Quarterly Report (10-q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended June 30, 2017

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

Commission file number 001-36006

Jones Energy, Inc.

(Exact name of registrant as specified in its charter)

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

807 Las Cimas Parkway, Suite 350
Austin, Texas 78746
(512) 328-2953
(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)

Robert J. Brooks

807 Las Cimas Parkway, Suite 350
Austin, Texas 78746
(512) 328-2953

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

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

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

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

Large accelerated filer ☐		Accelerated filer ☒

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

Emerging growth company ☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☒

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

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

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JONES ENERGY, INC.

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PART 1—FINANCIAL INFORMATION	1

Item 1. Financial Statements	1

Unaudited Consolidated Financial Statements	1

Balance Sheets	1

Statements of Operations	2

Statement of Changes in Stockholders’ Equity	3

Statements of Cash Flows	4

Notes to the Consolidated Financial Statements	5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	40

Item 3. Quantitative and Qualitative Disclosures About Market Risk	50

Item 4. Controls and Procedures	52

PART II—OTHER INFORMATION	53

Item 1. Legal Proceedings	53

Item 1A. Risk Factors	53

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	53

Item 3. Defaults upon Senior Securities	53

Item 4. Mine Safety Disclosures	53

Item 5. Other Information	53

Item 6. Exhibits	53

SIGNATURES	54

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this report that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this report specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, our expectations regarding our ability to drill the recently acquired acreage in the Merge, our potential decrease in capital spending if profitability or cash flows are lower than anticipated, our ability to mitigate commodity price risk through our hedging program, our ability to maintain compliance with our debt covenants, JEH’s obligations to pay cash distributions, expectations regarding litigation, our belief that we will be able to identify and prioritize projects with the greatest expected returns, and our ability to successfully execute our 2017 development plan. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include, but are not limited to, changes in prices for oil, natural gas liquids, and natural gas prices, weather, including its impact on oil and natural gas demand and weather-related delays on operations, the amount, nature and timing of planned capital expenditures, availability and method of funding acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, customers’ elections to reject ethane and include it as part of the natural gas stream, ability to fund our 2017 capital expenditure budget, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company’s business and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the SEC.

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

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PART 1—FINANCIAL INFORMATIO N

Item 1. Financial Statement s

Jones Energy, Inc.

Consolidated Balance Sheet s (Unaudited)


	June 30,		December 31,
(in thousands of dollars)	2017		2016
Assets
Current assets
Cash	$	6,254	$	34,642
Accounts receivable, net
Oil and gas sales		24,557		26,568
Joint interest owners		9,032		5,267
Other		7,205		6,061
Commodity derivative assets		39,823		24,100
Other current assets		11,381		2,684
Assets held for sale		3,455		—
Total current assets		101,707		99,322
Assets held for sale, net		64,200		—
Oil and gas properties, net, at cost under the successful efforts method		1,545,991		1,743,588
Other property, plant and equipment, net		2,812		2,996
Commodity derivative assets		5,914		34,744
Other assets		5,395		6,050
Total assets	$	1,726,019	$	1,886,700
Liabilities and Stockholders' Equity
Current liabilities
Trade accounts payable	$	56,053	$	36,527
Oil and gas sales payable		22,301		28,339
Accrued liabilities		19,571		25,707
Commodity derivative liabilities		3,036		14,650
Other current liabilities		8,099		2,584
Liabilities related to assets held for sale		7,472		—
Total current liabilities		116,532		107,807
Liabilities related to assets held for sale		1,143		—
Long-term debt		728,163		724,009
Deferred revenue		6,106		7,049
Commodity derivative liabilities		123		1,209
Asset retirement obligations		19,061		19,458
Liability under tax receivable agreement		11,807		43,045
Other liabilities		902		792
Deferred tax liabilities		2,911		2,905
Total liabilities		886,748		906,274
Commitments and contingencies (Note 14)
Mezzanine equity
Series A preferred stock, $0.001 par value; 1,840,000 shares issued and outstanding at June 30, 2017 and December 31, 2016		89,288		88,975
Stockholders' equity
Class A common stock, $0.001 par value; 66,671,659 shares issued and 66,649,057 shares outstanding at June 30, 2017 and 57,048,076 shares issued and 57,025,474 shares outstanding at December 31, 2016		67		57
Class B common stock, $0.001 par value; 29,823,927 shares issued and outstanding at June 30, 2017 and 29,832,098 shares issued and outstanding at December 31, 2016		30		30
Treasury stock, at cost: 22,602 shares at June 30, 2017 and December 31, 2016		(358)		(358)
Additional paid-in-capital		477,390		447,137
Retained (deficit) / earnings		(121,477)		(8,652)
Stockholders' equity		355,652		438,214
Non-controlling interest		394,331		453,237
Total stockholders’ equity		749,983		891,451
Total liabilities and stockholders' equity	$	1,726,019	$	1,886,700

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

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Jones Energy, Inc.

Consolidated Statements of Operation s (Unaudited)


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

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

Weighted average Class A shares outstanding (1) :
Basic		65,681		33,598		63,948		33,410
Diluted		65,681		33,598		63,948		33,410

(1)

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

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

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Jones Energy, Inc.

Statement of Changes in Stockholders’ Equit y (Unaudited)


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

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

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Jones Energy, Inc.

Consolidated Statements of Cash Flow s (Unaudited)


	Six months ended June 30,
(in thousands of dollars)	2017		2016
Cash flows from operating activities
Net income (loss)	$	(148,847)	$	(10,132)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, and amortization		80,990		79,899
Exploration (dry hole and lease abandonment)		6,880		27
Impairment of oil and gas properties		161,886		—
Accretion of ARO liability		467		590
Amortization of debt issuance costs		1,953		2,107
Stock compensation expense		3,736		3,084
Deferred and other non-cash compensation expense		180		401
Amortization of deferred revenue		(942)		(1,241)
(Gain) loss on commodity derivatives		(43,847)		22,783
(Gain) loss on sales of assets		119		1
(Gain) on debt extinguishment		—		(99,530)
Deferred income tax provision		6		(3,291)
Change in liability under tax receivable agreement		(30,599)		(162)
Other - net		1,307		1,111
Changes in operating assets and liabilities
Accounts receivable		(4,188)		11,353
Other assets		(12,590)		(482)
Accrued interest expense		(1,301)		(4,201)
Accounts payable and accrued liabilities		6,268		3,683
Net cash provided by operations		21,478		6,000
Cash flows from investing activities
Additions to oil and gas properties		(107,250)		(27,592)
Net adjustments to purchase price of properties acquired		2,391		—
Proceeds from sales of assets		2,730		5
Acquisition of other property, plant and equipment		(436)		12
Current period settlements of matured derivative contracts		45,738		77,622
Net cash (used in) / provided by investing		(56,827)		50,047
Cash flows from financing activities
Proceeds from issuance of long-term debt		75,000		75,000
Repayment of long-term debt		(72,000)		—
Purchase of senior notes		—		(84,589)
Payment of cash dividends on preferred stock		(3,367)		—
Net distributions paid to JEH unitholders		(562)		(10,109)
Net payments for share based compensation		(462)		—
Proceeds from sale of common stock		8,352		1,056
Net cash provided by / (used in) financing		6,961		(18,642)
Net increase (decrease) in cash		(28,388)		37,405
Cash
Beginning of period		34,642		21,893
End of period	$	6,254	$	59,298
Supplemental disclosure of cash flow information
Cash paid for interest	$	24,064	$	29,700
Change in accrued additions to oil and gas properties		13,155		1,980
Asset retirement obligations incurred, including changes in estimate		395		160

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

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Jones Energy, Inc.

Notes to the Consolidated Financial Statement s (Unaudited)

1. Organization and Description of Business

Organization

Jones Energy, Inc. (the “Company”) was formed in March 2013 as a Delaware corporation to become a publicly-traded entity and the holding company of Jones Energy Holdings, LLC (“JEH”). As the sole managing member of JEH, the Company is responsible for all operational, management and administrative decisions relating to JEH’s business and consolidates the financial results of JEH and its subsidiaries.

JEH was formed as a Delaware limited liability company on December 16, 2009 through investments made by the Jones family, certain members of management and through private equity funds managed by Metalmark Capital, among others. JEH acts as a holding company of operating subsidiaries that own and operate assets that are used in the exploration, development, production and acquisition of oil and natural gas properties.

The Company’s certificate of incorporation authorizes two classes of common stock, Class A common stock and Class B common stock. The Class B common stock is held by the remaining owners of JEH prior to the initial public offering (“IPO”) of the Company (collectively, the “Class B shareholders”) and can be exchanged (together with a corresponding number of common units representing membership interests in JEH (“JEH Units”)) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. The Class B common stock has no economic rights but entitles its holders to one vote on all matters to be voted on by the Company’s stockholders generally. As of June 30, 2017, the Company held 66,649,057 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 29,823,927 JEH Units are held by the Class B shareholders. The Class B shareholders have no voting rights with respect to their economic interest in JEH, resulting in the Company reporting this ownership interest as a non-controlling interest.

The Company’s certificate of incorporation also authorizes the Board of Directors of the Company to establish one or more series of preferred stock. Unless required by law or by any stock exchange on which our common stock is listed, the authorized shares of preferred stock will be available for issuance without further action. Rights and privileges associated with shares of preferred stock are subject to authorization by the Board of Directors of the Company and may differ from those of any and all other series at any time outstanding.

On August 25, 2016, the Company issued 1,840,000 shares of its 8.0% Series A Perpetual Convertible Preferred Stock, par value $0.001 per share (the “Series A preferred stock”), pursuant to a registered public offering at $50 per share. See Note 11, “Stockholders’ and Mezzanine equity”.

Description of Business

The Company is engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States, spanning areas of Texas and Oklahoma. The Company’s assets are located within the Eastern Anadarko basin, targeting the liquids rich Woodford shale and Meramec formations in the Merge area of the STACK/SCOOP, and the Western Anadarko basin, targeting the liquids rich Cleveland, Granite Wash, Tonkawa and Marmaton formations, and are owned by JEH and its operating subsidiaries. The Company is headquartered in Austin, Texas.

2. Significant Accounting Policies

Basis of Presentation

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

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financial statements reported for June 30, 2017 and 2016 and each of the six-month periods then ended include the Company and all of its subsidiaries.

Certain prior period amounts have been reclassified to conform to the current presentation.

The accompanying unaudited condensed consolidated financial statements for the periods ending June 30, 2017 and 2016 have been prepared in accordance with GAAP for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. Certain information relating to the Company’s organization and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been appropriately condensed or omitted in this Quarterly Report. The Company believes the disclosures made are adequate to make the information presented not misleading. The unaudited condensed consolidated financial statements contained in this report include all normal and recurring material adjustments that, in the opinion of management, are necessary for a fair statement of the financial position, results of operations and cash flows for the interim periods presented herein. It is recommended that these unaudited condensed consolidated financial statements should be read in conjunction with our most recent audited consolidated financial statements included in Jones Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2016.

Use of Estimates

There have been no significant changes in our use of estimates since those reported in Jones Energy, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2016.

Production taxes

During the first quarter of 2017, the Company's application for High-Cost Gas Incentive refunds in Texas was approved for qualified wells on which taxes were initially paid between October 2012 and September 2016. The Company received a net production tax refund of $3.3 million, which was recorded as a reduction in Production and ad valorem taxes on the Company’s Consolidated Statement of Operations. No further refunds were received during the three months ended June 30, 2017.

Recent Accounting Pronouncements

Adopted in the current year-to-date period:

In March 2016, the FASB issued ASU 2016-09, “Compensation—Stock Compensation” (Topic 718). This amendment is intended to simplify the accounting for share-based payment awards to employees, specifically in regard to (1) the income tax consequences, (2) classification of awards as either equity or liabilities, and (3) classification on the statement of cash flows. The amendments are effective for interim and annual reporting periods beginning after December 15, 2016. Therefore, the Company has adopted ASU 2016-09 effective as of January 1, 2017. Upon adoption of ASU 2016-09, the Company elected to change its accounting policy to account for forfeitures as they occur. The change was applied on a modified retrospective basis with a cumulative effect adjustment to retained earnings for forfeitures of $0.7 million as of January 1, 2017. As a result of the valuation allowance against the Company’s deferred tax assets, there was no net adjustment to retained earnings for the change in accounting for unrecognized windfall tax benefits.

In May 2017, the FASB issued ASU 2017-09, “Scope of Modification Accounting” as it relates to “Compensation—Stock Compensation” (Topic 718). This amendment clarifies when changes to the terms or conditions of a share-based payment award must be accounted for as modifications. The new guidance is expected to reduce diversity in practice and result in fewer changes to the terms of an award being accounted for as modifications. Under ASU 2017-09, an entity will not apply modification accounting to a share-based payment award if the award’s fair value, vesting conditions and classification as an equity or liability instrument are the same immediately before and after the change. The amendments are effective for interim and annual reporting periods beginning after December 15, 2017. Early adoption is permitted and the Company chose to early adopt ASU 2017-09 beginning April 1, 2017. The change was applied prospectively to awards modified on or after the adoption date. Adoption did not have a material impact on the financial position, cash flows or results of operations.

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To be adopted in a future period:

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which creates a new topic in the Accounting Standards Codification (“ASC”), topic 606, “Revenue from Contracts with Customers.” This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09 by one year. The amendments are now effective for interim and annual reporting periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis. Early adoption is permitted. The Company is in the process of comparing our current revenue recognition policies to the new requirements for each of our revenue categories based upon review of our current contracts by product category and homogenous groupings. Our evaluation is not yet complete, and we have not concluded on the overall impacts of adopting the new requirements. The Company will continue to further evaluate the effect that the adoption of Update 2014-09 and Update 2015-14 will have on our financial statements and our anticipated method of adoption. We anticipate adoption of Update 2014-09 and Update 2015-14 effective as of January 1, 2018.

In February 2016, the FASB issued ASU 2016-02, “Leases” (Topic 842). This amendment requires, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for leases. We anticipate adoption of ASU 2016-02 effective as of January 1, 2019.

3. Acquisitions and Divestitures

During the six months ended June 30, 2017 and the year ended December 31, 2016, the Company entered into several purchase and sale agreements, as described below.

Merge Acquisition

On September 22, 2016, JEH acquired oil and gas properties located in the Merge area of the STACK/SCOOP (the “Merge”) play in Central Oklahoma (the “Merge Acquisition”) from SCOOP Energy Company, LLC for cash consideration of $134.4 million, net of the final working capital settlement of $2.4 million received in the first quarter of 2017. The oil and gas properties acquired in the Merge Acquisition, on a closed and funded basis, principally consist of 16,975 undeveloped net acres in Canadian, Grady and McClain Counties, Oklahoma. This transaction has been accounted for as an asset acquisition. The Company used proceeds from our equity offerings to fund a portion of the purchase. See Note 11, “Stockholders’ and Mezzanine equity”.

Anadarko Acquisition

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

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The assets acquired in the Anadarko Acquisition included interests in 174 wells, 59% of which were operated by the company, and approximately 25,000 net acres in Lipscomb and Ochiltree Counties in the Texas Panhandle. As of the closing date, the acquired acreage was producing approximately 900 barrels of oil equivalent per day.

Arkoma Divestiture

On August 1, 2017, JEH closed its previously announced agreement to sell its Arkoma Basin properties (the “Arkoma Assets”) for a purchase price of $65.0 million, subject to customary adjustments (the “Arkoma Divestiture”). JEH may also receive up to $2.5 million in contingent payments based on natural gas prices. No amounts have been recorded related to this contingent payment as of June 30, 2017. The Company received a deposit of $4.9 million associated with the pending sale which has been included in Other current liabilities on the Company’s Consolidated Balance Sheet as of June 30, 2017. See Note 15, “Subsequent Events - Arkoma Divestiture”.

Assets held for sale

As of June 30, 2017, the Arkoma Assets and related liabilities (the “Held for sale assets”) were classified as held for sale due to the pending Arkoma Divestiture. Upon the classification change occurring on June 30, 2017, the Company ceased recording depletion on the Held for sale assets. Based on the Company’s anticipated sales price, the Company has recognized an impairment charge of $161.9 million at June 30, 2017 which has been included in Impairment of oil and gas properties on the Company’s Consolidated Statement of Operations.

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


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

Accounts receivable, net
Oil and gas sales	$	3,250
Joint interest owners		102
Other		14

Other current assets		4

Leasehold improvements		27
Other		68
Less: Accumulated depreciation and amortization		(10)
Other property, plant and equipment, net		85

Total current assets held for sale		3,455

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

Total assets held for sale, net	$	67,655

Liabilities:

Trade accounts payable	$	379
Oil and gas sales payable,		6,015
Accrued liabilities		1,078

Total current liabilities related to assets held for sale		7,472

Asset retirement obligations		1,143

Total liabilities related to assets held for sale	$	8,615

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4. Properties, Plant and Equipment

Oil and Gas Properties

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


	June 30,		December 31,
(in thousands of dollars)	2017		2016
Mineral interests in properties
Unproved	$	180,018	$	213,153
Proved		879,149		1,054,683
Wells and equipment and related facilities		1,311,087		1,395,291
		2,370,254		2,663,127
Less: Accumulated depletion and impairment		(824,263)		(919,539)
Net oil and gas properties	$	1,545,991	$	1,743,588

There were no exploratory wells drilled during the six months ended June 30, 2017 or 2016. As such, no associated costs were capitalized and no exploratory wells resulted in exploration expense during either period.

The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. During the six months ended June 30, 2017, the Company capitalized $0.2 million associated with such in progress projects. The Company did not capitalize any interest during the six months ended June 30, 2016 as no projects lasted more than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

Depletion of oil and gas properties amounted to $45.1 million and $80.5 million for the three and six months ended June 30, 2017, respectively, and $37.8 million and $79.3 million for the three and six months ended June 30, 2016, respectively.

The Company continues to monitor its proved and unproved properties for impairment. No impairments of proved or unproved properties were recorded as a result of our standard impairment assessment during the six months ended June 30, 2017 or 2016. However, as noted in Note 3, “Acquisitions and Divestitures - Assets held for sale,” the Company has recognized an impairment charge of $161.9 million at June 30, 2017 based on the anticipated sales price of our Held for sale assets.

Other Property, Plant and Equipment

Other property, plant and equipment consisted of the following at June 30, 2017 and December 31, 2016:


	June 30,		December 31,
(in thousands of dollars)	2017		2016
Leasehold improvements	$	1,186	$	1,213
Furniture, fixtures, computers and software		4,378		4,170
Vehicles		1,768		1,677
Aircraft		910		910
Other		215		284
		8,457		8,254
Less: Accumulated depreciation and amortization		(5,645)		(5,258)
Net other property, plant and equipment	$	2,812	$	2,996

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

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5. Long-Term Debt

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


(in thousands of dollars)	June 30, 2017		December 31, 2016
Revolver	$	181,000	$	178,000
2022 Notes		409,148		409,148
2023 Notes		150,000		150,000
Total principal amount		740,148		737,148
Less: unamortized discount		(5,735)		(6,240)
Less: debt issuance costs, net		(6,250)		(6,899)
Total carrying amount	$	728,163	$	724,009

Senior Unsecured Notes

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

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

During 2016, the Company purchased an aggregate principal amount of $190.9 million of its senior unsecured notes through several open market and privately negotiated purchases. The Company purchased $90.9 million principal amount of its 2022 Notes for $38.1 million, and $100.0 million principal amount of its 2023 Notes for $46.5 million, in each case excluding accrued interest and including any associated fees. The Company used cash on hand and borrowings from its Revolver to fund the note purchases. In conjunction with the extinguishment of this debt, JEH recognized cancellation of debt income of $99.5 million for the twelve months ended December 31, 2016, on a pre-tax basis. This income is recorded in Gain on debt extinguishment on the Company’s Consolidated Statement of Operations. Of the Company’s total repurchases, $20.3 million principal amount of its 2022 Notes were not cancelled and are available for future reissuance, subject to applicable securities laws.

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

The Company may redeem the 2022 Notes at any time on or after April 1, 2017 and the 2023 Notes at any time on or after March 15, 2018 at a declining redemption price set forth in the respective indentures, plus accrued and unpaid interest.

The indentures governing the 2022 Notes and 2023 Notes are substantially identical and contain covenants that, among other things, limit the ability of the Company to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or other payments from the Company’s restricted subsidiaries to the Company, consolidate, merge or transfer all of the Company’s assets, engage in transactions with affiliates or create unrestricted subsidiaries. If at any time when the 2022 Notes or 2023 Notes are rated investment grade and no

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default or event of default (as defined in the indenture) has occurred and is continuing, many of the foregoing covenants pertaining to the 2022 Notes or 2023 Notes, as applicable, will be suspended. If the ratings on the 2022 Notes or 2023 Notes, as applicable, were to decline subsequently to below investment grade, the suspended covenants would be reinstated.

As of June 30, 2017, the Company was in compliance with the indentures governing the 2022 Notes and 2023 Notes.

Other Long-Term Debt

The Company entered into two credit agreements dated December 31, 2009, with Wells Fargo Bank N.A, the Senior Secured Revolving Credit Facility (the “Revolver”) and the Second Lien Term Loan (the “Term Loan”). On April 1, 2014, the Term Loan was repaid in full and terminated in connection with the issuance of the 2022 Notes. On November 6, 2014, the Company amended the Revolver to, among other things, extend the maturity date of the Revolver to November 6, 2019. The Company’s oil and gas properties are pledged as collateral to secure its obligations under the Revolver.

On August 1, 2016, the Company entered into an amendment to the Revolver to, among other things (i) require that the Company's deposit accounts and securities accounts (subject to certain exclusions) become subject to control agreements, (ii) restrict the Company from borrowing or receiving Letters of Credit under the Revolver if the Company has, or, after giving effect to such borrowing or issuance of Letter of Credit, will have, a Consolidated Cash Balance (as defined in the Revolver) in excess of $30.0 million (in each case giving effect to the anticipated use of proceeds thereof) and (iii) set the borrowing base under the Revolver at $425.0 million. The borrowing base was reaffirmed at this level during the most recent semi-annual borrowing base re-determination effective May 15, 2017. On August 1, 2017, upon closing of the Arkoma Divestiture, the Company’s borrowing base was reduced to $375.0 million. See Note 15, “Subsequent Events”.

The terms of the Revolver require the Company to make periodic payments of interest on the loans outstanding thereunder, with all outstanding principal and interest under the Revolver due on the maturity date. The Revolver is subject to a borrowing base, which limits the amount of borrowings which may be drawn thereunder. The borrowing base will be re-determined by the lenders at least semi-annually on or about April 1 and October 1 of each year, with such re-determination based primarily on reserve reports using lender commodity price expectations at such time. Any reduction in the borrowing base will reduce our liquidity, and, if the reduction results in the outstanding amount under our revolving credit facility exceeding the borrowing base, we will be required to repay the deficiency within a short period of time.

Interest on the Revolver is calculated, at the Company’s option, at either (a) the London Interbank Offered (“LIBO”) rate for the applicable interest period plus a margin of 1.50% to 2.50% based on the level of borrowing base utilization at such time or (b) the greatest of the federal funds rate plus 0.50%, the one month adjusted LIBO rate plus 1.00%, or the prime rate announced by Wells Fargo Bank, N.A. in effect on such day, in each case plus a margin of 0.50% to 1.50% based on the level of borrowing base utilization at such time. For the three and six months ended June 30, 2017, the average interest rates under the Revolver were 2.84% and 2.72%, respectively, on average outstanding balances of $194.6 million and $194.9 million, respectively. For the three and six months ended June 30, 2016, the average interest rates under the Revolver were 2.25% and 2.43%, respectively, on average outstanding balances of $185.0 million and $164.0 million, respectively.

Total interest and commitment fees under the Revolver were $1.6 million and $3.1 million for the three and six months ended June 30, 2017, respectively, and $1.3 million and $2.6 million for the three and six months ended June 30, 2016, respectively.

Jones Energy, Inc. and its consolidated subsidiaries are subject to certain covenants under the Revolver, including the requirement to maintain the following financial ratios:

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

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

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

6. Derivative Instruments and Hedging Activities

The Company uses derivative instruments to mitigate volatility in commodity prices. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our hedging positions.

The following tables summarize our hedging positions as of June 30, 2017:

Hedging Positions


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

The Company recognized net gains on derivative instruments of $21.5 million and $43.8 million for the three and six months ended June 30, 2017, respectively. The Company recognized net losses on derivative instruments of $40.0 million and $22.8 million for the three and six months ended June 30, 2016, respectively.

The Company routinely enters into oil and natural gas swap contracts as seller, thus resulting in a fixed price. During 2016 and 2017, the Company realized certain mark-to-market gains associated with oil and natural gas hedges the Company had in place for years 2018 and 2019. The gains were effectively realized by purchasing, as opposed to selling, oil and natural gas swap contracts for the equal volume that was associated with the initial hedge transaction. Therefore, as prices fluctuate, the loss (or gain) on any single contract in 2018 and 2019 will be offset by an equal gain (or loss). This essentially leaves the underlying production open to fluctuations in market prices. Based on the original contract terms of these purchased swaps, the gains would be recognized as the hedge contracts mature in 2018 and 2019. See further discussion below. Information related to these purchased oil and natural gas swap contracts is presented in the table above as the “offset exercise price”, and the volumes in the table above are presented “net” of such purchased oil and natural gas swap contracts.

During the three and six months ended June 30, 2017, the Company unwound a portion of its realized 2018 and 2019 hedges resulting in approximately $8.1 million and $28.0 million, respectively, of recognized gains which

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

Offsetting Assets and Liabilities

As of June 30, 2017, the counterparties to our commodity derivative contracts consisted of six financial institutions. All of our counterparties or their affiliates are also lenders under the Revolver. We are not generally required to post additional collateral under our derivative agreements.

Our derivative agreements contain set-off provisions that state that in the event of default or early termination, any obligation owed by the defaulting party may be offset against any obligation owed to the defaulting party.

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


					Net Amounts
			Gross		of Assets /		Gross Amounts
	Gross Amounts		Amounts		Liabilities		Not
	of Recognized		Offset in the		Presented in		Offset in the
	Assets /		Balance		the Balance		Balance
(in thousands of dollars)	Liabilities		Sheet		Sheet		Sheet		Net Amount
June 30, 2017
Commodity derivative contracts
Assets	$	58,023	$	(12,286)	$	45,737	$	—	$	45,737
Liabilities		(15,445)		12,286		(3,159)		—		(3,159)
December 31, 2016
Commodity derivative contracts
Assets	$	79,649	$	(20,805)	$	58,844	$	—	$	58,844
Liabilities		(36,664)		20,805		(15,859)		—		(15,859)

7. Fair Value Measurement

Fair Value of Financial Instruments

The Company determines fair value amounts using available market information and appropriate valuation methodologies. Fair value is the price that would be received to sell an asset or would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions and/or estimation methods may have a material effect on the estimated fair value amounts.

The Company enters into a variety of derivative financial instruments, which may include over-the-counter instruments, such as natural gas, crude oil, and natural gas liquid contracts. The Company utilizes valuation techniques that maximize the use of observable inputs, where available. If listed market prices or quotes are not published, fair value is determined based upon a market quote, adjusted by other market-based or independently sourced market data, such as trading volume, historical commodity volatility, and counterparty-specific considerations. These adjustments may include amounts to reflect counterparty credit quality, the time value of money, and the liquidity of the market.

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

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Liquidity valuation adjustments are necessary when the Company is not able to observe a recent market price for financial instruments that trade in less active markets. Exchange traded contracts are valued at market value without making any additional valuation adjustments; therefore, no liquidity reserve is applied.

Valuation Hierarchy

Fair value measurements are grouped into a three-level valuation hierarchy. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. A financial instrument’s categorization within the hierarchy is based upon the input that requires the highest degree of judgment in the determination of the instrument’s fair value. The three levels are defined as follows:

Level 1 Pricing inputs are based on published prices in active markets for identical assets or liabilities as of the reporting date.

Level 2 Pricing inputs include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, as of the reporting date. Contracts that are not traded on a recognized exchange or are tied to pricing transactions for which forward curve pricing is readily available are classified as Level 2 instruments. These include natural gas, crude oil and some natural gas liquids price swaps and natural gas basis swaps.

Level 3 Pricing inputs include significant inputs that are generally unobservable from objective sources. The Company classifies natural gas liquid swaps and basis swaps for which future pricing is not readily available as Level 3. The Company obtains estimates from independent third parties for its open positions and subjects those to the credit adjustment criteria described above.

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


(in thousands of dollars)	June 30, 2017
	Fair Value Measurements Using
Commodity Price Hedges	(Level 1)		(Level 2)		(Level 3)		Total
Current assets	$	—	$	39,823	$	—	$	39,823
Long-term assets		—		3,567		2,347		5,914
Current liabilities		—		2,702		334		3,036
Long-term liabilities (1)		—		(137)		260		123


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

(1)

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

(2)

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

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


	Quantitative Information About Level 3 Fair Value Measurements
	Fair Value			Unobservable
Commodity Price Hedges	(000’s)		Valuation Technique	Input	Range
Natural gas liquid swaps	$	(252)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$22.89 - $23.94 per barrel
Crude oil collars	$	2,766	Use a discounted option model approach using inputs including interpolated volatilities for certain settlement months where market volatility quotes were unavailable for the option strike price	Market volatility quotes at the option strike for certain settlement months in 2019	$45.00 - $61.00 per barrel
Natural gas collars	$	(761)	Use a discounted option model approach using inputs including interpolated volatilities for certain settlement months where market volatility quotes were unavailable for the option strike price	Market volatility quotes at the option strike for certain settlement months in 2019	$2.55 - $3.41 per barrel

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

The following table summarizes the Company’s commodity derivative contract activity involving Level 3 instruments during the six months ended June 30, 2017:


(in thousands of dollars)
Balance at December 31, 2016, net	$	(2,971)
Purchases		131
Settlements		716
Transfers to Level 2		—
Transfers to Level 3		—
Changes in fair value		3,877
Balance at June 30, 2017, net	$	1,753

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Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

The following table provides the fair value of financial instruments that are not recorded at fair value in the consolidated financial statements:


	June 30, 2017				December 31, 2016
	Principal				Principal
(in thousands of dollars)	Amount		Fair Value		Amount		Fair Value
Debt:
Revolver	$	181,000	$	181,000	$	178,000	$	178,000
2022 Notes		409,148		289,206		409,148		393,150
2023 Notes		150,000		111,590		150,000		153,375

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

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

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

As a result of the Arkoma Divestiture that was pending as of June 30, 2017, the Company recognized an impairment charge of $161.9 million at June 30, 2017. This impairment was recorded for excess net book value over anticipated sales proceeds less costs to sell. Fair values of assets held for sale were determined based upon the anticipated sales proceeds less costs to sell, which resulted in a Level 2 classification. See Note 3, “Acquisitions and Divestitures” for further details regarding the “Arkoma Divestiture” and the related “Assets held for sale”.

8. Asset Retirement Obligations

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


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

9. Stock-based Compensation

Management Unit Awards

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

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

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


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

Stock compensation expense associated with the Management Units was $0.2 million and $0.4 million for the three and six months ended June 30, 2017, respectively, and $0.2 million and $0.8 million for the three and six months ended June 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

2013 Omnibus Incentive Plan

Under the Amended and Restated Jones Energy, Inc. 2013 Omnibus Incentive Plan (the “LTIP”), established in conjunction with the Company’s IPO and restated on May 4, 2016 following approval by the Company’s stockholders, the Company has reserved a total of 8,010,102 shares of Class A common stock for non-employee director, consultant, and employee stock-based compensation awards, as adjusted for the effects of the Special Stock Dividend and the preferred stock dividend paid in shares, as described in Note 11 “Stockholders’ and Mezzanine equity”.

The Company granted (i) performance share unit and restricted stock unit awards to certain officers and employees and (ii) restricted shares of Class A common stock to the Company’s non-employee directors under the LTIP during 2014, 2015, 2016 and 2017. During 2016 and 2017, the Company also granted performance unit awards to certain members of the senior management team under the LTIP.

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

Restricted Stock Unit Awards

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

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The following table summarizes information related to the total number of units awarded to officers and employees as of June 30, 2017:


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

(1)

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

Stock compensation expense associated with the employee restricted stock unit awards was $1.0 million and $2.0 million for the three and six months ended June 30, 2017, respectively, and $0.9 million and $1.0 million for the three and six months ended June 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

Performance Share Unit Awards

The Company has outstanding performance share unit awards granted to certain members of the senior management team of the Company under the LTIP. Prior to the second quarter of 2016, the performance share unit awards were described in the Company’s filings as performance unit awards. During the second quarter of 2016, the Company created a new class of equity award, described below as a performance unit award, that is settled in cash rather than shares of the Company’s Class A common stock. As a result, references to performance unit awards in the Company’s filings prior to the second quarter of 2016 refer to this description of performance share unit awards.

Upon the completion of the applicable three-year performance period, each recipient may vest in a number of performance share units. The percent of awarded performance share units in which each recipient vests at such time, if any, will range from 0% to 200% based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. Each vested performance share unit is exchangeable for one share of the Company’s Class A common stock. The grant date fair value of the performance share units was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance share units earned. The fair value of the performance share units is expensed on a straight-line basis over the applicable three-year performance period.

The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the performance share unit awards granted during the six months ended June 30, 2017:


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

For the performance share units granted during the six months ended June 30, 2017, the Monte Carlo simulation

model resulted in approximately 29% of performance share units expected to be earned.

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


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

(1)

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

Stock compensation expense associated with the performance share unit awards was $0.5 million and $1.0 million for the three and six months ended June 30, 2017, respectively, and $0.6 million and $1.0 million for the three and six months ended June 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

Performance Unit Awards

The value of awarded performance units in which each recipient vests at such time, if any, will range from $0.00 to $200.00 per performance unit based on the Company’s total shareholder return relative to an industry peer group over the applicable three-year performance period. For accounting purposes, the performance units are treated as a liability award with the liability being re-measured at the end of each reporting period. Therefore, the expense associated with these awards is subject to volatility until the payout is finally determined at the end of the performance period. The value of the performance units was determined using a Monte Carlo simulation model, as of the grant date, which resulted in an estimated final value upon vesting of $0.4 and $1.3 million for awards made during 2017 and 2016, respectively. The fair value measured as of June 30, 2017 was $0.8 million.

The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated stock-based compensation expense of the performance unit awards granted during the six months ended June 30, 2017:


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

For the performance units granted during the six months ended June 30, 2017, the Monte Carlo simulation

model resulted in an expected payout of $28.25 per performance unit as of the grant date.

Stock compensation expense associated with the performance unit awards was an offset to expense of less than $0.1 million for the three and six months ended June 30, 2017, respectively, as a result of the decrease in market value of the outstanding awards and less than $0.1 million for the three and six months ended June 30, 2016, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. As of June 30, 2017, $0.5 million of unrecognized compensation expense related to the performance unit awards,

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subject to re-measurement and adjustment for the change in estimated final value as of the end of each reporting period, is expected to be recognized over the remaining weighted average service period of 1.9 years.

Restricted Stock Awards

The Company has outstanding restricted stock awards granted to the non-employee members of the Board of Directors of the Company under the LTIP. The restricted stock will vest upon the director serving as a director of the Company for a one-year service period in accordance with the terms of the award. The fair value of the awards was based on the price of the Company’s Class A common stock on the date of grant.

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


		Weighted Average
	Restricted	Grant Date Fair Value
	Stock Awards	per Share
Unvested at December 31, 2016	152,050	$	3.68
Granted	180,000		2.25
Forfeited	—		—
Vested	(152,050)		3.68
Unvested at June 30, 2017	180,000	$	2.25

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

10. Income Taxes

The Company records federal and state income tax liabilities associated with its status as a corporation. The Company recognizes a tax liability on its share of pre-tax book income, exclusive of the non-controlling interest. JEH is not subject to income tax at the federal level and only recognizes Texas franchise tax expense.

The Company’s effective tax rate was 1.6% and 1.6% for the three and six months ended June 30, 2017, respectively, and 17.4% and 14.3% for the three and six months ended June 30, 2016, respectively. The effective tax rate reduction is primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets. The effective rate differs from the statutory rate of 35% due to net income allocated to the non-controlling interest, percentage depletion, state income taxes, the valuation allowance recorded against deferred tax assets, and other permanent differences between book and tax accounting.

The Company’s income tax provision was a benefit of $2.4 million for the three and six months ended June 30, 2017, respectively, and a benefit of $12.4 million and $1.7 million for the three and six months ended June 30, 2016, respectively.

The following table summarizes information related to the allocation of the income tax provision between the controlling and non-controlling interests:


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

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

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taxable income based on the reversal of temporary differences to enable utilization of substantially all other tax carryforwards.

Tax Receivable Agreement

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

The actual amount and timing of payments to be made under the TRA will depend upon a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers, and the portion of the Company’s payments under the TRA constituting imputed interest. In the event that the Company records a valuation allowance against its deferred tax assets associated with an exchange, the TRA liability will also be reduced as the payment of the TRA liability is dependent on the realizability of the deferred tax assets. As of June 30, 2017 and December 31, 2016, the amount of the TRA liability was reduced by $33.2 million and $2.7 million, respectively, as a result of the valuation allowance recorded against the Company’s deferred tax assets. To the extent the Company does not realize all of the tax benefits in future years or in the event of a change in future tax rates, this liability may change.

As of June 30, 2017 and December 31, 2016, the Company had recorded a TRA liability of $12.4 million and $43.0 million, respectively, for the estimated payments that will be made to the Class B shareholders who have exchanged shares, after adjusting for the TRA liability reduction, along with corresponding deferred tax assets, net of valuation allowance, of $14.5 million, and $50.6 million, respectively, as a result of the increase in tax basis generated arising from such exchanges.

As of June 30, 2017, the Company had not made any significant payments under the TRA to Class B shareholders who have exchanged JEH Units and Class B common stock for Class A common stock. The Company anticipates making a payment of approximately $0.6 million under the TRA with respect to cash savings that the Company will realize on its 2016 tax returns as a result of tax attributes arising from prior exchanges, to be paid in the first quarter of 2018.

Cash Tax Distributions

The holders of JEH Units, including the Company, incur U.S. federal, state and local income taxes on their share of any taxable income of JEH. Under the terms of its operating agreement, JEH is generally required to make quarterly pro-rata cash tax distributions to its unitholders (including us) based on income allocated to its unitholders through the end of each relevant quarter, as adjusted to take into account good faith projections by the Company of taxable income or loss for the remainder of the calendar year, to the extent JEH has cash available for such distributions and subject to certain other restrictions.

A Special Committee of the Board of Directors comprised solely of directors who do not have a direct or indirect interest in such distribution approved, and JEH made, aggregate cash tax distributions during the three and six months ended June 30, 2017 of $0.0 million and $1.7 million, respectively. Distributions during the year were made pro-rata to all members of JEH, and included a $1.1 million payment to the Company and a $0.6 million payment to JEH unitholders other than the Company. During the three and six months ended June 30, 2016 the Company made aggregate cash tax distributions of $20.0 million to its unitholders towards its total 2016 projected tax distribution obligation. The distributions were made pro-rata to all members of JEH, and included a $9.9 million payment to the Company, and a $10.1 million payment to JEH unitholders other than the Company. All tax distributions were paid as a result of JEH’s 2016 taxable income.

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11. Stockholders’ and Mezzanine equity

Stockholders’ equity is comprised of two classes of common stock, Class A common stock and Class B common stock. The Class B common stock is held by the owners of JEH prior to the Company’s IPO and can be exchanged (together with a corresponding number of units representing membership interests in JEH Units) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. The Class B common stock has no economic rights but entitles its holders to one vote on all matters to be voted on by the Company’s stockholders generally.

The Company has classified the Series A preferred stock as mezzanine equity based upon the terms and conditions that contain various redemption and conversion features. For a description of these features, please see below under “—Offering of 8.0% Series A Perpetual Convertible Preferred Stock.”

Equity Distribution Agreement

On May 24, 2016, the Company and JEH entered into an Equity Distribution Agreement (“Equity Distribution Agreement”) with Citigroup Global Markets Inc. and Wells Fargo Securities, LLC (each, a “Manager” and collectively, the “Managers”). Pursuant to the terms of the Equity Distribution Agreement, the Company may sell from time to time through the Managers, as the Company’s sales agents, the Company’s Class A common stock having an aggregate offering price of up to $73.0 million (the “Class A Shares”). Under the terms of the Equity Distribution Agreement, the Company may also sell Class A Shares from time to time to any Manager as principal for its own account at a price to be agreed upon at the time of sale. Any sale of Class A Shares to a Manager as principal would be pursuant to the terms of a separate terms agreement between the Company and such Manager. Sales of the Class A Shares, if any, will be made by means of ordinary brokers’ transactions, to or through a market maker or directly on or through an electronic communication network, a “dark pool” or any similar market venue, or as otherwise agreed by the Company and one or more of the Managers.

During the three and six months ended June 30, 2017, the Company sold approximately 2.5 million and 3.7 million Class A Shares, respectively, under the Equity Distribution Agreement for net proceeds of approximately $5.6 million ($5.8 million gross proceeds, net of approximately $0.2 million in commissions and professional services expenses) and $8.4 million ($8.7 million gross proceeds, net of approximately $0.3 million in commissions and professional services expenses), respectively. The Company used the net proceeds for general corporate purposes. As of June 30, 2017, approximately $62.2 million in aggregate offering proceeds remained available to be issued and sold under the Equity Distribution Agreement.

Offering of Class A Common Stock

On August 26, 2016, the Company issued 21,000,000 shares of Class A common stock pursuant to an underwritten public offering, and on September 12, 2016 the Company issued an additional 3,150,000 shares of Class A common stock in connection with the exercise of the underwriters’ over-allotment option. The total net proceeds (after underwriters’ discounts and commissions, but before estimated expenses) of the offering, including the exercise of the over-allotment option, was $64.0 million.

Offering of 8.0% Series A Perpetual Convertible Preferred Stock

On August 26, 2016, the Company issued 1,840,000 shares of Series A preferred stock pursuant to an underwritten public offering for total net proceeds (after underwriters’ discounts and commissions but before expenses) of $88.3 million.

Holders of Series A preferred stock are entitled to receive, when as and if declared by the Company’s Board of Directors, cumulative dividends at the rate of 8.0% per annum (the “dividend rate”) per share on the $50.00 liquidation preference per share of the Series A Preferred Stock, payable quarterly in arrears on February 15, May 15, August 15 and November 15 of each year, beginning on November 15, 2016. Dividends may be paid in cash or, subject to certain limitations, in Class A common stock, or a combination thereof.

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Under the terms of the Series A preferred stock, the Company’s ability to declare or pay dividends or make distributions on, or purchase, redeem or otherwise acquire for consideration, shares of the Company’s Class A common stock, or any junior stock or parity stock currently outstanding or issued in the future, will be subject to certain restrictions in the event that the Company does not pay in full or declare and set aside for payment in full all accrued and unpaid dividends on the Series A preferred stock (including certain unpaid excess cash payment amounts excused from payment as a dividend due to restrictions in credit facilities or other indebtedness or legal requirements (“Unpaid Excess Cash Payment Amounts”)).

Each share of Series A preferred stock has a liquidation preference of $50.00 per share and is convertible, at the holder’s option at any time, into approximately 17.0683 shares of Class A common stock after adjusting the conversion ratio for the effects of the Special Stock Dividend, as defined in Note 11, “Stockholders’ and Mezzanine equity”, (which is equivalent to a conversion price of approximately $2.93 per share after adjusting for the effects of the Special Stock Dividend), subject to specified further adjustments and limitations as set forth in the certificate of designations for the Series A preferred stock. Based on the adjusted conversion rate and the full exercise of the Preferred Stock Underwriters’ over-allotment option, approximately 31.4 million shares of Class A common stock would be issuable upon conversion of all the Series A preferred stock.

On or after August 15, 2021, the Company may, at its option, give notice of its election to cause all outstanding shares of Series A preferred stock to be automatically converted into shares of Class A common stock at the conversion rate, if the closing sale price of the Class A common stock equals or exceeds 175% of the conversion price for at least 20 trading days in a period of 30 consecutive trading days.

On August 15, 2024 (the “designated redemption date”), each holder of Series A preferred stock may require us to redeem any or all Series A preferred stock held by such holder outstanding on the designated redemption date at a redemption price equal to a liquidation preference of $50.00 per share plus all accrued dividends on the shares up to but excluding the designated redemption date that have not been paid plus any Unpaid Excess Cash Payment Amounts (the “redemption price”). At our option, the redemption price may be paid in cash or, subject to certain limitations, in Class A common stock, or a combination thereof.

Except as required by law or the Company’s certificate of incorporation, which includes the certificate of designations for the Series A preferred stock, the holders of Series A preferred stock have no voting rights (other than with respect to certain matters regarding the Series A preferred stock or when dividends payable on the Series A preferred stock have not been paid for an aggregate of six quarterly dividend periods, or more, whether or not consecutive, as provided in the certificate of designations for the Series A preferred stock).

The Series A preferred stock is classified as mezzanine equity on the Company’s Consolidated Balance Sheet and is not listed on a national stock exchange.

A summary of the Company’s Mezzanine equity for the six months ended June 30, 2017 is as follows:


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

Preferred Stock Dividends

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

On April 17, 2017, the Company’s Board of Directors declared a quarterly dividend per share equal to 8.0% based on the liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock. On May 15, 2017, the dividend was paid in a combination of cash and the Company’s Class A

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common stock, with the cash component equal to $0.83 per share and the stock component equal to $0.17 per share. The price per share of the Class A common stock used to determine the number of shares issued was equal to 95% of the average volume-weighted average price per share for each day during the five-consecutive day trading period ending immediately prior to the payment date. This dividend was for the period beginning on the last payment date of February 15, 2017 through May 14, 2017 to shareholders of record as of May 1, 2017.

Special Stock Dividend

On March 31, 2017, the Company paid a stock dividend (the “Special Stock Dividend”) of 0.087423 shares of the Class A common stock to holders of record as of March 15, 2017. From time-to-time, JEH makes cash distributions to the holders of JEH Units to cover tax obligations that may occur as a result of any net taxable income of JEH allocable to holders of JEH Units. As a holder of JEH Units, the Company has received such cash distributions from JEH in excess of the amount required to satisfy the Company’s associated tax obligations. As a result, the Company used the excess cash of approximately $17.5 million in the aggregate to acquire newly-issued JEH Units from JEH.

The Special Stock Dividend was distributed in order to equalize the number of shares of Class A common stock outstanding to the number of JEH Units held by the Company, and the aggregate number of shares of Class A common stock issued in the Special Stock Dividend equaled the number of additional JEH Units the Company purchased from JEH. The Company purchased 4,999,927 JEH Units at a price of $3.50 per share, which is the volume weighted average price per share of the Class A common stock for the five trading days ended February 28, 2017. Immaterial cash payments were made in lieu of fractional shares. The comparative earnings per share information has been recast to retrospectively adjust for the effects of the Special Stock Dividend.

12. Earnings per Share

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

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands, except per share data)	2017		2016		2017		2016
Income (numerator):
Net income (loss) attributable to controlling interests	$	(89,239)	$	(23,245)	$	(90,626)	$	(4,334)
Less: Dividends and accretion on preferred stock		(1,966)		—		(3,993)		—
Net income (loss) attributable to common shareholder	$	(91,205)	$	(23,245)	$	(94,619)	$	(4,334)
Weighted-average shares (denominator): (1)
Weighted-average number of shares of Class A common stock - basic		65,681		33,598		63,948		33,410
Weighted-average number of shares of Class A common stock - diluted		65,681		33,598		63,948		33,410
Earnings (loss) per share: (1)
Basic - Net income (loss) attributable to common shareholders	$	(1.39)	$	(0.69)	$	(1.48)	$	(0.13)
Diluted - Net income (loss) attributable to common shareholders	$	(1.39)	$	(0.69)	$	(1.48)	$	(0.13)

(1)

13. Related Parties

Related Party Transactions

Transactions with Our Executive Officers, Directors and 5% Stockholders

Monarch Natural Gas Holdings, LLC Natural Gas Sale and Purchase Agreement

On May 7, 2013, the Company entered into a natural gas sale and purchase agreement with Monarch Natural Gas, LLC, (“Monarch”), under which Monarch has the first right to gather the natural gas the Company produces from dedicated properties, process the NGLs from this natural gas production and market the processed natural gas and extracted NGLs. Under the Monarch agreement, the Company is paid a specified percentage of the value of the NGLs extracted and sold by Monarch, based on a set liquids recovery percentage, and the amount received from the sale of the residue gas, after deducting a fixed volume for fuel, lost and unaccounted-for gas. The Company produced approximately 1.4 MMBoe of natural gas and NGLs for the year ended December 31, 2014, from the properties that became subject to the Monarch agreement. During the year ended December 31, 2014, the Company recognized $37.0 million of revenue associated with the aforementioned natural gas and NGL production. Effective May 1, 2015, the rights to gather natural gas under the sale and purchase agreement transferred from Monarch to Enable Midstream Partners LP, (“Enable”), an unaffiliated third-party. Prior to closing of the transfer of these rights, the Company produced approximately 1.0 MMBoe of natural gas and NGLs for the year ended December 31, 2015 from the properties that became subject to the Monarch agreement for which the Company recognized $10.6 million of revenue. The revenue, for all years mentioned, is recorded in Oil and gas sales on the Company’s Consolidated Statement of Operations. The initial term of the agreement, which remains unchanged by the transfer to Enable, runs for 10 years from the effective date of September 1, 2013.

At the time the Company entered into the 2013 Monarch agreement, Metalmark Capital owned approximately 81% of the outstanding equity interests of Monarch. In addition, Metalmark Capital beneficially owns in excess of five percent of the Company’s outstanding equity interests and two of our former directors, Howard I. Hoffen

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and Gregory D. Myers, are managing directors of Metalmark Capital and were directors at the time the Company entered into the 2013 Monarch agreement.

In connection with the Company’s entering into the 2013 Monarch agreement, Monarch issued to JEH equity interests in Monarch, having an estimated fair value of $15.0 million, in return for marketing services to be provided throughout the term of the agreement. The Company recorded this amount as deferred revenue which is being amortized on an estimated units-of-production basis commencing in September 2013, the first month of product sales to Monarch. The Company amortized $0.5 million and $0.9 million, respectively, of the deferred revenue balance during the three and six months ended June 30, 2017, and $0.6 million and $1.2 million, respectively, of the deferred revenue balance during the three and six months ended June 30, 2016. This revenue is recorded in Other revenues on the Company’s Consolidated Statement of Operations.

Following the issuance of $15.0 million Monarch equity interests to JEH, JEH assigned $2.4 million of the equity interests to Jonny Jones, the Company’s chief executive officer and chairman of the Board of Directors, and reserved $2.6 million of the equity interests for future distribution through an incentive plan to certain of the Company’s officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10.0 million of Monarch equity interests was distributed to certain of the Class B shareholders, which included, among others, Metalmark Capital, the Jones family entities, and certain of the Company’s officers and directors, including Jonny Jones, Mike McConnell and Eric Niccum. As of June 30, 2017, equity interests in Monarch of $0.7 million are included in Other assets on the Company’s Consolidated Balance Sheet. During the six months ended June 30, 2017, no equity interests were distributed to management under the incentive plan. The Company recognized expense of $0.1 million and $0.2 million during the three and six months ended June 30, 2017, respectively, in connection with the incentive plan.

In September 2014, the Company signed a 10-year oil gathering and transportation agreement with Monarch Oil Pipeline LLC, pursuant to which Monarch Oil Pipeline LLC built, at its expense, a new oil gathering system and connected the gathering system to dedicated Company leases in Texas. At the time the Company entered into the agreement, Metalmark Capital owned the majority of the outstanding equity interests of Monarch Oil Pipeline LLC and/or its parent. The system began service during the fourth quarter of 2015 and provides connectivity to both a regional refinery market as well as the Cushing market hub. The Company incurred gathering fees, which were paid to Monarch Oil Pipeline LLC, of $0.6 million and $1.3 million for the three and six months ended June 30, 2017, respectively, associated with the approximately 0.3 MMBoe and 0.6 MMBoe, respectively, of oil production transported under the agreement. These costs are recorded as an offset to Oil and gas sales in the Company’s Consolidated Statement of Operations. The aforementioned production was recognized as Oil and gas sales on the Company’s Consolidated Statement of Operations at the time it was sold to the purchasers, who are unaffiliated third parties, after passing through the gathering and transportation system. The audit committee of the Board of Directors reviewed and approved the terms of the agreement with Monarch Oil Pipeline LLC.

Purchases of Senior Unsecured Notes

On February 29, 2016, JEH and Jones Energy Finance Corp. purchased $50.0 million principal amount of their outstanding 2023 Notes from investment funds managed by Magnetar Capital and its affiliates, which investment funds collectively then owned more than 5% of a class of voting securities of the Company, for approximately $23.3 million excluding accrued interest and including any associated fees. On the same day, JEH and Jones Energy Finance Corp. purchased an additional $50.0 million principal amount of their outstanding 2023 Notes from investment funds managed by Blackstone Group Management L.L.C. and its affiliates, which investment funds collectively then owned more than 5% of a class of voting securities of the Company, for approximately $23.3 million excluding accrued interest and including any associated fees. In conjunction with the extinguishment of this $100.0 million principal amount of debt, JEH recognized cancellation of debt income of $48.3 million on a pre-tax basis. This income is recorded in Gain on debt extinguishment on the Company’s Consolidated Statement of Operations.

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Issuance of Class A Shares

In connection with the August 2016 issuance of Class A common stock pursuant to an underwritten public offering as described above under “Item 11. Stockholders’ and Mezzanine equity—Offering of Class A Common Stock,” affiliates of JVL Advisors, L.L.C. (“JVL”), who then owned more than 5% of a class of voting securities of the Company, purchased 9,025,270 shares of Class A common stock, prior to adjustment for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 11, “Stockholders’ and Mezzanine equity”, in the offering, for gross proceeds to the Company of $25.0 million, before underwriting discounts and commissions of $1.1 million.

Following its purchase in the offering, JVL owned in excess of 15% of our outstanding voting stock. As a result, the Company entered into a letter agreement with JVL (the “JVL Letter Agreement”) in connection with the offering. The JVL Letter Agreement approved, pursuant to Section 203 of the Delaware General Corporation Law (“Section 203”), the purchase of shares of Class A common stock in the offering by JVL. This approval resulted in JVL not being subject to the restrictions on “business combinations” contained in Section 203. In consideration of such approval, JVL agreed that, among other things:

it will not acquire any material assets of the Company;

it will not become the owner of more than 19.9% of the Company’s outstanding voting stock (other than as a result of actions taken solely by the Company) without the prior approval of the Company’s independent directors who are not affiliated with JVL; and

it will not engage in any “business combination” (as defined in the JVL Letter Agreement).

On May 3, 2017, the Company amended and restated its registration rights agreement dated August 29, 2013 (as amended and restated, the “Restated Registration Rights Agreement”) to add JVL as a party in order to facilitate an orderly distribution of JVL’s shares of Class A common stock in the future, a copy of which was filed on the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 3, 2017.

Issuance of Series A Preferred Stock

In connection with the August 2016 issuance of Series A preferred stock pursuant to an underwritten public offering as described above under “Item 11. Stockholders’ and Mezzanine equity—Offering of 8.0% Series A Perpetual Convertible Preferred Stock,” affiliates of Metalmark, who then owned more than 5% of a class of voting securities of the Company and had two representatives on our Board of Directors, purchased 200,000 shares of Series A preferred stock in the offering, for gross proceeds to the Company of $10.0 million, before underwriting discounts and commissions of $400,000.

Amended and Restated Registration Rights and Stockholders Agreement

On May 2, 2017, we entered into an Amended and Restated Registration Rights and Stockholders Agreement (the “Restated Agreement”) with certain entities affiliated with the Jones family (the “Jones Family Entities”), Metalmark and JVL.

The Restated Agreement amends and restates in its entirety that certain Registration Rights and Stockholders Agreement, dated July 29, 2013 (the “Original Agreement”), by and among the Company, Metalmark and the Jones Family Entities, to, among other things, provide JVL with certain rights, in addition to those rights granted to Metalmark and the Jones Family Entities in the Original Agreement, to require the Company to register the sale of any number of JVL’s shares of Class A common stock. JVL shall have the right to cause no more than one such required or “demand” registration, which shall be requested by a majority in interest of the JVL holders who hold certain equity securities of the Company or securities convertible or exchangeable into equity securities of the Company. The Company is not obligated to affect any demand registration in which the anticipated aggregate offering price included in such offering is equal to or less than $50,000,000 ($25,000,000 where the registration is on a Form S-3). Furthermore, if, at any time, the Company proposes to register an offering of Class A common stock (subject to certain exceptions) for the Company’s own account, then it must give prompt notice to Metalmark, JVL and the Jones Family Entities to allow them to include a specified number of their shares in that registration statement. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and the Company’s right to

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

14. Commitments and Contingencies

Litigation

The Company is subject to legal proceedings and claims that arise in the ordinary course of its business. When applicable, we record accruals for contingencies when it is probable that a liability will be incurred and the amount of loss can be reasonably estimated. While the outcome of lawsuits and other proceedings against us cannot be predicted with certainty, in the opinion of management, individually or in the aggregate, no such lawsuits are expected to have a material effect on our financial position, results of operations, or liquidity.

In an action filed on June 12, 2015 in the 31 st District Court of Hemphill County, Texas, Donna Kim Flowers and Mitchell Kirk Flowers v. Jones Energy, LLC f/k/a Jones Energy Limited, LLC f/k/a Jones Energy, Ltd. (Case No. 7225), the Company was sued by Donna Kim Flowers and Mitchell Kirk Flowers (the “plaintiffs”). The plaintiffs own surface rights to property located in Hemphill County, Texas. The mineral rights are leased to third parties, and the Company is the operator of the Oil and Gas Mineral Lease. On May 28, 2010, the plaintiffs and the Company entered into a Surface Use Agreement concerning the Company’s operations on the property, which require the Company to minimize disruption and damage to the plaintiffs’ surface rights. The plaintiffs allege that the Company is in breach of such contract, and seek monetary damages. In June 2016, the Company presented a settlement offer to the plaintiffs. As a result of this settlement offer, the Company accrued $1.5 million related to its estimated obligation under this settlement offer. This accrual was included in accrued liabilities on the Company’s Consolidated Balance Sheet as of December 31, 2016, and the charge was recorded as general and administrative expense on the Company’s Consolidated Statement of Operations during the three months ended June 30, 2016. In June 2017, the Company presented a revised settlement offer to the plaintiffs and the plaintiff accepted. The settlement was paid in cash during June 2017. Upon settlement, the Company recognized an additional charge of $1.4 million which was recorded as general and administrative expense on the Company’s Consolidated Statement of Operations during the three months ended June 30, 2017.

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15. Subsequent Events

Preferred Stock Dividend Declared

On July 13, 2017, the Company’s Board of Directors declared a quarterly dividend per share equal to 8.0% based on the liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock, to be paid entirely in shares of Class A common stock (the “August Preferred Dividend”). The price per share of the Class A common stock used to determine the number of shares issued will equal to 95% of the average volume-weighted average price per share for each day during the 5-consecutive day trading period ending immediately prior to the payment date. The August Preferred Dividend will be paid on August 15, 2017 for the period beginning on the last payment date of May 15, 2017 through August 14, 2017 to shareholders of record as of August 1, 2017.

Arkoma Divestiture

On August 1, 2017, JEH closed the previously announced Arkoma Divestiture for a purchase price of $65.0 million, subject to customary adjustments. Upon closing, the Company’s borrowing base on the Revolver was reduced to $375.0 million.

Class B to Class A Share Exchanges

On July 7, 2017, certain Class B shareholders exchanged an aggregate of 6,105,148 shares of Class B common stock (together with a corresponding number of JEH Units) for shares of Class A common stock on a one-for-one basis (the “July Exchanges”). As of June 30, 2017 and December 31, 2016, the Company had recorded a TRA liability of $12.4 million and $43.0 million, respectively, for the estimated payments that will be made to Class B shareholders who have exchanged shares of Class B common stock, after adjusting for the TRA liability reduction as a result of the increase in tax basis arising from such exchanges. After the July Exchanges, the gross TRA liability increased by approximately $18.7 million. The increase in TRA liability will be offset entirely as a result of the valuation allowance recorded against the deferred asset generated in the exchange that would lead to payment of such TRA liability.

16. Subsidiary Guarantors

The 2022 Notes and the 2023 Notes are guaranteed on a senior unsecured basis by the Company and by all of JEH’s current subsidiaries (except Jones Energy Finance Corp. and two immaterial subsidiaries) and certain future subsidiaries, including any future subsidiaries that guarantee any indebtedness under the Revolver. Each subsidiary guarantor is 100% owned by JEH, and all guarantees are full and unconditional, subject to customary exceptions pursuant to the indentures governing our 2022 Notes and 2023 Notes, as discussed below, and joint and several with all other subsidiary guarantees and the parent guarantee. Any subsidiaries of JEH other than the subsidiary guarantors and Jones Energy Finance Corp. are immaterial.

As of December 31, 2016, the 2022 Notes and the 2023 Notes were guaranteed on a senior unsecured basis by the Company and by all of its significant subsidiaries, other than Nosley SCOOP, LLC and Nosley Acquisition, LLC. These subsidiaries have since become guarantors during the first quarter of 2017 and are therefore presented accordingly in the accompanying condensed consolidated guarantor financial information.

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

The Company is a holding company whose sole material asset is an equity interest in JEH. The Company is the sole managing member of JEH and is responsible for all operational, management and administrative decisions related to JEH’s business. In accordance with JEH’s limited liability company agreement, the Company may not be removed as the sole managing member of JEH.

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As of June 30, 2017, the Company held 66,649,057 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 29,823,927 JEH Units are held by the Class B shareholders. The Class B shareholders have no voting rights with respect to their economic interest in JEH.

The Company has two classes of common stock, Class A common stock, which was sold to investors in the IPO, and Class B common stock, and one series of preferred stock, Series A preferred stock. Pursuant to the Company’s certificate of incorporation, each share of Class A common stock is entitled to one vote per share, and the shares of Class A common stock are entitled to 100% of the economic interests in the Company. Each share of Class B common stock has no economic rights in the Company, but entitles its holder to one vote on all matters to be voted on by the Company’s stockholders generally. Except as required by law or the Company’s certificate of incorporation, which includes the certificate of designations for the Series A preferred stock, the holders of Series A preferred stock have no voting rights (other than with respect to certain matters regarding the Series A preferred stock or when dividends payable on the Series A preferred stock have not been paid for an aggregate of six quarterly dividend periods, or more, whether or not consecutive, as provided in the certificate of designations for the Series A preferred stock).

In connection with a reorganization that occurred immediately prior to the IPO, each Existing Owner was issued a number of shares of Class B common stock that was equal to the number of JEH Units that such Class B shareholders held. Holders of the Company’s Class A common stock and Class B common stock generally vote together as a single class on all matters presented to the Company’s stockholders for their vote or approval. Accordingly, the Class B shareholders collectively have a number of votes in the Company equal to the aggregate number of JEH Units that they hold.

The Class B shareholders have the right, pursuant to the terms of an exchange agreement by and among the Company, JEH and each of the Class B shareholders (the “Exchange Agreement”), to exchange their JEH Units (together with a corresponding number of shares of Class B common stock) for shares of Class A common stock on a one-for-one basis, subject to customary conversion rate adjustments for stock splits, stock dividends and reclassifications and other similar transactions. As a result, the Company expects that over time the Company will have an increasing economic interest in JEH as Class B common stock and JEH Units are exchanged for Class A common stock. Moreover, any transfers of JEH Units outside of the Exchange Agreement (other than permitted transfers to affiliates) must be approved by the Company. The Company intends to retain full voting and management control over JEH.

During the preparation of the condensed consolidating financial information of Jones Energy, Inc. and Subsidiaries as of and for the three and six months period ended June 30, 2017, it was determined that the Issuer Investment in subsidiaries and the related Eliminations at December 31, 2016 as filed in the Company’s 2016 Form 10-K were improperly calculated and understated by $453.2 million. Additionally, it was determined that the Guarantor Subsidiaries Intercompany payable balances and the related Eliminations and the Issuer Intercompany receivable and the related Eliminations at December 31, 2016 as filed in the Company’s 2016 Form 10-K were improperly calculated and overstated by $453.2 million and $80.0 million, respectively. In addition, it was determined that the Issuer Equity interest in income (loss) and the related Eliminations for the three and six months period ended June 30, 2016 as filed in the Company’s second quarter 2016 Form 10-Q were improperly calculated and understated by $35.7 million and $5.8 million, respectively. Lastly, it was determined that the Issuer Adjustments to reconcile net income (loss) to net cash provided by operating activities and the related Eliminations for the six months period ended June 30, 2016 as filed in the Company’s second quarter 2016 Form 10-Q was improperly calculated and overstated by $5.8 million.

The errors, which the Company has determined are not material to this disclosure, had no impact on the total assets of the Parent or the Guarantor Subsidiaries and are eliminated upon consolidation, and therefore have no impact on the Company’s consolidated financial condition, results of operations or cash flows.

The Company has revised the Condensed Consolidating Balance Sheets for the Issuer, Guarantor Subsidiaries and Eliminations as of December 31, 2016, the Condensed Consolidating Income Statements for the Issuer and Eliminations for the three and six months period ended June 30, 2016 and the Condensed Consolidating Statement of Cash Flows for the six months ended June 30, 2016 to correct for these errors.

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Jones Energy, Inc.

Condensed Consolidating Balance Sheet

June 30, 2017


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Assets
Current assets
Cash	$	3,254	$	781	$	2,199	$	20	$	—	$	6,254
Accounts receivable, net
Oil and gas sales		—		—		24,557		—		—		24,557
Joint interest owners		—		—		9,032		—		—		9,032
Other		—		3,943		3,262		—		—		7,205
Commodity derivative assets		—		39,823		—		—		—		39,823
Other current assets		2,746		311		8,324		—		—		11,381
Assets held for sale		—		—		3,455		—		—		3,455
Intercompany receivable		18,567		1,204,759		—		—		(1,223,326)		—
Total current assets		24,567		1,249,617		50,829		20		(1,223,326)		101,707
Assets held for sale, net		—		—		64,200		—		—		64,200
Oil and gas properties, net, at cost under the successful efforts method		—		—		1,545,991		—		—		1,545,991
Other property, plant and equipment, net		—		—		2,239		573		—		2,812
Commodity derivative assets		—		5,914		—		—		—		5,914
Other assets		—		4,467		928		—		—		5,395
Investment in subsidiaries		432,964		394,331		—		—		(827,295)		—
Total assets	$	457,531	$	1,654,329	$	1,664,187	$	593	$	(2,050,621)	$	1,726,019
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	27	$	62	$	55,964	$	—	$	—	$	56,053
Oil and gas sales payable		—		—		22,301		—		—		22,301
Accrued liabilities		33		11,418		8,120		—		—		19,571
Commodity derivative liabilities		—		3,036		—		—		—		3,036
Other current liabilities		639		1,985		5,475		—		—		8,099
Liabilities related to assets held for sale		—		—		7,472		—		—		7,472
Intercompany payable		—		—		1,220,390		2,936		(1,223,326)		—
Total current liabilities		699		16,501		1,319,722		2,936		(1,223,326)		116,532
Liabilities related to assets held for sale		—		—		1,143		—		—		1,143
Long-term debt		—		728,163		—		—		—		728,163
Deferred revenue		—		6,106		—		—		—		6,106
Commodity derivative liabilities		—		123		—		—		—		123
Asset retirement obligations		—		—		19,061		—		—		19,061
Liability under tax receivable agreement		11,807		—		—		—		—		11,807
Other liabilities		—		236		666		—		—		902
Deferred tax liabilities		85		2,826		—		—		—		2,911
Total liabilities		12,591		753,955		1,340,592		2,936		(1,223,326)		886,748
Mezzanine equity
Series A preferred stock, $0.001 par value; 1,840,000 shares issued and outstanding at June 30, 2017		89,288		—		—		—		—		89,288
Stockholders’/ members' equity (deficit)
Members' equity		—		900,374		323,595		(2,343)		(1,221,626)		—
Class A common stock, $0.001 par value; 66,671,659 shares issued and 66,649,057 shares outstanding at June 30, 2017		67		—		—		—		—		67
Class B common stock, $0.001 par value; 29,823,927 shares issued and outstanding at June 30, 2017		30		—		—		—		—		30
Treasury stock, at cost: 22,602 shares at June 30, 2017		(358)		—		—		—		—		(358)
Additional paid-in-capital		477,390		—		—		—		—		477,390
Retained earnings (deficit)		(121,477)		—		—		—		—		(121,477)
Stockholders' equity (deficit)		355,652		900,374		323,595		(2,343)		(1,221,626)		355,652
Non-controlling interest		—		—		—		—		394,331		394,331
Total stockholders’ equity		355,652		900,374		323,595		(2,343)		(827,295)		749,983
Total liabilities and stockholders’ equity	$	457,531	$	1,654,329	$	1,664,187	$	593	$	(2,050,621)	$	1,726,019

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Jones Energy, Inc.

Condensed Consolidating Balance Sheet

December 31, 2016


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

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2017


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—	$	—	$	48,114	$	—	$	—	$	48,114
Other revenues		—		485		27		—		—		512
Total operating revenues		—		485		48,141		—		—		48,626
Operating costs and expenses
Lease operating		—		—		9,425		—		—		9,425
Production and ad valorem taxes		—		—		2,790		—		—		2,790
Exploration		—		—		6,725		—		—		6,725
Depletion, depreciation and amortization		—		—		45,313		23		—		45,336
Impairment of oil and gas properties		—		—		161,886		—		—		161,886
Accretion of ARO liability		—		—		266		—		—		266
General and administrative		—		2,920		5,626		87		—		8,633
Total operating expenses		—		2,920		232,031		110		—		235,061
Operating income (loss)		—		(2,435)		(183,890)		(110)		—		(186,435)
Other income (expense)
Interest expense		—		(12,941)		264		—		—		(12,677)
Net gain (loss) on commodity derivatives		—		21,527		—		—		—		21,527
Other income (expense)		29,913		(24)		(55)		—		—		29,834
Other income (expense), net		29,913		8,562		209		—		—		38,684
Income (loss) before income tax		29,913		6,127		(183,681)		(110)		—		(147,751)
Equity interest in income (loss)		(121,557)		(56,107)		—		—		177,664		—
Income tax provision (benefit)		(2,405)		(14)		—		—		—		(2,419)
Net income (loss)		(89,239)		(49,966)		(183,681)		(110)		177,664		(145,332)
Net income (loss) attributable to non-controlling interests		—		—		—		—		(56,093)		(56,093)
Net income (loss) attributable to controlling interests	$	(89,239)	$	(49,966)	$	(183,681)	$	(110)	$	233,757	$	(89,239)
Dividends and accretion on preferred stock		(1,966)		—		—		—		—		(1,966)
Net income (loss) attributable to common shareholders	$	(91,205)	$	(49,966)	$	(183,681)	$	(110)	$	233,757	$	(91,205)

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2017


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

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Three Months Ended June 30, 2016


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

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Six Months Ended June 30, 2016


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

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Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2017


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Cash flows from operating activities
Net income (loss)	$	(90,626)	$	(45,148)	$	(194,723)	$	(176)	$	181,826	$	(148,847)
Adjustments to reconcile net income (loss) to net cash provided by operating activities		60,656		(2,685)		294,004		176		(181,826)		170,325
Net cash (used in) / provided by operations		(29,970)		(47,833)		99,281		—		—		21,478
Cash flows from investing activities
Additions to oil and gas properties		—		—		(107,250)		—		—		(107,250)
Net adjustments to purchase price of properties acquired		—		—		2,391		—		—		2,391
Proceeds from sales of assets		—		—		2,730		—		—		2,730
Acquisition of other property, plant and equipment		—		—		(436)		—		—		(436)
Current period settlements of matured derivative contracts		—		45,738		—		—		—		45,738
Net cash (used in) / provided by investing		—		45,738		(102,565)		—		—		(56,827)
Cash flows from financing activities
Proceeds from issuance of long-term debt		—		75,000		—		—		—		75,000
Repayment of long-term debt		—		(72,000)		—		—		—		(72,000)
Payment of cash dividends on preferred stock		(3,367)		—		—		—		—		(3,367)
Net distributions paid to JEH unitholders		1,075		(1,637)		—		—		—		(562)
Net payments for share based compensation		—		(462)		—		—		—		(462)
Proceeds from sale of common stock		8,352		—		—		—		—		8,352
Net cash (used in) / provided by financing		6,060		901		—		—		—		6,961
Net increase (decrease) in cash		(23,910)		(1,194)		(3,284)		—		—		(28,388)
Cash
Beginning of period		27,164		1,975		5,483		20		—		34,642
End of period	$	3,254	$	781	$	2,199	$	20	$	—	$	6,254

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Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Six Months Ended June 30, 2016


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Cash flows from operating activities
Net income (loss)	$	(4,334)	$	37,979	$	(55,662)	$	(94)	$	11,979	$	(10,132)
Adjustments to reconcile net income (loss) to net cash provided by operating activities		3,278		(86,767)		111,506		94		(11,979)		16,132
Net cash (used in) / provided by operations		(1,056)		(48,788)		55,844		—		—		6,000
Cash flows from investing activities
Additions to oil and gas properties		—		—		(27,592)		—		—		(27,592)
Proceeds from sales of assets		—		—		5		—		—		5
Acquisition of other property, plant and equipment		—		—		12		—		—		12
Current period settlements of matured derivative contracts		—		77,622		—		—		—		77,622
Net cash (used in) / provided by investing		—		77,622		(27,575)		—		—		50,047
Cash flows from financing activities
Proceeds from issuance of long-term debt		—		75,000		—		—		—		75,000
Purchase of senior notes		—		(84,589)		—		—		—		(84,589)
Net distributions paid to JEH unitholders		9,910		(20,019)		—		—		—		(10,109)
Proceeds from sale of common stock		1,056		—		—		—		—		1,056
Net cash (used in) / provided by financing		10,966		(29,608)		—		—		—		(18,642)
Net increase (decrease) in cash		9,910		(774)		28,269		—		—		37,405
Cash												—
Beginning of period		100		12,448		9,325		20		—		21,893
End of period	$	10,010	$	11,674	$	37,594	$	20	$	—	$	59,298

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Item 2. Management’s Discussion and Analysi s of Financial Condition and Results of Operations

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

Overview

We are an independent oil and gas company engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States, spanning areas of Texas and Oklahoma. Our Chairman and CEO, Jonny Jones, founded our predecessor company in 1988 in continuation of his family’s long history in the oil and gas business, which dates back to the 1920’s. We have grown rapidly by leveraging our focus on low cost drilling and completion methods and our horizontal drilling expertise to develop our inventory and execute several strategic acquisitions. We have accumulated extensive knowledge and experience in developing the Anadarko basin, having concentrated our operations in the Anadarko basin for over 25 years. We have drilled over 880 total wells as operator, including approximately 705 horizontal wells, since our formation and delivered compelling rates of return over various commodity price cycles. Our operations are focused on horizontal drilling and completions within two distinct areas in the Texas Panhandle and Oklahoma:

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

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

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

Second Quarter and Year-to-Date 2017 Highlights:

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

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

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

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

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

Net loss for the second quarter of 2017 of $145.3 million, which includes a $161.9 million impairment charge related to the Arkoma sale, non-GAAP adjusted net income of $5.7 million, or $0.12 per share and EBITDAX of $48.3 million.

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Updated Capital Expenditures Outlook

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

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Results of Operations

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


(in thousands of dollars except for	Three Months Ended June 30,						Six Months Ended June 30,
production, sales price and average cost data)	2017		2016		Change		2017		2016		Change
Revenues:
Oil	$	23,312	$	16,108	$	7,204	$	41,579	$	29,422	$	12,157
Natural gas		12,767		5,115		7,652		24,194		11,657		12,537
NGLs		12,035		7,175		4,860		23,018		12,399		10,619
Total oil and gas		48,114		28,398		19,716		88,791		53,478		35,313
Other		512		746		(234)		1,068		1,524		(456)
Total operating revenues		48,626		29,144		19,482		89,859		55,002		34,857
Costs and expenses:
Lease operating		9,425		7,545		1,880		18,231		16,162		2,069
Production and ad valorem taxes		2,790		1,727		1,063		1,884		3,328		(1,444)
Exploration		6,725		77		6,648		9,669		239		9,430
Depletion, depreciation and amortization		45,336		38,137		7,199		80,990		79,899		1,091
Impairment of oil and gas properties		161,886		—		161,886		161,886		—		161,886
Accretion of ARO liability		266		297		(31)		467		590		(123)
General and administrative		8,633		8,126		507		16,674		15,630		1,044
Total costs and expenses		235,061		55,909		179,152		289,801		115,848		173,953
Operating income (loss)		(186,435)		(26,765)		(159,670)		(199,942)		(60,846)		(139,096)
Other income (expenses):
Interest expense		(12,677)		(12,807)		130		(25,564)		(27,605)		2,041
Gain on debt extinguishment		—		8,878		(8,878)		—		99,530		(99,530)
Net gain (loss) on commodity derivatives		21,527		(40,002)		61,529		43,847		(22,783)		66,630
Other income/(expense)		29,834		(338)		30,172		30,414		(113)		30,527
Total other income (expense)		38,684		(44,269)		82,953		48,697		49,029		(332)
Income (loss) before income tax		(147,751)		(71,034)		(76,717)		(151,245)		(11,817)		(139,428)
Income tax provision (benefit)		(2,419)		(12,388)		9,969		(2,398)		(1,685)		(713)
Net income (loss)		(145,332)		(58,646)		(86,686)		(148,847)		(10,132)		(138,715)
Net income (loss) attributable to non-controlling interests		(56,093)		(35,401)		(20,692)		(58,221)		(5,798)		(52,423)
Net income (loss) attributable to controlling interests	$	(89,239)	$	(23,245)	$	(65,994)	$	(90,626)	$	(4,334)	$	(86,292)
Dividends and accretion on preferred stock		(1,966)		—		(1,966)		(3,993)		—		(3,993)
Net income (loss) attributable to common shareholders	$	(91,205)	$	(23,245)	$	(67,960)	$	(94,619)	$	(4,334)	$	(90,285)

Net production volumes:
Oil (MBbls)		525		396		129		910		875		35
Natural gas (MMcf)		5,836		4,608		1,228		10,491		9,528		963
NGLs (MBbls)		668		529		139		1,206		1,084		122
Total (MBoe)		2,166		1,693		473		3,865		3,547		318
Average net (Boe/d)		23,802		18,604		5,198		21,354		19,489		1,865
Average sales price, unhedged:
Oil (per Bbl), unhedged	$	44.40	$	40.68	$	3.72	$	45.69	$	33.63	$	12.06
Natural gas (per Mcf), unhedged		2.19		1.11		1.08		2.31		1.22		1.09
NGLs (per Bbl), unhedged		18.02		13.56		4.46		19.09		11.44		7.65
Combined (per Boe), unhedged		22.21		16.77		5.44		22.97		15.08		7.89
Average sales price, hedged:
Oil (per Bbl), hedged	$	61.30	$	87.87	$	(26.57)	$	82.47	$	85.77	$	(3.30)
Natural gas (per Mcf), hedged		4.04		3.40		0.64		3.84		3.54		0.30
NGLs (per Bbl), hedged		15.36		17.64		(2.28)		14.65		17.33		(2.68)
Combined (per Boe), hedged		30.49		35.33		(4.84)		34.42		35.96		(1.54)
Average costs (per BOE):
Lease operating	$	4.35	$	4.46	$	(0.11)	$	4.72	$	4.56	$	0.16
Production and ad valorem taxes		1.29		1.02		0.27		0.49		0.94		(0.45)
Depletion, depreciation and amortization		20.93		22.53		(1.60)		20.95		22.53		(1.58)
General and administrative		3.99		4.80		(0.81)		4.31		4.41		(0.10)

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Non-GAAP financial measures

EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

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

The following table sets forth a reconciliation of net income (loss) as determined in accordance with GAAP to EBITDAX for the periods indicated:


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

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

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

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


	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands except per share data)	2017			2016			2017			2016
Net income (loss)	$	(145,332)		$	(58,646)		$	(148,847)		$	(10,132)
Net (gain) loss on derivative contracts		(21,527)			40,002			(43,847)			22,783
Current period settlements of matured derivative contracts		17,921			31,410			44,253			74,081
Impairment of oil and gas properties		161,886			—			161,886			—
Exploration		6,725			77			9,669			239
Non-cash stock compensation expense		1,764			1,899			3,736			3,084
Deferred and other non-cash compensation expense		44			133			180			401
(Gain) on debt extinguishment		—			(8,878)			—			(99,530)
Financing expenses		—			—			—			—
Change in TRA liability		(29,931)			267			(30,599)			(162)
Tax impact of adjusting items (1)		(34,141)			(11,390)			(36,017)			(331)
Change in valuation allowance		48,261			(597)			49,173			392
Adjusted net income (loss)		5,670			(5,723)			9,587			(9,175)
Adjusted net income (loss) attributable to non-controlling interests		(3,991)			(2,948)			(3,018)			(5,566)
Adjusted net income (loss) attributable to controlling interests		9,661			(2,775)			12,605			(3,609)
Dividends and accretion on preferred stock		(1,966)			—			(3,993)			—
Adjusted net income (loss) attributable to common shareholders	$	7,695		$	(2,775)		$	8,612		$	(3,609)

Earnings per share (basic and diluted): (2)	$	(1.39)		$	(0.69)		$	(1.48)		$	(0.13)
Net (gain) loss on derivative contracts		(0.23)			0.59			(0.46)			0.34
Current period settlements of matured derivative contracts		0.19			0.46			0.46			1.10
Impairment of oil and gas properties		1.70			—			1.75			—
Exploration		0.07			0.03			0.10			0.05
Non-cash stock compensation expense		0.02			—			0.04			0.01
Deferred and other non-cash compensation expense		—			(0.13)			—			(1.46)
(Gain) on debt extinguishment		—			—			—			—
Financing expenses		—			—			—			—
Change in TRA liability		(0.46)			0.01			(0.48)			—
Tax impact of adjusting items (1)		(0.51)			(0.33)			(0.56)			(0.01)
Change in valuation allowance		0.73			(0.02)			0.77			0.01
Adjusted earnings per share (basic and diluted)	$	0.12		$	(0.08)		$	0.14		$	(0.09)

Weighted average Class A shares outstanding: (2)
Basic		65,681			33,598			63,948			33,410
Diluted		65,681			33,598			63,948			33,410
Effective tax rate on net income (loss) attributable to controlling interests		40.3	%		36.8	%		40.0	%		36.8	%

(1)

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

(2)

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Results of Operations - Three months ended June 30, 2017 as compared to the three months ended June 30, 2016

Operating revenues

Oil and gas sales. Oil and gas sales increased $ 19.7 million, or 69.4%, to $48.1 million for the three months ended June 30, 2017, as compared to $28.4 million for the three months ended June 30, 2016. The increase was attributable to the increase in production volumes ($10.9 million) and the increase in commodity prices ($8.8 million). The increase in production volumes was driven by the year-over-year increase in producing wells due to continued drilling activity. The average realized oil price, excluding the effects of commodity derivative instruments, increased from $40.68 per Bbl for the three months ended June 30, 2016 to $44.40 per Bbl for the three months ended June 30, 2017, or 9.1%. The average realized natural gas price, excluding the effects of commodity derivative instruments, increased from $1.11 per Mcf for the three months ended June 30, 2016 to $2.19 per Mcf for the three months ended June 30, 2017, or 97.3%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increased from $13.56 per Bbl for the three months ended June 30, 2016 to $18.02 per Bbl for the three months ended June 30, 2017, or 32.9%. Average daily production increased 27.9% to 23,802 Boe per day for the three months ended June 30, 2017 as compared to 18,604 Boe per day for the three months ended June 30, 2016.

Costs and expenses

Lease operating. Lease operating expenses increased by $1.9 million, or 25.3%, to $9.4 million for the three months ended June 30, 2017, as compared to $7.5 million for the three months ended June 30, 2016. The increase in lease operating expenses is primarily attributable to the increase in number of producing wells. On a per unit basis, lease operating expenses decreased $0.11 per Boe, or 2.5%, from $4.46 per Boe in the three months ended June 30, 2016 to $4.35 per Boe in the three months ended June 30, 2017.

Production and ad valorem taxes. Production and ad valorem taxes increased by $1.1 million, or 64.7%, to $2.8 million for the three months ended June 30, 2017, as compared to $1.7 million for the three months ended June 30, 2016. Production taxes increased $0.9 million, from $1.4 million for the three months ended June 30, 2016 to $2.3 million for the three months ended June 30, 2017. The increase was attributable to the increase in production volumes. Production tax rates vary between states, products, and production levels; therefore, the overall blended rate is impacted by numerous factors and the mix of producing wells at any given time. Further, estimated ad valorem taxes increased $0.2 million, from $0.3 million for the three months ended June 30, 2016 to $0.5 million for the three months ended June 30, 2017. The average effective rate excluding the impact of ad valorem taxes remained constant at 4.8% for the three months ended June 30, 2016 and 2017.

Exploration. Exploration expense increased from $0.1 million for the three months ended June 30, 2016 to $6.7 million for the three months ended June 30, 2017. The Company recognized charges for lease abandonment of $5.2 million relating to certain leases that the Company decided during the second quarter of 2017 not to develop. Spending during 2017 primarily related to geological data and seismic processing associated with unproved acreage. No exploratory wells resulted in exploration expense during the second quarter of either year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $7.2 million, or 18.9%, to $45.3 million for the three months ended June 30, 2017, as compared to $38.1 million for the three months ended June 30, 2016. The increase was primarily the result of capital spending related to our drilling program. On a per unit basis, depletion expense decreased $1.60 per Boe or 7.1% from $22.53 per Boe for the three months ended June 30, 2016 as compared to $20.93 per Boe for the three months ended June 30, 2017. The decrease was primarily the result of lower production and capital spending throughout 2016, driven by a temporary suspension of the drilling program late in 2015 and continuing into early 2016.

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

General and administrative. General and administrative expenses increased by $0.5 million, or 6.2%, to $8.6 million for the three months ended June 30, 2017, as compared to $8.1 million for the three months ended June 30, 2016. The increase was driven by a litigation settlement for which the Company recognized an additional charge of $1.4 million

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during the three months ended June 30, 2017, offset by reductions in other costs. Non-cash compensation expense decreased $0.2 million, from $2.0 million for the three months ended June 30, 2016 to $1.8 million for the three months ended June 30, 2017. On a per unit basis, general and administrative expenses, excluding all non-cash items, decreased from $2.63 per Boe for the three months ended June 30, 2016 to $2.57 per Boe for the three months ended June 30, 2017.

Interest expense. Interest expense decreased by $0.1 million, or 0.8%, to $12.7 million for three months ended June 30, 2017, as compared to $12.8 million for the three months ended June 30, 2016. The decrease was driven by a reduction in the outstanding balance of the 2022 Notes and the 2023 Notes as a result of our 2016 debt extinguishments. During the three months ended June 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.84%, 6.75% and 9.25%, respectively. Average outstanding balances for the three months ended June 30, 2017 were $194.6 million, $409.1 million and $150.0 million under the Revolver, the 2022 Notes and the 2023 Notes, respectively.

Net gain (loss) on commodity derivatives. The net gain (loss) on commodity derivatives was a net gain of $21.5 million for the three months ended June 30, 2017, as compared to a net loss of $40.0 million for the three months ended June 30, 2016. The gain was primarily driven by lower average crude oil and natural gas prices ($48.10 per barrel and $3.08 per Mcf, respectively) for the three months ended June 30, 2017, as compared to the crude oil and natural gas prices as of March 31, 2017 ($50.54 per barrel and $3.13 per Mcf, respectively). Additionally, the Company unwound a portion of its realized 2018 hedges resulting in gains of approximately $8.1 million for the three months ended June 30, 2017. See Note 6, “Derivative Instruments and Hedging Activities,” for further details.

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

Income taxes. The provision for federal and state income taxes for the three months ended June 30, 2017 was a benefit of $2.4 million resulting in a 1.6% effective tax rate as a percentage of our pre-tax book income for the quarter as compared to a benefit of $12.4 million resulting in a 17.4% effective tax rate as a percentage of our pre-tax book income for the three months ended June 30, 2016. Our effective tax rate is based on the statutory rate applicable to the U.S. and the blended rate of the states in which we conduct business and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest. The effective tax rate reduction is primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets. See Note 10, “Income Taxes,” for further details.

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

Operating revenues

Oil and gas sales. Oil and gas sales increased $35.3 million, or 66.0%, to $88.8 million for the six months ended June 30, 2017, as compared to $53.5 million for the six months ended June 30, 2016. The increase was attributable to the increase in commodity prices ($29.2 million) and the increase in production volumes ($6.1 million). The increase in production volumes was driven by the year-over-year increase in producing wells due to continued drilling activity. The average realized oil price, excluding the effects of commodity derivative instruments, increased from $33.63 per Bbl for the six months ended June 30, 2016 to $45.69 per Bbl for the six months ended June 30, 2017, or 35.9%. The average realized natural gas price, excluding the effects of commodity derivative instruments, increased from $1.22 per Mcf for the six months ended June 30, 2016 to $2.31 per Mcf for the six months ended June 30, 2017, or 89.3%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increased from $11.44 per Bbl for the six months ended June 30, 2016 to $19.09 per Bbl for the six months ended June 30, 2017, or 66.9%. Average daily production increased 9.6% to 21,354 Boe per day for the six months ended June 30, 2017 as compared to 19,489 Boe per day for the six months ended June 30, 2016.

Costs and expenses

Lease operating. Lease operating expenses increased by $2.0 million, or 12.3%, to $18.2 million for the six months ended June 30, 2017, as compared to $16.2 million for the six months ended June 30, 2016. The increase in lease operating expenses is primarily attributable to the increase in number of producing wells. On a per unit basis, lease

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operating expenses increased $0.16 per Boe, or 3.5%, from $4.56 per Boe in the six months ended June 30, 2016 to $4.72 per Boe in the six months ended June 30, 2017.

Production and ad valorem taxes. Production and ad valorem taxes decreased by $1.4 million, or 42.4%, to $1.9 million for the six months ended June 30, 2017, as compared to $3.3 million for the six months ended June 30, 2016. During the first quarter of 2017, the Company's application for High-Cost Gas Incentive refunds in Texas was approved for qualified wells on which taxes were initially paid between October 2012 and September 2016. The Company received a net production tax refund of $3.3 million during the six months ended June 30, 2017, which was recorded as a reduction in Production and ad valorem taxes on the Company’s Consolidated Statement of Operations. Production taxes, excluding the impact of this refund, increased from $2.5 million for the six months ended June 30, 2016 to $4.1 million for the six months ended June 30, 2017. The increase was attributable to the increase in production volumes. Production tax rates vary between states, products, and production levels; therefore, the overall blended rate is impacted by numerous factors and the mix of producing wells at any given time. Further, estimated ad valorem taxes increased $0.3 million from $0.7 million for the six months ended June 30, 2016 to $1.0 million for the six months ended June 30, 2017. The average effective rate excluding the impact of ad valorem taxes decreased from 4.8% for the six months ended June 30, 2016 to 1.0% for the six months ended June 30, 2017.

Exploration. Exploration expense increased from $0.2 million for the six months ended June 30, 2016 to $9.7 million for the six months ended June 30, 2017. The Company recognized charges for lease abandonment of $6.9 million relating to certain leases that the Company decided during 2017 not to develop. Spending during 2017 primarily related to geological data and seismic processing associated with unproved acreage. No exploratory wells resulted in exploration expense during the six months ended June 30 of either year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $1.1 million, or 1.4%, to $81.0 million for the six months ended June 30, 2017, as compared to $79.9 million for the six months ended June 30, 2016. The increase was primarily the result of capital spending related to our drilling program. On a per unit basis, depletion expense decreased $1.58 per Boe or 7.0% from $22.53 per Boe for the six months ended June 30, 2016 as compared to $20.95 per Boe for the six months ended June 30, 2017. The decrease was primarily the result of lower production and capital spending throughout 2016, driven by a temporary suspension of the drilling program late in 2015 and continuing into early 2016.

General and administrative. General and administrative expenses increased by $1.1 million, or 7.1%, to $16.7 million for the six months ended June 30, 2017, as compared to $15.6 million for the six months ended June 30, 2016. The increase was driven by a litigation settlement for which the Company recognized an additional charge of $1.4 million during the six months ended June 30, 2017, offset by reductions in other costs. Non-cash compensation expense increased $0.4 million, from $3.5 million for the six months ended June 30, 2016 to $3.9 million for the six months ended June 30, 2017. On a per unit basis, general and administrative expenses, excluding all non-cash items, decreased from $3.11 per Boe for the six months ended June 30, 2016 to $2.96 per Boe for the six months ended June 30, 2017.

Interest expense. Interest expense decreased by $2.0 million, or 7.2%, to $25.6 million for six months ended June 30, 2017, as compared to $27.6 million for the six months ended June 30, 2016. The decrease was driven by a reduction in the outstanding balance of the 2022 Notes and the 2023 Notes as a result of our 2016 debt extinguishments. During the six months ended June 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.72%, 6.75% and 9.25%, respectively. Average outstanding balances for the six months ended June 30, 2017 were $194.9 million, $409.1 million and $150.0 million under the Revolver, the 2022 Notes and the 2023 Notes, respectively.

Net gain (loss) on commodity derivatives. The net gain (loss) on commodity derivatives was a net gain of $43.8 million for the six months ended June 30, 2017, as compared to a net loss of $22.8 million for the six months ended June 30, 2016. The gain was primarily driven by lower average crude oil and natural gas prices ($49.85 per barrel and $3.05 per Mcf, respectively) for the six months ended June 30, 2017, as compared to the crude oil and natural gas prices as of December 31, 2016 ($53.75 per barrel and $3.71 per Mcf, respectively). Additionally, the Company unwound a portion

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of its realized 2018 and 2019 hedges resulting in gains of approximately $28.0 million for the six months ended June 30, 2017. See Note 6, “Derivative Instruments and Hedging Activities,” for further details.

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

Income taxes. The provision for federal and state income taxes for the six months ended June 30, 2017 was a benefit of $2.4 million resulting in a 1.6% effective tax rate as a percentage of our pre-tax book income for the quarter as compared to a benefit of $1.7 million resulting in a 14.3% effective tax rate as a percentage of our pre-tax book income for the six months ended June 30, 2016. Our effective tax rate is based on the statutory rate applicable to the U.S. and the blended rate of the states in which we conduct business and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest. The effective tax rate reduction is primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets. See Note 10, “Income Taxes,” for further details.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been private and public sales of our debt and equity, borrowings under bank credit facilities and cash flows from operations. Our primary use of capital has been for the exploration, development and acquisition of oil and gas properties. As we pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We strive to maintain financial flexibility in order to maintain substantial borrowing capacity under our Revolver (as defined below), facilitate drilling on our undeveloped acreage positions and permit us to selectively expand our acreage positions. Depending on the profitability, timing and concentration of the development of our non-proved locations, we may be required to generate or raise significant amounts of capital to develop all of our potential drilling locations should we endeavor to do so. In the event our profitability or cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending. Our balance sheet at June 30, 2017 reflects a negative working capital balance. We have historically and in the future expect to maintain a negative working capital balance, and we use our Revolver to help manage our working capital.

Availability under the Revolver is subject to a borrowing base, as well as financial covenants. Our borrowing base at June 30, 2017 was $425.0 million of which $181.0 million was utilized leaving an unused capacity of $244.0 million. On August 1, 2017, upon closing of the Arkoma Divestiture, the Company’s borrowing base was reduced to $375.0 million. The borrowing base will be re-determined at least semi-annually on or about April 1 and October 1 of each year, with such re-determination based primarily on reserve reports using lender commodity price expectations at such time. Any reduction in the borrowing base will reduce our liquidity, and, if the reduction results in the outstanding amount under our Revolver exceeding the borrowing base, we will be required to repay the deficiency within a short period of time. The financial covenants may further constrain our ability to borrow under our Revolver.

The Revolver also contains a covenant which restricts the ability of Jones Energy, Inc. to (i) hold any assets, (ii) incur, create, assume, or suffer to exist any debt or any other liability or obligation, (iii) create, make or enter into any investment or (iv) engage in any other activity or operation other than, among other exceptions described therein, its ownership of equity interests in JEH and the activities of a passive holding company and assets and operations incidental thereto (including the maintenance of cash and reserves for the payment of operational costs and expenses).

Jones Energy, Inc. and its consolidated subsidiaries are also subject to certain covenants under the Revolver, including the requirement to maintain the following financial ratios:

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

a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.0 to 1.0 as of the last day of any fiscal quarter.

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The Company routinely enters into oil and natural gas swap contracts as seller, thus resulting in a fixed price. During 2016 and 2017, the Company realized certain mark-to-market gains associated with oil and natural gas hedges the Company had in place for years 2018 and 2019. The gains were effectively realized by purchasing, as opposed to selling, oil and natural gas swap contracts for the equal volume that was associated with the initial hedge transaction. During the three and six months ended June 30, 2017, the Company unwound a portion of its realized 2018 and 2019 hedges resulting in approximately $8.1 million and $28.0 million, respectively, of recognized gains which have been included in Net gain (loss) on commodity derivatives on the Company’s Consolidated Statement of Operations. The estimated mark-to-market value of the Company’s remaining realized gains as a result of these offsetting hedges were approximately $15.1 million relating to the year ended December 31, 2018, incorporating NYMEX strip pricing as of July 28, 2017, but excluding adjustments for credit risk.

The amount, timing and allocation of capital expenditures are largely discretionary and within management’s control. If oil and gas prices decline to levels below our acceptable levels or costs increase to levels above our acceptable levels, we may choose to defer a portion of our budgeted capital expenditures until later periods in order to achieve the desired balance between sources and uses of liquidity and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We continuously monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and completion costs, industry conditions, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

The following table summarizes our cash flows for the six months ended June 30, 2017 and 2016:


	Six Months Ended June 30,
(in thousands of dollars)	2017		2016
Net cash provided by operating activities	$	21,478	$	6,000
Net cash (used in) / provided by investing activities		(56,827)		50,047
Net cash provided by / (used in) financing activities		6,961		(18,642)
Net increase (decrease) in cash	$	(28,388)	$	37,405

Cash flow provided by operating activities

Net cash provided by operating activities was $21.5 million during the six months ended June 30, 2017 as compared to $6.0 million during the six months ended June 30, 2016. The increase in operating cash flows was primarily due to the $35.3 million increase in oil and gas revenues for the six months ended June 30, 2017 as compared to the six months ended June 30, 2016, primarily driven by the increase in commodity prices.

Cash flow (used in) / provided by investing activities

Net cash used in investing activities was $56.8 million during the six months ended June 30, 2017 as compared to net cash provided by investing activities of $50.0 million during the six months ended June 30, 2016. The decrease in investing cash flow was primarily driven by increased capital spending, following the temporary suspension of the drilling program late in 2015 and continuing into early 2016.

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Cash flow provided by / (used in) financing activities

Net cash provided by financing activities was $7.0 million during the six months ended June 30, 2017 as compared to net cash used in financing activities of $18.6 million during the six months ended June 30, 2016. The increase in financing cash flows was primarily due to a reduction of $12.6 million in cash used toward reducing outstanding borrowings. During the six months ended June 30, 2017, the Company made repayments of $72.0 million toward borrowings under the Revolver, as compared to cash of $84.6 million used to purchase an aggregate principal amount of $190.9 million of our senior unsecured notes during the six months ended June 30, 2016. Also contributing to the increase in cash flows was a reduction of $9.5 million in cash tax distributions, from $10.1 million during the six months ended June 30, 2016 to $0.6 million during the six months ended June 30, 2017. Additionally, there was an increase in proceeds from the sale of Class A common stock of $7.2 million, from $1.1 million during the six months ended June 30, 2016 to $8.4 million during the six months ended June 30, 2017. These increases in cash flow were partially offset by the payment of dividends on Series A preferred stock of $3.4 million during the six months ended June 30, 2017.

Contractual Obligations

The holders of JEH Units, including us, incur U.S. federal, state and local income taxes on their share of any taxable income of JEH. Under the terms of its operating agreement, JEH is generally required to make quarterly pro-rata cash tax distributions to its unitholders (including us) based on income allocated to its unitholders through the end of each relevant quarter, as adjusted to take into account good faith projections by the Company of taxable income or loss for the remainder of the calendar year, to the extent JEH has cash available for such distributions and subject to certain other restrictions. This tax distribution is computed based on the estimate of net taxable income of JEH allocated to each holder of JEH Units multiplied by the highest marginal effective rate of federal, state and local income tax applicable to an individual resident in New York, New York, without regard for the federal benefit of the deduction for any state taxes.

During 2016, JEH generated taxable income, resulting in the payment of cash tax distributions to JEH unitholders. As a result of JEH’s 2016 taxable income (all of which is passed-through and taxed to us and JEH’s other unitholders), during the first quarter of 2017, we made further income tax payments to federal and state taxing authorities of $4.1 million and JEH made further tax distributions to JEH unitholders (other than us) of $0.6 million.

Based on information available as of this filing, we do not anticipate that we will be required to make any additional tax payments or that JEH will make any additional tax distributions during the remainder of 2017. Estimating the tax distributions required under the operating agreement is imprecise by nature, highly uncertain, and dependent upon a variety of factors.

There have been no other material changes in our contractual obligations as reported in our Annual Report on Form 10-K for the year ended December 31, 2016.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

There have been no changes to our critical accounting policies and estimates from those set forth in our Annual Report on Form 10-K for the year ended December 31, 2016.

Item 3. Quantitative and Qualitative Disclosure s about Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2016, as well as with the unaudited consolidated financial statements and notes included in this Quarterly Report.

We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes. We do not designate these or future derivative instruments as hedges for

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accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.

Potential Impairment of Oil and Gas Properties

Oil and natural gas prices are inherently volatile and have decreased significantly since 2014. Depressed commodity prices have continued into 2017 and historically low commodity prices may exist for an extended period. Taking into consideration the business environment in which we operate, we continually review our held for use oil and gas properties for indicators of potential impairment on an undiscounted basis. While no such indicators were present at June 30, 2017, assets held for sale related to the Arkoma Divestiture were written down to the estimated selling price resulting in an impairment charge of $161.9 million.

Our revenues and net income are sensitive to crude oil, NGL and natural gas prices which have been and are expected to continue to be highly volatile. The recent volatility in crude oil and natural gas prices increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. Although we are unable to predict future commodity prices, a prolonged period of depressed commodity prices may have a significant impact on the volumetric quantities of our proved reserves. The impact of commodity prices on our estimated proved reserves can be illustrated as follows: if the prices used for our December 31, 2016 Reserve Report had been replaced with the unweighted arithmetic average of the first-day-of-the-month prices for the applicable commodity for the trailing twelve-month period ended June 30, 2017 (without regard to our commodity derivative positions and without assuming any change in development plans, costs, or other variables), then estimated proved reserves volumes as of December 31, 2016 would have increased by approximately 3.1%. The use of this pricing example is for illustration purposes only, and does not indicate management’s view on future commodity prices, costs or other variables, or represent a forecast or estimate of the actual amount by which our proved reserves may fluctuate when a full assessment of our reserves is completed as of December 31, 2017.

Periodic revisions to the estimated reserves and related future cash flows may be necessary as a result of a number of factors, including changes in oil and natural gas prices, reservoir performance, new drilling and completion, purchases, sales and terminations of leases, drilling and operating cost changes, technological advances, new geological or geophysical data or other economic factors. All of these factors are inherently estimates and are inter dependent. While each variable carries its own degree of uncertainty, some factors, such as oil and natural gas prices, have historically been highly volatile and may be highly volatile in the future. This high degree of volatility causes a high degree of uncertainty associated with the estimation of reserve quantities and estimated future cash flows. Therefore, future results are highly uncertain and subject to potentially significant revisions. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions, as such revisions could be negatively impacted by:

Declines in commodity prices or actual realized prices below those assumed for future years;

Increases in service costs;

Increases in future global or regional production or decreases in demand;

Increases in operating costs;

Reductions in availability of drilling, completion, or other equipment.

If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in an impairment of assets that may be material. Any future impairments are difficult to predict, and although it is not reasonably practicable to quantify the impact of any future impairments at this time, such impairments may be significant.

Commodity price risk and hedges

Our principal market risk exposure is to oil, natural gas and NGL prices, which are inherently volatile. As such, future earnings are subject to change due to fluctuations in such prices. Realized prices are primarily driven by the prevailing prices for oil and regional spot prices for natural gas and NGLs. We have used, and expect to continue to use, oil, natural

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gas and NGL derivative contracts to reduce our risk of price fluctuations of these commodities. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. The fair value of our oil, natural gas and NGL derivative contracts at June 30, 2017 was a net asset of $42.6 million.

Counterparty risk

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. We evaluate the credit standing of our counterparties, but do not require them to post collateral. The majority of our derivative contracts currently in place are with lenders under our Revolver, who have investment grade ratings.

Interest rate risk

We are subject to market risk exposure related to changes in interest rates on our variable rate indebtedness. The terms of the senior secured revolving credit facility provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 0.50% to 2.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. The base rate margins under the terminated term loan were 6.0% to 7.0% depending on the base rate used and the amount of the loan outstanding. The terms of our senior notes provide for a fixed interest rate through their respective maturity dates. During the three months ended June 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.84%, 6.75% and 9.25%, respectively. During the six months ended June 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.72%, 6.75% and 9.25%, respectively.

Item 4. Controls and Procedure s

Changes in Internal Control over Financial Reporting

There have been no changes in internal control over financial reporting during the quarter ended June 30, 2017 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Evaluation of Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our principal executive officer and principal financial officer concluded that as of June 30, 2017, the end of the period covered by this report, our disclosure controls and procedures are effective at a reasonable assurance level.

Management’s Assessment of Internal Control over Financial Reporting

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules requiring every public company that files reports with the SEC to include a management report on such company’s internal control over financial reporting in its annual report. Pursuant to the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), our independent registered public accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for up to five years or through such earlier date that we are no longer an “emerging growth company” as defined in the JOBS Act. Our Annual Report on Form 10-K for the year ended December 31, 2016 included a report of management’s assessment regarding internal control over financial reporting.

Table of Contents

PART II—OTHER INFORMATIO N

Item 1. Legal Proceeding s

For a discussion of legal proceedings, see Note 14 “Commitments and Contingencies,” in the Notes to Consolidated Financial Statements for further discussion appearing in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated in this item by reference.

Item 1A. Risk Factor s

Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings, including our Annual Report on Form 10-K for the year ended December 31, 2016, could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

For a discussion of our potential risks and uncertainties, see the information in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016. There have been no material changes in our risk factors from those described in our Annual Report for the year ended December 31, 2016.

Item 2. Unregistered Sales of Equity Securitie s and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securitie s

None.

Item 4. Mine Safety Disclosure s

Not applicable.

Item 5. Other Informatio n

Not applicable.

Item 6. Exhibit s


Exhibit No.		Description
2.1*		Purchase and Sale Agreement, dated June 22, 2017, between Jones Energy Holdings, LLC and the purchaser party thereto.
4.1		Amended and Restated Registration Rights and Stockholders Agreement, dated May 2, 2017, among Jones Energy, Inc., Jones Energy Holdings, LLC and the other parties thereto (incorporated by reference to the Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission on May 5, 2017).
31.1*		Rule 13a-14(a)/15d-14(a) Certification of Jonny Jones (Principal Executive Officer).
31.2*		Rule 13a-14(a)/15d-14(a) Certification of Robert J. Brooks (Principal Financial Officer).
32.1**		Section 1350 Certification of Jonny Jones (Principal Executive Officer).
32.2**		Section 1350 Certification of Robert J. Brooks (Principal Financial Officer).
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Taxonomy Extension Schema Document.
101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

* - filed herewith

** - furnished herewith

Table of Contents

SIGNATURE S

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


	Jones Energy, Inc.

	(registrant)


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

Signature Page to Form 10-Q (Q2 2017)

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