS”) is computed by dividing net income (loss) attributable to controlling interests by the weighted average number of shares of Class A common stock outstanding during the period. Shares of Class B common stock are not included in the calculation of earnings per share because they are not participating securities and have no economic interest in the Company. Diluted earnings per share takes into account the potential dilutive effect of shares that could be issued by the Company in conjunction with the Series A preferred stock and from stock awards that have been granted to directors and employees. Awards of non-vested shares are considered outstanding as of the respective grant dates for purposes of computing diluted EPS even though the award is contingent upon vesting. For the three and nine months ended September 30, 2017, 3,073,871 restricted stock units, 1,473,995 performance share units, and 31,405,587 shares from the convertible Class A preferred stock, were excluded from the calculation as they would have had an anti-dilutive effect.

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The following is a calculation of the basic and diluted weighted-average number of shares of Class A common stock outstanding and EPS for the three and nine months ended September 30, 2017:

 	 	Three Months Ended September 30, 	 	Nine Months Ended September 30, 	 	
(in thousands, except per share data)	    	2017	    	2016	    	2017	    	2016	    	
Income (numerator):	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss) attributable to controlling interests	 	$	(64,806)	 	$	(9,853)	 	$	(148,409)	 	$	(14,187)	 	
Less: Dividends and accretion on preferred stock	 	 	(1,966)	 	 	(765)	 	 	(5,959)	 	 	(765)	 	
Net income (loss) attributable to common shareholder	 	$	(66,772)	 	$	(10,618)	 	$	(154,368)	 	$	(14,952)	 	
Weighted-average shares (denominator): (1)	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted-average number of shares of Class A common stock - basic	 	 	73,089	 	 	44,993	 	 	67,029	 	 	37,299	 	
Weighted-average number of shares of Class A common stock - diluted	 	 	73,089	 	 	44,993	 	 	67,029	 	 	37,299	 	
Earnings (loss) per share: (1)	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic - Net income (loss) attributable to common shareholders	 	$	(0.91)	 	$	(0.24)	 	$	(2.30)	 	$	(0.40)	 	
Diluted - Net income (loss) attributable to common shareholders	 	$	(0.91)	 	$	(0.24)	 	$	(2.30)	 	$	(0.40)	 	

	(1)		All share and earnings per share information presented has been recast to retrospectively adjust for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 12, “Stockholders’ and Mezzanine equity”, distributed on March 31, 2017.	

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

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and Gregory D. Myers, are managing directors of Metalmark Capital and were directors at the time the Company entered into the 2013 Monarch agreement.
 
In connection with the Company’s entering into the 2013 Monarch agreement, Monarch issued to JEH equity interests in Monarch, having an estimated fair value of $15.0 million, in return for marketing services to be provided throughout the term of the agreement. The Company recorded this amount as deferred revenue which is being amortized on an estimated units-of-production basis commencing in September 2013, the first month of product sales to Monarch. The Company amortized $0.5 million and $1.4 million, respectively, of the deferred revenue balance during the three and nine months ended September 30, 2017, and $0.6 million and $1.8 million, respectively, of the deferred revenue balance during the three and nine months ended September 30, 2016. This revenue is recorded in Other revenues on the Company’s Consolidated Statement of Operations.
 
Following the issuance of $15.0 million Monarch equity interests to JEH, JEH assigned $2.4 million of the equity interests to Jonny Jones, the Company’s chief executive officer and chairman of the Board of Directors, and reserved $2.6 million of the equity interests for future distribution through an incentive plan to certain of the Company’s officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10.0 million of Monarch equity interests was distributed to certain of the Class B shareholders, which included, among others, Metalmark Capital, the Jones family entities, and certain of the Company’s officers and directors, including Jonny Jones, Mike McConnell and Eric Niccum. As of September 30, 2017, equity interests in Monarch of $0.4 million are included in Other assets on the Company’s Consolidated Balance Sheet. During the three and nine months ended September 30, 2017, equity interests in Monarch of $0.3 million were distributed to management under the incentive plan. The Company recognized expense of $0.1 million and $0.3 million during the three and nine months ended September 30, 2017, respectively, in connection with the incentive plan.
 
In September 2014, the Company signed a 10-year oil gathering and transportation agreement with Monarch Oil Pipeline LLC, pursuant to which Monarch Oil Pipeline LLC built, at its expense, a new oil gathering system and connected the gathering system to dedicated Company leases in Texas. At the time the Company entered into the agreement, Metalmark Capital owned the majority of the outstanding equity interests of Monarch Oil Pipeline LLC and/or its parent. The system began service during the fourth quarter of 2015 and provides connectivity to both a regional refinery market as well as the Cushing market hub. The Company incurred gathering fees, which were paid to Monarch Oil Pipeline LLC, of $0.5 million and $1.8 million for the three and nine months ended September 30, 2017, respectively, associated with the approximately 0.3 MMBoe and 0.9 MMBoe, respectively, of oil production transported under the agreement. These costs are recorded as an offset to Oil and gas sales in the Company’s Consolidated Statement of Operations. The aforementioned production was recognized as Oil and gas sales on the Company’s Consolidated Statement of Operations at the time it was sold to the purchasers, who are unaffiliated third parties, after passing through the gathering and transportation system. The audit committee of the Board of Directors reviewed and approved the terms of the agreement with Monarch Oil Pipeline LLC.
 
Purchases of Senior Unsecured Notes
 
On February 29, 2016, JEH and Jones Energy Finance Corp. purchased $50.0 million principal amount of their outstanding 2023 Notes from investment funds managed by Magnetar Capital and its affiliates, which investment funds collectively then owned more than 5% of a class of voting securities of the Company, for approximately $23.3 million excluding accrued interest and including any associated fees. On the same day, JEH and Jones Energy Finance Corp. purchased an additional $50.0 million principal amount of their outstanding 2023 Notes from investment funds managed by Blackstone Group Management L.L.C. and its affiliates, which investment funds collectively then owned more than 5% of a class of voting securities of the Company, for approximately $23.3 million excluding accrued interest and including any associated fees. In conjunction with the extinguishment of this $100.0 million principal amount of debt, JEH recognized cancellation of debt income of $48.3 million on a pre-tax basis. This income is recorded in Gain on debt extinguishment on the Company’s Consolidated Statement of Operations.

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Issuance of Class A Shares
 
In connection with the August 2016 issuance of Class A common stock pursuant to an underwritten public offering as described above under “Item 11. Stockholders’ and Mezzanine equity—Offering of Class A Common Stock,” affiliates of JVL Advisors, L.L.C. (“JVL”), who then owned more than 5% of a class of voting securities of the Company, purchased 9,025,270 shares of Class A common stock, prior to adjustment for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 12, “Stockholders’ and Mezzanine equity”, in the offering, for gross proceeds to the Company of $25.0 million, before underwriting discounts and commissions of $1.1 million.
 
Following its purchase in the offering, JVL owned in excess of 15% of our outstanding voting stock. As a result, the Company entered into a letter agreement with JVL (the “JVL Letter Agreement”) in connection with the offering. The JVL Letter Agreement approved, pursuant to Section 203 of the Delaware General Corporation Law (“Section 203”), the purchase of shares of Class A common stock in the offering by JVL. This approval resulted in JVL not being subject to the restrictions on “business combinations” contained in Section 203. In consideration of such approval, JVL agreed that, among other things:
 
	·		it will not acquire any material assets of the Company;	
	·		it will not become the owner of more than 19.9% of the Company’s outstanding voting stock (other than as a result of actions taken solely by the Company) without the prior approval of the Company’s independent directors who are not affiliated with JVL; and	
	·		it will not engage in any “business combination” (as defined in the JVL Letter Agreement).	
 
On May 3, 2017, the Company amended and restated its registration rights agreement dated August 29, 2013 (as amended and restated, the “Restated Registration Rights Agreement”) to add JVL as a party in order to facilitate an orderly distribution of JVL’s shares of Class A common stock in the future, a copy of which was filed on the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 3, 2017.
 
Issuance of Series A Preferred Stock
 
In connection with the August 2016 issuance of Series A preferred stock pursuant to an underwritten public offering as described above under “Item 11. Stockholders’ and Mezzanine equity—Offering of 8.0% Series A Perpetual Convertible Preferred Stock,” affiliates of Metalmark, who then owned more than 5% of a class of voting securities of the Company and had two representatives on our Board of Directors, purchased 200,000 shares of Series A preferred stock in the offering, for gross proceeds to the Company of $10.0 million, before underwriting discounts and commissions of $400,000.
 
Amended and Restated Registration Rights and Stockholders Agreement
 
On May 2, 2017, we entered into an Amended and Restated Registration Rights and Stockholders Agreement (the “Restated Agreement”) with certain entities affiliated with the Jones family (the “Jones Family Entities”), Metalmark and JVL.
 
The Restated Agreement amends and restates in its entirety that certain Registration Rights and Stockholders Agreement, dated July 29, 2013 (the “Original Agreement”), by and among the Company, Metalmark and the Jones Family Entities, to, among other things, provide JVL with certain rights, in addition to those rights granted to Metalmark and the Jones Family Entities in the Original Agreement, to require the Company to register the sale of any number of JVL’s shares of Class A common stock. JVL shall have the right to cause no more than one such required or “demand” registration, which shall be requested by a majority in interest of the JVL holders who hold certain equity securities of the Company or securities convertible or exchangeable into equity securities of the Company. The Company is not obligated to affect any demand registration in which the anticipated aggregate offering price included in such offering is equal to or less than $50,000,000 ($25,000,000 where the registration is on a Form S-3). Furthermore, if, at any time, the Company proposes to register an offering of Class A common stock (subject to certain exceptions) for the Company’s own account, then it must give prompt notice to Metalmark, JVL and the Jones Family Entities to allow them to include a specified number of their shares in that registration statement. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and the Company’s right to

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delay or withdraw a registration statement under certain circumstances. The Company will generally be obligated to pay all registration expenses in connection with the registration obligations, regardless of whether a registration statement is filed or becomes effective. The Restated Agreement also includes customary provisions dealing with indemnification, contribution and allocation of expenses.
 
15.      Commitments and Contingencies
 
Litigation
 
The Company is subject to legal proceedings and claims that arise in the ordinary course of its business. When applicable, we record accruals for contingencies when it is probable that a liability will be incurred and the amount of loss can be reasonably estimated. While the outcome of lawsuits and other proceedings against us cannot be predicted with certainty, in the opinion of management, individually or in the aggregate, no such lawsuits are expected to have a material effect on our financial position, results of operations, or liquidity.
 
In an action filed on June 12, 2015 in the 31 st District Court of Hemphill County, Texas, Donna Kim Flowers and Mitchell Kirk Flowers v. Jones Energy, LLC f/k/a Jones Energy Limited, LLC f/k/a Jones Energy, Ltd. (Case No. 7225), the Company was sued by Donna Kim Flowers and Mitchell Kirk Flowers (the “plaintiffs”). The plaintiffs own surface rights to property located in Hemphill County, Texas. The mineral rights are leased to third parties, and the Company is the operator of the Oil and Gas Mineral Lease. On May 28, 2010, the plaintiffs and the Company entered into a Surface Use Agreement concerning the Company’s operations on the property, which require the Company to minimize disruption and damage to the plaintiffs’ surface rights. The plaintiffs allege that the Company is in breach of such contract, and seek monetary damages. In June 2016, the Company presented a settlement offer to the plaintiffs. As a result of this settlement offer, the Company accrued $1.5 million related to its estimated obligation under this settlement offer. This accrual was included in accrued liabilities on the Company’s Consolidated Balance Sheet as of December 31, 2016, and the charge was recorded as general and administrative expense on the Company’s Consolidated Statement of Operations during the second quarter of 2016. In June 2017, the Company presented a revised settlement offer to the plaintiffs and the plaintiff accepted. The settlement was paid in cash during June 2017. Upon settlement, the Company recognized an additional charge of $1.4 million which was recorded as general and administrative expense on the Company’s Consolidated Statement of Operations during the second quarter of 2017.
 
16.      Subsequent Events
 
Class B to Class A Share Exchanges
 
On October 2, 2017, certain Class B shareholders, including Metalmark, exchanged an aggregate of 12,689,815 shares of Class B common stock (together with a corresponding number of JEH Units) for shares of Class A common stock on a one-for-one basis (the “October Exchanges”). As of September 30, 2017 and December 31, 2016, the Company had recorded a TRA liability of $55.8 million and $43.0 million, respectively, for the estimated payments that will be made to Class B shareholders who have exchanged shares of Class B common stock, after adjusting for the TRA liability reduction as a result of the increase in tax basis arising from such exchanges. After the October Exchanges, the gross TRA liability increased by approximately $50.3 million. Substantially all of the increase in TRA liability will be offset as a result of the valuation allowance recorded against the deferred tax asset generated in the exchange, the utilization of which would lead to payment of the TRA liability.
 
Preferred Stock Dividend Declared
 
On October 9, 2017, the Company’s Board of Directors declared a quarterly dividend per share equal to 8.0% based on the liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock, to be paid entirely in shares of Class A common stock (the “November Preferred Dividend”). The price per share of the Class A common stock used to determine the number of shares issued will equal 95% of the average volume-weighted average price per share for each day during the five-consecutive day trading period ending immediately prior to the payment date. The November Preferred Dividend will be paid on November 15, 2017 for the period beginning on the last payment date of August 15, 2017 through November 14, 2017 to shareholders of record as of November 1, 2017.

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17.      Subsidiary Guarantors
 
The 2022 Notes and the 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of JEH’s current subsidiaries (except Jones Energy Finance Corp. and two immaterial subsidiaries) and certain future subsidiaries, including any future subsidiaries that guarantee any indebtedness under the Revolver. Each subsidiary guarantor is 100% owned by JEH, and all guarantees are full and unconditional, subject to customary exceptions pursuant to the indentures governing our 2022 Notes and 2023 Notes, as discussed below, and joint and several with all other subsidiary guarantees and the parent guarantee. Any subsidiaries of JEH other than the subsidiary guarantors and Jones Energy Finance Corp. are immaterial.
 
As of December 31, 2016, the 2022 Notes and the 2023 Notes were guaranteed on a senior unsecured basis by the Company and by all of its significant subsidiaries, other than Nosley SCOOP, LLC and Nosley Acquisition, LLC. These subsidiaries have since become guarantors during the first quarter of 2017 and are therefore presented accordingly in the accompanying condensed consolidated guarantor financial information.
 
Guarantees of the 2022 Notes and 2023 Notes will be released under certain circumstances, including (i) in connection with any sale or other disposition of (a) all or substantially all of the properties or assets of a guarantor (including by way of merger or consolidation) or (b) all of the capital stock of such guarantor, in each case, to a person that is not the Company or a restricted subsidiary of the Company, (ii) if the Company designates any restricted subsidiary that is a guarantor as an unrestricted subsidiary, (iii) upon legal defeasance, covenant defeasance or satisfaction and discharge of the applicable indenture, or (iv) at such time as such guarantor ceases to guarantee any other indebtedness of the Company or any other guarantor.
 
The Company is a holding company whose sole material asset is an equity interest in JEH. The Company is the sole managing member of JEH and is responsible for all operational, management and administrative decisions related to JEH’s business. In accordance with JEH’s limited liability company agreement, the Company may not be removed as the sole managing member of JEH.
 
As of September 30, 2017, the Company held 74,353,789 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 23,718,779 JEH Units are held by the Class B shareholders. The Class B shareholders have no voting rights with respect to their economic interest in JEH.
 
The Company has two classes of common stock, Class A common stock, which was sold to investors in the IPO, and Class B common stock, and one series of preferred stock, Series A preferred stock. Pursuant to the Company’s certificate of incorporation, each share of Class A common stock is entitled to one vote per share, and the shares of Class A common stock are entitled to 100% of the economic interests in the Company. Each share of Class B common stock has no economic rights in the Company, but entitles its holder to one vote on all matters to be voted on by the Company’s stockholders generally. Except as required by law or the Company’s certificate of incorporation, which includes the certificate of designations for the Series A preferred stock, the holders of Series A preferred stock have no voting rights (other than with respect to certain matters regarding the Series A preferred stock or when dividends payable on the Series A preferred stock have not been paid for an aggregate of six quarterly dividend periods, or more, whether or not consecutive, as provided in the certificate of designations for the Series A preferred stock).
 
In connection with a reorganization that occurred immediately prior to the IPO, each Existing Owner was issued a number of shares of Class B common stock that was equal to the number of JEH Units that such Class B shareholders held. Holders of the Company’s Class A common stock and Class B common stock generally vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval. Accordingly, the Class B shareholders collectively have a number of votes in the Company equal to the aggregate number of JEH Units that they hold.
 
The Class B shareholders have the right, pursuant to the terms of an exchange agreement by and among the Company, JEH and each of the Class B shareholders (the “Exchange Agreement”), to exchange their JEH Units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. As a result, the Company expects that over time the Company will have an increasing economic interest in JEH as Class B common stock and JEH Units are exchanged for Class A common stock. Moreover, any transfers of JEH Units outside of the Exchange Agreement (other than permitted transfers to affiliates) must be approved by the Company. The Company intends to retain full voting and management control over JEH.

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During the preparation of the condensed consolidating financial information of Jones Energy, Inc. and Subsidiaries in the second quarter of 2017, it was determined that the Issuer Investment in subsidiaries and the related Eliminations at December 31, 2016 as filed in the Company’s 2016 Form 10-K were improperly calculated and understated by $453.2 million. Additionally, it was determined that the Guarantor Subsidiaries Intercompany payable balances and the related Eliminations and the Issuer Intercompany receivable and the related Eliminations at December 31, 2016 as filed in the Company’s 2016 Form 10-K were improperly calculated and overstated by $453.2 million and $80.0 million, respectively. In addition, it was determined that the Issuer Equity interest in income (loss) and the related Eliminations for the three and nine months period ended September 30, 2016 as filed in the Company’s third quarter 2016 Form 10-Q were improperly calculated and understated by $13.2 million and $19.1 million, respectively. Lastly, it was determined that the Issuer Adjustments to reconcile net income (loss) to net cash provided by operating activities and the related Eliminations for the nine months period ended September 30, 2016 as filed in the Company’s third quarter 2016 Form 10-Q was improperly calculated and overstated by $19.1 million.
 
The errors, which the Company has determined are not material to this disclosure, had no impact on the total assets of the Parent or the Guarantor Subsidiaries and are eliminated upon consolidation, and therefore have no impact on the Company’s consolidated financial condition, results of operations or cash flows.
 
The Company has revised the Condensed Consolidating Balance Sheets for the Issuer, Guarantor Subsidiaries and Eliminations as of December 31, 2016, the Condensed Consolidating Income Statements for the Issuer and Eliminations for the three and nine months period ended September 30, 2016 and the Condensed Consolidating Statement of Cash Flows for the nine months ended September 30, 2016 to correct for these errors.

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Jones Energy, Inc.
Condensed Consolidating Balance Sheet
 
September 30, 2017
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	Guarantor	 	Non-Guarantor	 	 	 	 	 	 	 	
(in thousands of dollars)	    	JEI (Parent)	    	Issuers	    	Subsidiaries	    	Subsidiaries	    	Eliminations	    	Consolidated	 	
Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash	 	$	3,254	 	$	35	 	$	2,169	 	$	20	 	$	 —	 	$	5,478	 	
Accounts receivable, net	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas sales	 	 	 —	 	 	 —	 	 	29,136	 	 	 —	 	 	 —	 	 	29,136	 	
Joint interest owners	 	 	 —	 	 	 —	 	 	17,533	 	 	 —	 	 	 —	 	 	17,533	 	
Other	 	 	 —	 	 	2,162	 	 	1,708	 	 	 —	 	 	 —	 	 	3,870	 	
Commodity derivative assets	 	 	 —	 	 	7,590	 	 	 —	 	 	 —	 	 	 —	 	 	7,590	 	
Other current assets	 	 	3,128	 	 	431	 	 	6,832	 	 	 —	 	 	 —	 	 	10,391	 	
Intercompany receivable	 	 	199,444	 	 	1,104,136	 	 	 —	 	 	 —	 	 	(1,303,580)	 	 	 —	 	
Total current assets	 	 	205,826	 	 	1,114,354	 	 	57,378	 	 	20	 	 	(1,303,580)	 	 	73,998	 	
Oil and gas properties, net, at cost under the successful efforts method	 	 	 —	 	 	 —	 	 	1,578,739	 	 	 —	 	 	 —	 	 	1,578,739	 	
Other property, plant and equipment, net	 	 	 —	 	 	 —	 	 	2,015	 	 	550	 	 	 —	 	 	2,565	 	
Commodity derivative assets	 	 	 —	 	 	1,608	 	 	 —	 	 	 —	 	 	 —	 	 	1,608	 	
Other assets	 	 	 —	 	 	3,707	 	 	961	 	 	 —	 	 	 —	 	 	4,668	 	
Investment in subsidiaries	 	 	292,368	 	 	298,896	 	 	 —	 	 	 —	 	 	(591,264)	 	 	 —	 	
Total assets	 	$	498,194	 	$	1,418,565	 	$	1,639,093	 	$	570	 	$	(1,894,844)	 	$	1,661,578	 	
Liabilities and Stockholders’ Equity	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Trade accounts payable	 	$	 —	 	$	59	 	$	67,491	 	$	 —	 	$	 —	 	$	67,550	 	
Oil and gas sales payable	 	 	 —	 	 	 —	 	 	21,510	 	 	 —	 	 	 —	 	 	21,510	 	
Accrued liabilities	 	 	33	 	 	14,593	 	 	9,845	 	 	 1	 	 	 —	 	 	24,472	 	
Commodity derivative liabilities	 	 	 —	 	 	15,696	 	 	 —	 	 	 —	 	 	 —	 	 	15,696	 	
Other current liabilities	 	 	639	 	 	1,985	 	 	600	 	 	 —	 	 	 —	 	 	3,224	 	
Intercompany payable	 	 	 —	 	 	 —	 	 	1,300,579	 	 	3,001	 	 	(1,303,580)	 	 	 —	 	
Total current liabilities	 	 	672	 	 	32,333	 	 	1,400,025	 	 	3,002	 	 	(1,303,580)	 	 	132,452	 	
Long-term debt	 	 	 —	 	 	698,740	 	 	 —	 	 	 —	 	 	 —	 	 	698,740	 	
Deferred revenue	 	 	 —	 	 	5,632	 	 	 —	 	 	 —	 	 	 —	 	 	5,632	 	
Commodity derivative liabilities	 	 	 —	 	 	5,355	 	 	 —	 	 	 —	 	 	 —	 	 	5,355	 	
Asset retirement obligations	 	 	 —	 	 	 —	 	 	19,239	 	 	 —	 	 	 —	 	 	19,239	 	
Liability under tax receivable agreement	 	 	55,096	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	55,096	 	
Other liabilities	 	 	 —	 	 	310	 	 	700	 	 	 —	 	 	 —	 	 	1,010	 	
Deferred tax liabilities	 	 	 —	 	 	2,732	 	 	 —	 	 	 —	 	 	 —	 	 	2,732	 	
Total liabilities	 	 	55,768	 	 	745,102	 	 	1,419,964	 	 	3,002	 	 	(1,303,580)	 	 	920,256	 	
Mezzanine equity	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Series A preferred stock, $0.001 par value; 1,839,995 shares issued and outstanding at September 30, 2017	 	 	89,413	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	89,413	 	
Stockholders’/ members' equity (deficit)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Members' equity	 	 	 —	 	 	673,463	 	 	219,129	 	 	(2,432)	 	 	(890,160)	 	 	 —	 	
Class A common stock, $0.001 par value; 74,376,391 shares issued and 74,353,789 shares outstanding at September 30, 2017	 	 	74	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	74	 	
Class B common stock, $0.001 par value; 23,718,779 shares issued and outstanding at September 30, 2017	 	 	24	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	24	 	
Treasury stock, at cost: 22,602 shares at September 30, 2017	 	 	(358)	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(358)	 	
Additional paid-in-capital	 	 	534,499	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	534,499	 	
Retained earnings (deficit)	 	 	(181,226)	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(181,226)	 	
Stockholders' equity (deficit)	 	 	353,013	 	 	673,463	 	 	219,129	 	 	(2,432)	 	 	(890,160)	 	 	353,013	 	
Non-controlling interest	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	298,896	 	 	298,896	 	
Total stockholders’ equity	 	 	353,013	 	 	673,463	 	 	219,129	 	 	(2,432)	 	 	(591,264)	 	 	651,909	 	
Total liabilities and stockholders’ equity	 	$	498,194	 	$	1,418,565	 	$	1,639,093	 	$	570	 	$	(1,894,844)	 	$	1,661,578	 	

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Jones Energy, Inc.
Condensed Consolidating Balance Sheet
December 31, 2016

 	 	 	 	 	 	 	 	Guarantor	 	Non-Guarantor	 	 	 	 	 	 	 	
(in thousands of dollars)	    	JEI (Parent)	    	Issuers	    	Subsidiaries	    	Subsidiaries	    	Eliminations	    	Consolidated	 	
Assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current assets	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash	 	$	27,164	 	$	1,975	 	$	5,483	 	$	20	 	$	 —	 	$	34,642	 	
Accounts receivable, net	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas sales	 	 	 —	 	 	 —	 	 	26,568	 	 	 —	 	 	 —	 	 	26,568	 	
Joint interest owners	 	 	 —	 	 	 —	 	 	5,267	 	 	 —	 	 	 —	 	 	5,267	 	
Other	 	 	 —	 	 	5,434	 	 	627	 	 	 —	 	 	 —	 	 	6,061	 	
Commodity derivative assets	 	 	 —	 	 	24,100	 	 	 —	 	 	 —	 	 	 —	 	 	24,100	 	
Other current assets	 	 	 —	 	 	422	 	 	2,262	 	 	 —	 	 	 —	 	 	2,684	 	
Intercompany receivable	 	 	15,666	 	 	1,100,834	 	 	 —	 	 	 —	 	 	(1,116,500)	 	 	 —	 	
Total current assets	 	 	42,830	 	 	1,132,765	 	 	40,207	 	 	20	 	 	(1,116,500)	 	 	99,322	 	
Oil and gas properties, net, at cost under the successful efforts method	 	 	 —	 	 	 —	 	 	1,743,588	 	 	 —	 	 	 —	 	 	1,743,588	 	
Other property, plant and equipment, net	 	 	 —	 	 	 —	 	 	2,378	 	 	618	 	 	 —	 	 	2,996	 	
Commodity derivative assets	 	 	 —	 	 	34,744	 	 	 —	 	 	 —	 	 	 —	 	 	34,744	 	
Other assets	 	 	 —	 	 	5,265	 	 	785	 	 	 —	 	 	 —	 	 	6,050	 	
Investment in subsidiaries	 	 	531,363	 	 	453,237	 	 	 —	 	 	 —	 	 	(984,600)	 	 	 —	 	
Total assets	 	$	574,193	 	$	1,626,011	 	$	1,786,958	 	$	638	 	$	(2,101,100)	 	$	1,886,700	 	
Liabilities and Stockholders’ Equity	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Current liabilities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Trade accounts payable	 	$	 —	 	$	13	 	$	36,514	 	$	 —	 	$	 —	 	$	36,527	 	
Oil and gas sales payable	 	 	 —	 	 	 —	 	 	28,339	 	 	 —	 	 	 —	 	 	28,339	 	
Accrued liabilities	 	 	3,874	 	 	11,227	 	 	10,597	 	 	 9	 	 	 —	 	 	25,707	 	
Commodity derivative liabilities	 	 	 —	 	 	14,650	 	 	 —	 	 	 —	 	 	 —	 	 	14,650	 	
Other current liabilities	 	 	 —	 	 	1,984	 	 	600	 	 	 —	 	 	 —	 	 	2,584	 	
Intercompany payable	 	 	 —	 	 	 —	 	 	1,113,704	 	 	2,796	 	 	(1,116,500)	 	 	 —	 	
Total current liabilities	 	 	3,874	 	 	27,874	 	 	1,189,754	 	 	2,805	 	 	(1,116,500)	 	 	107,807	 	
Long-term debt	 	 	 —	 	 	724,009	 	 	 —	 	 	 —	 	 	 —	 	 	724,009	 	
Deferred revenue	 	 	 —	 	 	7,049	 	 	 —	 	 	 —	 	 	 —	 	 	7,049	 	
Commodity derivative liabilities	 	 	 —	 	 	1,209	 	 	 —	 	 	 —	 	 	 —	 	 	1,209	 	
Asset retirement obligations	 	 	 —	 	 	 —	 	 	19,458	 	 	 —	 	 	 —	 	 	19,458	 	
Liability under tax receivable agreement	 	 	43,045	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	43,045	 	
Other liabilities	 	 	 —	 	 	269	 	 	523	 	 	 —	 	 	 —	 	 	792	 	
Deferred tax liabilities	 	 	85	 	 	2,820	 	 	 —	 	 	 —	 	 	 —	 	 	2,905	 	
Total liabilities	 	 	47,004	 	 	763,230	 	 	1,209,735	 	 	2,805	 	 	(1,116,500)	 	 	906,274	 	
Mezzanine equity	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Series A preferred stock, $0.001 par value; 1,840,000 shares issued and outstanding at December 31, 2016	 	 	88,975	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	88,975	 	
Stockholders’/ members' equity (deficit)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Members' equity	 	 	 —	 	 	862,781	 	 	577,223	 	 	(2,167)	 	 	(1,437,837)	 	 	 —	 	
Class A common stock, $0.001 par value; 57,048,076 shares issued and 57,025,474 shares outstanding at December 31, 2016	 	 	57	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	57	 	
Class B common stock, $0.001 par value; 29,832,098 shares issued and outstanding at December 31, 2016	 	 	30	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	30	 	
Treasury stock, at cost: 22,602 shares at December 31, 2016	 	 	(358)	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(358)	 	
Additional paid-in-capital	 	 	447,137	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	447,137	 	
Retained earnings (deficit)	 	 	(8,652)	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(8,652)	 	
Stockholders' equity (deficit)	 	 	438,214	 	 	862,781	 	 	577,223	 	 	(2,167)	 	 	(1,437,837)	 	 	438,214	 	
Non-controlling interest	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	453,237	 	 	453,237	 	
Total stockholders’ equity	 	 	438,214	 	 	862,781	 	 	577,223	 	 	(2,167)	 	 	(984,600)	 	 	891,451	 	
Total liabilities and stockholders’ equity	 	$	574,193	 	$	1,626,011	 	$	1,786,958	 	$	638	 	$	(2,101,100)	 	$	1,886,700	 	

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Jones Energy, Inc.
Condensed Consolidating Statement of Operations
 
Three Months Ended September 30, 2017

 	 	 	 	 	 	 	 	Guarantor	 	Non-Guarantor	 	 	 	 	 	 	 	
(in   thousands of dollars)	    	JEI   (Parent)	    	Issuers	    	Subsidiaries	    	Subsidiaries	    	Eliminations	    	Consolidated	 	
Operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas sales	 	$	 —	 	$	 —	 	$	43,636	 	$	 —	 	$	 —	 	$	43,636	 	
Other revenues	 	 	 —	 	 	475	 	 	91	 	 	 —	 	 	 —	 	 	566	 	
Total operating revenues	 	 	 —	 	 	475	 	 	43,727	 	 	 —	 	 	 —	 	 	44,202	 	
Operating costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating	 	 	 —	 	 	 —	 	 	9,458	 	 	 —	 	 	 —	 	 	9,458	 	
Production and ad valorem taxes	 	 	 —	 	 	 —	 	 	2,757	 	 	 —	 	 	 —	 	 	2,757	 	
Exploration	 	 	 —	 	 	 —	 	 	1,969	 	 	 —	 	 	 —	 	 	1,969	 	
Depletion, depreciation and amortization	 	 	 —	 	 	 —	 	 	46,330	 	 	23	 	 	 —	 	 	46,353	 	
Impairment of oil and gas properties	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	
Accretion of ARO liability	 	 	 —	 	 	 —	 	 	253	 	 	 —	 	 	 —	 	 	253	 	
General and administrative	 	 	 —	 	 	3,044	 	 	4,705	 	 	70	 	 	 —	 	 	7,819	 	
Total operating expenses	 	 	 —	 	 	3,044	 	 	65,472	 	 	93	 	 	 —	 	 	68,609	 	
Operating income (loss)	 	 	 —	 	 	(2,569)	 	 	(21,745)	 	 	(93)	 	 	 —	 	 	(24,407)	 	
Other income (expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	 	 	 —	 	 	(12,917)	 	 	100	 	 	 —	 	 	 —	 	 	(12,817)	 	
Net gain (loss) on commodity derivatives	 	 	 —	 	 	(32,539)	 	 	 —	 	 	 —	 	 	 —	 	 	(32,539)	 	
Other income (expense)	 	 	(12,417)	 	 	(25)	 	 	(1,250)	 	 	 —	 	 	 —	 	 	(13,692)	 	
Other income (expense), net	 	 	(12,417)	 	 	(45,481)	 	 	(1,150)	 	 	 —	 	 	 —	 	 	(59,048)	 	
Income (loss) before income tax	 	 	(12,417)	 	 	(48,050)	 	 	(22,895)	 	 	(93)	 	 	 —	 	 	(83,455)	 	
Equity interest in income (loss)	 	 	(52,955)	 	 	(18,083)	 	 	 —	 	 	 —	 	 	71,038	 	 	 —	 	
Income tax provision (benefit)	 	 	(566)	 	 	74	 	 	 —	 	 	 —	 	 	 —	 	 	(492)	 	
Net income (loss)	 	 	(64,806)	 	 	(66,207)	 	 	(22,895)	 	 	(93)	 	 	71,038	 	 	(82,963)	 	
Net income (loss) attributable to non-controlling interests	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(18,157)	 	 	(18,157)	 	
Net income (loss) attributable to controlling interests	 	$	(64,806)	 	$	(66,207)	 	$	(22,895)	 	$	(93)	 	$	89,195	 	$	(64,806)	 	
Dividends and accretion on preferred stock	 	 	(1,966)	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(1,966)	 	
Net income (loss) attributable to common shareholders	 	$	(66,772)	 	$	(66,207)	 	$	(22,895)	 	$	(93)	 	$	89,195	 	$	(66,772)	 	

37

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Jones Energy, Inc.
Condensed Consolidating Statement of Operations
 
Nine Months Ended September 30, 2017

 	 	 	 	 	 	 	 	Guarantor	 	Non-Guarantor	 	 	 	 	 	 	 	
(in thousands of dollars)	    	JEI (Parent)	    	Issuers	    	Subsidiaries	    	Subsidiaries	    	Eliminations	    	Consolidated	 	
Operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas sales	 	$	 —	 	$	 —	 	$	132,427	 	$	 —	 	$	 —	 	$	132,427	 	
Other revenues	 	 	 —	 	 	1,417	 	 	217	 	 	 —	 	 	 —	 	 	1,634	 	
Total operating revenues	 	 	 —	 	 	1,417	 	 	132,644	 	 	 —	 	 	 —	 	 	134,061	 	
Operating costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating	 	 	 —	 	 	 —	 	 	27,689	 	 	 —	 	 	 —	 	 	27,689	 	
Production and ad valorem taxes	 	 	 —	 	 	 —	 	 	4,641	 	 	 —	 	 	 —	 	 	4,641	 	
Exploration	 	 	 —	 	 	 —	 	 	11,638	 	 	 —	 	 	 —	 	 	11,638	 	
Depletion, depreciation and amortization	 	 	 —	 	 	 —	 	 	127,275	 	 	68	 	 	 —	 	 	127,343	 	
Impairment of oil and gas properties	 	 	 —	 	 	 —	 	 	148,016	 	 	 —	 	 	 —	 	 	148,016	 	
Accretion of ARO liability	 	 	 —	 	 	 —	 	 	720	 	 	 —	 	 	 —	 	 	720	 	
General and administrative	 	 	 —	 	 	8,957	 	 	15,336	 	 	200	 	 	 —	 	 	24,493	 	
Total operating expenses	 	 	 —	 	 	8,957	 	 	335,315	 	 	268	 	 	 —	 	 	344,540	 	
Operating income (loss)	 	 	 —	 	 	(7,540)	 	 	(202,671)	 	 	(268)	 	 	 —	 	 	(210,479)	 	
Other income (expense)  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	 	 	 —	 	 	(38,673)	 	 	292	 	 	 —	 	 	 —	 	 	(38,381)	 	
Net gain (loss) on commodity derivatives	 	 	 —	 	 	11,308	 	 	 —	 	 	 —	 	 	 —	 	 	11,308	 	
Other income (expense)	 	 	15,831	 	 	(72)	 	 	(1,370)	 	 	 —	 	 	 —	 	 	14,389	 	
Other income (expense), net	 	 	15,831	 	 	(27,437)	 	 	(1,078)	 	 	 —	 	 	 —	 	 	(12,684)	 	
Income (loss) before income tax	 	 	15,831	 	 	(34,977)	 	 	(203,749)	 	 	(268)	 	 	 —	 	 	(223,163)	 	
Equity interest in income (loss)	 	 	(167,027)	 	 	(71,966)	 	 	 —	 	 	 —	 	 	238,993	 	 	 —	 	
Income tax provision (benefit)	 	 	(2,787)	 	 	80	 	 	 —	 	 	 —	 	 	 —	 	 	(2,707)	 	
Net income (loss)	 	 	(148,409)	 	 	(107,023)	 	 	(203,749)	 	 	(268)	 	 	238,993	 	 	(220,456)	 	
Net income (loss) attributable to non-controlling interests	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(72,047)	 	 	(72,047)	 	
Net income (loss) attributable to controlling interests  	 	$	(148,409)	 	$	(107,023)	 	$	(203,749)	 	$	(268)	 	$	311,040	 	$	(148,409)	 	
Dividends and accretion on preferred stock	 	 	(5,959)	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(5,959)	 	
Net income (loss) attributable to common shareholders	 	$	(154,368)	 	$	(107,023)	 	$	(203,749)	 	$	(268)	 	$	311,040	 	$	(154,368)	 	

38

Table of Contents

Jones Energy, Inc.
Condensed Consolidating Statement of Operations
 
Three Months Ended September 30, 2016

 	 	 	 	 	 	 	 	Guarantor	 	Non-Guarantor	 	 	 	 	 	 	 	
(in thousands of dollars)	    	JEI (Parent)	    	Issuers	    	Subsidiaries	    	Subsidiaries	    	Eliminations	    	Consolidated	 	
Operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas sales	 	$	 —	 	$	 —	 	$	32,582	 	$	 —	 	$	 —	 	$	32,582	 	
Other revenues	 	 	 —	 	 	587	 	 	184	 	 	 —	 	 	 —	 	 	771	 	
Total operating revenues	 	 	 —	 	 	587	 	 	32,766	 	 	 —	 	 	 —	 	 	33,353	 	
Operating costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating	 	 	 —	 	 	 —	 	 	7,865	 	 	 —	 	 	 —	 	 	7,865	 	
Production and ad valorem taxes	 	 	 —	 	 	 —	 	 	1,733	 	 	 —	 	 	 —	 	 	1,733	 	
Exploration	 	 	 —	 	 	 —	 	 	998	 	 	 —	 	 	 —	 	 	998	 	
Depletion, depreciation and amortization	 	 	 —	 	 	 —	 	 	36,527	 	 	23	 	 	 —	 	 	36,550	 	
Accretion of ARO liability	 	 	 —	 	 	 —	 	 	323	 	 	 —	 	 	 —	 	 	323	 	
General and administrative	 	 	 —	 	 	2,928	 	 	3,476	 	 	44	 	 	 —	 	 	6,448	 	
Total operating expenses	 	 	 —	 	 	2,928	 	 	50,922	 	 	67	 	 	 —	 	 	53,917	 	
Operating income (loss)	 	 	 —	 	 	(2,341)	 	 	(18,156)	 	 	(67)	 	 	 —	 	 	(20,564)	 	
Other income (expense)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	 	 	 —	 	 	(12,652)	 	 	(140)	 	 	 —	 	 	 —	 	 	(12,792)	 	
Net gain (loss) on commodity derivatives	 	 	 —	 	 	4,014	 	 	 —	 	 	 —	 	 	 —	 	 	4,014	 	
Other income (expense)	 	 	261	 	 	(25)	 	 	128	 	 	 —	 	 	 —	 	 	364	 	
Other income (expense), net	 	 	261	 	 	(8,663)	 	 	(12)	 	 	 —	 	 	 —	 	 	(8,414)	 	
Income (loss) before income tax	 	 	261	 	 	(11,004)	 	 	(18,168)	 	 	(67)	 	 	 —	 	 	(28,978)	 	
Equity interest in income (loss)	 	 	(15,999)	 	 	(13,240)	 	 	 —	 	 	 —	 	 	29,239	 	 	 —	 	
Income tax provision (benefit)	 	 	(5,885)	 	 	(664)	 	 	 —	 	 	 —	 	 	 —	 	 	(6,549)	 	
Net income (loss)	 	 	(9,853)	 	 	(23,580)	 	 	(18,168)	 	 	(67)	 	 	29,239	 	 	(22,429)	 	
Net income (loss) attributable to non-controlling interests	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(12,576)	 	 	(12,576)	 	
Net income (loss) attributable to controlling interests	 	$	(9,853)	 	$	(23,580)	 	$	(18,168)	 	$	(67)	 	$	41,815	 	$	(9,853)	 	
Dividends and accretion on preferred stock	 	 	(765)	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(765)	 	
Net income (loss) attributable to common shareholders	 	$	(10,618)	 	$	(23,580)	 	$	(18,168)	 	$	(67)	 	$	41,815	 	$	(10,618)	 	

39

Table of Contents

Jones Energy, Inc.
Condensed Consolidating Statement of Operations
 
Nine Months Ended September 30, 2016

 	 	 	 	 	 	 	 	Guarantor	 	Non-Guarantor	 	 	 	 	 	 	 	
(in thousands of dollars)	    	JEI (Parent)	    	Issuers	    	Subsidiaries	    	Subsidiaries	    	Eliminations	    	Consolidated	 	
Operating revenues	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil and gas sales	 	$	 —	 	$	 —	 	$	86,060	 	$	 —	 	$	 —	 	$	86,060	 	
Other revenues	 	 	 —	 	 	1,828	 	 	467	 	 	 —	 	 	 —	 	 	2,295	 	
Total operating revenues	 	 	 —	 	 	1,828	 	 	86,527	 	 	 —	 	 	 —	 	 	88,355	 	
Operating costs and expenses	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating	 	 	 —	 	 	 —	 	 	24,027	 	 	 —	 	 	 —	 	 	24,027	 	
Production and ad valorem taxes	 	 	 —	 	 	 —	 	 	5,061	 	 	 —	 	 	 —	 	 	5,061	 	
Exploration	 	 	 —	 	 	 —	 	 	1,237	 	 	 —	 	 	 —	 	 	1,237	 	
Depletion, depreciation and amortization	 	 	 —	 	 	 —	 	 	116,385	 	 	64	 	 	 —	 	 	116,449	 	
Accretion of ARO liability	 	 	 —	 	 	 —	 	 	913	 	 	 —	 	 	 —	 	 	913	 	
General and administrative	 	 	 —	 	 	8,782	 	 	13,087	 	 	209	 	 	 —	 	 	22,078	 	
Total operating expenses	 	 	 —	 	 	8,782	 	 	160,710	 	 	273	 	 	 —	 	 	169,765	 	
Operating income (loss)	 	 	 —	 	 	(6,954)	 	 	(74,183)	 	 	(273)	 	 	 —	 	 	(81,410)	 	
Other income (expense)  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	 	 	 —	 	 	(40,417)	 	 	20	 	 	 —	 	 	 —	 	 	(40,397)	 	
Gain on debt extinguishment	 	 	 —	 	 	99,530	 	 	 —	 	 	 —	 	 	 —	 	 	99,530	 	
Net gain (loss) on commodity derivatives	 	 	 —	 	 	(18,769)	 	 	 —	 	 	 —	 	 	 —	 	 	(18,769)	 	
Other income (expense)	 	 	423	 	 	(298)	 	 	126	 	 	 —	 	 	 —	 	 	251	 	
Other income (expense), net	 	 	423	 	 	40,046	 	 	146	 	 	 —	 	 	 —	 	 	40,615	 	
Income (loss) before income tax	 	 	423	 	 	33,092	 	 	(74,037)	 	 	(273)	 	 	 —	 	 	(40,795)	 	
Equity interest in income (loss)	 	 	(22,130)	 	 	(19,088)	 	 	 —	 	 	 —	 	 	41,218	 	 	 —	 	
Income tax provision (benefit)	 	 	(7,520)	 	 	(714)	 	 	 —	 	 	 —	 	 	 —	 	 	(8,234)	 	
Net income (loss)	 	 	(14,187)	 	 	14,718	 	 	(74,037)	 	 	(273)	 	 	41,218	 	 	(32,561)	 	
Net income (loss) attributable to non-controlling interests	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(18,374)	 	 	(18,374)	 	
Net income (loss) attributable to controlling interests  	 	$	(14,187)	 	$	14,718	 	$	(74,037)	 	$	(273)	 	$	59,592	 	$	(14,187)	 	
Dividends and accretion on preferred stock	 	 	(765)	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(765)	 	
Net income (loss) attributable to common shareholders	 	$	(14,952)	 	$	14,718	 	$	(74,037)	 	$	(273)	 	$	59,592	 	$	(14,952)	 	

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Jones Energy, Inc.
Condensed Consolidating Statement of Cash Flows
 
Nine Months Ended September 30, 2017

 	 	 	 	 	 	 	 	Guarantor	 	Non-Guarantor	 	 	 	 	 	 	 	
(in thousands of dollars)	   	JEI   (Parent)	   	Issuers	   	Subsidiaries	   	Subsidiaries	   	Eliminations	   	Consolidated	 	
Cash flows from operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	(148,409)	 	$	(107,023)	 	$	(203,749)	 	$	(268)	 	$	238,993	 	$	(220,456)	 	
Adjustments to reconcile net income (loss) to net cash provided by operating activities	 	 	118,459	 	 	64,770	 	 	317,377	 	 	268	 	 	(238,993)	 	 	261,881	 	
Net cash (used in) / provided by operations	 	 	(29,950)	 	 	(42,253)	 	 	113,628	 	 	 —	 	 	 —	 	 	41,425	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Additions to oil and gas properties	 	 	 —	 	 	 —	 	 	(179,152)	 	 	 —	 	 	 —	 	 	(179,152)	 	
Net adjustments to purchase price of properties acquired	 	 	 —	 	 	 —	 	 	2,391	 	 	 —	 	 	 —	 	 	2,391	 	
Proceeds from sales of assets	 	 	 —	 	 	 —	 	 	60,422	 	 	 —	 	 	 —	 	 	60,422	 	
Acquisition of other property, plant and equipment	 	 	 —	 	 	 —	 	 	(603)	 	 	 —	 	 	 —	 	 	(603)	 	
Current period settlements of matured derivative contracts	 	 	 —	 	 	69,412	 	 	 —	 	 	 —	 	 	 —	 	 	69,412	 	
Net cash (used in) / provided by investing	 	 	 —	 	 	69,412	 	 	(116,942)	 	 	 —	 	 	 —	 	 	(47,530)	 	
Cash flows from financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proceeds from issuance of long-term debt	 	 	 —	 	 	102,000	 	 	 —	 	 	 —	 	 	 —	 	 	102,000	 	
Repayment of long-term debt	 	 	 —	 	 	(129,000)	 	 	 —	 	 	 —	 	 	 —	 	 	(129,000)	 	
Payment of cash dividends on preferred stock	 	 	(3,367)	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	(3,367)	 	
Net distributions paid to JEH unitholders	 	 	1,075	 	 	(1,637)	 	 	 —	 	 	 —	 	 	 —	 	 	(562)	 	
Net payments for share based compensation	 	 	 —	 	 	(462)	 	 	 —	 	 	 —	 	 	 —	 	 	(462)	 	
Proceeds from sale of common stock	 	 	8,332	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	8,332	 	
Net cash (used in) / provided by financing	 	 	6,040	 	 	(29,099)	 	 	 —	 	 	 —	 	 	 —	 	 	(23,059)	 	
Net increase (decrease) in cash	 	 	(23,910)	 	 	(1,940)	 	 	(3,314)	 	 	 —	 	 	 —	 	 	(29,164)	 	
Cash	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Beginning of period	 	 	27,164	 	 	1,975	 	 	5,483	 	 	20	 	 	 —	 	 	34,642	 	
End of period	 	$	3,254	 	$	35	 	$	2,169	 	$	20	 	$	 —	 	$	5,478	 	

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Jones Energy, Inc.
Condensed Consolidating Statement of Cash Flows
 
Nine Months Ended September 30, 2016

 	 	 	 	 	 	 	 	Guarantor	 	Non-Guarantor	 	 	 	 	 	 	 	
(in thousands of dollars)	   	JEI   (Parent)	   	Issuers	   	Subsidiaries	   	Subsidiaries	   	Eliminations	   	Consolidated	 	
Cash flows from operating activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	(14,187)	 	$	14,718	 	$	(74,037)	 	$	(273)	 	$	41,218	 	$	(32,561)	 	
Adjustments to reconcile net income (loss) to net cash provided by operating activities	 	 	(134,592)	 	 	(53,206)	 	 	276,213	 	 	273	 	 	(41,218)	 	 	47,470	 	
Net cash (used in) / provided by operations	 	 	(148,779)	 	 	(38,488)	 	 	202,176	 	 	 —	 	 	 —	 	 	14,909	 	
Cash flows from investing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Additions to oil and gas properties	 	 	 —	 	 	 —	 	 	(212,419)	 	 	 —	 	 	 —	 	 	(212,419)	 	
Proceeds from sales of assets	 	 	 —	 	 	 —	 	 	1,615	 	 	 —	 	 	 —	 	 	1,615	 	
Acquisition of other property, plant and equipment	 	 	 —	 	 	 —	 	 	(194)	 	 	 —	 	 	 —	 	 	(194)	 	
Current period settlements of matured derivative contracts	 	 	 —	 	 	106,151	 	 	 —	 	 	 —	 	 	 —	 	 	106,151	 	
Net cash (used in) / provided by investing	 	 	 —	 	 	106,151	 	 	(210,998)	 	 	 —	 	 	 —	 	 	(104,847)	 	
Cash flows from financing activities	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Proceeds from issuance of long-term debt	 	 	 —	 	 	75,000	 	 	 —	 	 	 —	 	 	 —	 	 	75,000	 	
Repayment under long-term debt	 	 	 —	 	 	(42,000)	 	 	 —	 	 	 —	 	 	 —	 	 	(42,000)	 	
Purchase of senior notes	 	 	 —	 	 	(84,589)	 	 	 —	 	 	 —	 	 	 —	 	 	(84,589)	 	
Net distributions paid to JEH unitholders	 	 	9,910	 	 	(20,019)	 	 	 —	 	 	 —	 	 	 —	 	 	(10,109)	 	
Proceeds from sale of common stock	 	 	65,548	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	65,548	 	
Proceeds from sale of preferred stock	 	 	88,236	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	88,236	 	
Net cash (used in) / provided by financing	 	 	163,694	 	 	(71,608)	 	 	 —	 	 	 —	 	 	 —	 	 	92,086	 	
Net increase (decrease) in cash	 	 	14,915	 	 	(3,945)	 	 	(8,822)	 	 	 —	 	 	 —	 	 	2,148	 	
Cash	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 —	 	
Beginning of period	 	 	100	 	 	12,448	 	 	9,325	 	 	20	 	 	 —	 	 	21,893	 	
End of period	 	$	15,015	 	$	8,503	 	$	503	 	$	20	 	$	 —	 	$	24,041	 	

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Item 2. Management’s Discussion and Analysi  s of Financial Condition and Results of Operations
 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2016, filed with the Securities and Exchange Commission (the “Commission”) on March 10, 2017, and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report and in our quarterly report for the quarter ended March 31, 2017, filed with the Commission on May 5, 2017 and our quarterly report on Form 10-Q for the quarter ended June 30, 2017, filed with the Commission on August 7, 2017. Unless indicated otherwise in this Quarterly Report or the context requires otherwise, all references to “Jones Energy,” the “Company,” “our company,” “we,” “our” and “us” refer to Jones Energy, Inc. and its subsidiaries, including Jones Energy Holdings, LLC (“JEH”). Jones Energy, Inc. (“JONE”) is a holding company whose sole material asset is an equity interest in JEH.
 
Overview
 
We are an independent oil and gas company engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States, spanning areas of Texas and Oklahoma. Our Chairman and Chief Executive Officer, Jonny Jones, founded our predecessor company in 1988 in continuation of his family’s long history in the oil and gas business, which dates back to the 1920’s. We have grown rapidly by leveraging our focus on low cost drilling and completion methods and our horizontal drilling expertise to develop our inventory and execute several strategic acquisitions. We have accumulated extensive knowledge and experience in developing the Anadarko basin, having concentrated our operations in the Anadarko basin for over 25 years. We have drilled approximately 905 total wells as operator, including nearly 730 horizontal wells, since our formation and delivered compelling rates of return over various commodity price cycles. Our operations are focused on horizontal drilling and completions within two distinct areas in the Texas Panhandle and Oklahoma:
 
	·		the Eastern Anadarko Basin—targeting the liquids rich Woodford shale and Meramec formations in the Merge area of the STACK/SCOOP (the “Merge”); and	
 
	·		the Western Anadarko Basin—targeting the liquids rich Cleveland, Granite Wash, Tonkawa and Marmaton formations.	
 
We seek to optimize returns through a disciplined emphasis on controlling costs and promoting operational efficiencies, and we are recognized as one of the lowest cost drilling and completion operators in the Cleveland shale formation. We believe that our low-cost drilling expertise will apply directly to our new drilling in the Merge area, which is located approximately 150 miles to the east of our Cleveland play.
 
Third Quarter and Year-to-Date 2017 Highlights:
 
	·		Strong initial rates seen from six recently completed wells in the Merge, with rates still increasing.	
 
	·		First pair of long lateral Merge wells drilled at Company-record pace, currently undergoing completions.	
 
	·		Suspended drilling activity in Western Anadarko, released last remaining rig in October.	
 
	·		Average daily net production for third quarter 2017 of 21.4 MBoe/d.	
 
	·		Working with lenders to increase financial flexibility to enable increased Merge activity in 2018.	
 
	·		Net loss for the third quarter of 2017 of $83.0 million, non-GAAP adjusted net loss of $10.9 million, or a loss of $0.13 per share, and EBITDAX of $47.1 million.	

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Updated Capital Expenditures Outlook
 
As previously announced on August 3, 2017, we have revised our full year 2017 budget for capital expenditures to be $250.0 million versus the initial budget of $275.0 million. The updated budget reflects reduced activity in the Cleveland, realized and projected cost inflation, increased costs related to frac designs in the Merge, increased costs related to long lateral drilling, and less than anticipated non-op spending from the initial budget. The Company continues to have a high degree of flexibility in its program and could take further action if conditions merit

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

(in thousands of dollars except for 	 	Three Months Ended September 30, 	 	Nine Months Ended September 30, 	 	
production, sales price and average cost data)	    	2017	    	2016	    	Change	    	2017	    	2016	    	Change	    	
Revenues:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil	 	$	21,566	 	$	15,817	 	$	5,749	 	$	63,145	 	$	45,239	 	$	17,906	 	
Natural gas	 	 	9,421	 	 	9,580	 	 	(159)	 	 	33,615	 	 	21,237	 	 	12,378	 	
NGLs	 	 	12,649	 	 	7,185	 	 	5,464	 	 	35,667	 	 	19,584	 	 	16,083	 	
Total oil and gas	 	 	43,636	 	 	32,582	 	 	11,054	 	 	132,427	 	 	86,060	 	 	46,367	 	
Other	 	 	566	 	 	771	 	 	(205)	 	 	1,634	 	 	2,295	 	 	(661)	 	
Total operating revenues	 	 	44,202	 	 	33,353	 	 	10,849	 	 	134,061	 	 	88,355	 	 	45,706	 	
Costs and expenses:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating	 	 	9,458	 	 	7,865	 	 	1,593	 	 	27,689	 	 	24,027	 	 	3,662	 	
Production and ad valorem taxes	 	 	2,757	 	 	1,733	 	 	1,024	 	 	4,641	 	 	5,061	 	 	(420)	 	
Exploration	 	 	1,969	 	 	998	 	 	971	 	 	11,638	 	 	1,237	 	 	10,401	 	
Depletion, depreciation and amortization	 	 	46,353	 	 	36,550	 	 	9,803	 	 	127,343	 	 	116,449	 	 	10,894	 	
Impairment of oil and gas properties	 	 	 —	 	 	 —	 	 	 —	 	 	148,016	 	 	 —	 	 	148,016	 	
Accretion of ARO liability	 	 	253	 	 	323	 	 	(70)	 	 	720	 	 	913	 	 	(193)	 	
General and administrative	 	 	7,819	 	 	6,448	 	 	1,371	 	 	24,493	 	 	22,078	 	 	2,415	 	
Total costs and expenses	 	 	68,609	 	 	53,917	 	 	14,692	 	 	344,540	 	 	169,765	 	 	174,775	 	
Operating income (loss)	 	 	(24,407)	 	 	(20,564)	 	 	(3,843)	 	 	(210,479)	 	 	(81,410)	 	 	(129,069)	 	
Other income (expenses):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Interest expense	 	 	(12,817)	 	 	(12,792)	 	 	(25)	 	 	(38,381)	 	 	(40,397)	 	 	2,016	 	
Gain on debt extinguishment	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	 	99,530	 	 	(99,530)	 	
Net gain (loss) on commodity derivatives	 	 	(32,539)	 	 	4,014	 	 	(36,553)	 	 	11,308	 	 	(18,769)	 	 	30,077	 	
Other income/(expense)	 	 	(13,692)	 	 	364	 	 	(14,056)	 	 	14,389	 	 	251	 	 	14,138	 	
Total other income (expense)	 	 	(59,048)	 	 	(8,414)	 	 	(50,634)	 	 	(12,684)	 	 	40,615	 	 	(53,299)	 	
Income (loss) before income tax	 	 	(83,455)	 	 	(28,978)	 	 	(54,477)	 	 	(223,163)	 	 	(40,795)	 	 	(182,368)	 	
Income tax provision (benefit)	 	 	(492)	 	 	(6,549)	 	 	6,057	 	 	(2,707)	 	 	(8,234)	 	 	5,527	 	
Net income (loss)	 	 	(82,963)	 	 	(22,429)	 	 	(60,534)	 	 	(220,456)	 	 	(32,561)	 	 	(187,895)	 	
Net income (loss) attributable to non-controlling interests	 	 	(18,157)	 	 	(12,576)	 	 	(5,581)	 	 	(72,047)	 	 	(18,374)	 	 	(53,673)	 	
Net income (loss) attributable to controlling interests	 	$	(64,806)	 	$	(9,853)	 	$	(54,953)	 	$	(148,409)	 	$	(14,187)	 	$	(134,222)	 	
Dividends and accretion on preferred stock	 	 	(1,966)	 	 	(765)	 	 	(1,201)	 	 	(5,959)	 	 	(765)	 	 	(5,194)	 	
Net income (loss) attributable to common shareholders	 	$	(66,772)	 	$	(10,618)	 	$	(56,154)	 	$	(154,368)	 	$	(14,952)	 	$	(139,416)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net production volumes:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil (MBbls)	 	 	481	 	 	396	 	 	85	 	 	1,391	 	 	1,271	 	 	120	 	
Natural gas (MMcf)	 	 	5,171	 	 	4,602	 	 	569	 	 	15,663	 	 	14,130	 	 	1,533	 	
NGLs (MBbls)	 	 	627	 	 	549	 	 	78	 	 	1,833	 	 	1,633	 	 	200	 	
Total (MBoe)	 	 	1,970	 	 	1,712	 	 	258	 	 	5,835	 	 	5,259	 	 	576	 	
Average net (Boe/d)	 	 	21,413	 	 	18,609	 	 	2,804	 	 	21,374	 	 	19,193	 	 	2,181	 	
Average sales price, unhedged:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil (per Bbl), unhedged	 	$	44.84	 	$	39.94	 	$	4.90	 	$	45.40	 	$	35.59	 	$	9.81	 	
Natural gas (per Mcf), unhedged	 	 	1.82	 	 	2.08	 	 	(0.26)	 	 	2.15	 	 	1.50	 	 	0.65	 	
NGLs (per Bbl), unhedged	 	 	20.17	 	 	13.09	 	 	7.08	 	 	19.46	 	 	11.99	 	 	7.47	 	
Combined (per Boe), unhedged	 	 	22.15	 	 	19.03	 	 	3.12	 	 	22.70	 	 	16.36	 	 	6.34	 	
Average sales price, hedged:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil (per Bbl), hedged	 	$	79.50	 	$	87.34	 	$	(7.84)	 	$	81.44	 	$	86.26	 	$	(4.82)	 	
Natural gas (per Mcf), hedged	 	 	3.62	 	 	3.46	 	 	0.16	 	 	3.77	 	 	3.51	 	 	0.26	 	
NGLs (per Bbl), hedged	 	 	13.63	 	 	17.54	 	 	(3.91)	 	 	14.30	 	 	17.40	 	 	(3.10)	 	
Combined (per Boe), hedged	 	 	33.26	 	 	35.12	 	 	(1.86)	 	 	34.03	 	 	35.69	 	 	(1.66)	 	
Average costs (per BOE):	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Lease operating	 	$	4.80	 	$	4.59	 	$	0.21	 	$	4.75	 	$	4.57	 	$	0.18	 	
Production and ad valorem taxes	 	 	1.40	 	 	1.01	 	 	0.39	 	 	0.80	 	 	0.96	 	 	(0.16)	 	
Depletion, depreciation and amortization	 	 	23.53	 	 	21.35	 	 	2.18	 	 	21.82	 	 	22.14	 	 	(0.32)	 	
General and administrative	 	 	3.97	 	 	3.77	 	 	0.20	 	 	4.20	 	 	4.20	 	 	 —	 	

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

 	 	Three Months Ended September 30, 	 	Nine Months Ended September 30, 	 	
(in thousands of dollars)	    	2017	    	2016	    	2017	    	2016	  	
Reconciliation of net income to EBITDAX	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net income (loss)	 	$	(82,963)	 	$	(22,429)	 	$	(220,456)	 	$	(32,561)	 	
Interest expense	 	 	12,817	 	 	12,792	 	 	38,381	 	 	40,397	 	
Exploration expense	 	 	1,969	 	 	998	 	 	11,638	 	 	1,237	 	
Income taxes	 	 	(492)	 	 	(6,549)	 	 	(2,707)	 	 	(8,234)	 	
Depreciation and depletion	 	 	46,353	 	 	36,550	 	 	127,343	 	 	116,449	 	
Impairment of oil and natural gas properties	 	 	 —	 	 	 —	 	 	148,016	 	 	 —	 	
Accretion of ARO liability	 	 	253	 	 	323	 	 	720	 	 	913	 	
Change in TRA liability	 	 	12,435	 	 	(260)	 	 	(15,831)	 	 	(422)	 	
Other non-cash charges	 	 	585	 	 	116	 	 	1,892	 	 	1,227	 	
Stock compensation expense	 	 	1,966	 	 	2,185	 	 	5,702	 	 	5,269	 	
Deferred and other non-cash compensation expense	 	 	155	 	 	213	 	 	335	 	 	614	 	
Net (gain) loss on derivative contracts	 	 	32,539	 	 	(4,014)	 	 	(11,308)	 	 	18,769	 	
Current period settlements of matured derivative contracts	 	 	21,892	 	 	27,538	 	 	66,145	 	 	101,619	 	
Amortization of deferred revenue	 	 	(475)	 	 	(587)	 	 	(1,417)	 	 	(1,828)	 	
(Gain) loss on sale of assets	 	 	12	 	 	(69)	 	 	131	 	 	(68)	 	
(Gain) on debt extinguishment	 	 	 —	 	 	 —	 	 	 —	 	 	(99,530)	 	
Financing expenses and other loan fees	 	 	24	 	 	25	 	 	72	 	 	298	 	
EBITDAX	 	$	47,070	 	$	46,832	 	$	148,656	 	$	144,149	 	

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

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

 	 	Three Months Ended September 30, 	 	Nine Months Ended September 30, 	 	
(in thousands except per share data)	    	2017	    	2016	 	2017	    	2016	    	
Net income (loss)	 	$	(82,963)	 	$	(22,429)	 	$	(220,456)	 	$	(32,561)	 	
Net (gain) loss on derivative contracts	 	 	32,539	 	 	(4,014)	 	 	(11,308)	 	 	18,769	 	
Current period settlements of matured derivative contracts	 	 	21,892	 	 	27,538	 	 	66,145	 	 	101,619	 	
Impairment of oil and gas properties	 	 	 —	 	 	 —	 	 	148,016	 	 	 —	 	
Exploration	 	 	1,969	 	 	998	 	 	11,638	 	 	1,237	 	
Non-cash stock compensation expense	 	 	1,966	 	 	2,185	 	 	5,702	 	 	5,269	 	
Deferred and other non-cash compensation expense	 	 	155	 	 	213	 	 	335	 	 	614	 	
(Gain) on debt extinguishment	 	 	 —	 	 	 —	 	 	 —	 	 	(99,530)	 	
Financing expenses	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	
Tax impact of adjusting items (1)	 	 	(15,543)	 	 	(5,374)	 	 	(48,666)	 	 	(5,705)	 	
Change in TRA liability	 	 	12,435	 	 	(260)	 	 	(15,831)	 	 	(422)	 	
Change in valuation allowance	 	 	16,616	 	 	106	 	 	62,105	 	 	498	 	
Adjusted net income (loss)	 	 	(10,934)	 	 	(1,037)	 	 	(2,320)	 	 	(10,212)	 	
Adjusted net income (loss) attributable to non-controlling interests	 	 	(3,665)	 	 	(1,074)	 	 	(6,683)	 	 	(6,640)	 	
Adjusted net income (loss) attributable to controlling interests	 	 	(7,269)	 	 	37	 	 	4,363	 	 	(3,572)	 	
Dividends and accretion on preferred stock	 	 	(1,966)	 	 	(765)	 	 	(5,959)	 	 	(765)	 	
Adjusted net income (loss) attributable to common shareholders	 	$	(9,235)	 	$	(728)	 	$	(1,596)	 	$	(4,337)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings per share (basic and diluted): (2)	 	$	(0.91)	 	$	(0.24)	 	$	(2.30)	 	$	(0.40)	 	
Net (gain) loss on derivative contracts	 	 	0.33	 	 	(0.05)	 	 	(0.07)	 	 	0.24	 	
Current period settlements of matured derivative contracts	 	 	0.23	 	 	0.35	 	 	0.69	 	 	1.41	 	
Impairment of oil and gas properties	 	 	 —	 	 	 —	 	 	1.51	 	 	 —	 	
Exploration	 	 	0.02	 	 	0.01	 	 	0.12	 	 	0.02	 	
Non-cash stock compensation expense	 	 	0.02	 	 	0.03	 	 	0.06	 	 	0.07	 	
Deferred and other non-cash compensation expense	 	 	 —	 	 	 —	 	 	 —	 	 	0.01	 	
(Gain) on debt extinguishment	 	 	 —	 	 	 —	 	 	 —	 	 	(1.32)	 	
Financing expenses	 	 	 —	 	 	 —	 	 	 —	 	 	 —	 	
Tax impact of adjusting items (1)	 	 	(0.21)	 	 	(0.12)	 	 	(0.73)	 	 	(0.15)	 	
Change in TRA liability	 	 	0.17	 	 	 —	 	 	(0.24)	 	 	(0.01)	 	
Change in valuation allowance	 	 	0.22	 	 	 —	 	 	0.94	 	 	0.01	 	
Adjusted earnings per share (basic and diluted)	 	$	(0.13)	 	$	(0.02)	 	$	(0.02)	 	$	(0.12)	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average Class A shares outstanding: (2)	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic	 	 	73,089	 	 	44,993	 	 	67,029	 	 	37,299	 	
Diluted	 	 	73,089	 	 	44,993	 	 	67,029	 	 	37,299	 	
Effective tax rate on net income (loss) attributable to controlling interests	 	 	37.9	%	 	35.5	%	 	37.9	%	 	35.5	%	

	(1)		In arriving at adjusted net income, the tax impact of the adjustments to net income is determined by applying the appropriate tax rate to each adjustment and then allocating the tax impact between the controlling and non-controlling interests.	
	(2)		All share and earnings per share information presented has been recast to retrospectively adjust for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 12, “Stockholders’ and Mezzanine equity”, distributed on March 31, 2017.	

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Results of Operations - Three months ended  September 30, 2017 as compared to the three months ended September 30, 2016
 
Operating revenues
 
Oil and gas sales. Oil and gas sales increased $11.0 million, or 33.7%, to $43.6 million for the three months ended  September 30, 2017, as compared to $32.6 million for the three months ended  September 30, 2016. The increase was attributable to the increase in production volumes ($6.4 million) and the increase in commodity prices ($4.6 million). The increase in production volumes was driven by the year-over-year increase in producing wells due to continued drilling activity. The average realized oil price, excluding the effects of commodity derivative instruments, increased from $39.94 per Bbl for the three months ended September 30, 2016 to $44.84 per Bbl for the three months ended September 30, 2017, or 12.3%. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $2.08 per Mcf for the three months ended September 30, 2016 to $1.82 per Mcf for the three months ended September 30, 2017, or 12.5%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increased from $13.09 per Bbl for the three months ended September 30, 2016 to $20.17 per Bbl for the three months ended September 30, 2017, or 54.1%. Average daily production increased 15.1% to 21,413 Boe per day for the three months ended September 30, 2017 as compared to 18,609 Boe per day for the three months ended September 30, 2016.
 
Costs and expenses
 
Lease operating. Lease operating expenses increased by $1.6 million, or 20.3%, to $9.5 million for the three months ended September 30, 2017, as compared to $7.9 million for the three months ended September 30, 2016. The increase in lease operating expenses is primarily attributable to the increase in number of producing wells. On a per unit basis, lease operating expenses increased $0.21 per Boe, or 4.6%, from $4.59 per Boe in the three months ended September 30, 2016 to $4.80 per Boe in the three months ended September 30, 2017.
 
Production and ad valorem taxes. Production and ad valorem taxes increased by $1.1 million, or 64.7%, to $2.8 million for the three months ended September 30, 2017, as compared to $1.7 million for the three months ended September 30, 2016. Production taxes increased $0.7 million, from $1.5 million for the three months ended September 30, 2016 to $2.2 million for the three months ended September 30, 2017. The increase was attributable to the increase in production volumes. Production tax rates vary between states, products, and production levels; therefore, the overall blended rate is impacted by numerous factors and the mix of producing wells at any given time. Further, estimated ad valorem taxes increased $0.3 million, from $0.2 million for the three months ended September 30, 2016 to $0.5 million for the three months ended September 30, 2017. The average effective rate excluding the impact of ad valorem taxes increased from 4.7% for the three months ended September 30, 2016 to 5.1% for the three months ended September 30, 2017.
 
Exploration. Exploration expense increased from $1.0 million for the three months ended September 30, 2016 to $2.0 million for the three months ended September 30, 2017. The Company recognized charges for lease abandonment of $1.8 million relating to certain leases that the Company decided during the third quarter of 2017 not to develop. Spending during 2017 primarily related to geological data and seismic processing associated with unproved acreage. No exploratory wells resulted in exploration expense during the three months ended September 30 of either year.
 
Depreciation, depletion and amortization. Depreciation, depletion and amortization  increased by $9.8 million, or 26.8%, to $46.4 million for the three months ended September 30, 2017, as compared to $36.6 million for the three months ended September 30, 2016. On a per unit basis, depletion expense increased $2.18 per Boe or 10.2% from $21.35 per Boe for the three months ended September 30, 2016 to $23.53 per Boe for the three months ended September 30, 2017.  The increase was primarily the result of capital spending related to our drilling program.
 
General and administrative. General and administrative expenses increased by $1.4 million, or 21.9%, to $7.8 million for the three months ended September 30, 2017, as compared to $6.4 million for the three months ended September 30, 2016. The increase was primarily attributable to increased headcount associated with the opening of our Oklahoma City office. Non-cash compensation expense decreased $0.3 million, from $2.4 million for the three months ended September 30, 2016 to $2.1 million for the three months ended September 30, 2017. On a per unit basis, general and administrative expenses, excluding all non-cash items, increased from $2.30 per Boe for the three months ended September 30, 2016 to $2.60 per Boe for the three months ended September 30, 2017.

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Interest expense. Interest expense remained consistent at $12.8 million for the three months ended September 30, 2017 and 2016. During the three months ended September 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 3.12%, 6.75% and 9.25%, respectively. Average outstanding balances for the three months ended September 30, 2017 were $172.9 million, $409.1 million and $150.0 million under the Revolver, the 2022 Notes and the 2023 Notes, respectively.
 
Net gain (loss) on commodity derivatives. The net gain (loss) on commodity derivatives was a net loss of $32.5 million for the three months ended September 30, 2017, as compared to a net gain of $4.0 million for the three months ended September 30, 2016. The loss was primarily driven by higher average crude oil prices ($48.18 per barrel) for the three months ended September 30, 2017, as compared to the crude oil prices as of June 30, 2017 ($46.02 per barrel). The Company unwound its realized 2018 hedges resulting in recognized gains of approximately $14.8 million for the three months ended September 30, 2017. See Note 7, “Derivative Instruments and Hedging Activities,” for further details.
 
Other income (expense). Other income (expense) for the three months ended September 30, 2017 was net expense of $13.7 million, as compared to net income of $0.4 million for the three months ended September 30, 2016. Other income (expense) during the three months ended September 30, 2017 primarily related to a decrease in the TRA valuation allowance which resulted in expense of $12.4 million.
 
Income taxes. The provision for federal and state income taxes for the three months ended September 30, 2017 was a benefit of $0.5 million resulting in a 0.6% effective tax rate as a percentage of our pre-tax book income for the quarter as compared to a benefit of $6.5 million resulting in a 22.6% effective tax rate as a percentage of our pre-tax book income for the three months ended September 30, 2016. Our effective tax rate is based on the statutory rate applicable to the U.S. and the blended rate of the states in which we conduct business and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest. The effective tax rate reduction is primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets. See Note 11, “Income Taxes,” for further details.
 
Results of Operations - Nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016
 
Operating revenues
 
Oil and gas sales. Oil and gas sales increased $46.3 million, or 53.8%, to $132.4 million for the nine months ended September 30, 2017, as compared to $86.1 million for the nine months ended September 30, 2016. The increase was attributable to the increase in commodity prices ($33.7 million) and the increase in production volumes ($12.6 million). The increase in production volumes was driven by the year-over-year increase in producing wells due to continued drilling activity. The average realized oil price, excluding the effects of commodity derivative instruments, increased from $35.59 per Bbl for the nine months ended September 30, 2016 to $45.40 per Bbl for the nine months ended September 30, 2017, or 27.6%. The average realized natural gas price, excluding the effects of commodity derivative instruments, increased from $1.50 per Mcf for the nine months ended September 30, 2016 to $2.15 per Mcf for the nine months ended September 30, 2017, or 43.3%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increased from $11.99 per Bbl for the nine months ended September 30, 2016 to $19.46 per Bbl for the nine months ended September 30, 2017, or 62.3%. Average daily production increased 11.4% to 21,374 Boe per day for the nine months ended September 30, 2017 as compared to 19,193 Boe per day for the nine months ended September 30, 2016.
 
Costs and expenses
 
Lease operating. Lease operating expenses increased by $3.7 million, or 15.4%, to $27.7 million for the nine months ended September 30, 2017, as compared to $24.0 million for the nine months ended September 30, 2016. The increase in lease operating expenses is primarily attributable to the increase in number of producing wells. On a per unit basis, lease operating expenses increased $0.18 per Boe, or 3.9%, from $4.57 per Boe in the nine months ended September 30, 2016 to $4.75 per Boe in the nine months ended September 30, 2017.
 
Production and ad valorem taxes. Production and ad valorem taxes decreased by $0.5 million, or 9.8%, to $4.6 million for the nine months ended September 30, 2017, as compared to $5.1 million for the nine months ended September 30, 2016. During the first quarter of 2017, the Company's application for High-Cost Gas Incentive refunds in Texas was

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approved for qualified wells on which taxes were initially paid between October 2012 and September 2016. The Company received a net production tax refund of $3.3 million during the nine months ended September 30, 2017, which was recorded as a reduction in Production and ad valorem taxes on the Company’s Consolidated Statement of Operations. Production taxes, excluding the impact of this refund, increased from $4.1 million for the nine months ended September 30, 2016 to $6.4 million for the nine months ended September 30, 2017. The increase was attributable to the increase in production volumes. Production tax rates vary between states, products, and production levels; therefore, the overall blended rate is impacted by numerous factors and the mix of producing wells at any given time. Offsetting, estimated ad valorem taxes increased $0.6 million from $1.0 million for the nine months ended September 30, 2016 to $1.6 million for the nine months ended September 30, 2017. The average effective rate excluding the impact of ad valorem taxes decreased from 4.8% for the nine months ended September 30, 2016 to 2.3% for the nine months ended September 30, 2017.
 
Exploration. Exploration expense increased from $1.2 million for the nine months ended September 30, 2016 to $11.6 million for the nine months ended September 30, 2017. The Company recognized charges for lease abandonment of $8.7 million relating to certain leases that the Company decided during 2017 not to develop. Spending during 2017 primarily related to geological data and seismic processing associated with unproved acreage. No exploratory wells resulted in exploration expense during the nine months ended September 30 of either year.
 
Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $10.9 million, or 9.4%, to $127.3 million for the nine months ended September 30, 2017, as compared to $116.4 million for the nine months ended September 30, 2016. The increase was primarily the result of capital spending related to our drilling program. On a per unit basis, depletion expense decreased $0.32 per Boe or 1.4% from $22.14 per Boe for the nine months ended September 30, 2016 to $21.82 per Boe for the nine months ended September 30, 2017. The decrease was primarily the result of lower production and capital spending throughout 2016, driven by a temporary suspension of the drilling program late in 2015 and continuing into early 2016.
 
Impairment of oil and gas properties. As a result of the Arkoma Divestiture, the Company recognized an impairment charge due to the loss on disposal of the Arkoma Basin oil and gas property assets and related liabilities. Based on the Company’s sales price, an impairment charge of $148.0 million was recognized during the nine months ended September 30, 2017. No impairment charges were recognized during the nine months ended September 30, 2016.
 
General and administrative. General and administrative expenses increased by $2.4 million, or 10.9%, to $24.5 million for the nine months ended September 30, 2017, as compared to $22.1 million for the nine months ended September 30, 2016. The increase was primarily driven by a litigation settlement for which the Company recognized an additional charge of $1.4 million during the second quarter of 2017. Non-cash compensation expense increased $0.1 million, from $5.9 million for the nine months ended September 30, 2016 to $6.0 million for the nine months ended September 30, 2017. On a per unit basis, general and administrative expenses, excluding all non-cash items, decreased from $2.85 per Boe for the nine months ended September 30, 2016 to $2.84 per Boe for the nine months ended September 30, 2017.
 
Interest expense. Interest expense decreased by $2.0 million, or 5.0%, to $38.4 million for nine months ended September 30, 2017, as compared to $40.4 million for the nine months ended September 30, 2016. The decrease was driven by a reduction in the outstanding balance of the 2022 Notes and the 2023 Notes as a result of our 2016 debt extinguishments. During the nine months ended September 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.84%, 6.75% and 9.25%, respectively. Average outstanding balances for the nine months ended September 30, 2017 were $187.5 million, $409.1 million and $150.0 million under the Revolver, the 2022 Notes and the 2023 Notes, respectively.
 
Net gain (loss) on commodity derivatives. The net gain (loss) on commodity derivatives was a net gain of $11.3 million for the nine months ended September 30, 2017, as compared to a net loss of $18.8 million for the nine months ended September 30, 2016. The gain was primarily driven by lower average crude oil and natural gas prices ($49.30 per barrel and $3.01 per Mcf, respectively) for the nine months ended September 30, 2017, as compared to the crude oil and natural gas prices as of December 31, 2016 ($53.75 per barrel and $3.71 per Mcf, respectively). Additionally, the Company unwound its realized 2018 and 2019 hedges resulting in recognized gains of approximately $42.8 million for the nine months ended September 30, 2017. See Note 7, “Derivative Instruments and Hedging Activities,” for further details.

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Other income (expense). Other income (expense) for the nine months ended September 30, 2017 was net income of $14.4 million, as compared to net income of $0.3 million for the nine months ended September 30, 2016. Other income (expense) during the nine months ended September 30, 2017 primarily related to an increase in the TRA valuation allowance which resulted in income of $15.8 million.
 
Income taxes. The provision for federal and state income taxes for the nine months ended September 30, 2017 was a benefit of $2.7 million resulting in a 1.2% effective tax rate as a percentage of our pre-tax book income year-to-date as compared to a benefit of $8.2 million resulting in a 20.2% effective tax rate as a percentage of our pre-tax book income for the nine months ended September 30, 2016. Our effective tax rate is based on the statutory rate applicable to the U.S. and the blended rate of the states in which we conduct business and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest. The effective tax rate reduction is primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets. See Note 11, “Income Taxes,” for further details.
 
Liquidity and Capital Resources
 
Historically, our primary sources of liquidity have been private and public sales of our debt and equity, borrowings under bank credit facilities and cash flows from operations. Our primary use of capital has been for the exploration, development and acquisition of oil and gas properties. As we pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We strive to maintain financial flexibility in order to maintain substantial borrowing capacity under our Revolver (as defined in Note 6), facilitate drilling on our undeveloped acreage positions and permit us to selectively expand our acreage positions. Depending on the profitability, timing and concentration of the development of our non-proved locations, we may be required to generate or raise significant amounts of capital to develop all of our potential drilling locations should we endeavor to do so. In the event our profitability or cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending. Our balance sheet at September 30, 2017 reflects a negative working capital balance. We have historically maintained, and in the future we expect to maintain, a negative working capital balance, and we use our Revolver to help manage our working capital.
 
Availability under the Revolver is subject to a borrowing base, as well as financial covenants. Our borrowing base at September 30, 2017 was $375.0 million, of which $151.0 million was utilized, leaving an unused capacity of $224.0 million. The borrowing base will be re-determined at least semi-annually on or about April 1 and October 1 of each year, with such re-determination based primarily on reserve reports using lender commodity price expectations at such time. Any reduction in the borrowing base will reduce our liquidity, and, if the reduction results in the outstanding amount under our Revolver exceeding the borrowing base, we will be required to repay the deficiency within a short period of time. The financial covenants may further constrain our ability to borrow under our Revolver.
 
The Revolver also contains a covenant which restricts the ability of Jones Energy, Inc. to (i) hold any assets, (ii) incur, create, assume, or suffer to exist any debt or any other liability or obligation, (iii) create, make or enter into any investment or (iv) engage in any other activity or operation other than, among other exceptions described therein, its ownership of equity interests in JEH and the activities of a passive holding company and assets and operations incidental thereto (including the maintenance of cash and reserves for the payment of operational costs and expenses).
 
Jones Energy, Inc. and its consolidated subsidiaries are also subject to certain covenants under the Revolver, including the requirement to maintain the following financial ratios:
 
	·		a total leverage ratio, consisting of consolidated debt to EBITDAX, of not greater than 4.00 to 1.00 as of the last day of any fiscal quarter; and	
 
	·		a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.00 to 1.00 as of the last day of any fiscal quarter.	
 
As of September 30, 2017, our total leverage ratio was 3.90 to 1.00 and our current ratio was 2.49 to 1.00, as calculated based on the requirements in our covenants. We were in compliance with all terms of our Revolver at September 30,

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2017. However, factors including those outside of our control, such as commodity price declines, may prevent us from maintaining compliance with these covenants, at future measurement dates in 2017 and beyond. We are currently in discussions with the lenders under our Revolver regarding an amendment to the Revolver that would modify the financial covenants discussed above. Without the amendment, we may breach the total leverage ratio under our Revolver. If an event of default exists under the Revolver, the lenders would be able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change of control, as defined in the Revolver. See Note 6, “Long-Term Debt” for more information.
 
The Company routinely enters into oil and natural gas swap contracts as seller, thus resulting in a fixed price. During 2016 and 2017, the Company realized certain mark-to-market gains associated with oil and natural gas hedges the Company had in place for years 2018 and 2019. The gains were effectively realized by purchasing, as opposed to selling, oil and natural gas swap contracts for the equal volume that was associated with the initial hedge transaction. During the three and nine months ended September 30, 2017, the Company unwound its realized 2018 and 2019 hedges resulting in approximately $14.8 million and $42.8 million, respectively, of recognized gains which have been included in Net gain (loss) on commodity derivatives on the Company’s Consolidated Statement of Operations.
 
The amount, timing and allocation of capital expenditures are largely discretionary and within management’s control. If oil and gas prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses of liquidity and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We continuously monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and completion costs, industry conditions, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.
 
The following table summarizes our cash flows for the nine months ended September 30, 2017 and 2016:

 	 	Nine Months Ended September 30, 	 	
(in thousands of dollars)	    	2017	    	2016	    	
Net cash provided by operating activities	 	$	41,425	 	$	14,909	 	
Net cash (used in) investing activities	 	 	(47,530)	 	 	(104,847)	 	
Net cash (used in) / provided by financing activities	 	 	(23,059)	 	 	92,086	 	
Net increase (decrease) in cash	 	$	(29,164)	 	$	2,148	 	
 
Cash flow provided by operating activities
 
Net cash provided by operating activities was $41.4 million during the nine months ended September 30, 2017 as compared to $14.9 million during the nine months ended September 30, 2016. The increase in operating cash flows was primarily due to the $46.3 million increase in oil and gas revenues for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016, primarily driven by the increase in commodity prices, as well as production volumes.
 
Cash flow (used in) investing activities
 
Net cash used in investing activities was $47.5 million during the nine months ended September 30, 2017 as compared to $104.8 million during the nine months ended September 30, 2016. The decrease in investing cash flow was primarily driven by reduced capital spending during 2017 as compared to 2016. During 2016, capital spending levels increased upon resuming the drilling program in early 2016 following the temporary suspension of the program  beginning late in 2015.
 
Cash flow (used in) / provided by financing activities
Net cash (used in) / provided by financing activities was cash used of $23.1 million during the nine months ended September 30, 2017 as compared to cash provided of $92.1 million during the nine months ended September 30, 2016. The decrease in financing cash flows was primarily due to repayments under the Revolver, net of borrowings, which

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totaled $27.0 million during the nine months ended September 30, 2017 as compared to net borrowings of $33.0 million during the nine months ended September 30, 2016. Cash flows provided by financing activities were also impacted by net equity offerings of $8.3 million during the nine months ended September 30, 2017 as compared to $153.8 million during the nine months ended September 30, 2016. Offsetting these decrease, the Company did not engage in the repurchase of our senior unsecured notes during the nine months ended September 30, 2017 as compared to cash used toward repurchases of $85.0 million during the nine months ended September 30, 2016.
 
Contractual Obligations
 
The holders of JEH Units, including us, incur U.S. federal, state and local income taxes on their share of any taxable income of JEH. Under the terms of its operating agreement, JEH is generally required to make quarterly pro-rata cash tax distributions to its unitholders (including us) based on income allocated to its unitholders through the end of each relevant quarter, as adjusted to take into account good faith projections by the Company of taxable income or loss for the remainder of the calendar year, to the extent JEH has cash available for such distributions and subject to certain other restrictions. This tax distribution is computed based on the estimate of net taxable income of JEH allocated to each holder of JEH Units multiplied by the highest marginal effective rate of federal, state and local income tax applicable to an individual resident in New York, New York, without regard for the federal benefit of the deduction for any state taxes.
 
During 2016, JEH generated taxable income, resulting in the payment of cash tax distributions to JEH unitholders. As a result of JEH’s 2016 taxable income (all of which is passed-through and taxed to us and JEH’s other unitholders), during the first quarter of 2017, we made further income tax payments to federal and state taxing authorities of $4.1 million, and JEH made further tax distributions to JEH unitholders (other than us) of $0.6 million.
 
Based on information available as of this filing, we do not anticipate that we will be required to make any additional tax payments or that JEH will make any additional tax distributions during the remainder of 2017. Estimating the tax distributions required under the operating agreement is imprecise by nature, highly uncertain, and dependent upon a variety of factors.
 
There have been no other material changes in our contractual obligations as reported in our Annual Report on Form 10-K for the year ended December 31, 2016.
 
Off-Balance Sheet Arrangements
 
We do not have any off-balance sheet arrangements.
 
Critical Accounting Policies and Estimates
 
There have been no changes to our critical accounting policies and estimates from those set forth in our Annual Report on Form 10-K for the year ended December 31, 2016.
 
Item 3. Quantitative and Qualitative Disclosure  s about Market Risk
 
The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2016, as well as with the unaudited consolidated financial statements and notes included in this Quarterly Report.
 
We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes. We do not designate these or future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.
 
Potential Impairment of Oil and Gas Properties
 
Oil and natural gas prices are inherently volatile and have decreased significantly since 2014. Depressed commodity prices have continued into 2017 and historically low commodity prices may exist for an extended period. Taking into

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consideration the business environment in which we operate, we continually review our oil and gas properties for indicators of potential impairment on an undiscounted basis. No such indicators were present at September 30, 2017.
 
Our revenues and net income are sensitive to crude oil, NGL and natural gas prices which have been and are expected to continue to be highly volatile. The recent volatility in crude oil and natural gas prices increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. Although we are unable to predict future commodity prices, a prolonged period of depressed commodity prices may have a significant impact on the volumetric quantities of our proved reserves. The impact of commodity prices on our estimated proved reserves can be illustrated as follows: if the prices used for our December 31, 2016 Reserve Report had been replaced with the unweighted arithmetic average of the first-day-of-the-month prices for the applicable commodity for the trailing twelve-month period ended September 30, 2017 (without regard to our commodity derivative positions and without assuming any change in development plans, costs, or other variables), then estimated proved reserves volumes as of December 31, 2016 would have increased by approximately 3.7%. The use of this pricing example is for illustration purposes only, and does not indicate management’s view on future commodity prices, costs or other variables, or represent a forecast or estimate of the actual amount by which our proved reserves may fluctuate when a full assessment of our reserves is completed as of December 31, 2017.
 
Periodic revisions to the estimated reserves and related future cash flows may be necessary as a result of a number of factors, including changes in oil and natural gas prices, reservoir performance, new drilling and completion including required access to capital, purchases, sales and terminations of leases, drilling and operating cost changes, technological advances, new geological or geophysical data or other economic factors. All of these factors are inherently estimates and are inter dependent. While each variable carries its own degree of uncertainty, some factors, such as oil and natural gas prices, have historically been highly volatile and may be highly volatile in the future. This high degree of volatility causes a high degree of uncertainty associated with the estimation of reserve quantities and estimated future cash flows. Therefore, future results are highly uncertain and subject to potentially significant revisions. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions, as such revisions could be negatively impacted by:
 
	·		Declines in commodity prices or actual realized prices below those assumed for future years;	
 
	·		Increases in service costs;	
 
	·		Increases in future global or regional production or decreases in demand;	
 
	·		Increases in operating costs;	
 
	·		Reductions in availability of drilling, completion, or other equipment.	
 
If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. Any future impairments are difficult to predict, and although it is not reasonably practicable to quantify the impact of any future impairments at this time, such impairments may be significant.
 
Commodity price risk and hedges
 
Our principal market risk exposure is to oil, natural gas and NGL prices, which are inherently volatile. As such, future earnings are subject to change due to fluctuations in such prices. Realized prices are primarily driven by the prevailing prices for oil and regional spot prices for natural gas and NGLs. We have used, and expect to continue to use, oil, natural gas and NGL derivative contracts to reduce our risk of price fluctuations of these commodities. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. The fair value of our oil, natural gas and NGL derivative contracts at September 30, 2017 was a net liability of $11.9 million.
 
Counterparty risk

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Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. We evaluate the credit standing of our counterparties, but do not require them to post collateral. The majority of our derivative contracts currently in place are with lenders under our Revolver, who have investment grade ratings.
 
Interest rate risk
 
We are subject to market risk exposure related to changes in interest rates on our variable rate indebtedness. The terms of our Revolver provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 0.50% to 2.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. The terms of our senior notes provide for a fixed interest rate through their respective maturity dates. During the three months ended September 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 3.12%, 6.75% and 9.25%, respectively. During the nine months ended September 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.84%, 6.75% and 9.25%, respectively.
 
Item 4. Controls and Procedure  s
 
Changes in Internal Control over Financial Reporting
 
There have been no changes in internal control over financial reporting during the quarter ended September 30, 2017 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
 
Evaluation of Disclosure Controls and Procedures
 
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.
 
Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our principal executive officer and principal financial officer concluded that as of September 30, 2017, the end of the period covered by this report, our disclosure controls and procedures are effective at a reasonable assurance level.
 
Management’s Assessment of Internal Control over Financial Reporting
 
The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring every public company that files reports with the SEC to include a management report on such company’s internal control over financial reporting in its annual report. Pursuant to the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we are no longer an “emerging growth company” as defined in the JOBS Act. Our Annual Report on Form 10-K for the year ended December 31, 2016 included a report of management’s assessment regarding internal control over financial reporting.
 
PART II—OTHER INFORMATIO  N
 
Item 1. Legal Proceeding  s
 
For a discussion of legal proceedings, see Note 15 “Commitments and Contingencies,” in the Notes to Consolidated Financial Statements for further discussion appearing in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated in this item by reference.

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Item 1A. Risk Factor  s
 
Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings, including our Annual Report on Form 10-K for the year ended December 31, 2016, could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.
 
For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016. There have been no material changes in our risk factors from those described in our Annual Report for the year ended December 31, 2016, except as set forth below.
 
In certain circumstances including transactions involving a change in control, significant payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.
Under certain circumstances, we could become obligated to make significant payments under our Tax Receivable Agreement that could exceed or represent a substantial portion of our liquidity and market capitalization. These payment obligations could be to persons without significant equity ownership in the Company at the time such obligation arises. If we elect to terminate the Tax Receivable Agreement early or it is terminated early due to certain mergers or other changes of control, we would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the Tax Receivable Agreement. Such calculation of anticipated future tax benefits will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including the assumptions that (i) we have sufficient taxable income to fully utilize such benefits, (ii) any JEH Units that the Class B shareholders or their permitted transferees own on the termination date are exchanged for shares of our Class A common stock on the termination date and (iii) the amount of future depletion deductions to which we are entitled is based on recoverable reserves and rates of recovery reflected in the most recent reserve reports and estimates available on the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of such future benefits.
In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or other changes of control due to the additional transaction cost a potential acquirer may attribute to satisfying such obligations. For example, if the Tax Receivable Agreement were terminated at September 30, 2017, we estimate that the termination payment would be approximately $105.1 million (calculated using a discount rate equal to LIBOR, plus 100 basis points, applied against the anticipated undiscounted liability and assuming a market value of our Class A common stock equal to $1.92 per share, the closing price on September 29, 2017). The foregoing is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.
Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. The holders of rights under the Tax Receivable Agreement will not reimburse us for any payments previously made under the Tax Receivable Agreement if such basis increases or other benefits are subsequently disallowed, except that excess payments made to any Class B shareholder will be netted against payments otherwise to be made, if any, to such Class B shareholder after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.
 
We may be unable to maintain compliance with certain financial ratio covenants of our outstanding indebtedness which could result in an event of default that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.
 
Our Revolver requires us to maintain certain financial ratios, including a total leverage ratio, consisting of consolidated debt to EBITDAX, of not more than 4.00 to 1.00 and a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.00 to 1.00. 
 
As of September 30, 2017, we were in compliance with our financial covenants. However, we cannot guarantee that we will be able to comply with such terms at all times in the future. As of September 30, 2017, our total leverage ratio was 3.90 to 1.00 and our current ratio was 2.49 to 1.00. We are currently in discussions with the lenders under our Revolver

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regarding an amendment to the Revolver that would modify the financial covenants discussed above. However, there can be no assurances that the requisite lenders under our Revolver approve any such amendment, and, as a result, we may breach the total leverage ratio. Any failure to comply with the conditions and covenants in our Revolver that is not waived by our lenders or otherwise cured could lead to a termination of our Revolver, acceleration of all amounts due under our revolving credit facility, or trigger cross default provisions under other financing arrangements. These restrictions may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our indebtedness impose on us.

Item 2. Unregistered Sales of Equity Securitie  s and Use of Proceeds
 
None.
 
Item 3. Defaults Upon Senior Securitie  s
 
None.
 
Item 4. Mine Safety Disclosure  s
 
Not applicable.
 
Item 5. Other Informatio  n
 
Not applicable.
 
Item 6. Exhibit  s

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

* - filed herewith
** - furnished herewith

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

 	Jones Energy, Inc.	
 	 	
 	(registrant)	

Date: November 8, 2017	By: 	/s/ Robert J. Brooks	
 	Name:  Robert J. Brooks	
 	Title:    Chief Financial Officer (Principal Financial Officer)	
 
Signature Page to Form 10-Q (Q3 2017)

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Exhibit 31.1
 
Certification by Chief Executive Officer pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,
as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
I, Jonny Jones, certify that:
 
	1.		I have reviewed this Quarterly Report on Form 10-Q of Jones Energy, Inc.;	
 
	2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 
	3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 
	4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	
 
	(a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 
	(b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 
	(c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 
	(d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	
 
	5.		The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	
 
	(a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 
	(b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	

 	By:	/s/ Jonny Jones	
 	 	Jonny Jones	
 	 	Chief Executive Officer	
 	 	 	
Date: November 8, 2017	 	 	

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Exhibit 31.2
 
Certification by Chief Financial Officer pursuant to
Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934,
as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
I, Robert J. Brooks, certify that:
 
	1.		I have reviewed this Quarterly Report on Form 10-Q of Jones Energy, Inc.;	
 
	2.		Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;	
 
	3.		Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;	
 
	4.		The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:	
 
	(a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;	
 
	(b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;	
 
	(c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and	
 
	(d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and	
 
	5.		The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):	
 
	(a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and	
 
	(b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.	

 	By:	/s/ Robert J. Brooks	
 	 	Robert J. Brooks	
 	 	Chief Financial Officer	
 	 	 	
Date: November 8, 2017	 	 	

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Exhibit 32.1
 
Certification Pursuant to
18 U.S.C. Section 1350,
as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
In connection with the quarterly report of Jones Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended September 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jonny Jones, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge:
 
	1.		The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and	
 
	2.		The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.	

 	By:	/s/ Jonny Jones	
 	 	Jonny Jones	
 	 	Chief Executive Officer	
 	 	 	
Date: November 8, 2017	 	 	
 
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained and furnished to the Securities and Exchange Commission or its staff upon request.

Exhibit 32.2
 
Certification Pursuant to
18 U.S.C. Section 1350,
as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
In connection with the quarterly report of Jones Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended September 30, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert J. Brooks, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge:
 
	1.		The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and	
 
	2.		The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.	

 	By:	/s/ Robert J. Brooks	
 	 	Robert J. Brooks	
 	 	Chief Financial Officer	
 	 	 	
Date: November 8, 2017	 	 	
 
A signed original of this written statement required by Section 906 has been provided to the Company and will be retained and furnished to the Securities and Exchange Commission or its staff upon request.