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, 2018

or

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

Commission file number 001-36006

Jones Energy, Inc.

(Exact name of registrant as specified in its charter)

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

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

Robert J. Brooks

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

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

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

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

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

Large accelerated filer ☐	Accelerated filer ☒
Non-accelerated filer ☐	Smaller reporting company ☒
(Do not check if a smaller reporting company)
Emerging growth company ☒

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

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

On July 27, 2018, the Registrant had 98,039,826 shares of Class A common stock outstanding and 4,825,038 shares of Class B common stock outstanding.

JONES ENERGY, INC.

TABLE OF CONTENTS

PART 1—FINANCIAL INFORMATION	1
Item 1. Financial Statements	1
Unaudited Consolidated Financial Statements	1
Consolidated Balance Sheets	1
Consolidated Statements of Operations	2
Consolidated Statement of Changes in Stockholders’ Equity	3
Consolidated Statements of Cash Flows	4
Notes to the Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
Item 3. Quantitative and Qualitative Disclosures About Market Risk	54
Item 4. Controls and Procedures	55
PART II—OTHER INFORMATION	56
Item 1. Legal Proceedings	56
Item 1A. Risk Factors	56
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	57
Item 3. Defaults upon Senior Securities	57
Item 4. Mine Safety Disclosures	57
Item 5. Other Information	57
Item 6. Exhibits	58
SIGNATURES	59

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this report that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this report specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, our ability to mitigate commodity price risk through our hedging program, expectations regarding litigation, our ability to successfully pursue a liability management program, expectations regarding, our ability to successfully consummate a strategic transaction, including a DrillCo, our belief that we will be able to identify and prioritize projects with the greatest expected returns, our ability to cure our NYSE price deficiency by implementing a reverse stock split, our expectations regarding our working capital balance, projections regarding taxable income generated by JEH, and our ability to successfully execute our 2018 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, 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 2018 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.

ii

PART 1—FINANCIAL INFORMATION

Item 1. Financial Statements

Jones Energy, Inc.

Consolidated Balance Sheets (Unaudited)

	June 30,		December 31,
(in thousands of dollars)	2018		2017
Assets
Current assets
Cash and cash equivalents	$	148,070	$	19,472
Accounts receivable, net
Oil and gas sales		39,990		34,492
Joint interest owners		34,789		31,651
Other		1,167		1,236
Commodity derivative assets		723		3,474
Other current assets		7,070		14,376
Total current assets		231,809		104,701
Oil and gas properties, net, under the successful efforts method		1,620,083		1,597,040
Other property, plant and equipment, net		2,243		2,719
Commodity derivative assets		1,371		172
Other assets		993		5,431
Total assets	$	1,856,499	$	1,710,063
Liabilities and Stockholders' Equity
Current liabilities
Trade accounts payable	$	43,725	$	72,663
Oil and gas sales payable		39,930		31,462
Accrued liabilities		46,199		21,604
Commodity derivative liabilities		46,686		36,709
Other current liabilities		3,863		4,049
Total current liabilities		180,403		166,487
Long-term debt		978,727		759,316
Deferred revenue		4,675		5,457
Commodity derivative liabilities		14,949		8,788
Asset retirement obligations		20,146		19,652
Liability under tax receivable agreement		50,529		59,596
Other liabilities		874		811
Deferred tax liabilities		9,732		14,281
Total liabilities		1,260,035		1,034,388
Commitments and contingencies (Note 15)
Mezzanine equity
Series A preferred stock, $0.001 par value; 1,837,995 shares issued and outstanding at June 30, 2018 and 1,839,995 shares issued and outstanding at December 31, 2017		91,534		89,539
Stockholders' equity
Class A common stock, $0.001 par value; 93,799,481 shares issued and 93,776,879 shares outstanding at June 30, 2018 and 90,139,840 shares issued and 90,117,238 shares outstanding at December 31, 2017		94		90
Class B common stock, $0.001 par value; 9,074,330 shares issued and outstanding at June 30, 2018 and 9,627,821 shares issued and outstanding at December 31, 2017		9		10
Treasury stock, at cost: 22,602 shares at June 30, 2018 and December 31, 2017		(358)		(358)
Additional paid-in-capital		611,242		606,319
Retained (deficit) / earnings		(207,081)		(136,274)
Stockholders' equity		403,906		469,787
Non-controlling interest		101,024		116,349
Total stockholders’ equity		504,930		586,136
Total liabilities and stockholders' equity	$	1,856,499	$	1,710,063

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

1

Jones Energy, Inc.

Consolidated Statements of Operations (Unaudited)

	Three months ended June 30,				Six months ended June 30,
(in thousands of dollars except per share data)	2018		2017		2018		2017
Operating revenues
Oil and gas sales	$	64,748	$	48,114	$	122,886	$	88,791
Other revenues		507		512		(142)		1,068
Total operating revenues		65,255		48,626		122,744		89,859
Operating costs and expenses
Lease operating		11,592		9,425		21,821		18,231
Production and ad valorem taxes		3,284		2,790		6,035		1,884
Transportation and processing costs		885		—		1,591		—
Exploration		1,528		6,725		4,827		9,669
Depletion, depreciation and amortization		44,729		45,336		86,170		80,990
Impairment of oil and gas properties		—		148,016		—		148,016
Accretion of ARO liability		264		266		515		467
General and administrative		7,896		8,633		15,466		16,674
Total operating expenses		70,178		221,191		136,425		275,931
Operating income (loss)		(4,923)		(172,565)		(13,681)		(186,072)
Other income (expense)
Interest expense		(23,055)		(12,677)		(44,917)		(25,564)
Net gain (loss) on commodity derivatives		(30,145)		21,527		(39,167)		43,847
Other income (expense)		5,774		27,501		13,504		28,081
Other income (expense), net		(47,426)		36,351		(70,580)		46,364
Income (loss) before income tax		(52,349)		(136,214)		(84,261)		(139,708)
Income tax provision (benefit)		(5,418)		(2,236)		(8,410)		(2,215)
Net income (loss)		(46,931)		(133,978)		(75,851)		(137,493)
Net income (loss) attributable to non-controlling interests		(5,416)		(51,762)		(8,975)		(53,890)
Net income (loss) attributable to controlling interests	$	(41,515)	$	(82,216)	$	(66,876)	$	(83,603)
Dividends and accretion on preferred stock		(1,963)		(1,966)		(3,931)		(3,993)
Net income (loss) attributable to common shareholders	$	(43,478)	$	(84,182)	$	(70,807)	$	(87,596)
Earnings (loss) per share:
Basic - Net income (loss) attributable to common shareholders	$	(0.47)	$	(1.28)	$	(0.77)	$	(1.37)
Diluted - Net income (loss) attributable to common shareholders	$	(0.47)	$	(1.28)	$	(0.77)	$	(1.37)
Weighted average Class A shares outstanding:
Basic		93,429		65,681		92,253		63,948
Diluted		93,429		65,681		92,253		63,948

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

2

Jones Energy, Inc.

Statement of Changes in Stockholders’ Equity (Unaudited)

	Common Stock						Treasury Stock			Additional		Retained				Total
	Class A			Class B			Class A			Paid-in-		(Deficit)/		Non-controlling		Stockholders'
(amounts in thousands)	Shares	Value		Shares	Value		Shares	Value		Capital		Earnings		Interest		Equity
Balance at December 31, 2017	90,117	$	90	9,628	$	10	23	$	(358)	$	606,319	$	(136,274)	$	116,349	$	586,136
Stock-compensation expense	1,283		1	—		—	—		—		518		—		—		519
Exchange of Class B shares for Class A shares	553		1	(553)		(1)	—		—		2,470		—		(6,350)		(3,880)
Conversion of preferred shares for Class A shares	34		—	—		—	—		—		97		—		—		97
Dividends and accretion on preferred stock	1,789		2	—		—	—		—		1,838		(3,931)		—		(2,091)
Net income (loss)	—		—	—		—	—		—		—		(66,876)		(8,975)		(75,851)
Balance at June 30, 2018	93,776	$	94	9,075	$	9	23	$	(358)	$	611,242	$	(207,081)	$	101,024	$	504,930

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

3

Jones Energy, Inc.

Consolidated Statements of Cash Flows (Unaudited)

	Six months ended June 30,
(in thousands ofdollars)	2018		2017
Cash flows from operating activities
Net income (loss)	$	(75,851)	$	(137,493)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, and amortization		86,170		80,990
Exploration (dry hole and lease abandonment)		907		6,880
Impairment of oil and gas properties		—		148,016
Accretion of ARO liability		515		467
Amortization of debt issuance costs		7,261		1,953
Stock compensation expense		974		3,736
Deferred and other non-cash compensation expense		84		180
Amortization of deferred revenue		(782)		(942)
(Gain) loss on commodity derivatives		39,167		(43,847)
(Gain) loss on sales of assets		(1,945)		119
Deferred income tax provision		(8,410)		6
Change in liability under tax receivable agreement		(9,081)		(28,266)
Other - net		376		1,307
Changes in operating assets and liabilities
Accounts receivable		(9,246)		(4,188)
Other assets		7,574		(12,407)
Accrued interest expense		15,583		(1,301)
Accounts payable and accrued liabilities		(6,484)		6,268
Net cash provided by operations		46,812		21,478
Cash flows from investing activities
Additions to oil and gas properties		(114,832)		(107,250)
Net adjustments to purchase price of properties acquired		—		2,391
Proceeds from sales of assets		6,566		2,730
Acquisition of other property, plant and equipment		(71)		(436)
Current period settlements of matured derivative contracts		(25,655)		45,738
Net cash used in investing		(133,992)		(56,827)
Cash flows from financing activities
Proceeds from issuance of long-term debt		20,000		75,000
Repayment of long-term debt		(231,000)		(72,000)
Proceeds from senior notes		438,867		—
Payment of debt issuance costs		(11,537)		—
Payment of cash dividends on preferred stock		(97)		(3,367)
Net distributions paid to JEH unitholders		—		(562)
Net payments for share based compensation		(455)		(462)
Proceeds from sale of common stock		—		8,352
Net cash provided by financing		215,778		6,961
Net increase (decrease) in cash and cash equivalents		128,598		(28,388)
Cash and cash equivalents
Beginning of period		19,472		34,642
End of period	$	148,070	$	6,254
Supplemental disclosure of cash flow information
Cash paid for interest, net of capitalized interest	$	23,055	$	24,064
Change in accrued additions to oil and gas properties		(1,425)		13,155
Asset retirement obligations incurred, including changes in estimate		280		395

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

4

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

1.        Organization and Description of Business

Organization

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

JEH was formed as a Delaware limited liability company on December 16, 2009 through investments made by the Jones family, 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, 2018, the Company held 93,776,879 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 9,074,330 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 (the “Board”) 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 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, of which 1,837,995 remained issued and outstanding as of June 30, 2018. See Note 12, “Stockholders’ and Mezzanine equity”.

Description of Business

The Company is engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States, spanning areas of Oklahoma and Texas. 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 plays, 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.

NYSE Listing

On March 23, 2018, the New York Stock Exchange (the “NYSE”) notified the Company that it was non-compliant with certain continued listing standards because the price of the Company’s Class A common stock over a period of 30 consecutive trading days had fallen below $1.00 per share, which is the minimum average closing price per share required to maintain a listing on the NYSE. The Company is now in a six-month cure period during which it can regain compliance, which expires on September 23, 2018. Within the cure period, the

5

Company may regain compliance if the closing price per share is $1.00 or higher on the last trading day of a given month, or at the end of the cure period. Additionally, the 30-day average closing price per share must also be $1.00 or higher. We previously received a similar notice on December 26, 2017, but regained compliance on February 1, 2018.

The Company notified the NYSE that it intended to cure the price deficiency by proposing a reverse stock split for approval by the Company’s stockholders. At the Company’s annual meeting of stockholders held on May 22, 2018, the Company’s stockholders approved the reverse stock split, subject to further approval by the Board. The Board has not considered or made a decision as to whether it will approve a reverse stock split.

During the cure period, the Company’s Class A common stock will continue to be listed on the exchange so long as it remains compliant with other continued listing standards. The notice does not affect ongoing business operations of the Company or its reporting requirements with the Securities and Exchange Commission. For more information, see Item 1A of Part II, “Risk Factors.”

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, 2017 and the financial statements reported for June 30, 2018 and 2017 and each of the three and 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 ended June 30, 2018 and 2017 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, 2017.

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, 2017.

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 during the six months ended June 30, 2017. No further refunds were received during the three months ended June 30, 2017. During the three and six months ended June 30, 2018, the Company received net production tax refunds of $0.1 million for High-Cost Gas Incentive refunds and Low-Producing Gas Incentive refunds in Texas for qualified wells on which taxes were initially paid between November 2014 and June 2017. These refunds were recorded as a reduction in Production and ad valorem taxes on the Company’s Consolidated Statement of Operations.

6

Accrued Liabilities

Accrued liabilities consisted of the following at June 30, 2018 and December 31, 2017:

	June 30,		December 31,
(in thousands of dollars)	2018		2017
Accrued interest	$	27,692	$	12,109
Joint interest owners prepayments		9,199		4,061
Other accrued liabilities		9,308		5,434
Total accrued liabilities	$	46,199	$	21,604

Recent Accounting Pronouncements

Adopted in the current year-to-date period:

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which creates a new topic in the Accounting Standards Codification (“ASC”), topic 606, “Revenue from Contracts with Customers.” This standard sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09 by one year. The amendments may be applied on either a full or modified retrospective basis and are now effective for interim and annual reporting periods beginning after December 15, 2017. Therefore, the Company has adopted Update 2014-09 and Update 2015-14 effective as of January 1, 2018.  The change was applied on a modified retrospective basis, which did not result in a cumulative effect adjustment to retained earnings. However, adoption did result in certain changes in presentation of gross revenues and expenses on the Company’s Consolidated Statement of Operations; such costs were historically offset against revenues. Upon adoption, we have also expanded disclosures related to revenue recognition. See Note 4, “Revenue Recognition.”

In January 2017, the FASB issued ASU 2017-01, “Business Combinations” (Topic 805). The amendments under this ASU provide guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions/disposals or business combinations by providing a screen to determine when an integrated set of assets and activities is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired, or disposed of, is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business, therefore reducing the number of transactions that need to be further evaluated for treatment as a business combination. This new guidance is effective for annual periods beginning after December 15, 2017. Therefore, the Company adopted ASU 2017-01 effective as of January 1, 2018 applied prospectively, which did not have a material impact on our financial statements; however these amendments could result in the recording of fewer business combinations in future periods.

To be adopted in a future period:

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 and mineral 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. In July 2018, the FASB issued ASU 2018-11, “Leases” (Topic 842) Targeted Improvements, which allows issues an additional (and optional) transition method of adoption. Under the original standard issued in 2016, lessees and lessors were required to 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. However, under the new transition method allowed for in the standard released in 2018, an entity may elect to initially apply the new leases standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the impacts of the

7

amendments to our financial statements and accounting practices for leases, as well as the method of adoption. We anticipate adoption of ASU 2016-02 effective as of January 1, 2019.

3.         Divestitures

Six Months Ended June 30, 2018

Sales of non-core assets resulted in net gains of $4.6 million during the six months ended June 30, 2018. These gains were recognized during the first quarter of 2018.

Twelve Months Ended December 31, 2017

Arkoma Divestiture

As of June 30, 2017, the Company’s former assets in the Arkoma Basin and related liabilities (the “Held for sale assets”) were classified as held for sale due to the pending Arkoma Divestiture. Upon the classification change occurring on June 30, 2017, the Company ceased recording depletion on the Held for sale assets. Based on the Company’s sales price, the Company recognized an impairment charge of $148.0 million at June 30, 2017 which has been included in Impairment of oil and gas properties on the Company’s Consolidated Statement of Operations.

On August 1, 2017, JEH closed its previously announced agreement to sell its Arkoma Basin properties for a purchase price of $65.0 million, prior to customary effective date adjustments of $7.3 million, and subject to customary post-close adjustments (the “Arkoma Divestiture”). JEH may also receive up to $2.5 million in contingent payments based on natural gas prices. As of June 30, 2018, $0.1 million has been recorded related to this contingent payment. The $0.1 million was recorded as a gain in Other income (expense) on the Company’s Consolidated Statement of Operations during the three months ended June 30, 2018.

4.        Revenue Recognition

Adoption of ASC Topic 606, Revenue from Contracts with Customers

On January 1, 2018, the Company adopted ASC Topic 606 (“ASC 606”), Revenue from Contracts with Customers, using the modified retrospective approach, which was applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning January 1, 2018, are presented in accordance with ASC 606, while prior period amounts are reported in accordance with ASC Topic 605, Revenue Recognition.

In accordance with ASC 606, the Company now records transportation and processing costs that are incurred before control of its product has transferred to the customer (i.e. fixed fee contracts) as a separate expense line item on the Consolidated Statement of Operations. Prior to the adoption of ASC 606, these transportation and processing costs were recorded as a reduction of Oil and gas sales on the Consolidated Statement of Operations. See further discussion below in “Nature of revenue” related to transportation and processing costs associated with fixed fee contracts. Revenue under ASC 606 is recognized at the same point in time at which revenue was recognized under ASC Topic 605, thus there was no impact to net income (loss) or opening retained earnings as a result of adopting ASC 606.

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The following table presents the impact to the Consolidated Statement of Operations as a result of adopting ASC 606.

	Three Months Ended June 30, 2018						Six Months Ended June 30, 2018
	Amounts under		Adoption		Amounts under		Amounts under		Adoption		Amounts under
(in thousands of dollars except per share data)	ASC 606		impact		ASC 605 (1)		ASC 606		impact		ASC 605 (1)
Operating revenues
Oil and gas sales	$	64,748	$	(885)	$	63,863	$	122,886	$	(1,591)	$	121,295
Other revenues		507		—		507		(142)		—		(142)
Total operating revenues		65,255		(885)		64,370		122,744		(1,591)		121,153
Operating costs and expenses
Lease operating		11,592		—		11,592		21,821		—		21,821
Production and ad valorem taxes		3,284		—		3,284		6,035		—		6,035
Transportation and processing costs		885		(885)		—		1,591		(1,591)		—
Exploration		1,528		—		1,528		4,827		—		4,827
Depletion, depreciation and amortization		44,729		—		44,729		86,170		—		86,170
Accretion of ARO liability		264		—		264		515		—		515
General and administrative		7,896		—		7,896		15,466		—		15,466
Total operating expenses		70,178		(885)		69,293		136,425		(1,591)		134,834
Operating income (loss)		(4,923)		—		(4,923)		(13,681)		—		(13,681)
Other income (expense)
Interest expense		(23,055)		—		(23,055)		(44,917)		—		(44,917)
Net gain (loss) on commodity derivatives		(30,145)		—		(30,145)		(39,167)		—		(39,167)
Other income (expense)		5,774		—		5,774		13,504		—		13,504
Other income (expense), net		(47,426)		—		(47,426)		(70,580)		—		(70,580)
Income (loss) before income tax		(52,349)		—		(52,349)		(84,261)		—		(84,261)
Income tax provision (benefit)		(5,418)		—		(5,418)		(8,410)		—		(8,410)
Net income (loss)		(46,931)		—		(46,931)		(75,851)		—		(75,851)
Net income (loss) attributable to non-controlling interests		(5,416)		—		(5,416)		(8,975)		—		(8,975)
Net income (loss) attributable to controlling interests	$	(41,515)	$	—	$	(41,515)	$	(66,876)	$	—	$	(66,876)
Dividends and accretion on preferred stock		(1,963)		—		(1,963)		(3,931)		—		(3,931)
Net income (loss) attributable to common shareholders	$	(43,478)	$	—	$	(43,478)	$	(70,807)	$	—	$	(70,807)
Earnings (loss) per share:
Basic - Net income (loss) attributable to common shareholders	$	(0.47)	$	—	$	(0.47)	$	(0.77)	$	—	$	(0.77)
Diluted - Net income (loss) attributable to common shareholders	$	(0.47)	$	—	$	(0.47)	$	(0.77)	$	—	$	(0.77)
Weighted average Class A shares outstanding:
Basic		93,429		—		93,429		92,253		—		92,253
Diluted		93,429		—		93,429		92,253		—		92,253

(1) This column excludes the impact of adopting ASC 606 and is consistent with the presentation prior to January 1, 2018.

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Nature of revenue

Our revenues are primarily derived from the sale of oil and natural gas production, and from the sale of NGLs that are extracted from our natural gas. Sales of oil, natural gas, and NGLs from our interests in producing wells are recognized when we satisfy a performance obligation by transferring control of a product to a customer. Our oil and gas production is sold to purchasers under either short-term or long-term contracts at market-based prices. The sales prices for oil, natural gas, and NGLs are adjusted for transportation and other related deductions. These deductions are based on contractual data and do not require significant judgment. The revenue deductions reflect actual charges based on purchaser statements. Since there is a ready market for oil and natural gas, we sell the majority of production soon after it is produced at various locations.  Payment is generally received one month after the sale has occurred.

Under our oil sales contracts, we generally sell oil to the purchaser from storage tanks near the wellhead and collect a contractually agreed upon index price, net of pricing differentials. We transfer control of the product from the storage tanks to the purchaser and recognize revenue based on the contract price. For pipeline sales, title transfers upon oil passing the inlet or delivery point.

Under our natural gas sales contracts, we deliver natural gas to the purchaser at an agreed upon delivery point. Natural gas is transported from our wellheads to delivery points specified under sales contracts. To deliver natural gas to these points, the Company or third parties gather, compress, process and transport our natural gas. We maintain ownership and control of the natural gas during gathering, compression, processing, and transportation. Our sales contracts provide that we receive a specific index price adjusted for pricing differentials. We transfer ownership and control of the product at the delivery point and recognize revenue based on the contract price. The sales prices for natural gas is adjusted for transportation and other related deductions. The revenue deductions reflect actual charges based on purchaser statements. The costs to gather, compress, process, and transport the natural gas are separately presented as Transportation and processing costs on the Consolidated Statement of Operations.

NGLs, which are extracted from natural gas through processing, are either sold by us directly or to the processor under processing contracts. For NGLs sold by us directly, our sales contracts provide that we deliver the product to the purchaser at an agreed upon delivery point and that we receive a specific index price adjusted for pricing differentials. We transfer control of the product to the purchaser at the delivery point and recognize revenue based on the contract price. Several of our revenue contracts are fixed fee where title transfers to the customer at the tailgate of the processing plant and we pay a gathering and processing fee. Gathering and processing costs associated with fixed fee contracts have a distinct service payable and, as a result of the adoption of ASC 606, these costs are reported as a separate expense line item titled Transportation and processing costs on the Consolidated Statement of Operations. Prior to the adoption of ASC 606, these transportation and processing costs were recorded as a reduction of Oil and gas sales on the Consolidated Statement of Operations. There is no impact to the current method of recognizing revenue for percentage of recovery contracts for gathering and processing costs which, in accordance with ASC 606, remain deducted from sales proceeds and are recorded as a reduction of Oil and gas sales on the Consolidated Statement of Operations.

Significant accounting policy

Revenue is measured based on a consideration specified in a contract with a customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue when it satisfies a performance obligation by transferring control over a product or service to a customer. We generally consider the delivery of each unit (Bbl or MMBtu) to be separately identifiable and represents a distinct performance obligation that is satisfied at a point-in-time once control of the product has been transferred to the customer upon delivery to an agreed upon delivery point. Transfer of control typically occurs when the products are delivered to the purchaser, and title has transferred.

Revenue is recognized at a point in time as a result of not meeting any of the three criteria required for over time recognition.

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Certain transportation and processing costs associated with fixed fee contracts where title transfers to the customer at the tailgate of the processing plant and we pay a gathering and processing fee are recognized at the time of title transfer. These costs are presented as Transportation and processing costs on the Consolidated Statement of Operations.

The Company enters into marketing agreements with our non-operating partners to market and sell their share of production to third parties. Under these arrangements, we record revenue for our share of the production (i.e. we, as the operator, record revenue on a net basis). Distributions are made to our non-operating partners for their share of the revenue.

As part of our adoption of ASC 606, we used practical expedients permitted by the standard when applicable. These practical expedients included:

· Applying the new guidance only to contracts that are not completed as of January 1, 2018;

· Taxes assessed by a governmental authority that are both imposed on and concurrent with a specific revenue-producing transaction, that are collected by the Company from a customer, are excluded from revenue;

· The Company recognizes the incremental cost of obtaining contracts as an expense when incurred if the amortization period of the assets that the Company otherwise would have recognized is one year or less. These costs are included in General and administrative expenses;

· For our product sales that have a contact term greater than one year, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligation if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our product sales contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required; and

· For our product sales that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of the contract that has an original expected duration of one year or less.

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Disaggregation of revenue

The following tables present quantitative information about disaggregated revenues from contracts with customers by commodity and region of production for the three and six months ended June 30, 2018 as presented under ASC 606.

	Three Months Ended June 30, 2018
(in thousands of dollars)	Oil		Natural gas		NGLs		Total
Eastern Anadarko	$	19,102	$	1,896	$	6,792	$	27,790
Western Anadarko		22,831		5,149		8,978		36,958
Total	$	41,933	$	7,045	$	15,770	$	64,748
	Six Months Ended June 30, 2018
(in thousands of dollars)	Oil		Natural gas		NGLs		Total
Eastern Anadarko	$	32,614	$	3,087	$	10,565	$	46,266
Western Anadarko		45,996		12,145		18,479		76,620
Total	$	78,610	$	15,232	$	29,044	$	122,886

The following tables present quantitative information about disaggregated revenues from contracts with customers by commodity and region of production for the three and six months ended June 30, 2017 as presented under ASC 605 since the Company adopted ASC 606 under the modified retrospective method which does not require adjustment of prior period amounts.

	Three Months Ended June 30, 2017 (1)
(in thousands of dollars)	Oil		Natural gas		NGLs		Total
Eastern Anadarko	$	3,150	$	795	$	867	$	4,812
Western Anadarko		21,148		12,756		11,168		45,072
Total	$	24,298	$	13,551	$	12,035	$	49,884
	Six Months Ended June 30, 2017 (1)
(in thousands of dollars)	Oil		Natural gas		NGLs		Total
Eastern Anadarko	$	4,106	$	1,090	$	1,136	$	6,332
Western Anadarko		38,459		23,888		21,882		84,229
Total	$	42,565	$	24,978	$	23,018	$	90,561

(1) Prior period amounts have not been adjusted under the modified retrospective method.

During the six months ended June 30, 2018 and 2017, the timing of revenue recognition for all products was transferred at a point in time. No products and/or services were transferred over time.

Contract balances

The following table provides information about receivables, contract assets, and contract liabilities from contracts with customers at June 30, 2018 and December 31, 2017.

	June 30,		December 31,
(in thousands of dollars)	2018		2017
Accounts receivable, net
Oil and gas sales	$	39,990	$	34,492
Other current liabilities
Contract liabilities	$	1,294	$	—

Accounts receivable – Oil and gas sales consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. Under our sales contracts, payment is unconditional after our performance obligations have been satisfied under ASC 606. Accordingly, unconditional rights to consideration are presented separately as a receivable. Since our sales contracts are not conditional on factors other than the passage of time, the contracts do not give rise to contract assets under ASC 606.

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Other current liabilities – contract liabilities represent estimated fees for minimum volume and drilling commitments associated with certain revenue contracts with customers.

5.        Properties, Plant and Equipment

Oil and Gas Properties

The Company accounts for its oil and natural gas exploration and production activities under the successful efforts method of accounting. Oil and gas properties consisted of the following at June 30, 2018 and December 31, 2017:

	June 30,		December 31,
(in thousands of dollars)	2018		2017
Mineral interests in properties
Unproved	$	110,153	$	164,087
Proved		948,203		893,246
Wells and equipment and related facilities		1,542,932		1,434,383
		2,601,288		2,491,716
Less: Accumulated depletion and impairment		(981,205)		(894,676)
Net oil and gas properties	$	1,620,083	$	1,597,040

There were no exploratory wells drilled during the six months ended June 30, 2018 or 2017. As such, no associated costs were capitalized and no exploratory wells resulted in exploration expense during either period.

The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. During the three and six months ended June 30, 2018, the Company capitalized $0.1 million associated with such in progress projects. During the three and six months ended June 30, 2017, the Company capitalized $0.2 million associated with such in progress projects. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

Depletion of oil and gas properties amounted to $44.4 million and $85.6 million for the three and six months ended June 30, 2018, respectively, and $45.1 million and $80.5 million for the three and six months ended June 30, 2017, 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 impairment assessment during the three and six months ended June 30, 2018. As disclosed in Note 3, “Acquisitions and Divestitures - Arkoma Divestiture,” the Company recognized an impairment charge of $148.0 million during the second quarter of 2017 based on the Company’s negotiated selling price of the Arkoma Basin oil and gas property assets and related liabilities.

Other Property, Plant and Equipment

Other property, plant and equipment consisted of the following at June 30, 2018 and December 31, 2017:

	June 30,		December 31,
(in thousands of dollars)	2018		2017
Leasehold improvements	$	1,186	$	1,186
Furniture, fixtures, computers and software		4,383		4,410
Vehicles		1,922		1,922
Aircraft		910		910
Other		239		210
		8,640		8,638
Less: Accumulated depreciation and amortization		(6,397)		(5,919)
Net other property, plant and equipment	$	2,243	$	2,719

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Depreciation and amortization of other property, plant and equipment amounted to $0.3 million and $0.6 million, for the three and six months ended June 30, 2018, respectively, and $0.2 million and $0.5 million for the three and six months ended June 30, 2017, respectively.

6.        Long-Term Debt

Long-term debt consisted of the following at June 30, 2018 and December 31, 2017:

(in thousands of dollars)	June 30, 2018		December 31, 2017
Revolver	$	—	$	211,000
2022 Notes		409,148		409,148
2023 Notes		150,000		150,000
2023 First Lien Notes		450,000		—
Total principal amount		1,009,148		770,148
Less: unamortized discount		(14,943)		(5,228)
Less: debt issuance costs, net		(15,478)		(5,604)
Total carrying amount	$	978,727	$	759,316

Senior Unsecured Notes

On April 1, 2014, JEH and Jones Energy Finance Corp., JEH’s wholly owned subsidiary formed for the sole purpose of co-issuing certain of JEH’s debt (collectively, the “Issuers”), sold $500.0 million in aggregate principal amount of the Issuers’ 6.75% senior notes due 2022 (the “2022 Notes”). The Company used the net proceeds from the issuance of the 2022 Notes to repay certain indebtedness and for working capital and general corporate purposes. The 2022 Notes bear interest at a rate of 6.75% per year, payable semi-annually on April 1 and October 1 of each year beginning October 1, 2014. The 2022 Notes were registered in March 2015. The 2022 Notes mature on April 1, 2022.

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

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 during the year ended December 31, 2016, on a pre-tax basis. This income was 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. No additional purchases were made during the year ended December 31, 2017 and during the six months ended June 30, 2018.

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.

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The indentures governing the 2022 Notes and 2023 Notes are substantially identical and contain covenants that, among other things, limit the ability of the Company to incur additional indebtedness or issue certain preferred stock, pay dividends on capital stock, transfer or sell assets, make investments, create certain liens, enter into agreements that restrict dividends or other payments from the Company’s restricted subsidiaries to the Company, consolidate, merge or transfer all of the Company’s assets, engage in transactions with affiliates or create unrestricted subsidiaries. If at any time when the 2022 Notes or 2023 Notes are rated investment grade and no default or event of default (as defined in the indenture) has occurred and is continuing, many of the foregoing covenants pertaining to the 2022 Notes or 2023 Notes, as applicable, will be suspended. If the ratings on the 2022 Notes or 2023 Notes, as applicable, were to decline subsequently to below investment grade, the suspended covenants would be reinstated.

As of June 30, 2018, the Company was in compliance with the indentures governing the 2022 Notes and 2023 Notes.

Senior Secured First Lien Notes due 2023

On February 14, 2018, the Issuers sold $450.0 million of 9.25% senior secured first lien notes due 2023 (the “2023 First Lien Notes”) at an offering price equal to 97.526% of par in an offering exempt from registration under the Securities Act. The 2023 First Lien Notes are senior secured first lien obligations of JEH and Jones Energy Finance Corp. and are guaranteed on a senior secured first lien basis by the Company and each of the existing and future restricted subsidiaries of JEH and Jones Energy Finance Corp. The Company used the net proceeds from the offering to repay all but $25.0 million of the outstanding borrowings under the Revolver, to fund drilling and completion activities, and for other general corporate purposes. During the six months ended June 30, 2018, the Company capitalized $11.4 million of loan costs associated with the issuance of the 2023 First Lien Notes.

Other Long-Term Debt

The Company has a Senior Secured Revolving Credit Facility (the “Revolver”) with a syndicate of banks. At the beginning of 2018, the borrowing base under the Revolver was $350.0 million. In connection with the offering of the 2023 First Lien Notes, the borrowing base was reduced to $50.0 million effective February 14, 2018. On June 27, 2018 the borrowing base was further reduced to $25.00. The Company’s oil and gas properties are pledged as collateral to secure its obligations under the Revolver. The Revolver matures on November 6, 2019.

In connection with the offering of the 2023 First Lien Notes, on February 14, 2018, JEH amended the Revolver to, among other things, (a) permit the issuance of the 2023 First Lien Notes and additional senior secured notes in an aggregate principal amount, together with the notes issued pursuant to this offering, not to exceed $700.0 million, (b) permit the incurrence of liens securing the 2023 First Lien Notes pursuant to the terms of a collateral trust agreement, (c) reduce the borrowing base under the Revolver to $50.0 million and (d) suspend testing of our senior secured leverage ratio until March 31, 2019.

On June 27, 2018, the Company entered into an amendment to the Revolver to, among other things (a) remove the financial maintenance covenants contained therein, including the current ratio, total leverage ratio and senior secured leverage ratio, (b) align certain of the other covenants contained therein to be consistent with the terms of the indenture governing the 2023 First Lien Notes, (c) reduce lender commitments to $25.00, and (d) reduce the borrowing base to $25.00 for the remainder of the life of the facility. Additionally, outstanding borrowings of $25.0 million were repaid in connection with the closing of the amendment. The Company’s current outstanding borrowings under the Revolver are $0.00.

The Company recognized accelerated amortization of debt issuance costs of $0.6 million and $3.8 million during the three and six months ended June 30, 2018, respectively, associated with the modifications of the Revolver, which was recorded as Interest expense on the Company’s Consolidated Statement of Operations.

The terms of the Revolver require the Company to make periodic payments of interest on the loans outstanding thereunder, if any, 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.

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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 2.75% to 3.75% 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 1.75% to 2.75% based on the level of borrowing base utilization at such time. For the three and six months ended June 30, 2018, the average interest rate under the Revolver was 4.75% and 4.46%, respectively, on an average outstanding balance of $24.2 million and $74.3 million, respectively.

Total interest and commitment fees under the Revolver were $0.3 million and $1.8 million for the three and six months ended June 30, 2018, respectively, and $1.6 million and $3.1 million for the three and six months ended June 30, 2017, respectively.

Jones Energy, Inc. and its consolidated subsidiaries are subject to certain covenants under the Revolver, which are substantially similar to those set forth in the indenture governing the 2023 First Lien Notes or are otherwise customary for facilities of this type and which limit our ability to, among other things: borrow money or issue guarantees; pay dividends, redeem capital stock or make other restricted payments; incur liens to secure indebtedness; sell certain assets; enter into transactions with our affiliates; or merge with another person or sell substantially all of our assets. We were in compliance with all terms of our Revolver at June 30, 2018, and we expect to maintain compliance throughout the next twelve months. However, factors including those outside of our control may prevent us from maintaining compliance with these covenants. 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 terminating the Revolver. If an event of default exists under the Revolver, the lenders would be able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change of control, as defined in the Revolver.

7.        Derivative Instruments and Hedging Activities

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

The following tables summarize our hedging positions as of June 30, 2018:

Hedging Positions

	June 30, 2018
						Weighted		Final
		Low		High		Average		Expiration
Oil swaps	Exercise price	$	49.70	$	54.18	$	50.41	December 2020
	Net barrels per month		55,000		211,000		97,667
Natural gas swaps	Exercise price	$	2.76	$	3.10	$	2.86	December 2020
	Offset exercise price	$	2.83	$	2.85	$	2.84	December 2018
	Net MMbtu per month		700,000		1,600,000		1,012,667
Natural gas liquids swaps	Exercise price	$	22.89	$	45.26	$	30.04	December 2018
	Barrels per month		130,000		145,000		132,500
Natural gas basis swaps	Exercise price	$	(0.50)	$	(0.44)	$	(0.45)	October 2018
	Net MMbtu per month		800,000		800,000		800,000
Oil collars	Puts (floors)	$	45.00	$	50.00	$	48.52	December 2019
	Calls (ceilings)	$	56.60	$	61.00	$	59.64
	Net barrels per month		65,000		73,000		67,500
Natural gas collars	Puts (floors)	$	2.55	$	2.55	$	2.55	December 2019
	Calls (ceilings)	$	3.08	$	3.41	$	3.19
	Net barrels per month		950,000		1,050,000		990,833

The Company recognized net losses on derivative instruments of $30.1 million and $39.2 million for the three and six months ended June 30, 2018, respectively. 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.

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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 an equal volume that was associated with the initial hedge transaction. Therefore, as prices fluctuate, the loss (or gain) on any single contract in 2018 and 2019 will be offset by an equal gain (or loss). This essentially left the underlying production open to fluctuations in market prices prior to the point when the Company began to re-hedge the unhedged production. Based on the original contract terms of these purchased swaps, the gains would have been recognized as the hedge contracts mature in 2018 and 2019. However, during the year ended December 31, 2017, the Company unwound all of its realized 2018 and 2019 hedges. Approximately $8.1 million and $28.0 million of such recognized gains were included in Net gain (loss) on commodity derivatives on the Company’s Consolidated Statement of Operations for the three and six months ended June 30, 2017, respectively.

Offsetting Assets and Liabilities

As of June 30, 2018, 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, 2018 and December 31, 2017:

					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, 2018
Commodity derivative contracts
Assets	$	5,929	$	(3,835)	$	2,094	$	—	$	2,094
Liabilities		(65,470)		3,835		(61,635)		—		(61,635)
December 31, 2017
Commodity derivative contracts
Assets	$	8,572	$	(4,926)	$	3,646	$	—	$	3,646
Liabilities		(50,423)		4,926		(45,497)		—		(45,497)

8.        Fair Value Measurement

Fair Value of Financial Instruments

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

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

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considerations. These adjustments may include amounts to reflect counterparty credit quality, the time value of money, and the liquidity of the market.

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

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

Valuation Hierarchy

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

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

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 values to the counterparty credit adjustment, as described above.

The financial instruments carried at fair value as of June 30, 2018 and December 31, 2017, by consolidated balance sheet caption and by valuation hierarchy, as described above are as follows:

(in thousands of dollars)	June 30, 2018
	Fair Value Measurements Using
Commodity Price Hedges	(Level 1)		(Level 2)		(Level 3)		Total
Current assets	$	—	$	782	$	(59)	$	723
Long-term assets		—		1,276		95		1,371
Current liabilities		—		38,691		7,995		46,686
Long-term liabilities		—		12,078		2,871		14,949

(in thousands of dollars)	December 31, 2017
	Fair Value Measurements Using
Commodity Price Hedges	(Level 1)		(Level 2)		(Level 3)		Total
Current assets	$	—	$	3,474	$	—	$	3,474
Long-term assets		—		56		116		172
Current liabilities		—		28,946		7,763		36,709
Long-term liabilities		—		7,860		928		8,788

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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, 2018:

	Quantitative Information About Level 3 Fair Value Measurements
	Fair Value			Unobservable
Commodity Price Hedges	(000’s)		Valuation Technique	Input	Range
Natural gas liquid swaps	$	(4,289)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$27.93 - $44.00 per barrel
Crude oil collars	$	(6,616)	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	$	75	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, 2018. 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, 2018:

(in thousands of dollars)
Balance at December 31, 2017, net	$	(8,575)
Purchases		—
Settlements		3,699
Transfers to Level 2		—
Transfers to Level 3		—
Changes in fair value		(5,954)
Balance at June 30, 2018, net	$	(10,830)

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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, 2018				December 31, 2017
	Principal				Principal
(in thousands of dollars)	Amount		Fair Value		Amount		Fair Value
Debt:
Revolver	$	—	$	—	$	211,000	$	211,000
2022 Notes		409,148		250,104		409,148		305,404
2023 Notes		150,000		93,209		150,000		114,750
2023 First Lien Notes		450,000		451,391		—		—

The Revolver (as defined in Note 6) is categorized as Level 3 in the valuation hierarchy as the debt is not publicly traded and no observable market exists to determine the fair value; however, the carrying value of the Revolver approximates fair value, as it is subject to short-term floating interest rates that approximate the rates available to the Company for those periods.

The fair value of the 2022 Notes (as defined in Note 6) is based on pricing that is readily available in the public market. Accordingly, the 2022 Notes are classified as Level 1 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities and is actively traded.

The fair value of the 2023 Notes (as defined in Note 6) is based on indicative pricing that is available in the public market. Accordingly, the 2023 Notes are classified as Level 2 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities but is not actively traded.

The fair value of the 2023 First Lien Notes (as defined in Note 6) is based on indicative pricing that is available in the public market. Accordingly, the 2023 First Lien 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.

Assets and liabilities acquired in business combinations are recorded at their fair value on the date of acquisition. Significant Level 3 assumptions associated with the calculation of future cash flows used in the analysis of fair value of the oil and gas property acquired include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. Additionally, fair value is used to determine the inception value of the Company’s ARO. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition. Additions to the Company’s ARO represent a nonrecurring Level 3 measurement.

9.        Asset Retirement Obligations

A summary of the Company’s Asset Retirement Obligations (“ARO”) for the six months ended June 30, 2018 is as follows:

(in thousands of dollars)
Balance at December 31, 2017	$	20,372
Liabilities incurred		209
Accretion of ARO liability		515
Liabilities settled due to sale of related properties		(124)
Liabilities settled due to plugging and abandonment		(177)
Change in estimate		71
Total ARO balance at June 30, 2018		20,866
Less: Current portion of ARO		(720)
Total long-term ARO at June 30, 2018	$	20,146

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10.        Stock-based Compensation

Management Unit Awards

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

The following table summarizes information related to the vesting of Management Units as of June 30, 2018:

		Weighted Average
		Grant Date Fair Value
	JEH Units	per Share
Unvested at December 31, 2017	32,315	$	15.00
Granted	30,312		15.00
Forfeited	(30,312)		15.00
Vested	(30,312)		15.00
Unvested at June 30, 2018	2,003	$	15.00

Stock compensation expense associated with the Management Units was $0.0 million and $0.1 million for the three and six months ended June 30, 2018, respectively, and $0.2 million and $0.4 million for the three and six months ended June 30, 2017, 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 8,505,313 shares of Class A common stock for non-employee director, consultant, and employee stock-based compensation awards, as adjusted for the effects of the Special Stock Dividend and the preferred stock dividends paid in shares, as described in Note 12 “Stockholders’ and Mezzanine equity”.

The Company granted (i) performance share unit and restricted stock unit awards to certain officers and employees and (ii) restricted shares of Class A common stock to the Company’s non-employee directors under the LTIP during 2014, 2015, 2016, 2017 and 2018. During 2016 and 2017, the Company also granted performance unit awards to certain members of the senior management team under the LTIP.

Restricted Stock Unit Awards

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

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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, 2018:

	Restricted	Weighted Average
	Stock Unit	Grant Date Fair Value
	Awards	per Share
Unvested at December 31, 2017	2,762,771	$	2.79
Adjustment (1)	52,484		—
Granted	13,015		0.80
Forfeited	(782,757)		2.38
Vested	(1,057,498)		3.35
Unvested at June 30, 2018	988,015	$	2.34

(1) Increase of 0.019796 units for each unvested restricted stock unit awards at the time of the Company’s February 15, 2018 preferred stock dividend paid entirely in shares of the Company’s Class A common stock, as described in Note 12 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards.

Stock compensation expense associated with the employee restricted stock unit awards was $0.1 million and $1.0 million for the three and six months ended June 30, 2018, respectively, and $1.0 million and $2.0 million for the three and six months ended June 30, 2017, 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.

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 table summarizes information related to the total number of performance share units awarded to the senior management team as of June 30, 2018:

	Performance	Weighted Average
	Share Unit	Grant Date Fair Value
	Awards	per Share
Unvested at December 31, 2017	957,178	$	3.34
Adjustment (1)	18,953		—
Granted	652,300		1.30
Forfeited	(37,628)		4.13
Cancelled	(652,300)		3.34
Vested	(652,300)		1.30
Unvested at June 30, 2018	286,203	$	3.02

(1) Increase of 0.019796 units for each unvested performance share unit awards at the time of the Company’s February 15, 2018 preferred stock dividend paid entirely in shares of the Company’s Class A common stock, as described in Note 12 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards.

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The vesting of the awards issued to certain members of our senior management who departed on April 17, 2018 accelerated at 100% for the unvested performance share units at the time of departure in accordance with the terms of the award.

Stock compensation expense associated with the performance share unit awards was an offset to expense of $0.5 million and $0.2 million for the three and six months ended June 30, 2018, respectively, and $0.5 million and $1.0 million for the three and six months ended June 30, 2017, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

Performance Unit Awards

The Company has outstanding performance unit awards, granted in 2016 and 2017, to certain members of the senior management team of the Company under the LTIP. References to performance unit awards in filings prior to the second quarter of 2016 do not correspond to these newly created performance unit awards. Upon the completion of the applicable three-year performance period, each recipient may vest in a number of performance units. The value of awarded performance units in which each recipient vests at such time, if any, will range from $0.00 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 at award using a Monte Carlo simulation model, as of the grant date, which resulted in an estimated final value upon vesting of $0.1 million and $0.3 million for the awards made in 2017 and 2016, respectively, as adjusted for forfeitures. The fair value measured as of June 30, 2018 was less than $0.1 million.

The vesting of the awards issued to certain members of our senior management who departed on April 17, 2018 accelerated for the unvested performance unit awards at the time of departure in accordance with the terms of the award. Such awards vested at $100.00 per performance unit.

Stock compensation expense associated with the performance unit awards was an expense of $1.7 million and $1.7 million for the three and six months ended June 30, 2018, respectively, due to the accelerated unvested performance awards, and 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 is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. As of June 30, 2018, unrecognized compensation expense was less than $0.1 million related to all the performance unit awards and is subject to re-measurement and adjustment for the change in estimated final value as of the end of each reporting period and is expected to be recognized over the remaining weighted average remaining period of 1.2 years.

Restricted Stock Awards

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

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The following table summarizes information related to the total value of the awards to the Board as of June 30, 2018:

		Weighted Average
	Restricted	Grant Date Fair Value
	StockAwards	per Share
Unvested at December 31, 2017	187,419	$	2.16
Adjustment (1)	2,478		—
Granted	62,473		1.17
Cancelled	(62,473)		2.16
Vested	(189,897)		1.81
Unvested at June 30, 2018	—	$	—

(1) Increase of 0.019796 units for each unvested restricted stock awards at the time of the Company’s February 15, 2018 preferred stock dividend paid entirely in shares of the Company’s Class A common stock, as described in Note 12 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards.

Stock compensation expense associated with awards to the members of the Board was less than $0.1 million and $0.1 million for the three and six months ended June 30, 2018, respectively, and $0.1 million and $0.3 million for the three and six months ended June 30, 2017, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

11.       Income Taxes

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

On December 22, 2017, the US Congress enacted the Tax Cuts and Jobs Act (the “Tax Reform Legislation”), which made significant changes to US federal income tax law, including a reduction of the federal corporate tax rate to 21% effective January 1, 2018. We are required to recognize the effect of a rate change on deferred tax assets and liabilities in the period in which the tax rate change is enacted. Therefore, the rate change enacted by the Tax Reform Legislation resulted in the recognition of a tax benefit along with a benefit from the reduction of the liability under the Tax Receivable Agreement during the year ended December 31, 2017.

The Tax Reform Legislation is a comprehensive bill containing other provisions, such as limitations on the deductibility of interest expense and certain executive compensation, none of which are expected to lead to a material current tax liability at this time. The ultimate impact of Tax Reform Legislation may differ from our estimates due to changes in interpretations and assumptions made by us, as well as additional regulatory guidance that may be issued. The impact on our deferred tax assets and liabilities may be adjusted in future periods, as an adjustment to income tax expense or benefit, in the period in which the final amounts are determined. The Company has not made any further adjustments to its deferred tax assets and liabilities as a direct result of Tax Reform Legislation since recording the effects of the tax rate change during the year ended December 31, 2017.

The Company’s effective tax rate was 10.4% and 10.0% for the three and six months ended June 30, 2018, respectively, and 1.6% for the three and six months ended June 30, 2017. The effective tax rate increase was primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets, which partially offset the tax benefit generated during the six months ended June 30, 2018 and 2017. The effective rate differs from the enacted statutory rates of 21% and 35% for the six months ended June 30, 2018 and 2017, respectively, 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 $5.4 million and $8.4 million for the three and six months ended June 30, 2018, respectively, and a benefit of $2.2 million for the three and six months ended June 30, 2017.

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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)	2018		2017		2018		2017
Jones Energy, Inc.	$	(5,404)	$	(2,231)	$	(8,382)	$	(2,217)
Non-controlling interest		(14)		(5)		(28)		2
Income tax provision (benefit)	$	(5,418)	$	(2,236)	$	(8,410)	$	(2,215)

The Company had deferred tax assets for its federal and state net operating loss carry forwards at June 30, 2018. 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, 2018, we have a valuation allowance of $25.0 million as a result of management’s assessment of the realizability of federal and state deferred tax assets.

Internal Revenue Code ("IRC") Section 382 addresses corporate shareholder changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change as defined under the IRC. The Company experienced an ownership change within the meaning of IRC Section 382 during the third quarter of 2017 that will subject a portion of the Company’s net operating loss carryforwards and other tax attributes to an IRC Section 382 limitation in future periods.

The Internal Revenue Service has completed its examination of the 2013 federal partnership income tax return for JEH with no changes.

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 TRA liability is recorded based upon the projected tax savings at the time of an exchange. As a result of the Tax Reform Legislation, the amount of the TRA liability was remeasured to reflect the reduction of the federal corporate tax rate from 35% to 21% during the year ended December 31, 2017.

The actual amount and timing of payments to be made under the TRA will depend upon a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers, and the portion of the Company’s payments under the TRA constituting imputed interest. As of June 30, 2018 and December 31, 2017, the Company had a gross TRA liability of $70.5 million and $69.9 million, respectively. As a result of the valuation allowance recorded against the Company’s deferred tax assets associated with prior exchanges, the TRA liability was reduced, as the payment of the TRA liability is dependent on the realizability of the associated deferred tax assets. As of June 30, 2018 and December 31, 2017, the amount of the TRA liability was reduced by $20.0 million and $8.7 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, 2018 and December 31, 2017, the Company had recorded a net TRA liability of $50.5 million and $61.2 million, respectively, for the estimated payments that will be made to the Class B shareholders who have exchanged shares, after adjusting for the TRA liability reduction, along with corresponding deferred tax assets, net of valuation allowances, of $61.8 million and $72.3 million, respectively, as a result of the increase in tax basis from such shares exchanged by current and former Class B shareholders.

The Company made a payment of $1.6 million of the TRA liability with respect to cash savings that the Company realized on its 2016 tax return as a result of tax attributes arising from prior exchanges during the first quarter of 2018. The Company does not anticipate it will realize cash savings on its 2017 tax return as a result of

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tax attributes arising from prior exchanges, and therefore does not anticipate a payment under the TRA for the 2017 tax year.

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.

JEH does not project to generate taxable income for the 2018 tax year and did not generate taxable income for the 2017 tax year and therefore did not make quarterly tax distributions to its unitholders during the six months ended June 30, 2018 or during 2017 with respect to the 2018 or 2017 tax years.

A Special Committee of the Board 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 first quarter of 2017 of $1.7 million to its unitholders (including the Company) towards its total 2016 projected tax distribution obligation. Distributions during 2017 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.

12.      Stockholders’ and Mezzanine equity

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

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

Equity Distribution Agreement

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

The Company used the net proceeds from sales under the Equity Distribution Agreement for general corporate purposes. At June 30, 2018, approximately $62.2 million in aggregate offering proceeds remained available to be issued and sold under the Equity Distribution Agreement.

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Mezzanine equity

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 Board, 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.

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

Each share of Series A preferred stock has a liquidation preference of $50.00 per share and is convertible, at the holder’s option at any time, into approximately 17.0683 shares of Class A common stock after adjusting the conversion ratio for the effects of the Special Stock Dividend, as defined in Note 12, “Stockholders’ and Mezzanine equity”, (which is equivalent to a conversion price of approximately $2.93 per share after adjusting for the effects of the Special Stock Dividend), subject to specified further adjustments and limitations as set forth in the certificate of designations for the Series A preferred stock. Based on the adjusted conversion rate and the full exercise of the Preferred Stock Underwriters’ over-allotment option, approximately 31.4 million shares of Class A common stock would be issuable upon conversion of all the Series A preferred stock.

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

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

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

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

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A summary of the Company’s Mezzanine equity for the six months ended June 30, 2018 is as follows:

(in thousands of dollars)
Mezzanine equity at December 31, 2017	$	89,539
Dividends on preferred stock, net		1,837
Accretion on preferred stock		254
Change in estimate due to settlements		(96)
Mezzanine equity at June 30, 2018	$	91,534

Preferred Stock Dividends

On January 19, 2017, the Board 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 Board 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 common stock, with the cash component equal to $0.83 per share and the stock component equal to $0.17 per share. The price per share of the Class A common stock used to determine the number of shares issued was equal to 95% of the average volume-weighted average price per share for each day during the five-consecutive day trading period ending immediately prior to the payment date. This dividend was for the period beginning on the last payment date of February 15, 2017 through May 14, 2017 to shareholders of record as of May 1, 2017.

On July 13, 2017, the Board declared a quarterly dividend per share equal to 8.0% based on the liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock. On August 15, 2017, the dividend was paid entirely in shares of Class A common stock. The price per share of the Class A common stock used to determine the number of shares issued was equal to 95% of the average volume-weighted average price per share for each day during the 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 May 15, 2017 through August 14, 2017 to shareholders of record as of August 1, 2017.

On October 9, 2017, the Board 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 November 15, 2017, the dividend was paid entirely in shares of Class A common stock. The price per share of the Class A common stock used to determine the number of shares issued was equal to 95% of the average volume-weighted average price per share for each day during the 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 August 15, 2017 through November 14, 2017 to shareholders of record as of November 1, 2017.

On January 11, 2018, the Board 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 February 15, 2018, the dividend was paid entirely in shares of Class A common stock. The price per share of the Class A common stock used to determine the number of shares issued was equal to 95% of the average volume-weighted average price per share for each day during the 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 November 15, 2017 through February 14, 2018 to shareholders of record as of February 1, 2018.

On April 17, 2018, the Board declared a contingent 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. However, the contingently declared payment was not ultimately paid as the Company was prohibited from paying cash dividends on the Series A preferred stock under the terms of its indebtedness. In order for the Company to pay the dividend in full in shares of Class A common stock, the average of the daily volume weighted average price per share of Class A Common Stock for each day during the five consecutive day trading period ending on, May 14, 2018 (the “Dividend Valuation Price”), was required to be at or above $0.76 (the “Floor Price”). The Dividend Valuation Price did not meet the Floor Price. The right for holders of Series A

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preferred stock to receive this dividend has been accrued. As of June 30, 2018, the Company had $1.8 million of dividends in arrears on the Series A preferred stock, which related solely to the scheduled May 15, 2018 dividend that was not paid.

On July 17, 2018, the Board declared a contingent 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. See Note 16 “Subsequent Events,” in the Notes to Consolidated Financial Statements for further discussion.

Special Stock Dividend

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

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

13.      Earnings per Share

Basic earnings per share (“EPS”) is computed by dividing net income (loss) attributable to controlling interests by the weighted average number of shares of Class A common stock outstanding during the period. Shares of Class B common stock are not included in the calculation of earnings per share because they are not participating securities and have no economic interest in the Company. Diluted earnings per share takes into account the potential dilutive effect of shares that could be issued by the Company in conjunction with the Series A preferred stock and from stock awards that have been granted to directors and employees. Awards of non-vested shares are considered outstanding as of the respective grant dates for purposes of computing diluted EPS even though the award is contingent upon vesting. For the three and six months ended June 30, 2018, 988,015 restricted stock units, 286,203 performance share units, and 31,371,450 shares from the convertible Series A preferred stock, were excluded from the calculation as they would have had an anti-dilutive effect. For the three and six months ended June 30, 2017, 2,958,400 restricted stock units, 1,442,150 performance share units, and 31,405,672 shares from the convertible Series 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 periods presented:

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands, except per share data)	2018		2017		2018		2017
Income (numerator):
Net income (loss) attributable to controlling interests	$	(41,515)	$	(82,216)	$	(66,876)	$	(83,603)
Less: Dividends and accretion on preferred stock		(1,963)		(1,966)		(3,931)		(3,993)
Net income (loss) attributable to common shareholder	$	(43,478)	$	(84,182)	$	(70,807)	$	(87,596)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock - basic		93,429		65,681		92,253		63,948
Weighted-average number of shares of Class A common stock - diluted		93,429		65,681		92,253		63,948
Earnings (loss) per share:
Basic - Net income (loss) attributable to common shareholders	$	(0.47)	$	(1.28)	$	(0.77)	$	(1.37)
Diluted - Net income (loss) attributable to common shareholders	$	(0.47)	$	(1.28)	$	(0.77)	$	(1.37)

14.      Related Parties

Related Party Transactions

Transactions with Our Executive Officers, Directors and 5% Stockholders

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

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

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

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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 $0.4 million and $0.8 million of the deferred revenue balance during the three and six months ended June 30, 2018, respectively, and $0.5 million and $0.9 million of the deferred revenue balance during the three and six months ended June 30, 2017, respectively. 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 Chairman of the Board 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 and Robert Brooks. 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 and Mike McConnell. As of June 30, 2018, equity interests in Monarch of $0.3 million are included in Other assets on the Company’s Consolidated Balance Sheet. During the three and six months ended June 30, 2018, equity interests of $0.0 million and $0.1 million, respectively, were distributed to management under the incentive plan. The Company recognized expense of $0.1 million and $0.1 million during the three and six months ended June 30, 2018, respectively, in connection with the incentive plan.

In September 2014, the Company signed a 10-year oil gathering and transportation agreement with Monarch Oil Pipeline LLC, pursuant to which Monarch Oil Pipeline LLC built, at its expense, a new oil gathering system and connected the gathering system to dedicated Company leases in Texas. At the time the Company entered into the agreement, Metalmark Capital owned the majority of the outstanding equity interests of Monarch Oil Pipeline LLC and/or its parent. The system began service during the fourth quarter of 2015 and provides connectivity to both a regional refinery market as well as the Cushing market hub. The Company incurred gathering fees, which were paid to Monarch Oil Pipeline LLC, of $0.5 million and $1.0 million for the three and six months ended June 30, 2018, respectively, associated with the approximately 0.2 MMBoe and 0.5 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 reviewed and approved the terms of the agreement with Monarch Oil Pipeline LLC.

Issuance of Class A Shares to JVL

In connection with the August 2016 issuance of Class A common stock pursuant to an underwritten public offering as described in Note 12, “Stockholders’ and Mezzanine equity—Offering of Class A Common Stock,” affiliates of JVL Advisors, L.L.C. (“JVL”), who then owned more than 5% of a class of voting securities of the Company, purchased 9,025,270 shares of Class A common stock, prior to adjustment for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 12, “Stockholders’ and Mezzanine equity”, in the offering, for gross proceeds to the Company of $25.0 million, before underwriting discounts and commissions of $1.1 million.

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

· it will not acquire any material assets of the Company;

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

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

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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.

Purchases of Senior Secured First Lien Notes by Q Investments

On February 14, 2018, Jones Energy Holdings, LLC and Jones Energy Finance Corp. issued $450.0 million 9.25% senior secured first lien notes due 2023 (the “2023 First Lien Notes”) in an offering exempt from registration under the Securities Act of 1933, as amended, at an offering price equal to 97.526% of par. One or more affiliates of Q Investments, an affiliate of one of our principal stockholders and an affiliate of the employer of Scott McCarty, one of our directors, purchased an aggregate of $45.0 million of the 2023 First Lien Notes at the issue price.

Letter Agreement with Q Investments

On February 5, 2018, in connection with the appointment of Scott McCarty to the Board, an affiliate of Q Investments delivered an Acknowledgement and Stipulation pursuant to which Q Investments and its affiliates agreed not to (i) effect, seek or propose (whether publicly or otherwise) to effect or participate in any solicitation of proxies or consents to vote any securities of the Company or any of its subsidiaries, including soliciting consents or taking other action with respect to calling of a special meeting of the stockholders of the Company or any of its subsidiaries or engaging in a withhold vote campaign and (ii) otherwise act, alone or in concert with others, to seek representation on the Board or any governing body of a subsidiary of the Company. The obligations set forth remained in effect until May 23, 2018, the day following the Annual Meeting.

15.      Commitments and Contingencies

Litigation

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

16.      Subsequent Events

Contingent Preferred Stock Dividend Declared

On July 17, 2018, the Company’s Board declared a contingent quarterly dividend per share equal to 8.0% on an annualized basis based on the liquidation preference of $50.00 per share, or $1.00 per share, on the Series A preferred stock.  If paid, the dividend will be paid using the Company’s Class A common stock.  The price per share of the Class A common stock used to determine the number of shares to be issued (the “Dividend Valuation Price”) will be 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 contingent dividend is for the period beginning on the last scheduled payment date of May 15, 2018 through August 14, 2018 and, subject to the contingency described below, will be payable on August 15, 2018 to shareholders of record as of August 1, 2018. In order for the Company to pay the dividend in full in shares of Class A common stock in accordance with the terms of the Series A preferred stock, the Dividend Valuation Price must be at or above $0.76, as specified in the Certificate of Designations for the Series A preferred stock (the “Floor Price”). If the Dividend Valuation Price is below the Floor Price, the Series A preferred stock dividend payable on August 15, 2018 will not be paid by the Company and the right to receive those dividends will accrue for holders of Series A preferred stock. Future Preferred Stock dividend payments will be evaluated on a quarterly basis.

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Appointment of Chief Executive Officer

On July 20, 2018, the Company, announced the appointment of Carl F. Giesler, Jr. as Chief Executive Officer of the Company, effective July 23, 2018. Prior to joining the Company, Mr. Giesler, age 46, served since September 2014 as the Chief Executive Officer and a Director of Glacier Oil & Gas Corp (“Glacier”) and its predecessor companies. Immediately prior to joining Glacier, Mr. Giesler served as a Managing Director with Harbinger Group Inc. where he led its oil & gas investment efforts since October 2011. Prior to joining Harbinger Group Inc., Mr. Giesler served in various oil & gas principal investing, financial and other roles with Harbinger Capital Partners, AIG FP, Morgan Stanley and Bain & Company. In addition to serving as a Director of Glacier and its predecessor companies, Mr. Giesler has also served on the boards of Compass Production Partners, LP (private) and North American Energy Partners, Inc. (public). Mr. Giesler received his Bachelor of Arts from the University of Virginia and his Juris Doctorate from Harvard Law School. He is also a CFA Charterholder.

On July 12, 2018, Jones Energy, LLC, a wholly owned subsidiary of the Company, entered into an Employment Agreement (the “Agreement”) with Mr. Giesler, effective July 23, 2018 (the “Effective Date”), and unless terminated earlier in accordance with its terms, the Agreement will continue for an initial term of two years. In addition, on each anniversary of the Effective Date following the initial term, unless the Agreement has been terminated, the term of the Agreement will automatically be extended for an additional year unless either party provides written notice of non-renewal at least 90 days prior to such anniversary.

Prior to the Effective Date, Jeff Tanner served as the Interim Chief Executive Officer and the Chief Operating Officer of the Company. Upon the effectiveness of Mr. Giesler’s appointment as Chief Executive Officer, Mr. Tanner will cease to serve as the Interim Chief Executive Officer of the Company but will continue to serve as the Chief Operating Officer of the Company.

Changes to the Board of Directors

On July 20, 2018, the members of the Board of the Company voted unanimously to increase the size of the Board from seven members to eight members and, based on the selection made by the requisite holders pursuant to the Amended and Restated Registration Rights and Stockholders Agreement, dated as of May 2, 2017, appointed Stephen Jones to fill the vacancy created by the increased size of the Board and in anticipation of Mike S. McConnell’s resignation (as discussed below). Mr. Jones is the brother of Jonny Jones, the Chairman of the Board and the former Chief Executive Officer of the Company.

Also on July 20, 2018, Mr. McConnell, a member of the Board, notified the Company of his resignation from the Board, effective July 23, 2018 immediately following the effectiveness of Mr. Jones’ appointment to the Board. Mr. McConnell’s resignation from the Board did not result from any disagreement with the Company.

17.      Subsidiary Guarantors

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

The 2023 First Lien Notes are guaranteed on a senior secured 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 Each subsidiary guarantor is 100% owned by JEH, and all guarantees are full and unconditional, subject to customary exceptions pursuant to the indenture governing our 2023 First Lien Notes, as discussed below, and joint and several with all other subsidiary guarantees and the parent guarantee thereunder.

Guarantees of the 2022 Notes, 2023 Notes and 2023 First Lien 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) (in the case of

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the 2022 Notes and the 2023 Notes) 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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Jones Energy, Inc.

Condensed Consolidating Balance Sheet (Unaudited)

June 30, 2018

					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Assets
Current assets
Cash and cash equivalents	$	3,591	$	135,069	$	9,390	$	20	$	—	$	148,070
Accounts receivable, net
Oil and gas sales		—		—		39,990		—		—		39,990
Joint interest owners		—		—		34,789		—		—		34,789
Other		—		600		567		—		—		1,167
Commodity derivative assets		—		723		—		—		—		723
Other current assets		1,871		599		4,600		—		—		7,070
Intercompany receivable		399,703		1,184,425		—		—		(1,584,128)		—
Total current assets		405,165		1,321,416		89,336		20		(1,584,128)		231,809
Oil and gas properties, net, under the successful efforts method		—		—		1,620,083		—		—		1,620,083
Other property, plant and equipment, net		—		—		1,761		482		—		2,243
Commodity derivative assets		—		1,371		—		—		—		1,371
Other assets		—		309		684		—		—		993
Investment in subsidiaries		149,284		101,024		—		—		(250,308)		—
Total assets	$	554,449	$	1,424,120	$	1,711,864	$	502	$	(1,834,436)	$	1,856,499
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	—	$	544	$	43,179	$	2	$	—	$	43,725
Oil and gas sales payable		—		—		39,930		—		—		39,930
Accrued liabilities		—		30,879		15,320		—		—		46,199
Commodity derivative liabilities		—		46,686		—		—		—		46,686
Other current liabilities		—		1,723		2,140		—		—		3,863
Intercompany payable		—		—		1,580,906		3,222		(1,584,128)		—
Total current liabilities		—		79,832		1,681,475		3,224		(1,584,128)		180,403
Long-term debt		—		978,727		—		—		—		978,727
Deferred revenue		—		4,675		—		—		—		4,675
Commodity derivative liabilities		—		14,949		—		—		—		14,949
Asset retirement obligations		—		—		20,146		—		—		20,146
Liability under tax receivable agreement		50,529		—		—		—		—		50,529
Other liabilities		—		28		846		—		—		874
Deferred tax liabilities		8,480		1,252		—		—		—		9,732
Total liabilities		59,009		1,079,463		1,702,467		3,224		(1,584,128)		1,260,035
Mezzanine equity
Series A preferred stock, $0.001 par value; 1,837,995 shares issued and outstanding at June 30, 2018		91,534		—		—		—		—		91,534
Stockholders’/ members' equity (deficit)
Members' equity		—		344,657		9,397		(2,722)		(351,332)		—
Class A common stock, $0.001 par value; 93,799,481 shares issued and 93,776,879 shares outstanding at June 30, 2018		94		—		—		—		—		94
Class B common stock, $0.001 par value; 9,074,330 shares issued and outstanding at June 30, 2018		9		—		—		—		—		9
Treasury stock, at cost: 22,602 shares at June 30, 2018		(358)		—		—		—		—		(358)
Additional paid-in-capital		611,242		—		—		—		—		611,242
Retained earnings (deficit)		(207,081)		—		—		—		—		(207,081)
Stockholders' equity (deficit)		403,906		344,657		9,397		(2,722)		(351,332)		403,906
Non-controlling interest		—		—		—		—		101,024		101,024
Total stockholders’ equity		403,906		344,657		9,397		(2,722)		(250,308)		504,930
Total liabilities and stockholders’ equity	$	554,449	$	1,424,120	$	1,711,864	$	502	$	(1,834,436)	$	1,856,499

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Jones Energy, Inc.

Condensed Consolidating Balance Sheet

December 31, 2017

					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Assets
Current assets
Cash	$	5,248	$	1,180	$	13,024	$	20	$	—	$	19,472
Accounts receivable, net
Oil and gas sales		—		—		34,492		—		—		34,492
Joint interest owners		—		—		31,651		—		—		31,651
Other		—		—		1,236		—		—		1,236
Commodity derivative assets		—		3,474		—		—		—		3,474
Other current assets		1,866		358		12,152		—		—		14,376
Intercompany receivable		383,849		1,146,647		—		—		(1,530,496)		—
Total current assets		390,963		1,151,659		92,555		20		(1,530,496)		104,701
Oil and gas properties, net, under the successful efforts method		—		—		1,597,040		—		—		1,597,040
Other property, plant and equipment, net		—		—		2,192		527		—		2,719
Commodity derivative assets		—		172		—		—		—		172
Other assets		—		4,427		1,004		—		—		5,431
Investment in subsidiaries		242,617		116,349		—		—		(358,966)		—
Total assets	$	633,580	$	1,272,607	$	1,692,791	$	547	$	(1,889,462)	$	1,710,063
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	138	$	247	$	72,278	$	—	$	—	$	72,663
Oil and gas sales payable		—		—		31,462		—		—		31,462
Accrued liabilities		62		11,363		10,172		7		—		21,604
Commodity derivative liabilities		—		36,709		—		—		—		36,709
Other current liabilities		1,606		1,723		720		—		—		4,049
Intercompany payable		—		—		1,527,418		3,078		(1,530,496)		—
Total current liabilities		1,806		50,042		1,642,050		3,085		(1,530,496)		166,487
Long-term debt		—		759,316		—		—		—		759,316
Deferred revenue		—		5,457		—		—		—		5,457
Commodity derivative liabilities		—		8,788		—		—		—		8,788
Asset retirement obligations		—		—		19,652		—		—		19,652
Liability under tax receivable agreement		59,596		—		—		—		—		59,596
Other liabilities		—		68		743		—		—		811
Deferred tax liabilities		12,852		1,429		—		—		—		14,281
Total liabilities		74,254		825,100		1,662,445		3,085		(1,530,496)		1,034,388
Mezzanine equity
Series A preferred stock, $0.001 par value; 1,839,995 shares issued and outstanding at December 31, 2017		89,539		—		—		—		—		89,539
Stockholders’/ members' equity (deficit)
Members' equity		—		447,507		30,346		(2,538)		(475,315)		—
Class A common stock, $0.001 par value; 90,139,840 shares issued and 90,117,238 shares outstanding at December 31, 2017		90		—		—		—		—		90
Class B common stock, $0.001 par value; 9,627,821 shares issued and outstanding at December 31, 2017		10		—		—		—		—		10
Treasury stock, at cost: 22,602 shares at December 31, 2017		(358)		—		—		—		—		(358)
Additional paid-in-capital		606,319		—		—		—		—		606,319
Retained earnings (deficit)		(136,274)		—		—		—		—		(136,274)
Stockholders' equity (deficit)		469,787		447,507		30,346		(2,538)		(475,315)		469,787
Non-controlling interest		—		—		—		—		116,349		116,349
Total stockholders’ equity		469,787		447,507		30,346		(2,538)		(358,966)		586,136
Total liabilities and stockholders’ equity	$	633,580	$	1,272,607	$	1,692,791	$	547	$	(1,889,462)	$	1,710,063

36

Jones Energy, Inc.

Condensed Consolidating Statement of Operations (Unaudited)

Three Months Ended June 30, 2018

					Guarantor		Non-Guarantor
(inthousands of dollars)	JEI(Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—	$	—	$	64,748	$	—	$	—	$	64,748
Other revenues		—		408		99		—		—		507
Total operating revenues		—		408		64,847		—		—		65,255
Operating costs and expenses
Lease operating		—		—		11,592		—		—		11,592
Production and ad valorem taxes		—		—		3,284		—		—		3,284
Transportation and processing costs		—		—		885		—		—		885
Exploration		—		—		1,528		—		—		1,528
Depletion, depreciation and amortization		—		—		44,706		23		—		44,729
Accretion of ARO liability		—		—		264		—		—		264
General and administrative		9		1,468		6,335		84		—		7,896
Total operating expenses		9		1,468		68,594		107		—		70,178
Operating income (loss)		(9)		(1,060)		(3,747)		(107)		—		(4,923)
Other income (expense)
Interest expense		—		(22,787)		(268)		—		—		(23,055)
Net gain (loss) on commodity derivatives		—		(30,145)		—		—		—		(30,145)
Other income (expense)		5,599		(34)		209		—		—		5,774
Other income (expense), net		5,599		(52,966)		(59)		—		—		(47,426)
Income (loss) before income tax		5,590		(54,026)		(3,806)		(107)		—		(52,349)
Equity interest in income (loss)		(52,564)		(5,375)		—		—		57,939		—
Income tax provision (benefit)		(5,459)		41		—		—		—		(5,418)
Net income (loss)		(41,515)		(59,442)		(3,806)		(107)		57,939		(46,931)
Net income (loss) attributable to non-controlling interests		—		—		—		—		(5,416)		(5,416)
Net income (loss) attributable to controlling interests	$	(41,515)	$	(59,442)	$	(3,806)	$	(107)	$	63,355	$	(41,515)
Dividends and accretion on preferred stock		(1,963)		—		—		—		—		(1,963)
Net income (loss) attributable to common shareholders	$	(43,478)	$	(59,442)	$	(3,806)	$	(107)	$	63,355	$	(43,478)

37

Jones Energy, Inc.

Condensed Consolidating Statement of Operations (Unaudited)

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		—		—		148,016		—		—		148,016
Accretion of ARO liability		—		—		266		—		—		266
General and administrative		—		2,920		5,626		87		—		8,633
Total operating expenses		—		2,920		218,161		110		—		221,191
Operating income (loss)		—		(2,435)		(170,020)		(110)		—		(172,565)
Other income (expense)
Interest expense		—		(12,941)		264		—		—		(12,677)
Net gain (loss) on commodity derivatives		—		21,527		—		—		—		21,527
Other income (expense)		27,580		(24)		(55)		—		—		27,501
Other income (expense), net		27,580		8,562		209		—		—		36,351
Income (loss) before income tax		27,580		6,127		(169,811)		(110)		—		(136,214)
Equity interest in income (loss)		(112,018)		(51,776)		—		—		163,794		—
Income tax provision (benefit)		(2,222)		(14)		—		—		—		(2,236)
Net income (loss)		(82,216)		(45,635)		(169,811)		(110)		163,794		(133,978)
Net income (loss) attributable to non-controlling interests		—		—		—		—		(51,762)		(51,762)
Net income (loss) attributable to controlling interests	$	(82,216)	$	(45,635)	$	(169,811)	$	(110)	$	215,556	$	(82,216)
Dividends and accretion on preferred stock		(1,966)		—		—		—		—		(1,966)
Net income (loss) attributable to common shareholders	$	(84,182)	$	(45,635)	$	(169,811)	$	(110)	$	215,556	$	(84,182)

38

Jones Energy, Inc.

Condensed Consolidating Statement of Operations (Unaudited)

Six Months Ended June 30, 2018

					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—	$	—	$	122,886	$	—	$	—	$	122,886
Other revenues		—		782		(924)		—		—		(142)
Total operating revenues		—		782		121,962		—		—		122,744
Operating costs and expenses
Lease operating		—		—		21,821		—		—		21,821
Production and ad valorem taxes		—		—		6,035		—		—		6,035
Transportation and processing costs		—		—		1,591		—		—		1,591
Exploration		—		—		4,827		—		—		4,827
Depletion, depreciation and amortization		—		—		86,124		46		—		86,170
Accretion of ARO liability		—		—		515		—		—		515
General and administrative		9		4,675		10,644		138		—		15,466
Total operating expenses		9		4,675		131,557		184		—		136,425
Operating income (loss)		(9)		(3,893)		(9,595)		(184)		—		(13,681)
Other income (expense)
Interest expense		—		(44,406)		(511)		—		—		(44,917)
Net gain (loss) on commodity derivatives		—		(39,167)		—		—		—		(39,167)
Other income (expense)		9,081		(59)		4,482		—		—		13,504
Other income (expense), net		9,081		(83,632)		3,971		—		—		(70,580)
Income (loss) before income tax		9,072		(87,525)		(5,624)		(184)		—		(84,261)
Equity interest in income (loss)		(84,198)		(9,135)		—		—		93,333		—
Income tax provision (benefit)		(8,250)		(160)		—		—		—		(8,410)
Net income (loss)		(66,876)		(96,500)		(5,624)		(184)		93,333		(75,851)
Net income (loss) attributable to non-controlling interests		—		—		—		—		(8,975)		(8,975)
Net income (loss) attributable to controlling interests	$	(66,876)	$	(96,500)	$	(5,624)	$	(184)	$	102,308	$	(66,876)
Dividends and accretion on preferred stock		(3,931)		—		—		—		—		(3,931)
Net income (loss) attributable to common shareholders	$	(70,807)	$	(96,500)	$	(5,624)	$	(184)	$	102,308	$	(70,807)

39

Jones Energy, Inc.

Condensed Consolidating Statement of Operations (Unaudited)

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		—		—		148,016		—		—		148,016
Accretion of ARO liability		—		—		467		—		—		467
General and administrative		—		5,913		10,630		131		—		16,674
Total operating expenses		—		5,913		269,842		176		—		275,931
Operating income (loss)		—		(4,971)		(180,925)		(176)		—		(186,072)
Other income (expense)
Interest expense		—		(25,755)		191		—		—		(25,564)
Net gain (loss) on commodity derivatives		—		43,847		—		—		—		43,847
Other income (expense)		28,248		(48)		(119)		—		—		28,081
Other income (expense), net		28,248		18,044		72		—		—		46,364
Income (loss) before income tax		28,248		13,073		(180,853)		(176)		—		(139,708)
Equity interest in income (loss)		(114,072)		(53,884)		—		—		167,956		—
Income tax provision (benefit)		(2,221)		6		—		—		—		(2,215)
Net income (loss)		(83,603)		(40,817)		(180,853)		(176)		167,956		(137,493)
Net income (loss) attributable to non-controlling interests		—		—		—		—		(53,890)		(53,890)
Net income (loss) attributable to controlling interests	$	(83,603)	$	(40,817)	$	(180,853)	$	(176)	$	221,846	$	(83,603)
Dividends and accretion on preferred stock		(3,993)		—		—		—		—		(3,993)
Net income (loss) attributable to common shareholders	$	(87,596)	$	(40,817)	$	(180,853)	$	(176)	$	221,846	$	(87,596)

40

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows (Unaudited)

Six Months Ended June 30, 2018

							Non-
					Guarantor		Guarantor
(in thousands of dollars)	JEI(Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Cash flows from operating activities
Net income (loss)	$	(66,876)	$	(96,500)	$	(5,624)	$	(184)	$	93,333	$	(75,851)
Adjustments to reconcile net income (loss) to net cash provided by operating activities		65,316		40,169		110,327		184		(93,333)		122,663
Net cash (used in) / provided by operations		(1,560)		(56,331)		104,703		—		—		46,812
Cash flows from investing activities
Additions to oil and gas properties		—		—		(114,832)		—		—		(114,832)
Proceeds from sales of assets		—		—		6,566		—		—		6,566
Acquisition of other property, plant and equipment		—		—		(71)		—		—		(71)
Current period settlements of matured derivative contracts		—		(25,655)		—		—		—		(25,655)
Net cash (used in) / provided by investing		—		(25,655)		(108,337)		—		—		(133,992)
Cash flows from financing activities
Proceeds from issuance of long-term debt		—		20,000		—		—		—		20,000
Repayment of long-term debt		—		(231,000)		—		—		—		(231,000)
Proceeds from senior notes		—		438,867		—		—		—		438,867
Payment of debt issuance costs		—		(11,537)		—		—		—		(11,537)
Payment of cash dividends on preferred stock		(97)		—		—		—		—		(97)
Net payments for share based compensation		—		(455)		—		—		—		(455)
Net cash (used in) / provided by financing		(97)		215,875		—		—		—		215,778
Net increase (decrease) in cash and cash equivalents		(1,657)		133,889		(3,634)		—		—		128,598
Cash and cash equivalents
Beginning of period		5,248		1,180		13,024		20		—		19,472
End of period	$	3,591	$	135,069	$	9,390	$	20	$	—	$	148,070

41

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows (Unaudited)

Six Months Ended June 30, 2017

							Non-
					Guarantor		Guarantor
(in thousands of dollars)	JEI(Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Cash flows from operating activities
Net income (loss)	$	(83,603)	$	(40,817)	$	(180,853)	$	(176)	$	167,956	$	(137,493)
Adjustments to reconcile net income (loss) to net cash provided by operating activities		53,633		(7,016)		280,134		176		(167,956)		158,971
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 under long-term debt		—		(72,000)		—		—		—		(72,000)
Payment of 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

42

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and audited consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2017, filed with the Securities and Exchange Commission (the “Commission”) on February 28, 2018, 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, 2018, filed on May 4, 2018 with the 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 Oklahoma and Texas. Our Chairman of the Board, 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 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 there for over 25 years. We have drilled nearly 950 total wells as operator, including over 770 horizontal wells, since our formation. Our operations are focused on horizontal drilling within two distinct areas in Oklahoma and Texas:

· the Eastern Anadarko Basin—targeting the liquids rich Woodford shale and Meramec formations in the Merge area of the STACK/SCOOP plays; 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 have historically been recognized as one of the lowest-cost drilling and completion operators in the Cleveland formation. Our low-cost drilling expertise has applied directly to our newer operations in the Merge, where the Company plans to spend the majority of its 2018 capital budget.

Second Quarter and Year-to-Date 2018 Highlights:

· The Company has proactively initiated discussions with its unsecured noteholders. The aim of these liability management discussions is to achieve increased financial flexibility to optimize the value of Jones Energy’s core Merge and Western Anadarko Basin (“WAB”) assets for the benefit of all stakeholders.

· The Company remains active in its evaluation of strategic alternatives as well as its pursuit of a DrillCo with an exclusive joint development partner in order to accelerate drilling and value creation.

· 2018 Merge wells brought online showing average peak IP30 of 183 Boe/d per 1,000’ of lateral in the Meramec and 120 Boe/d per 1,000’ of lateral in the Woodford (3-stream).

· Net loss for the second quarter of 2018 of $46.9 million, or a net loss of $0.47 per share, non-GAAP adjusted net loss of $28.7 million, or an adjusted net loss of $0.29 per share, and EBITDAX of $29.7 million.

43

Appointment of Chief Executive Officer

On July 20, 2018, the Company, announced the appointment of Carl F. Giesler, Jr. as Chief Executive Officer of the Company, effective July 23, 2018. Prior to joining the Company, Mr. Giesler, age 46, served since September 2014 as the Chief Executive Officer and a Director of Glacier Oil & Gas Corp (“Glacier”) and its predecessor companies. Immediately prior to joining Glacier, Mr. Giesler served as a Managing Director with Harbinger Group Inc. where he led its oil & gas investment efforts since October 2011. Prior to joining Harbinger Group Inc., Mr. Giesler served in various oil & gas principal investing, financial and other roles with Harbinger Capital Partners, AIG FP, Morgan Stanley and Bain & Company. In addition to serving as a Director of Glacier and its predecessor companies, Mr. Giesler has also served on the boards of Compass Production Partners, LP (private) and North American Energy Partners, Inc. (public). Mr. Giesler received his Bachelor of Arts from the University of Virginia and his Juris Doctorate from Harvard Law School. He is also a CFA Charterholder.

On July 12, 2018, Jones Energy, LLC, a wholly owned subsidiary of the Company, entered into an Employment Agreement (the “Agreement”) with Mr. Giesler, effective July 23, 2018 (the “Effective Date”), and unless terminated earlier in accordance with its terms, the Agreement will continue for an initial term of two years. In addition, on each anniversary of the Effective Date following the initial term, unless the Agreement has been terminated, the term of the Agreement will automatically be extended for an additional year unless either party provides written notice of non-renewal at least 90 days prior to such anniversary.

Prior to the Effective Date, Jeff Tanner served as the Chief Operating Officer and Interim Chief Executive Officer of the Company. Upon the effectiveness of Mr. Giesler’s appointment as Chief Executive Officer, Mr. Tanner will cease to serve as the Interim Chief Executive Officer of the Company but will continue to serve as the Chief Operating Officer of the Company.

Changes to the Board of Directors

On July 20, 2018, the members of the Board of the Company voted unanimously to increase the size of the Board from seven members to eight members and, based on the selection made by the requisite holders pursuant to the Amended and Restated Registration Rights and Stockholders Agreement, dated as of May 2, 2017, appointed Stephen Jones to fill the vacancy created by the increased size of the Board and in anticipation of Mike S. McConnell’s resignation (as discussed below). Mr. Jones is the brother of Jonny Jones, the Chairman of the Board and the former Chief Executive Officer of the Company.

Also on July 20, 2018, Mr. McConnell, a member of the Board, notified the Company of his resignation from the Board, effective July 23, 2018 immediately following the effectiveness of Mr. Jones’ appointment to the Board. Mr. McConnell’s resignation from the Board did not result from any disagreement with the Company.

44

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)	2018		2017		Change		2018		2017		Change
Revenues:
Oil	$	41,933	$	23,312	$	18,621	$	78,610	$	41,579	$	37,031
Natural gas		7,045		12,767		(5,722)		15,232		24,194		(8,962)
NGLs		15,770		12,035		3,735		29,044		23,018		6,026
Total oil and gas		64,748		48,114		16,634		122,886		88,791		34,095
Other		507		512		(5)		(142)		1,068		(1,210)
Total operating revenues		65,255		48,626		16,629		122,744		89,859		32,885
Costs and expenses:
Lease operating		11,592		9,425		2,167		21,821		18,231		3,590
Production and ad valorem taxes		3,284		2,790		494		6,035		1,884		4,151
Transportation and processing costs		885		—		885		1,591		—		1,591
Exploration		1,528		6,725		(5,197)		4,827		9,669		(4,842)
Depletion, depreciation and amortization		44,729		45,336		(607)		86,170		80,990		5,180
Impairment of oil and gas properties		—		148,016		(148,016)		—		148,016		(148,016)
Accretion of ARO liability		264		266		(2)		515		467		48
General and administrative		7,896		8,633		(737)		15,466		16,674		(1,208)
Total costs and expenses		70,178		221,191		(151,013)		136,425		275,931		(139,506)
Operating income (loss)		(4,923)		(172,565)		167,642		(13,681)		(186,072)		172,391
Other income (expenses):
Interest expense		(23,055)		(12,677)		(10,378)		(44,917)		(25,564)		(19,353)
Net gain (loss) on commodity derivatives		(30,145)		21,527		(51,672)		(39,167)		43,847		(83,014)
Other income/(expense)		5,774		27,501		(21,727)		13,504		28,081		(14,577)
Total other income (expense)		(47,426)		36,351		(83,777)		(70,580)		46,364		(116,944)
Income (loss) before income tax		(52,349)		(136,214)		83,865		(84,261)		(139,708)		55,447
Income tax provision (benefit)		(5,418)		(2,236)		(3,182)		(8,410)		(2,215)		(6,195)
Net income (loss)		(46,931)		(133,978)		87,047		(75,851)		(137,493)		61,642
Net income (loss) attributable to non-controlling interests		(5,416)		(51,762)		46,346		(8,975)		(53,890)		44,915
Net income (loss) attributable to controlling interests	$	(41,515)	$	(82,216)	$	40,701	$	(66,876)	$	(83,603)	$	16,727
Dividends and accretion on preferred stock		(1,963)		(1,966)		3		(3,931)		(3,993)		62
Net income (loss) attributable to common shareholders	$	(43,478)	$	(84,182)	$	40,704	$	(70,807)	$	(87,596)	$	16,789
Net production volumes:
Oil (MBbls)		638		525		113		1,239		910		329
Natural gas (MMcf)		5,761		5,836		(75)		10,668		10,491		177
NGLs (MBbls)		674		668		6		1,253		1,206		47
Total (MBoe)		2,272		2,166		107		4,270		3,865		406
Average net (Boe/d)		24,967		23,802		1,165		23,591		21,354		2,237
Average sales price, unhedged:
Oil (per Bbl), unhedged	$	65.73	$	44.40	$	21.33	$	63.45	$	45.69	$	17.76
Natural gas (per Mcf), unhedged		1.22		2.19		(0.97)		1.43		2.31		(0.88)
NGLs (per Bbl), unhedged		23.40		18.02		5.38		23.18		19.09		4.09
Combined (per Boe), unhedged		28.50		22.21		6.29		28.78		22.97		5.81
Average sales price, hedged:
Oil (per Bbl), hedged	$	49.77	$	61.30	$	(11.53)	$	50.55	$	82.47	$	(31.92)
Natural gas (per Mcf), hedged		1.45		4.04		(2.59)		1.62		3.84		(2.22)
NGLs (per Bbl), hedged		17.93		15.36		2.57		17.15		14.65		2.50
Combined (per Boe), hedged		22.98		30.49		(7.51)		23.75		34.42		(10.67)
Average costs (per BOE):
Lease operating	$	5.10	$	4.35	$	0.75	$	5.11	$	4.72	$	0.39
Production and ad valorem taxes		1.45		1.29		0.16		1.41		0.49		0.92
Depletion, depreciation and amortization		19.69		20.93		(1.24)		20.18		20.95		(0.77)
General and administrative		3.48		3.99		(0.51)		3.62		4.31		(0.69)

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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)	2018		2017		2018		2017
Reconciliation of net income to EBITDAX
Net income (loss)	$	(46,931)	$	(133,978)	$	(75,851)	$	(137,493)
Interest expense		23,055		12,677		44,917		25,564
Exploration expense		1,528		6,725		4,827		9,669
Income taxes		(5,418)		(2,236)		(8,410)		(2,215)
Depreciation and depletion		44,729		45,336		86,170		80,990
Impairment of oil and natural gas properties		—		148,016		—		148,016
Accretion of ARO liability		264		266		515		467
Change in TRA liability		(5,599)		(27,598)		(9,081)		(28,266)
Other non-cash charges		25		1,266		376		1,307
Stock compensation expense		(356)		1,764		974		3,736
Deferred and other non-cash compensation expense		7		44		84		180
Net (gain) loss on derivative contracts		30,145		(21,527)		39,167		(43,847)
Current period settlements of matured derivative contracts		(12,537)		17,921		(21,477)		44,253
Amortization of deferred revenue		(408)		(484)		(782)		(942)
(Gain) loss on sale of assets		1,179		55		(1,945)		119
Financing expenses and other loan fees		34		24		59		48
EBITDAX	$	29,717	$	48,271	$	59,543	$	101,586

46

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

47

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)	2018			2017			2018			2017
Net income (loss)	$	(46,931)		$	(133,978)		$	(75,851)		$	(137,493)
Net (gain) loss on derivative contracts		30,145			(21,527)			39,167			(43,847)
Current period settlements of matured derivative contracts		(12,537)			17,921			(21,477)			44,253
Impairment of oil and gas properties		—			148,016			—			148,016
Exploration		1,528			6,725			4,827			9,669
Non-cash stock compensation expense		(356)			1,764			974			3,736
Deferred and other non-cash compensation expense		7			44			84			180
Financing expenses		638			—			3,885			—
Tax impact of adjusting items (1)		(3,645)			(31,247)			(5,509)			(33,123)
Change in TRA liability		(5,599)			(27,598)			(9,081)			(28,266)
Change in valuation allowance		8,067			44,577			12,163			45,489
Adjusted net income (loss)		(28,683)			4,697			(50,818)			8,614
Adjusted net income (loss) attributable to non-controlling interests		(3,659)			(3,991)			(6,446)			(3,018)
Adjusted net income (loss) attributable to controlling interests		(25,024)			8,688			(44,372)			11,632
Dividends and accretion on preferred stock		(1,963)			(1,966)			(3,931)			(3,993)
Adjusted net income (loss) attributable to common shareholders	$	(26,987)		$	6,722		$	(48,303)		$	7,639
Earnings per share (basic and diluted):	$	(0.47)		$	(1.28)		$	(0.77)		$	(1.37)
Net (gain) loss on derivative contracts		0.29			(0.23)			0.39			(0.46)
Current period settlements of matured derivative contracts		(0.12)			0.19			(0.21)			0.46
Impairment of oil and gas properties		—			1.55			—			1.60
Exploration		0.01			0.07			0.05			0.10
Non-cash stock compensation expense		—			0.02			0.01			0.04
Deferred and other non-cash compensation expense		—			—			—			—
Financing expenses		0.01			—			0.04			—
Tax impact of adjusting items (1)		(0.04)			(0.48)			(0.06)			(0.53)
Change in TRA liability		(0.06)			(0.42)			(0.10)			(0.44)
Change in valuation allowance		0.09			0.68			0.13			0.72
Adjusted earnings per share (basic and diluted)	$	(0.29)		$	0.10		$	(0.52)		$	0.12
Weighted average Class A shares outstanding:
Basic		93,429			65,681			92,253			63,948
Diluted		93,429			65,681			92,253			63,948
Effective tax rate on net income (loss) attributable to controlling interests		21.3	%		40.3	%		21.3	%		40.0	%

(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.

48

Results of Operations - Three months ended June 30, 2018 as compared to the three months ended June 30, 2017

Operating revenues

Oil and gas sales. Oil and gas sales increased $16.6 million, or 34.5%, to $64.7 million for the three months ended June 30, 2018, as compared to $48.1 million for the three months ended June 30, 2017. The increase was attributable to the increase in production volumes ($7.4 million) and the increase in commodity prices ($9.2 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 $44.40 per Bbl for the three months ended June 30, 2017 to $65.73 per Bbl for the three months ended June 30, 2018, or 48.0%. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $2.19 per Mcf for the three months ended June 30, 2017 to $1.22 per Mcf for the three months ended June 30, 2018, or 44.3%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increased from $18.02 per Bbl for the three months ended June 30, 2017 to $23.40 per Bbl for the three months ended June 30, 2018, or 29.9%. Average daily production increased 4.9% to 24,967 Boe per day for the three months ended June 30, 2018 as compared to 23,802 Boe per day for the three months ended June 30, 2017.

Costs and expenses

Lease operating. Lease operating expenses increased by $2.2 million, or 23.4%, to $11.6 million for the three months ended June 30, 2018, as compared to $9.4 million for the three months ended June 30, 2017. The increase in lease operating expenses was primarily attributable to the increase in number of producing wells, specifically as a result of our continued drilling program in the Merge. On a per unit basis, lease operating expenses increased $0.75 per Boe, or 17.2%, from $4.35 per Boe in the three months ended June 30, 2017 to $5.10 per Boe in the three months ended June 30, 2018.

Production and ad valorem taxes. Production and ad valorem taxes increased by $0.5 million to $3.3 million for the three months ended June 30, 2018, as compared to $2.8 million for the three months ended June 30, 2017. Production taxes increased $0.1 million, from $2.3 million for the three months ended June 30, 2017 to $2.4 million for the three months ended June 30, 2018. 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. Additionally, estimated ad valorem taxes increased $0.4 million, from $0.5 million for the three months ended June 30, 2017 to $0.9 million for the three months ended June 30, 2018. The average effective rate excluding the impact of ad valorem taxes decreased from 4.8% for the three months ended June 30, 2017 to 3.7% for the three months ended June 30, 2018.

Exploration. Exploration expense decreased from $6.7 million for the three months ended June 30, 2017 to $1.5 million for the three months ended June 30, 2018. The Company recognized charges for lease abandonment of $0.3 million during the three months ended June 30, 2018 as compared to $5.2 million during the three months ended June 30, 2017, relating to certain leases that the Company decided during the respective three-month period not to develop and to let lapse. Spending during the three months ended June 30, 2018 primarily related to geological data and seismic processing associated with unproved acreage, focused mainly in the Eastern Anadarko Basin. No exploratory wells resulted in exploration expense during the three months ended June 30 of either year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased by $0.6 million, or 1.3%, to $44.7 million for the three months ended June 30, 2018, as compared to $45.3 million for the three months ended June 30, 2017. The decrease was primarily the result of the Arkoma Divestiture offset by increased capital spending related to our continued drilling program in the Merge area. On a per unit basis, depletion expense decreased $1.24 per Boe or 5.9% from $20.93 per Boe for the three months ended June 30, 2017 to $19.69 per Boe for the three months ended June 30, 2018.

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 sales price, an impairment charge of $148.0 million was recognized during the three months ended June 30, 2017. No impairment charges were recognized during the three months ended June 30, 2018.

49

General and administrative. General and administrative expenses decreased by $0.7 million, or 8.1%, to $7.9 million for the three months ended June 30, 2018, as compared to $8.6 million for the three months ended June 30, 2017. Non-cash compensation expense decreased $2.2 million, from an expense position of $1.8 million for the three months ended June 30, 2017 to an income position of $0.4 million for the three months ended June 30, 2018. This decrease was offset by additional compensation expense of $1.7 million in the three months ended June 30, 2018 associated with the acceleration of certain unvested equity compensation awards made to certain members of our senior management team who departed on April 17, 2018. On a per unit basis, general and administrative expenses, excluding all non-cash items, increased from $2.57 per Boe for the three months ended June 30, 2017 to $3.51 per Boe for the three months ended June 30, 2018.

Interest expense. Interest expense increased by $10.4 million, or 81.9%, to $23.1 million for the three months ended June 30, 2018, as compared to $12.7 million for the three months ended June 30, 2017. The increase was driven by the issuance of the 2023 First Lien Notes on February 14, 2018. See Note 5, “Long-Term Debt,” for further details. During the three months ended June 30, 2018, borrowings under the Revolver, the 2022 Notes, the 2023 Notes, and the 2023 First Lien Notes bore interest at a weighted average rate of 4.75%, 6.75%, 9.25% and 9.25%, respectively. Average outstanding balances for the three months ended June 30, 2018 were $24.2 million, $409.1 million, $150.0 million, and $450.0 million under the Revolver, the 2022 Notes, the 2023 Notes and the 2023 First Lien Notes, respectively.

Net gain (loss) on commodity derivatives. The net gain (loss) on commodity derivatives was a net loss of $30.1 million for the three months ended June 30, 2018, as compared to a net gain of $21.5 million for the three months ended June 30, 2017. The loss was primarily driven by a higher average crude oil price and natural gas prices ($68.07 per barrel and $2.85 per Mcf, respectively) for the three months ended June 30, 2018, as compared to the crude oil and natural gas prices as of March 31, 2018 ($64.87 per barrel and $2.81 per Mcf, respectively).

Other income (expense). Other income (expense) for the three months ended June 30, 2018 was net income of $5.8 million, as compared to net income of $27.5 million for the three months ended June 30, 2017. Other income (expense) during the three months ended June 30, 2018 primarily related to an increase in the TRA valuation allowance which resulted in income of $5.6 million.

Income taxes. The provision for federal and state income taxes for the three months ended June 30, 2018 was a benefit of $5.4 million resulting in an 10.4% effective tax rate as a percentage of our pre-tax book income for the quarter as compared to a benefit of $2.2 million resulting in a 1.6% effective tax rate as a percentage of our pre-tax book income for the three months ended June 30, 2017. 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. For the three months ended June 30, 2018, the Company recorded its provision using the 21% federal tax rate enacted by the Tax Reform Legislation. The effective tax rate increase was primarily due to the magnitude of the valuation allowance recorded against the Company’s deferred tax assets, which partially offset the tax benefit generated the three months ended June 30, 2018 and 2017. See Note 11, “Income Taxes,” for further details.

Results of Operations - Six months ended June 30, 2018 as compared to the six months ended June 30, 2017

Operating revenues

Oil and gas sales. Oil and gas sales increased $34.1 million, or 38.4%, to $122.9 million for the six months ended June 30, 2018, as compared to $88.8 million for the six months ended June 30, 2017. The increase was attributable to the increase in production volumes ($22.2 million) and the increase in commodity prices ($11.9 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 $45.69 per Bbl for the six months ended June 30, 2017 to $63.45 per Bbl for the six months ended June 30, 2018, or 38.9%. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $2.31 per Mcf for the six months ended June 30, 2017 to $1.43 per Mcf for the six months ended June 30, 2018, or 38.1%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increased from $19.09 per Bbl for the six months ended June 30, 2017 to $23.18 per Bbl for the six months ended June 30, 2018, or 21.4%. Average daily production increased 10.5% to 23,591 Boe per day for the six months ended June 30, 2018 as compared to 21,354 Boe per day for the six months ended June 30, 2017.

50

Costs and expenses

Lease operating. Lease operating expenses increased by $3.6 million, or 19.8%, to $21.8 million for the six months ended June 30, 2018, as compared to $18.2 million for the six months ended June 30, 2018. The increase in lease operating expenses was primarily attributable to the increase in number of producing wells, specifically as a result of our continued drilling program in the Merge. On a per unit basis, lease operating expenses increased $0.39 per Boe, or 8.3%, from $4.72 per Boe in the six months ended June 30, 2017 to $5.11 per Boe in the six months ended June 30, 2018.

Production and ad valorem taxes. Production and ad valorem taxes increased by $4.1 million to $6.0 million for the six months ended June 30, 2018, as compared to $1.9 million for the six months ended June 30, 2017. During 2017, the Company's applications for High-Cost Gas Incentive refunds and Low-Producing Gas Incentive refunds in Texas were approved for qualified wells on which taxes were initially paid between October 2012 and April 2017. The Company received net production tax refunds of $3.3 million during the six months ended June 30, 2017. During the six months ended June 30, 2018, the Company received net production tax refunds of $0.1 million for High-Cost Gas Incentive refunds and Low-Producing Gas Incentive refunds in Texas for qualified wells on which taxes were initially paid between November 2014 and June 2017. These refunds were recorded as a reduction in Production and ad valorem taxes on the Company’s Consolidated Statement of Operations. Production taxes, excluding the impact of these refunds, increased from $4.1 million for the six months ended June 30, 2017 to $4.7 million for the six months ended June 30, 2018. 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. Additionally, estimated ad valorem taxes increased $0.4 million, from $1.0 million for the six months ended June 30, 2017 to $1.4 million for the six months ended June 30, 2018. The average effective rate excluding the impact of ad valorem taxes increased from 1.0% for the six months ended June 30, 2017 to 3.7% for the six months ended June 30, 2018.

Exploration. Exploration expense decreased from $9.7 million for the six months ended June 30, 2017 to $4.8 million for the six months ended June 30, 2018. The Company recognized charges for lease abandonment of $0.9 million during the six months ended June 30, 2018 as compared to $6.9 million during the six months ended June 30, 2017, relating to certain leases that the Company decided during the respective six-month period not to develop and to let lapse. Spending during 2018 primarily related to geological data and seismic processing associated with unproved acreage, focused mainly in the Eastern Anadarko Basin. 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 $5.2 million, or 6.4%, to $86.2 million for the six months ended June 30, 2018, as compared to $81.0 million for the six months ended June 30, 2017. The increase was primarily the result of capital spending related to our continued drilling program in the Merge area offset by the impact of the Arkoma Divestiture. On a per unit basis, depletion expense decreased $0.77 per Boe or 3.7% from $20.95 per Boe for the six months ended June 30, 2017 to $20.18 per Boe for the six months ended June 30, 2018.

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 sales price, an impairment charge of $148.0 million was recognized during the six months ended June 30, 2017. No impairment charges were recognized during the six months ended June 30, 2018.

General and administrative. General and administrative expenses decreased by $1.2 million, or 7.2%, to $15.5 million for the six months ended June 30, 2018, as compared to $16.7 million for the six months ended June 30, 2017. Non-cash compensation expense decreased $2.9 million, from $3.9 million for the three months ended June 30, 2017 to $1.0 million for the three months ended June 30, 2018. This decrease was offset by additional compensation expense of $1.7 million in the three months ended June 30, 2018 associated with the acceleration of certain unvested equity compensation awards made to certain members of our senior management team who departed on April 17, 2018. On a per unit basis, general and administrative expenses, excluding all non-cash items, increased from $2.96 per Boe for the six months ended June 30, 2017 to $3.23 per Boe for the six months ended June 30, 2018.

Interest expense. Interest expense increased by $19.3 million, or 75.4%, to $44.9 million for the six months ended June 30, 2018, as compared to $25.6 million for the six months ended June 30, 2017. The increase was driven by the issuance of the 2023 First Lien Notes on February 14, 2018. Additionally, the Company recognized accelerated amortization of

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debt issuance costs of $3.8 million during the six months ended June 30, 2018 associated with the modification of the Revolver due to the issuance of the 2023 First Lien Notes. See Note 5, “Long-Term Debt,” for further details. During the six months ended June 30, 2018, borrowings under the Revolver, the 2022 Notes, the 2023 Notes, and the 2023 First Lien Notes bore interest at a weighted average rate of 4.46%, 6.75%, 9.25% and 9.25%, respectively. Average outstanding balances for the six months ended June 30, 2018 were $74.3 million, $409.1 million, $150.0 million, and $450.0 million under the Revolver, the 2022 Notes, the 2023 Notes and the 2023 First Lien Notes, respectively.

Net gain (loss) on commodity derivatives. The net gain (loss) on commodity derivatives was a net loss of $39.2 million for the six months ended June 30, 2018, as compared to a net gain of $43.8 million for the six months ended June 30, 2017. The loss was primarily driven by a higher average crude oil price ($65.55 per barrel) for the six months ended June 30, 2018, as compared to the crude oil and natural gas prices as of December 31, 2017 ($60.46 per barrel).

Other income (expense). Other income (expense) for the six months ended June 30, 2018 was net income of $13.5 million, as compared to net income of $28.1 million for the six months ended June 30, 2017. Other income (expense) during the six months ended June 30, 2018 was primarily related to an increase in the TRA valuation allowance which resulted in income of $9.1 million. Additionally, the Company recognized net gains on the sale of non-core assets.

Income taxes. The provision for federal and state income taxes for the six months ended June 30, 2018 was a benefit of $8.4 million resulting in an 10.0% effective tax rate as a percentage of our pre-tax book income for the quarter as compared to a benefit of 2.2 million resulting in a 1.6% effective tax rate as a percentage of our pre-tax book income for the six months ended June 30, 2017. 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. For the six months ended June 30, 2018, the Company recorded its provision using the 21% federal tax rate enacted by the Tax Reform Legislation. The effective tax rate increase was primarily due to the magnitude of the effect of the valuation allowance recorded against the Company’s deferred tax assets, which partially offset the tax benefit generated the six months ended June 30, 2018 and 2017. See Note 11, “Income Taxes,” for further details.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been private and public sales of our debt and equity, borrowings under bank credit facilities and cash flows from operations. Our primary use of capital has been for the exploration, development and acquisition of oil and gas properties. As we pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We strive to maintain financial flexibility in order to facilitate drilling on our undeveloped acreage positions and permit us to selectively expand our acreage positions. We are likely to 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 insufficient 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, 2018 reflects a substantial cash position as a result of the issuance of the 2023 First Lien Notes. We intend to use this cash balance to meet future financial obligations and planned capital expenditure activities.

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 some or all 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.

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The following table summarizes our cash flows for the six months ended June 30, 2018 and 2017:

	Six Months Ended June 30,
(in thousands of dollars)	2018		2017
Net cash provided by operating activities	$	46,812	$	21,478
Net cash used in investing activities		(133,992)		(56,827)
Net cash provided by financing activities		215,778		6,961
Net increase (decrease) in cash	$	128,598	$	(28,388)

Cash flow provided by operating activities

Net cash provided by operating activities was $46.8 million during the six months ended June 30, 2018 as compared to $21.5 million during the six months ended June 30, 2017. The increase in operating cash flows was primarily due to the $34.1 million increase in oil and gas revenues for the six months ended June 30, 2018 as compared to the six months ended June 30, 2017, primarily driven by the increase in production volumes, as well as commodity prices.

Cash flow (used in) investing activities

Net cash used in investing activities was $134.0 million during the six months ended June 30, 2018 as compared to $56.8 million during the six months ended June 30, 2017. The increase in investing cash flow was primarily driven by an increase in current period settlements of matured derivative contracts ($71.4 million). Additionally, capital spend related to our continued drilling program increased year-over-year ($7.6 million) which further increased investing cash flows.

Cash flow provided by financing activities

Net cash provided by financing activities was $215.8 million during the six months ended June 30, 2018 as compared to $7.0 million during the six months ended June 30, 2017. The increase in financing cash flows was primarily due to the issuance of the 2023 First Lien Notes on February 14, 2018. Upon issuance, the Company received proceeds of $438.9 million. The Company used the proceeds from the offering toward net repayments under the Revolver of $211.0 million. On June 27, 2018, all outstanding borrowings under the Revolver were repaid in full.  The Company’s current outstanding borrowings under the Revolver are $0.00.

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 such 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.

During 2016, JEH generated taxable income, resulting in the payment during 2016 of $17.3 million in cash tax distributions to JEH unitholders (other than us). 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 2017 we made further income tax payments to federal and state taxing authorities of $2.3 million and JEH made further tax distributions to JEH unitholders (other than us) of $0.6 million. During 2017, JEH did not generate taxable income, therefore we did not make any additional tax payments nor did JEH make any additional tax distributions other than those made as a result of 2016 JEH taxable income.

Based on our initial 2018 operating budget and 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 2018. 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, 2017.

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Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

There have been no changes to our critical accounting policies and estimates from those set forth in our Annual Report on Form 10-K for the year ended December 31, 2017.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

The following market risk disclosures should be read in conjunction with the quantitative and qualitative disclosures about market risk contained in our Annual Report on Form 10-K for the year ended December 31, 2017, as well as with the unaudited consolidated financial statements and notes included in this Quarterly Report.

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

Potential Impairment of Oil and Gas Properties

Oil and natural gas prices are inherently volatile. Taking into consideration the business environment in which we operate, we continually review our oil and gas properties for indicators of potential impairment on an undiscounted basis. No such indicators were present at June 30, 2018.

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, 2017 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, 2018 (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, 2017 would have increased by approximately 1.6%. The use of this pricing example is for illustration purposes only and does not indicate management’s view on future commodity prices, costs or other variables, or represent a forecast or estimate of the actual amount by which our proved reserves may fluctuate when a full assessment of our reserves is completed as of December 31, 2018.

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

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

· Increases in service costs;

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

· Increases in operating costs;

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

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

Commodity price risk and hedges

Our principal market risk exposure is to oil, natural gas and NGL prices, which are inherently volatile. As such, future earnings are subject to change due to fluctuations in such prices. Realized prices are primarily driven by the prevailing prices for oil and regional spot prices for natural gas and NGLs. We have used, and expect to continue to use, oil, natural gas and NGL derivative contracts to reduce our risk of price fluctuations of these commodities. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. The fair value of our oil, natural gas and NGL derivative contracts at June 30, 2018 was a net liability of $59.5 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. All of our derivative contracts currently in place are with lenders under our Revolver or their affiliates, who have investment grade ratings.

Interest rate risk

We are subject to market risk exposure related to changes in interest rates on our variable rate indebtedness. The terms of our Revolver provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 1.75% to 3.75% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. The terms of our senior notes provide for a fixed interest rate through their respective maturity dates. During the three months ended June 30, 2018, borrowings under the Revolver, the 2022 Notes, the 2023 Notes and the 2023 First Lien Notes bore interest at a weighted average rate of 4.75%, 6.75%, 9.25% and 9.25%, respectively. During the six months ended June 30, 2018, borrowings under the Revolver, the 2022 Notes, the 2023 Notes and the 2023 First Lien Notes bore interest at a weighted average rate of 4.46%, 6.75%, 9.25% and 9.25%, respectively.

Item 4. Controls and Procedures

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the six months ended June 30, 2018 that have materially affected, or are reasonably likely to materially affect, our 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.

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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, 2018, 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, 2017 included a report of management’s assessment regarding internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of legal proceedings, see Note 15 “Commitments and Contingencies,” in the Notes to Consolidated Financial Statements for further discussion appearing in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated in this item by reference.

Item 1A. Risk Factors

Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings, including our Annual Report on Form 10-K for the year ended December 31, 2017, 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, 2017. There have been no material changes in our risk factors from those described in our Annual Report for the year ended December 31, 2017, except as set forth below.

We are currently out of compliance with the NYSE’s minimum share price requirement and are at risk of the NYSE delisting our Class A common stock, which would have a material adverse effect on our business, financial condition, prospects and liquidity and value of our common stock.

Our Class A common stock is currently listed on the NYSE, and the continued listing of our Class A common stock is subject to our compliance with a number of listing standards. On March 23, 2018, we were notified by the NYSE that we are no longer in compliance with the continued listing standards because the average closing price of our Class A common stock had fallen below $1.00 per share over a period of 30 consecutive trading days. Pursuant to the NYSE’s rules, we have a period of six months (subject to possible extension) from March 23, 2018 to regain compliance with the minimum share price criteria. In order to regain compliance, on the last trading day in any calendar month or at the end of the cure period, the Class A common stock must have (i) a closing price of at least $1.00 per share and (ii) an average closing price of at least $1.00 per share over the 30-consecutive trading-day period ending on the last trading day of such month. If we are unable to regain compliance, the NYSE will initiate procedures to suspend and delist the Class A common stock.

In order to cure such non–compliance during the cure period, we may elect to effect a reverse stock split, subject to and upon approval by our stockholders and the Board. At our 2018 annual meeting of stockholders, our stockholders authorized the Board to amend our certificate of incorporation to effect a reverse stock split of no less than 1-for-5 and no more than 1-for-20, subject to approval of the Board. There can be no assurance, however, that any reverse stock split will be approved or implemented or at all. Further, even if a reverse stock split is approved and successfully implemented, there can be no assurance that such action will directly or indirectly cure any non-compliance with NYSE continued listing standards.

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If our Class A common stock ultimately were to be delisted for any reason, it could negatively impact us by (i) reducing the liquidity and market price of our Class A common stock; (ii) reducing the number of investors willing to hold or acquire our Class A common stock, which could negatively impact our ability to raise equity financing; (iii) limiting our ability to use a registration statement to offer and sell freely tradeable securities, thereby preventing us from accessing the public capital markets; and (iv) impairing our ability to provide equity incentives to our employees.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

Exhibit No.	Description
4.1	First Supplemental Indenture, dated as of April 20, 2018, among Nosley Midstream, LLC, Jones Energy Holdings, LLC, Jones Energy Finance Corp., UMB Bank, N.A., and Wells Fargo Bank, National Association (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 10-Q filed with the Securities and Exchange Commission on May 4, 2018).
10.1	Amendment No. 13 to Credit Agreement dated as of June 28, 2018, among Jones Energy Holdings, LLC, as borrower, Jones Energy, Inc., Jones Energy, LLC, Nosley Assets, LLC, Nosley SCOOP, LLC, Nosley Acquisition, LLC, Jones Energy Finance Corp. and Nosley Midstream, LLC as guarantors, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 2, 2018).
31.1*	Rule 13a-14(a)/15d-14(a) Certification of Carl F. Giesler, Jr. (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 Carl F. Giesler, Jr. (Principal Executive Officer).
32.2**	Section 1350 Certification of Robert J. Brooks (Principal Financial Officer).
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

* - filed herewith

** - furnished herewith

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SIGNATURES

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

	Jones Energy, Inc.
	(registrant)
Date: August 8, 2018	By:	/s/ Robert J. Brooks
	Name:  Robert J. Brooks
	Title:    Chief Financial Officer (Principal Financial Officer)

Signature Page to Form 10-Q (Q2 2018)

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