Jones Energy, Inc. - FORM 10-Q

Attached files

file	filename
EX-32.2 - EX-32.2 - Jones Energy, Inc.	jone-20180930ex32214ceaa.htm
EX-32.1 - EX-32.1 - Jones Energy, Inc.	jone-20180930ex321337a95.htm
EX-31.2 - EX-31.2 - Jones Energy, Inc.	jone-20180930ex312b477aa.htm
EX-31.1 - EX-31.1 - Jones Energy, Inc.	jone-20180930ex311e53db9.htm
EX-10.2 - EX-10.2 - Jones Energy, Inc.	jone-20180930ex1022086cb.htm
EX-10.1 - EX-10.1 - Jones Energy, Inc.	jone-20180930ex101aac5aa.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended September 30, 2018

☐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, every Interactive Data File required to be submitted 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 ☒

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 October 26, 2018, the Registrant had 4,971,044 shares of Class A common stock outstanding and 172,193 shares of Class B common stock outstanding.

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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, our belief that we will be able to identify and prioritize projects with the greatest expected returns, our ability to maintain compliance with the continued listing requirements of the New York Stock Exchange (the “NYSE”), our expectations regarding our working capital balance and our expected capital expenditures, the potential impairment of our Western Anadarko basin properties, projections regarding taxable income generated by Jones Energy Holdings, LLC (“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 future capital expenditure plan, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company’s business and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the SEC.

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

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PART 1—FINANCIAL INFORMATION

Item 1. Financial Statements

Jones Energy, Inc.

Consolidated Balance Sheets (Unaudited)


	September 30,		December 31,
(in thousands of dollars)	2018		2017
Assets
Current assets
Cash and cash equivalents	$	93,676	$	19,472
Accounts receivable, net
Oil and gas sales		38,605		34,492
Joint interest owners		29,025		31,651
Other		964		1,236
Commodity derivative assets		581		3,474
Other current assets		9,032		14,376
Total current assets		171,883		104,701
Oil and gas properties, net, under the successful efforts method		1,613,972		1,597,040
Other property, plant and equipment, net		2,030		2,719
Commodity derivative assets		1,257		172
Other assets		769		5,431
Total assets	$	1,789,911	$	1,710,063
Liabilities and Stockholders' Equity
Current liabilities
Trade accounts payable	$	35,750	$	72,663
Oil and gas sales payable		36,904		31,462
Accrued liabilities		37,982		21,604
Commodity derivative liabilities		41,930		36,709
Other current liabilities		3,674		4,049
Total current liabilities		156,240		166,487
Long-term debt		980,373		759,316
Deferred revenue		4,274		5,457
Commodity derivative liabilities		16,219		8,788
Asset retirement obligations		20,347		19,652
Liability under tax receivable agreement		58,681		59,596
Other liabilities		985		811
Deferred tax liabilities		10,078		14,281
Total liabilities		1,247,197		1,034,388
Commitments and contingencies (Note 15)
Mezzanine equity
Series A preferred stock, $0.001 par value; 1,837,195 shares issued and outstanding at September 30, 2018 and 1,839,995 shares issued and outstanding at December 31, 2017		93,453		89,539
Stockholders' equity (1)
Class A common stock, $0.001 par value; 4,903,116 shares issued and 4,901,986 shares outstanding at September 30, 2018 and 4,506,991 shares issued and 4,505,861 shares outstanding at December 31, 2017		5		5
Class B common stock, $0.001 par value; 241,251 shares issued and outstanding at September 30, 2018 and 481,391 shares issued and outstanding at December 31, 2017		—		—
Treasury stock, at cost: 1,130 shares at September 30, 2018 and December 31, 2017		(358)		(358)
Additional paid-in-capital		640,286		606,414
Retained (deficit) / earnings		(242,130)		(136,274)
Stockholders' equity		397,803		469,787
Non-controlling interest		51,458		116,349
Total stockholders’ equity		449,261		586,136
Total liabilities and stockholders' equity	$	1,789,911	$	1,710,063

(1)

All share information presented has been recast to retrospectively adjust for the effects of the Reverse Stock Split, as defined in Note 12, “Stockholders’ and Mezzanine Equity”, effective on September 7, 2018.

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

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Jones Energy, Inc.

Consolidated Statements of Operations (Unaudited)


	Three months ended September 30,				Nine months ended September 30,
(in thousands of dollars except per share data)	2018		2017		2018		2017
Operating revenues
Oil and gas sales	$	59,910	$	43,636	$	182,796	$	132,427
Other revenues		(184)		566		(326)		1,634
Total operating revenues		59,726		44,202		182,470		134,061
Operating costs and expenses
Lease operating		11,149		9,458		32,970		27,689
Production and ad valorem taxes		2,950		2,757		8,985		4,641
Transportation and processing costs		914		—		2,505		—
Exploration		2,174		1,969		7,001		11,638
Depletion, depreciation and amortization		39,810		46,353		125,980		127,343
Impairment of oil and gas properties		—		—		—		148,016
Accretion of ARO liability		269		253		784		720
General and administrative		8,737		7,819		24,203		24,493
Total operating expenses		66,003		68,609		202,428		344,540
Operating income (loss)		(6,277)		(24,407)		(19,958)		(210,479)
Other income (expense)
Interest expense		(22,197)		(12,817)		(67,114)		(38,381)
Net gain (loss) on commodity derivatives		(12,886)		(32,539)		(52,053)		11,308
Other income (expense)		(12,525)		(13,692)		979		14,389
Other income (expense), net		(47,608)		(59,048)		(118,188)		(12,684)
Income (loss) before income tax		(53,885)		(83,455)		(138,146)		(223,163)
Income tax provision (benefit)		(18,530)		(492)		(26,940)		(2,707)
Net income (loss)		(35,355)		(82,963)		(111,206)		(220,456)
Net income (loss) attributable to non-controlling interests		(2,264)		(18,157)		(11,239)		(72,047)
Net income (loss) attributable to controlling interests	$	(33,091)	$	(64,806)	$	(99,967)	$	(148,409)
Dividends and accretion on preferred stock		(1,958)		(1,966)		(5,889)		(5,959)
Net income (loss) attributable to common shareholders	$	(35,049)	$	(66,772)	$	(105,856)	$	(154,368)

Earnings (loss) per share (1) :
Basic - Net income (loss) attributable to common shareholders	$	(7.16)	$	(18.27)	$	(22.48)	$	(46.07)
Diluted - Net income (loss) attributable to common shareholders	$	(7.16)	$	(18.27)	$	(22.48)	$	(46.07)

Weighted average Class A shares outstanding (1) :
Basic		4,897		3,654		4,708		3,351
Diluted		4,897		3,654		4,708		3,351

(1)

All share and earnings per share information presented has been recast to retrospectively adjust for the effects of the Reverse Stock Split, as defined in Note 12, “Stockholders’ and Mezzanine Equity”, effective on September 7, 2018.

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

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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 (1)	Value		Shares (1)	Value		Shares (1)	Value		Capital		Earnings		Interest		Equity
Balance at December 31, 2017	4,506	$	5	481	$	—	1	$	(358)	$	606,414	$	(136,274)	$	116,349	$	586,136
Stock-compensation expense	64		—	—		—	—		—		1,054		—		—		1,054
Exchange of Class B shares for Class A shares	240		—	(240)		—	—		—		30,845		—		(53,652)		(22,807)
Conversion of preferred shares for Class A shares	3		—	—		—	—		—		135		—		—		135
Dividends and accretion on preferred stock	89		—	—		—	—		—		1,838		(5,889)		—		(4,051)
Net income (loss)	—		—	—		—	—		—		—		(99,967)		(11,239)		(111,206)
Balance at September 30, 2018	4,902	$	5	241	$	—	1	$	(358)	$	640,286	$	(242,130)	$	51,458	$	449,261

(1)

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

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Jones Energy, Inc.

Consolidated Statements of Cash Flows (Unaudited)


	Nine months ended September 30,
(in thousands of dollars)	2018		2017
Cash flows from operating activities
Net income (loss)	$	(111,206)	$	(220,456)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, and amortization		125,980		127,343
Exploration (dry hole and lease abandonment)		3,079		8,680
Impairment of oil and gas properties		—		148,016
Accretion of ARO liability		784		720
Amortization of debt issuance costs		8,964		2,930
Stock compensation expense		1,511		5,702
Deferred and other non-cash compensation expense		88		335
Amortization of deferred revenue		(1,182)		(1,417)
(Gain) loss on commodity derivatives		52,053		(11,308)
(Gain) loss on sales of assets		(9,867)		131
Deferred income tax provision		(26,940)		80
Change in liability under tax receivable agreement		(986)		(15,831)
Other - net		379		1,892
Changes in operating assets and liabilities
Accounts receivable		(1,933)		(15,070)
Other assets		5,615		(8,238)
Accrued interest expense		4,993		2,028
Accounts payable and accrued liabilities		(6,331)		15,888
Net cash provided by operations		45,001		41,425
Cash flows from investing activities
Additions to oil and gas properties		(153,813)		(179,152)
Net adjustments to purchase price of properties acquired		—		2,391
Proceeds from sales of assets		10,052		60,422
Acquisition of other property, plant and equipment		(92)		(603)
Current period settlements of matured derivative contracts		(42,652)		69,412
Net cash used in investing		(186,505)		(47,530)
Cash flows from financing activities
Proceeds from issuance of long-term debt		20,000		102,000
Repayment of long-term debt		(231,000)		(129,000)
Proceeds from senior notes		438,867		—
Payment of debt issuance costs		(11,702)		—
Payment of cash dividends on preferred stock		—		(3,367)
Net distributions paid to JEH unitholders		—		(562)
Net payments for share based compensation		(457)		(462)
Proceeds from sale of common stock		—		8,332
Net cash provided by / (used in) financing		215,708		(23,059)
Net increase (decrease) in cash and cash equivalents		74,204		(29,164)
Cash and cash equivalents
Beginning of period		19,472		34,642
End of period	$	93,676	$	5,478
Supplemental disclosure of cash flow information
Cash paid for interest, net of capitalized interest	$	54,633	$	33,736
Change in accrued additions to oil and gas properties		(9,134)		7,982
Asset retirement obligations incurred, including changes in estimate		397		437

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

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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 September 30, 2018, the Company held 4,901,986 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 241,251 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 1,837,195 remained issued and outstanding as of September 30, 2018. See Note 12, “Stockholders’ and Mezzanine Equity”.

On September 7, 2018, the Company effected a 1-for-20 reverse stock split of its Class A common stock and its Class B common stock. 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.

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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 September 30, 2018 and 2017 and each of the three and nine-month periods then ended include the Company and all of its subsidiaries.

Certain prior period amounts have been reclassified to conform to the current presentation, including all share and earnings per share information presented which has been recast to retrospectively adjust for the effects of the Reverse Stock Split, as defined in Note 12, “Stockholders’ and Mezzanine Equity”, effective on September 7, 2018.

The accompanying unaudited condensed consolidated financial statements for the periods ended September 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 nine months ended September 30, 2017. During the nine months ended September 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. No refunds were received during the three months ended September 30, 2017 and 2018.

Accrued Liabilities

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


	September 30,		December 31,
(in thousands of dollars)	2018		2017
Accrued interest expense	$	17,102	$	12,109
Joint interest owners prepayments		9,849		4,061
Commodity derivative liabilities		5,044		14
Other accrued liabilities		5,987		5,420
Total accrued liabilities	$	37,982	$	21,604

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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 issuers 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. While the Company has not yet finalized the impact this standards update will have on the consolidated financial statements, the adoption will likely increase the Company recorded assets and liabilities related to leases. We will adopt ASU 2016-02 effective as of January 1, 2019 and anticipate using the cumulative effect approach and will recognize a right of use asset and lease liability on the adoption date. We plan to apply practical expedients provided in the standards update that allow, among other things, not to reassess contracts that commenced prior to the adoption. We also anticipate to elect a policy not to recognize right of use assets and lease liabilities related to short-term leases.

In June 2018, the FASB issued ASU 2018-07 "Compensation-Stock Compensation" (Topic 718). The amendments under this ASU provide an expanded scope of Topic 718, to include share-based payment transactions for acquiring goods and services from non-employees. The new standards update is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. The Company is

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currently evaluating the impacts of the amendments to our financial statements and accounting practices for stock compensation, as well as the method of adoption. We anticipate adoption of ASU 2018-07 effective as of January 1, 2019.

In August 2018, the FASB issued ASU 2018-13, “Fair Value Measurement” (Topic 820). The amendments under this ASU provide additional disclosure requirements that eliminates the requirement to disclose transfers between Level 1 and Level 2 of the fair value hierarchy and provides for additional disclosures for Level 3 fair value measurements. This new standards update is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. The Company is currently evaluating the impacts of the amendments to our financial statements and accounting practices for fair value measurement, as well as the method of adoption. We anticipate adoption of ASU 2018-13 effective as of January 1, 2020.

3. Divestitures

Nine Months Ended September 30, 2018

Sales of non-core assets resulted in net losses of $4.4 million and net gains of $0.3 million during the three and nine months ended September 30, 2018, respectively.

Twelve Months Ended December 31, 2017

Arkoma Divestiture

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 through the period ending October 1, 2019. As of September 30, 2018, $0.1 million has been recorded related to this contingent payment. The contingent payment was recorded as a gain in Other income (expense) on the Company’s Consolidated Statement of Operations of $0.1 million during the nine months ended September 30, 2018. No contingent payment gains were recorded during the three months ended September 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 September 30, 2018						Nine Months Ended September 30, 2018
(in thousands of dollars except	Amounts under		Adoption		Amounts under		Amounts under		Adoption		Amounts under
per share data)	ASC 606		impact		ASC 605 (1)		ASC 606		impact		ASC 605 (1)
Operating revenues
Oil and gas sales	$	59,910	$	(914)	$	58,996	$	182,796	$	(2,505)	$	180,291
Other revenues		(184)		—		(184)		(326)		—		(326)
Total operating revenues		59,726		(914)		58,812		182,470		(2,505)		179,965
Operating costs and expenses
Lease operating		11,149		—		11,149		32,970		—		32,970
Production and ad valorem taxes		2,950		—		2,950		8,985		—		8,985
Transportation and processing costs		914		(914)		—		2,505		(2,505)		—
Exploration		2,174		—		2,174		7,001		—		7,001
Depletion, depreciation and amortization		39,810		—		39,810		125,980		—		125,980
Accretion of ARO liability		269		—		269		784		—		784
General and administrative		8,737		—		8,737		24,203		—		24,203
Total operating expenses		66,003		(914)		65,089		202,428		(2,505)		199,923
Operating income (loss)		(6,277)		—		(6,277)		(19,958)		—		(19,958)
Other income (expense)
Interest expense		(22,197)		—		(22,197)		(67,114)		—		(67,114)
Net gain (loss) on commodity derivatives		(12,886)		—		(12,886)		(52,053)		—		(52,053)
Other income (expense)		(12,525)		—		(12,525)		979		—		979
Other income (expense), net		(47,608)		—		(47,608)		(118,188)		—		(118,188)
Income (loss) before income tax		(53,885)		—		(53,885)		(138,146)		—		(138,146)
Income tax provision (benefit)		(18,530)		—		(18,530)		(26,940)		—		(26,940)
Net income (loss)		(35,355)		—		(35,355)		(111,206)		—		(111,206)
Net income (loss) attributable to non-controlling interests		(2,264)		—		(2,264)		(11,239)		—		(11,239)
Net income (loss) attributable to controlling interests	$	(33,091)	$	—	$	(33,091)	$	(99,967)	$	—	$	(99,967)
Dividends and accretion on preferred stock		(1,958)		—		(1,958)		(5,889)		—		(5,889)
Net income (loss) attributable to common shareholders	$	(35,049)	$	—	$	(35,049)	$	(105,856)	$	—	$	(105,856)

Earnings (loss) per share (2) :
Basic - Net income (loss) attributable to common shareholders	$	(7.16)	$	—	$	(7.16)	$	(22.48)	$	—	$	(22.48)
Diluted - Net income (loss) attributable to common shareholders	$	(7.16)	$	—	$	(7.16)	$	(22.48)	$	—	$	(22.48)

Weighted average Class A shares outstanding (2) :
Basic		4,897		—		4,897		4,708		—		4,708
Diluted		4,897		—		4,897		4,708		—		4,708

(1)

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

(2)

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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 by 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, in accordance with the governing states’ remittance policy.

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


	Three Months Ended September 30, 2018
(in thousands of dollars)	Oil		Natural gas		NGLs		Total
Eastern Anadarko	$	13,407	$	1,680	$	6,615	$	21,702
Western Anadarko		21,928		6,088		10,192		38,208
Total	$	35,335	$	7,768	$	16,807	$	59,910

	Nine Months Ended September 30, 2018
(in thousands of dollars)	Oil		Natural gas		NGLs		Total
Eastern Anadarko	$	46,021	$	4,767	$	17,180	$	67,968
Western Anadarko		67,924		18,233		28,671		114,828
Total	$	113,945	$	23,000	$	45,851	$	182,796

The following tables present quantitative information about disaggregated revenues from contracts with customers by commodity and region of production for the three and nine months ended September 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 September 30, 2017 (1)
(in thousands of dollars)	Oil		Natural gas		NGLs		Total
Eastern Anadarko	$	4,863	$	723	$	2,178	$	7,764
Western Anadarko		17,129		9,068		10,471		36,668
Total	$	21,992	$	9,791	$	12,649	$	44,432

	Nine Months Ended September 30, 2017 (1)
(in thousands of dollars)	Oil		Natural gas		NGLs		Total
Eastern Anadarko	$	8,969	$	1,813	$	3,314	$	14,096
Western Anadarko		55,588		32,956		32,353		120,897
Total	$	64,557	$	34,769	$	35,667	$	134,993

(1)

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

During the nine months ended September 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 September 30, 2018 and December 31, 2017.


	September 30,		December 31,
(in thousands of dollars)	2018		2017
Accounts receivable, net
Oil and gas sales	$	38,605	$	34,492
Other current liabilities
Contract liabilities	$	604	$	—

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 September 30, 2018 and December 31, 2017:


	September 30,		December 31,
(in thousands of dollars)	2018		2017
Mineral interests in properties
Unproved	$	97,846	$	164,087
Proved		954,917		893,246
Wells and equipment and related facilities		1,584,163		1,434,383
		2,636,926		2,491,716
Less: Accumulated depletion and impairment		(1,022,954)		(894,676)
Net oil and gas properties	$	1,613,972	$	1,597,040

There were no exploratory wells drilled during the nine months ended September 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 nine months ended September 30, 2018, the Company capitalized less than $0.1 million and $0.2 million, respectively, associated with such in progress projects. During the three and nine months ended September 30, 2017, the Company capitalized $0.1 million and $0.3 million, respectively, associated with such in progress projects. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

Depletion of oil and gas properties amounted to $39.6 million and $125.2 million for the three and nine months ended September 30, 2018, respectively, and $46.1 million and $126.6 million for the three and nine months ended September 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 nine months ended September 30, 2018. As a result of the 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 September 30, 2018 and December 31, 2017:


	September 30,		December 31,
(in thousands of dollars)	2018		2017
Leasehold improvements	$	1,186	$	1,186
Furniture, fixtures, computers and software		4,404		4,410
Vehicles		1,922		1,922
Aircraft		910		910
Other		239		210
		8,661		8,638
Less: Accumulated depreciation and amortization		(6,631)		(5,919)
Net other property, plant and equipment	$	2,030	$	2,719

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Depreciation and amortization of other property, plant and equipment amounted to $0.2 million and $0.8 million, for the three and nine months ended September 30, 2018, respectively, and $0.3 million and $0.8 million for the three and nine months ended September 30, 2017, respectively.

6. Long-Term Debt

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


(in thousands of dollars)	September 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		(14,142)		(5,228)
Less: debt issuance costs, net		(14,633)		(5,604)
Total carrying amount	$	980,373	$	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 nine months ended September 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.

The Company is 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 nine months ended September 30, 2018, the Company capitalized $11.5 million of loan costs associated with the issuance of the 2023 First Lien Notes.

The Company is in compliance with the indenture governing 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, in connection with an amendment described below, 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 does not currently have any borrowings under the Revolver.

The Company recognized accelerated amortization of debt issuance costs of $3.8 million during the nine months ended September 30, 2018 associated with the modification of the Revolver, which was recorded as Interest expense on the Company’s Consolidated Statement of Operations. No accelerated amortization of debt issuance costs was recognized during the three months ended September 30, 2018 associated with the modification of the Revolver.

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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.

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 nine months ended September 30, 2018, the average interest rate under the Revolver was 4.46% on an average outstanding balance of $74.3 million. There were no outstanding borrowings under the Revolver during the three months ended September 30, 2018.

Total interest and commitment fees under the Revolver were $1.8 million for the nine months ended September 30, 2018, and $1.6 million and $4.7 million for the three and nine months ended September 30, 2017, respectively. No interest and commitment fees under the Revolver were incurred during the three months ended September 30, 2018.

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 September 30, 2018, and we expect to maintain compliance throughout the next twelve months.

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 September 30, 2018:

Hedging Positions


	September 30, 2018
						Weighted		Final
		Low		High		Average		Expiration
Oil swaps	Exercise price	$	52.00	$	49.70	$	50.17	December 2020
	Barrels per month		168,000		55,000		80,741
Natural gas swaps	Exercise price	$	3.10	$	2.76	$	2.84	December 2020
	Offset exercise price	$	2.85	$	2.83	$	2.84	December 2018
	Net MMbtu per month		1,480,000		700,000		934,074
Natural gas liquids swaps	Exercise price	$	45.26	$	23.21	$	30.15	December 2018
	Barrels per month		130,000		130,000		130,000
Natural gas basis swaps	Exercise price	$	(0.50)	$	(0.44)	$	(0.45)	October 2018
	MMbtu per month		800,000		800,000		800,000
Oil collars	Puts (floors)	$	50.00	$	45.00	$	48.52	December 2019
	Calls (ceilings)	$	61.00	$	56.60	$	59.64
	Net barrels per month		73,000		65,000		67,500
Natural gas collars	Puts (floors)	$	2.55	$	2.55	$	2.55	December 2019
	Calls (ceilings)	$	3.41	$	3.08	$	3.19
	Net MMbtu per month		1,050,000		950,000		990,833

The Company recognized net losses on derivative instruments of $12.9 million and $52.1 million for the three and nine months ended September 30, 2018, respectively. The Company recognized net losses on derivative instruments of $32.5 million and net gains of $11.3 million for the three and nine months ended September 30, 2017, respectively.

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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 $14.8 million and $42.8 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 nine months ended September 30, 2017, respectively.

Offsetting Assets and Liabilities

As of September 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 September 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
September 30, 2018
Commodity derivative contracts
Assets	$	4,698	$	(2,860)	$	1,838	$	—	$	1,838
Liabilities		(61,009)		2,860		(58,149)		—		(58,149)
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 September 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)	September 30, 2018
	Fair Value Measurements Using
Commodity Price Hedges	(Level 1)		(Level 2)		(Level 3)		Total
Current assets	$	—	$	424	$	157	$	581
Long-term assets (1)		—		1,282		(25)		1,257
Current liabilities		—		32,324		9,606		41,930
Long-term liabilities		—		13,948		2,271		16,219


(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

(1) Level 3 long-term assets are negative as a result of the netting of our commodity derivatives reflected on our Consolidated Balance Sheet as of September 30, 2018. Our agreements include set-off provisions, as noted in Note 6, “Derivative Instruments and Hedging Activities - Offsetting Assets and Liabilities”.

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The following table represents quantitative information about Level 3 inputs used in the fair value measurement of the Company’s commodity derivative contracts as of September 30, 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	$	(1,810)	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	$	(10,072)	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	$	137	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 MMbtu

The following table presents the changes in the Company’s commodity derivative contract activity involving Level 3 instruments during the nine months ended September 30, 2018:


(in thousands of dollars)
Balance at December 31, 2017, net	$	(8,575)
Purchases		—
Settlements		5,138
Transfers to Level 2		958
Transfers to Level 3		—
Changes in fair value		(9,266)
Balance at September 30, 2018, net	$	(11,745)

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. Significant increases/decreases in natural gas liquid prices in isolation would result in a significantly lower/higher fair value measurement.

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Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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


	September 30, 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		240,354		409,148		305,404
2023 Notes		150,000		90,339		150,000		114,750
2023 First Lien Notes		450,000		464,279		—		—

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 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 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 nine months ended September 30, 2018 is as follows:


(in thousands of dollars)
Balance at December 31, 2017	$	20,372
Liabilities incurred		262
Accretion of ARO liability		784
Liabilities settled due to sale of related properties		(234)
Liabilities settled due to plugging and abandonment		(252)
Change in estimate		135
Total ARO balance at September 30, 2018		21,067
Less: Current portion of ARO		(720)
Total long-term ARO at September 30, 2018	$	20,347

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10. Stock-based Compensation

All share and weighted average fair value per share information presented has been recast to retrospectively adjust for the effects of the Reverse Stock Split, as defined in Note 12, “Stockholders’ and Mezzanine Equity”, effective on September 7, 2018.

Management Unit Awards

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

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


		Weighted Average
		Grant Date Fair Value
	JEH Units	per Share
Unvested at December 31, 2017	1,615	$	300.00
Granted	1,515		300.00
Forfeited	(1,515)		300.00
Vested	(1,615)		300.00
Unvested at September 30, 2018	—	$	—

Stock compensation expense associated with the Management Units was $0.0 million and $0.1 million for the three and nine months ended September 30, 2018, respectively, and $0.1 million and $0.5 million for the three and nine months ended September 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 425,265 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, the preferred stock dividends paid in shares and the Reverse Stock Split, as defined 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 September 30, 2018:


	Restricted	Weighted Average
	Stock Unit	Grant Date Fair Value
	Awards	per Share
Unvested at December 31, 2017	137,949	$	55.61
Adjustment (1)	2,624		—
Granted	179,947		9.16
Forfeited	(42,150)		47.46
Vested	(52,874)		66.62
Unvested at September 30, 2018	225,496	$	16.83

(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 $0.4 million and $1.4 million for the three and nine months ended September 30, 2018, respectively, and $1.1 million and $3.1 million for the three and nine months ended September 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 September 30, 2018:


	Performance	Weighted Average
	Share Unit	Grant Date Fair Value
	Awards	per Share
Unvested at December 31, 2017	47,851	$	66.79
Adjustment (1)	946		—
Granted	32,615		26.00
Forfeited	(1,881)		82.62
Cancelled	(32,615)		62.87
Vested	(32,615)		26.00
Unvested at September 30, 2018	14,301	$	62.91

(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 expense of $0.1 million and an offset to expense of $0.1 million for the three and nine months ended September 30, 2018, respectively, and $0.7 million and $1.7 million for the three and nine months ended September 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 September 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 less than $0.1 million and $1.7 million for the three and nine months ended September 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 nine months ended September 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 September 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 1.1 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 September 30, 2018:


		Weighted Average
	Restricted	Grant Date Fair Value
	Stock Awards	per Share
Unvested at December 31, 2017	9,370	$	43.22
Adjustment (1)	123		—
Granted	3,123		23.40
Cancelled	(3,123)		(43.23)
Vested	(9,493)		(36.14)
Unvested at September 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 $0.0 million and $0.1 million for the three and nine months ended September 30, 2018, respectively, and $0.1 million and $0.4 million for the three and nine months ended September 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 34.4% and 19.5% for the three and nine months ended September 30, 2018, respectively, and 0.6% and 1.2% for the three and nine months ended September 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 nine months ended September 30, 2018 and 2017. The effective rate differs from the enacted statutory rates of 21% and 35% for the nine months ended September 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 $18.5 million and $26.9 million for the three and nine months ended September 30, 2018, respectively, and a benefit of $0.5 million and $2.7 million for the three and nine months ended September 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 September 30,				Nine Months Ended September 30,
(in thousands of dollars)	2018		2017		2018		2017
Jones Energy, Inc.	$	(18,506)	$	(495)	$	(26,889)	$	(2,711)
Non-controlling interest		(24)		3		(51)		4
Income tax provision (benefit)	$	(18,530)	$	(492)	$	(26,940)	$	(2,707)

The Company had deferred tax assets for its federal and state net operating loss carry forwards at September 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 September 30, 2018, we have a valuation allowance of $29.2 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.

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 September 30, 2018 and December 31, 2017, the Company had a gross TRA liability of $79.2 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 September 30, 2018 and December 31, 2017, the amount of the TRA liability was reduced by $20.5 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 September 30, 2018 and December 31, 2017, the Company had recorded a net TRA liability of $58.7 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 $71.2 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.

During the first quarter of 2018, the Company made a payment of $1.6 million related to 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. The Company will not realize cash savings on its 2017 tax return as a result of tax attributes arising from prior exchanges, and therefore does not anticipate a payment under the TRA for the 2017 tax year.

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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 nine months ended September 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 did 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 September 30, 2018, approximately $62.2 million in aggregate offering proceeds remained available to be issued and sold under the Equity Distribution Agreement.

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.

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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 0.8534 shares of Class A common stock after adjusting the conversion ratio for the effects of the Special Stock Dividend and the Reverse Stock Split, as defined in Note 12, “Stockholders’ and Mezzanine Equity” (which is equivalent to a conversion price of approximately $58.59 per share after such adjustments), 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 1.6 million shares of Class A common stock would be issuable upon conversion of all the Series A preferred stock.

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

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

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

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

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


(in thousands of dollars)
Mezzanine equity at December 31, 2017	$	89,539
Accrued dividends on preferred stock		3,673
Accretion on preferred stock		376
Change in estimate due to settlements		(135)
Mezzanine equity at September 30, 2018	$	93,453

Reverse Stock Split

On March 23, 2018, 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

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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 had a six-month cure period during which it could regain compliance.

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 voting item that granted the Board discretionary authority to effect an amendment to the Company’s Amended and Restated Certificate of Incorporation to effect a reverse stock split of the Common Stock (as defined below), at a ratio between 1-for-5 and 1-for-20, with such ratio to be determined by the Board in its sole discretion.

On August 17, 2018, the Board approved a reverse stock split for the Company’s issued and outstanding Class A and Class B common stock (together, the “Common Stock”) of 1-for-20 (the “Reverse Stock Split”), effective after market close on September 7, 2018.

In connection with the Reverse Stock Split, the Company filed an amendment to its Amended and Restated Certificate of Incorporation with the Secretary of State of the State of Delaware (the “Amendment”). The Amendment, effective as of 5:00 p.m., New York City time, on September 7, 2018, converted each 20 issued and outstanding share of Class A common stock into one share of Class A common stock and each 20 issued and outstanding shares of Class B common stock into one share of Class B common stock. A Certificate of Correction to the Amendment (the “Certificate of Correction”) correcting the cash payout process for fractional shares resulting from the Reverse Stock Split was filed with the Secretary of State of the State of Delaware on September 10, 2018. Pursuant to the Certificate of Correction, any fraction of a share of Common Stock that would otherwise have resulted from the Reverse Stock Split were settled by cash payment, equal to the fraction of one share of Common Stock multiplied by the average of the high and low trading prices of the Class A common stock on the NYSE during regular trading hours for the five trading days immediately preceding September 7, 2018.

The Reverse Stock Split did not affect any record holder’s percentage ownership interest in the Company, except for de minimis changes as a result of the elimination of fractional shares. The Reverse Stock Split reduced the number of shares of Class A common stock outstanding from 98,039,826 (excluding treasury shares) to 4,901,986 and the number of shares of Class B common stock outstanding from 4,825,038 to 241,251. The Reverse Stock Split did not affect the authorized number of shares of Class A common stock or Class B common stock.

The Class A common stock began trading on a reverse split-adjusted basis on the NYSE at the opening of trading on September 10, 2018. The Class A common stock continues trading on the NYSE under the symbol “JONE” with a new CUSIP number (48019R 306).

All outstanding equity awards, pursuant to the various instruments governing them, were adjusted immediately prior to the Reverse Stock Split by dividing the number of shares of Class A common stock into which such equity awards were exercisable or convertible by 20. In connection with such proportionate adjustments, the number of shares of Class A common stock issuable upon exercise or conversion of outstanding equity awards was rounded down to the nearest whole share.

The Reverse Stock Split did not affect the number of authorized or outstanding shares of the Company’s Series A preferred stock or the dividend rate per share of any outstanding shares of Series A preferred stock. In accordance with the Certificate of Designations governing the Series A preferred stock, the conversion rate of the Series A preferred stock has been adjusted to reflect the Reverse Stock Split and is currently equal to 0.8534.

On September 21, 2018, the Company received notice from the NYSE that the Company had regained compliance with the NYSE’s continued listing standards. As a result of the Reverse Stock Split, the Company regained compliance as of market close September 21, 2018, because the closing price per share of the Company’s Class A common stock was above $1.00 per share and was on average above $1.00 for the 30 trading days preceding September 21, 2018. The shares of Class A common stock continued trading on the NYSE without interruption.

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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 $15.20, as adjusted for the effects of the Reverse Stock Split (the “Floor Price”). The Dividend Valuation Price did not meet the Floor Price. The right for holders of Series A preferred stock to receive this dividend has been accrued.

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. 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 Dividend Valuation Price, was required to be at or above the Floor Price, as adjusted for the effects of the Reverse Stock Split. The Dividend

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Valuation Price did not meet the Floor Price. The right for holders of Series A preferred stock to receive this dividend has been accrued.

As of September 30, 2018, the Company had $3.7 million of cumulative dividends in arrears on the Series A preferred stock, which related to the scheduled May 15, 2018 and August 15, 2018 dividends that were not paid.

On October 15, 2018, the Board declared a contingent 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 (prior to adjustment for the effects of the Reverse Stock Split) 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 249,996 JEH Units, as adjusted for the effects of the Reverse Stock Split, at a price of $70.00 per share, which is the volume weighted average price per share of the Class A common stock for the five trading days ended February 28, 2017. Immaterial cash payments were made in lieu of fractional shares. The comparative earnings per share information has been recast to retrospectively adjust for the effects of the Special Stock Dividend.

13. Earnings per Share

Basic earnings per share (“EPS”) is computed by dividing net income (loss) attributable to controlling interests by the weighted average number of shares of Class A common stock outstanding during the period. Shares of Class B common stock are not included in the calculation of earnings per share because they are not participating securities and have no economic interest in the Company. Diluted earnings per share takes into account the potential dilutive effect of shares that could be issued by the Company in conjunction with the Series A preferred stock and from stock awards that have been granted to directors and employees. Awards of non-vested shares are considered outstanding as of the respective grant dates for purposes of computing diluted EPS even though the award is contingent upon vesting. For the three and nine months ended September 30, 2018, 225,496 restricted stock units, 14,301 performance share units, and 1,567,862 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 nine months ended September 30, 2017, 153,693 restricted stock units, 73,699 performance share units, and 1,570,279 shares from the convertible Series A preferred stock, as adjusted for the effects of the Reverse Stock Split, 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 September 30,				Nine Months Ended September 30,
(in thousands, except per share data)	2018		2017 (1)		2018		2017 (1)
Income (numerator):
Net income (loss) attributable to controlling interests	$	(33,091)	$	(64,806)	$	(99,967)	$	(148,409)
Less: Dividends and accretion on preferred stock		(1,958)		(1,966)		(5,889)		(5,959)
Net income (loss) attributable to common shareholder	$	(35,049)	$	(66,772)	$	(105,856)	$	(154,368)
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock - basic		4,897		3,654		4,708		3,351
Weighted-average number of shares of Class A common stock - diluted		4,897		3,654		4,708		3,351
Earnings (loss) per share:
Basic - Net income (loss) attributable to common shareholders	$	(7.16)	$	(18.27)	$	(22.48)	$	(46.07)
Diluted - Net income (loss) attributable to common shareholders	$	(7.16)	$	(18.27)	$	(22.48)	$	(46.07)

(1)

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

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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.

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 $1.2 million of the deferred revenue balance during the three and nine months ended September 30, 2018, respectively, and $0.5 million and $1.4 million of the deferred revenue balance during the three and nine months ended September 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 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. As of September 30, 2018, equity interests in Monarch of $0.1 million are included in Other assets on the Company’s Consolidated Balance Sheet. During the three and nine months ended September 30, 2018, equity interests of $0.2 million and $0.3 million, respectively, were distributed to management under the incentive plan. The Company recognized expense of $0.0 million and $0.1 million during the three and nine months ended September 30, 2018, respectively, in connection with the incentive plan. As of September 30, 2018, all equity interests subject to the incentive plan have been distributed.

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 $1.5 million for the three and nine months ended September 30, 2018, respectively, associated with the approximately 0.3 MMBoe and 0.7 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 490,714 shares of Class A common stock, as adjusted for the effects of the 0.087423 per share Special Stock Dividend and the Reverse Stock Split, 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;

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

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

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

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 October 15, 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. This contingent dividend is for the period beginning on the last scheduled payment date of August 15, 2018 through November 14, 2018 and, subject to the contingency described below, will be payable on November 15, 2018 to shareholders of record as of November 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 the Floor Price. If the Dividend Valuation Price is below the Floor Price, the Series A preferred stock dividend payable on November 15, 2018 will not be paid by the Company, the right to receive those dividends will accrue for holders of Series A preferred stock and the Company will have executed its third dividend holiday (of five) without penalty. Future Preferred Stock dividend payments will be evaluated on a quarterly basis.

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Changes to Management

Executive Officers

On October 31, 2018, Robert J. Brooks, the Company’s Executive Vice President, Chief Financial Officer, Secretary and Treasurer, tendered his resignation, effective immediately following the filing of this Quarterly Report on Form 10-Q. Following such resignation, Thomas Hester, the Company’s Vice President of Finance and Secretary, has been appointed as an executive officer, the principal financial officer and the principal accounting officer, effective immediately following Mr. Brooks’s resignation. Also on October 31, 2018, the Company named Kirk Goehring, the Company’s Vice President of Strategy, an executive officer of the Company, effective immediately following Mr. Brooks’s resignation.

Other Officers

On October 31, 2018, the Company hired Salah Gamoudi as Chief Accounting Officer, effective immediately.

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 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)

September 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	$	62,682	$	27,383	$	20	$	—	$	93,676
Accounts receivable, net
Oil and gas sales		—		—		38,605		—		—		38,605
Joint interest owners		—		—		29,025		—		—		29,025
Other		—		—		964		—		—		964
Commodity derivative assets		—		581		—		—		—		581
Other current assets		1,871		1,096		6,065		—		—		9,032
Intercompany receivable		450,079		1,205,504		—		—		(1,655,583)		—
Total current assets		455,541		1,269,863		102,042		20		(1,655,583)		171,883
Oil and gas properties, net, under the successful efforts method		—		—		1,613,972		—		—		1,613,972
Other property, plant and equipment, net		—		—		1,571		459		—		2,030
Commodity derivative assets		—		1,257		—		—		—		1,257
Other assets		—		88		681		—		—		769
Investment in subsidiaries		103,483		51,458		—		—		(154,941)		—
Total assets	$	559,024	$	1,322,666	$	1,718,266	$	479	$	(1,810,524)	$	1,789,911
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	—	$	34	$	35,716	$		$	—	$	35,750
Oil and gas sales payable		—		—		36,904		—		—		36,904
Accrued liabilities		—		21,231		16,751		—		—		37,982
Commodity derivative liabilities		—		41,930		—		—		—		41,930
Other current liabilities		—		1,723		1,951		—		—		3,674
Intercompany payable		—		—		1,652,333		3,250		(1,655,583)		—
Total current liabilities		—		64,918		1,743,655		3,250		(1,655,583)		156,240
Long-term debt		—		980,373		—		—		—		980,373
Deferred revenue		—		4,274		—		—		—		4,274
Commodity derivative liabilities		—		16,219		—		—		—		16,219
Asset retirement obligations		—		—		20,347		—		—		20,347
Liability under tax receivable agreement		58,681		—		—		—		—		58,681
Other liabilities		—		35		950		—		—		985
Deferred tax liabilities		9,087		991		—		—		—		10,078
Total liabilities		67,768		1,066,810		1,764,952		3,250		(1,655,583)		1,247,197
Mezzanine equity
Series A preferred stock, $0.001 par value; 1,837,195 shares issued and outstanding at September 30, 2018		93,453		—		—		—		—		93,453
Stockholders’/ members' equity (deficit)
Members' equity		—		255,856		(46,686)		(2,771)		(206,399)		—
Class A common stock, $0.001 par value; 4,903,116 shares issued and 4,901,986 shares outstanding at September 30, 2018		5		—		—		—		—		5
Class B common stock, $0.001 par value; 241,251 shares issued and outstanding at September 30, 2018		—		—		—		—		—		—
Treasury stock, at cost: 1,130 shares at September 30, 2018		(358)		—		—		—		—		(358)
Additional paid-in-capital		640,286		—		—		—		—		640,286
Retained earnings (deficit)		(242,130)		—		—		—		—		(242,130)
Stockholders' equity (deficit)		397,803		255,856		(46,686)		(2,771)		(206,399)		397,803
Non-controlling interest		—		—		—		—		51,458		51,458
Total stockholders’ equity		397,803		255,856		(46,686)		(2,771)		(154,941)		449,261
Total liabilities and stockholders’ equity	$	559,024	$	1,322,666	$	1,718,266	$	479	$	(1,810,524)	$	1,789,911

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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; 4,506,991 shares issued and 4,505,861 shares outstanding at December 31, 2017		5		—		—		—		—		5
Class B common stock, $0.001 par value; 481,391 shares issued and outstanding at December 31, 2017		—		—		—		—		—		—
Treasury stock, at cost: 1,130 shares at December 31, 2017		(358)		—		—		—		—		(358)
Additional paid-in-capital		606,414		—		—		—		—		606,414
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

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations (Unaudited)

Three Months Ended September 30, 2018


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—	$	—	$	59,910	$	—	$	—	$	59,910
Other revenues		—		401		(585)		—		—		(184)
Total operating revenues		—		401		59,325		—		—		59,726
Operating costs and expenses
Lease operating		—		—		11,149		—		—		11,149
Production and ad valorem taxes		—		—		2,950		—		—		2,950
Transportation and processing costs		—		—		914		—		—		914
Exploration		—		—		2,174		—		—		2,174
Depletion, depreciation and amortization		—		—		39,787		23		—		39,810
Accretion of ARO liability		—		—		269		—		—		269
General and administrative		(9)		4,619		4,100		27		—		8,737
Total operating expenses		(9)		4,619		61,343		50		—		66,003
Operating income (loss)		9		(4,218)		(2,018)		(50)		—		(6,277)
Other income (expense)
Interest expense		—		(22,104)		(93)		—		—		(22,197)
Net gain (loss) on commodity derivatives		—		(12,886)		—		—		—		(12,886)
Other income (expense)		(8,095)		(24)		(4,406)		—		—		(12,525)
Other income (expense), net		(8,095)		(35,014)		(4,499)		—		—		(47,608)
Income (loss) before income tax		(8,086)		(39,232)		(6,517)		(50)		—		(53,885)
Equity interest in income (loss)		(43,340)		(2,461)		—		—		45,801		—
Income tax provision (benefit)		(18,335)		(195)		—		—		—		(18,530)
Net income (loss)		(33,091)		(41,498)		(6,517)		(50)		45,801		(35,355)
Net income (loss) attributable to non-controlling interests		—		—		—		—		(2,264)		(2,264)
Net income (loss) attributable to controlling interests	$	(33,091)	$	(41,498)	$	(6,517)	$	(50)	$	48,065	$	(33,091)
Dividends and accretion on preferred stock		(1,958)		—		—		—		—		(1,958)
Net income (loss) attributable to common shareholders	$	(35,049)	$	(41,498)	$	(6,517)	$	(50)	$	48,065	$	(35,049)

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations (Unaudited)

Three Months Ended September 30, 2017


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

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations (Unaudited)

Nine Months Ended September 30, 2018


					Guarantor		Non-Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Operating revenues
Oil and gas sales	$	—	$	—	$	182,796	$	—	$	—	$	182,796
Other revenues		—		1,183		(1,509)		—		—		(326)
Total operating revenues		—		1,183		181,287		—		—		182,470
Operating costs and expenses
Lease operating		—		—		32,970		—		—		32,970
Production and ad valorem taxes		—		—		8,985		—		—		8,985
Transportation and processing costs		—		—		2,505		—		—		2,505
Exploration		—		—		7,001		—		—		7,001
Depletion, depreciation and amortization		—		—		125,911		69		—		125,980
Accretion of ARO liability		—		—		784		—		—		784
General and administrative		—		9,295		14,744		164		—		24,203
Total operating expenses		—		9,295		192,900		233		—		202,428
Operating income (loss)		—		(8,112)		(11,613)		(233)		—		(19,958)
Other income (expense)
Interest expense		—		(66,510)		(604)		—		—		(67,114)
Net gain (loss) on commodity derivatives		—		(52,053)		—		—		—		(52,053)
Other income (expense)		986		(83)		76		—		—		979
Other income (expense), net		986		(118,646)		(528)		—		—		(118,188)
Income (loss) before income tax		986		(126,758)		(12,141)		(233)		—		(138,146)
Equity interest in income (loss)		(127,538)		(11,596)		—		—		139,134		—
Income tax provision (benefit)		(26,585)		(355)		—		—		—		(26,940)
Net income (loss)		(99,967)		(137,999)		(12,141)		(233)		139,134		(111,206)
Net income (loss) attributable to non-controlling interests		—		—		—		—		(11,239)		(11,239)
Net income (loss) attributable to controlling interests	$	(99,967)	$	(137,999)	$	(12,141)	$	(233)	$	150,373	$	(99,967)
Dividends and accretion on preferred stock		(5,889)		—		—		—		—		(5,889)
Net income (loss) attributable to common shareholders	$	(105,856)	$	(137,999)	$	(12,141)	$	(233)	$	150,373	$	(105,856)

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations (Unaudited)

Nine Months Ended September 30, 2017


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

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Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows (Unaudited)

Nine Months Ended September 30, 2018


							Non-
					Guarantor		Guarantor
(in thousands of dollars)	JEI (Parent)		Issuers		Subsidiaries		Subsidiaries		Eliminations		Consolidated
Cash flows from operating activities
Net income (loss)	$	(99,967)	$	(137,999)	$	(12,141)	$	(233)	$	139,134	$	(111,206)
Adjustments to reconcile net income (loss) to net cash provided by operating activities		98,310		26,445		170,353		233		(139,134)		156,207
Net cash (used in) / provided by operations		(1,657)		(111,554)		158,212		—		—		45,001
Cash flows from investing activities
Additions to oil and gas properties		—		—		(153,813)		—		—		(153,813)
Proceeds from sales of assets		—		—		10,052		—		—		10,052
Acquisition of other property, plant and equipment		—		—		(92)		—		—		(92)
Current period settlements of matured derivative contracts		—		(42,652)		—		—		—		(42,652)
Net cash (used in) / provided by investing		—		(42,652)		(143,853)		—		—		(186,505)
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		—		(11,702)		—		—		—		(11,702)
Payment of cash dividends on preferred stock		—		—		—		—		—		—
Net payments for share based compensation		—		(457)		—		—		—		(457)
Net cash (used in) / provided by financing		—		215,708		—		—		—		215,708
Net increase (decrease) in cash and cash equivalents		(1,657)		61,502		14,359		—		—		74,204
Cash and cash equivalents
Beginning of period		5,248		1,180		13,024		20		—		19,472
End of period	$	3,591	$	62,682	$	27,383	$	20	$	—	$	93,676

Table of Contents

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows (Unaudited)

Nine Months Ended September 30, 2017


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

Table of Contents

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 on Form 10-Q for the quarter ended March 31, 2018, filed with the Commission on May 4, 2018 and our quarterly report on Form 10-Q for the quarter ended June 30, 2018, filed with the Commission on August 8, 2018. 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 over 950 total wells as operator, including nearly 780 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.

Third Quarter and Year-to-Date 2018 Highlights:

Average daily net production for third quarter 2018 of 21.8 MBoe/d.

Merge HBP drilling expected to be complete in the fourth quarter of 2018, with all HBP wells online by year-end 2018.

Malinda 2H, the Company’s first operated Marmaton well achieves peak IP-30 of 582 Boe/d (3-stream, 62% oil, 77% liquids).

Net loss for the third quarter of 2018 of $35.4 million, or a net loss of $7.16 per share, non-GAAP adjusted net loss of $33.5 million, or a non-GAAP adjusted net loss of $6.77 per share, and EBITDAX of $20.0 million.

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Outlook

Liability Management and Strategic Review

As previously disclosed, the Company and its advisors have been engaged in discussions with certain beneficial holders of the Company’s funded debt and equity (the “Holders”) regarding a potential transaction addressing the Company’s debt and equity. While no such transaction has occurred, the Company’s initiatives are ongoing. The Company is continuing to work with its advisors to evaluate other strategic and financial alternatives, including potential sales of non-core assets. The Company has deferred its evaluation of a DrillCo, the consideration of which was disclosed in previous filings.

Capital Expenditures Update

On September 19, 2018, the Board approved certain capital projects that management anticipates resulting in full year 2018 capital expenditures of approximately $195.0 million versus the initial budget of $150.0 million. The additional spend reflects increased working interests on previously-drilled wells in the Merge and higher than anticipated non-op spending from the initial budget. We will continue to monitor market conditions and may decide, at a later date, to spend more or less capital for a variety of reasons.

Impairment of Oil and Gas Properties

See "Impairment of Oil and Gas Properties" and “Critical Accounting Policies and Estimates” included in the Company's Annual Report on Form 10-K for the year ended December 31, 2017 for a discussion of the Company’s accounting policies and significant assumptions related to accounting for oil and gas producing activities, and the Company's policies and processes with respect to impairment reviews for proved and unproved property. We continually review our oil and gas properties for indicators of potential impairment on an undiscounted basis. No such indicators were present at September 30, 2018. However, the Company’s current liquidity position may cause the Company to recognize a significant impairment on the assets in the Western Anadarko Basin, which had a carrying value of approximately $1.2 billion as of September 30, 2018.

Changes to the Board of Directors and Management

Changes to Board

On September 27, 2018, Paul B. Loyd, Jr. and John V. Lovoi resigned from the Board and all committees thereof, effective as of September 28, 2018. In connection with these resignations, pursuant to the bylaws of the Company, the Board voted to decrease the size of the Board from eight to seven members. Further, as of September 28, 2018, the Board appointed Mr. Carl F. Giesler, Jr., the Company’s Chief Executive Officer, to the Board and appointed Mr. Hal Washburn as chair of the Nominating and Governance Committee. As a result of the departures of Mr. Loyd and Mr. Lovoi, we currently do not have a majority-independent Board and only have two independent directors to serve on the Audit Committee of the Board as opposed to the three independent directors required by the rules of the NYSE. We are currently in the process of identifying a third independent director who would qualify for service on the Audit Committee of the Board and who would cause our Board to be majority-independent.

Changes to Executive Officers

Changes to Other Officers

On October 31, 2018, the Company hired Salah Gamoudi as Chief Accounting Officer, effective immediately.

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Results of Operations

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


(in thousands of dollars except for	Three Months Ended September 30,						Nine Months Ended September 30,
production, sales price and average cost data)	2018		2017		Change		2018		2017		Change
Revenues:
Oil	$	35,335	$	21,566	$	13,769	$	113,945	$	63,145	$	50,800
Natural gas		7,768		9,421		(1,653)		23,000		33,615		(10,615)
NGLs		16,807		12,649		4,158		45,851		35,667		10,184
Total oil and gas		59,910		43,636		16,274		182,796		132,427		50,369
Other		(184)		566		(750)		(326)		1,634		(1,960)
Total operating revenues		59,726		44,202		15,524		182,470		134,061		48,409
Costs and expenses:
Lease operating		11,149		9,458		1,691		32,970		27,689		5,281
Production and ad valorem taxes		2,950		2,757		193		8,985		4,641		4,344
Transportation and processing costs		914		—		914		2,505		—		2,505
Exploration		2,174		1,969		205		7,001		11,638		(4,637)
Depletion, depreciation and amortization		39,810		46,353		(6,543)		125,980		127,343		(1,363)
Impairment of oil and gas properties		—		—		—		—		148,016		(148,016)
Accretion of ARO liability		269		253		16		784		720		64
General and administrative		8,737		7,819		918		24,203		24,493		(290)
Total costs and expenses		66,003		68,609		(2,606)		202,428		344,540		(142,112)
Operating income (loss)		(6,277)		(24,407)		18,130		(19,958)		(210,479)		190,521
Other income (expenses):
Interest expense		(22,197)		(12,817)		(9,380)		(67,114)		(38,381)		(28,733)
Net gain (loss) on commodity derivatives		(12,886)		(32,539)		19,653		(52,053)		11,308		(63,361)
Other income/(expense)		(12,525)		(13,692)		1,167		979		14,389		(13,410)
Total other income (expense)		(47,608)		(59,048)		11,440		(118,188)		(12,684)		(105,504)
Income (loss) before income tax		(53,885)		(83,455)		29,570		(138,146)		(223,163)		85,017
Income tax provision (benefit)		(18,530)		(492)		(18,038)		(26,940)		(2,707)		(24,233)
Net income (loss)		(35,355)		(82,963)		47,608		(111,206)		(220,456)		109,250
Net income (loss) attributable to non-controlling interests		(2,264)		(18,157)		15,893		(11,239)		(72,047)		60,808
Net income (loss) attributable to controlling interests	$	(33,091)	$	(64,806)	$	31,715	$	(99,967)	$	(148,409)	$	48,442
Dividends and accretion on preferred stock		(1,958)		(1,966)		8		(5,889)		(5,959)		70
Net income (loss) attributable to common shareholders	$	(35,049)	$	(66,772)	$	31,723	$	(105,856)	$	(154,368)	$	48,512

Net production volumes:
Oil (MBbls)		514		481		33		1,753		1,391		362
Natural gas (MMcf)		5,209		5,171		38		15,877		15,663		214
NGLs (MBbls)		619		627		(8)		1,872		1,833		39
Total (MBoe)		2,001		1,970		31		6,271		5,835		437
Average net (Boe/d)		21,750		21,413		337		22,971		21,374		1,597
Average sales price, unhedged:
Oil (per Bbl), unhedged	$	68.75	$	44.84	$	23.91	$	65.00	$	45.40	$	19.60
Natural gas (per Mcf), unhedged		1.49		1.82		(0.33)		1.45		2.15		(0.70)
NGLs (per Bbl), unhedged		27.15		20.17		6.98		24.49		19.46		5.03
Combined (per Boe), unhedged		29.94		22.15		7.79		29.15		22.70		6.45
Average sales price, hedged:
Oil (per Bbl), hedged	$	43.35	$	79.50	$	(36.15)	$	48.44	$	81.44	$	(33.00)
Natural gas (per Mcf), hedged		1.63		3.62		(1.99)		1.62		3.77		(2.15)
NGLs (per Bbl), hedged		21.07		13.63		7.44		18.45		14.30		4.15
Combined (per Boe), hedged		21.89		33.26		(11.37)		23.15		34.03		(10.88)
Average costs (per BOE):
Lease operating	$	5.57	$	4.80	$	0.77	$	5.26	$	4.75	$	0.51
Production and ad valorem taxes		1.47		1.40		0.07		1.43		0.80		0.63
Depletion, depreciation and amortization		19.90		23.53		(3.63)		20.09		21.82		(1.73)
General and administrative		4.37		3.97		0.40		3.86		4.20		(0.34)

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Non-GAAP financial measures

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

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

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


	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands of dollars)	2018		2017		2018		2017
Reconciliation of net income to EBITDAX
Net income (loss)	$	(35,355)	$	(82,963)	$	(111,206)	$	(220,456)
Interest expense		22,197		12,817		67,114		38,381
Exploration expense		2,174		1,969		7,001		11,638
Income taxes		(18,530)		(492)		(26,940)		(2,707)
Depreciation and depletion		39,810		46,353		125,980		127,343
Impairment of oil and natural gas properties		—		—		—		148,016
Accretion of ARO liability		269		253		784		720
Change in TRA liability		8,095		12,435		(986)		(15,831)
Other non-cash charges		3		585		379		1,892
Stock compensation expense		537		1,966		1,511		5,702
Deferred and other non-cash compensation expense		4		155		88		335
Net (gain) loss on derivative contracts		12,886		32,539		52,053		(11,308)
Current period settlements of matured derivative contracts		(16,116)		21,892		(37,593)		66,145
Amortization of deferred revenue		(400)		(475)		(1,182)		(1,417)
(Gain) loss on sale of assets, net of proceeds		4,436		12		(185)		131
Financing expenses and other loan fees		24		24		83		72
EBITDAX	$	20,034	$	47,070	$	76,901	$	148,656

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

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


	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands except per share data)	2018			2017			2018			2017
Net income (loss)	$	(35,355)		$	(82,963)		$	(111,206)		$	(220,456)
Net (gain) loss on derivative contracts		12,886			32,539			52,053			(11,308)
Current period settlements of matured derivative contracts		(16,116)			21,892			(37,593)			66,145
Impairment of oil and gas properties		—			—			—			148,016
Exploration		2,174			1,969			7,001			11,638
Non-cash stock compensation expense		537			1,966			1,511			5,702
Deferred and other non-cash compensation expense		4			155			88			335
Financing expenses		41			—			3,926			—
Tax impact of adjusting items (1)		84			(15,543)			(5,423)			(48,666)
Change in TRA liability		8,095			12,435			(986)			(15,831)
Change in valuation allowance		(5,842)			16,616			6,321			62,105
Adjusted net income (loss)		(33,492)			(10,934)			(84,308)			(2,320)
Adjusted net income (loss) attributable to non-controlling interests		(2,284)			(3,665)			(8,730)			(6,683)
Adjusted net income (loss) attributable to controlling interests		(31,208)			(7,269)			(75,578)			4,363
Dividends and accretion on preferred stock		(1,958)			(1,966)			(5,889)			(5,959)
Adjusted net income (loss) attributable to common shareholders	$	(33,166)		$	(9,235)		$	(81,467)		$	(1,596)

Earnings per share (basic and diluted):	$	(7.16)		$	(18.27)		$	(22.48)		$	(46.07)
Net (gain) loss on derivative contracts		2.51			6.69			10.16			(1.50)
Current period settlements of matured derivative contracts		(3.13)			4.50			(7.40)			13.75
Impairment of oil and gas properties		—			—			—			30.38
Exploration		0.42			0.40			1.37			2.40
Non-cash stock compensation expense		0.10			0.40			0.30			1.19
Deferred and other non-cash compensation expense		—			0.03			0.02			0.07
Financing expenses		0.01			—			0.76			—
Tax impact of adjusting items (1)		0.02			(4.23)			(1.16)			(14.51)
Change in TRA liability		1.65			3.40			(0.21)			(4.72)
Change in valuation allowance		(1.19)			4.55			1.34			18.53
Adjusted earnings per share (basic and diluted)	$	(6.77)		$	(2.53)		$	(17.30)		$	(0.48)

Weighted average Class A shares outstanding:
Basic		4,897			3,654			4,708			3,351
Diluted		4,897			3,654			4,708			3,351
Effective tax rate on net income (loss) attributable to controlling interests		21.2	%		37.9	%		25.6	%		37.9	%

(1)

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

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

Operating revenues

Oil and gas sales. Oil and gas sales increased $16.3 million, or 37.4%, to $59.9 million for the three months ended September 30, 2018, as compared to $43.6 million for the three months ended September 30, 2017. The increase was attributable to the increase in commodity prices ($14.2 million) and the increase in production volumes ($2.1 million). The increase in production volumes was driven by the year-over-year increase in producing wells due to continued drilling activity. The average realized oil price, excluding the effects of commodity derivative instruments, increased from $44.84 per Bbl for the three months ended September 30, 2017 to $68.75 per Bbl for the three months ended September 30, 2018, or 53.3%. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $1.82 per Mcf for the three months ended September 30, 2017 to $1.49 per Mcf for the three months ended September 30, 2018, or 18.1%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increased from $20.17 per Bbl for the three months ended September 30, 2017 to $27.15 per Bbl for the three months ended September 30, 2018, or 34.6%. Average daily production increased 1.6% to 21,750 Boe per day for the three months ended September 30, 2018 as compared to 21,413 Boe per day for the three months ended September 30, 2017.

Costs and expenses

Lease operating. Lease operating expenses increased by $1.6 million, or 16.8%, to $11.1 million for the three months ended September 30, 2018, as compared to $9.5 million for the three months ended September 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 $0.77 per Boe, or 16.0%, from $4.80 per Boe in the three months ended September 30, 2017 to $5.57 per Boe in the three months ended September 30, 2018. The increase was primarily the result of lower initial production on the newly drilled Merge wells, therefore resulting in higher lease operating costs on a Boe basis.

Production and ad valorem taxes. Production and ad valorem taxes increased by $0.2 million to $3.0 million for the three months ended September 30, 2018, as compared to $2.8 million for the three months ended September 30, 2017. Production taxes increased $0.5 million, from $2.2 million for the three months ended September 30, 2017 to $2.7 million for the three months ended September 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 decreased $0.3 million, from $0.5 million for the three months ended September 30, 2017 to $0.2 million for the three months ended September 30, 2018. The average effective rate excluding the impact of ad valorem taxes decreased from 5.1% for the three months ended September 30, 2017 to 4.6% for the three months ended September 30, 2018.

Exploration. Exploration expense increased from $2.0 million for the three months ended September 30, 2017 to $2.2 million for the three months ended September 30, 2018. The Company recognized charges for lease abandonment of $2.2 million during the three months ended September 30, 2018 as compared to $1.8 million during the three months ended September 30, 2017, relating to certain leases that the Company decided during the respective three-month period not to develop and to let lapse. No exploratory wells resulted in exploration expense during the three months ended September 30 of either year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased by $6.6 million, or 14.2%, to $39.8 million for the three months ended September 30, 2018, as compared to $46.4 million for the three months ended September 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 $3.63 per Boe or 15.4% from $23.53 per Boe for the three months ended September 30, 2017 to $19.90 per Boe for the three months ended September 30, 2018.

General and administrative. General and administrative expenses increased by $0.9 million, or 11.5%, to $8.7 million for the three months ended September 30, 2018, as compared to $7.8 million for the three months ended September 30, 2017. Non-cash compensation expense decreased $1.6 million, from $2.1 million for the three months ended September 30, 2017 to $0.5 million for the three months ended September 30, 2018. On a per unit basis, general and administrative

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expenses, excluding all non-cash items, increased from $2.60 per Boe for the three months ended September 30, 2017 to $4.09 per Boe for the three months ended September 30, 2018. The increase was primarily due to our ongoing restructuring efforts.

Interest expense. Interest expense increased by $9.4 million, or 73.4%, to $22.2 million for the three months ended September 30, 2018, as compared to $12.8 million for the three months ended September 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 September 30, 2018, borrowings under the 2022 Notes, the 2023 Notes, and the 2023 First Lien Notes bore interest at a weighted average rate of 6.75%, 9.25% and 9.25%, respectively. Average outstanding balances for the three months ended September 30, 2018 were $409.1 million, $150.0 million, and $450.0 million under 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 $12.9 million for the three months ended September 30, 2018, as compared to a net loss of $32.5 million for the three months ended September 30, 2017. The loss was primarily driven by higher average crude oil price and natural gas prices ($69.69 per barrel and $2.93 per Mcf, respectively) for the three months ended September 30, 2018, as compared to the average crude oil and natural gas prices for the three months ended June 30, 2018 ($68.07 per barrel and $2.85 per Mcf, respectively).

Other income (expense). Other income (expense) for the three months ended September 30, 2018 was net expense of $12.5 million, as compared to net expense of $13.7 million for the three months ended September 30, 2017. Other income (expense) during the three months ended September 30, 2018 primarily related to a decrease in the TRA valuation allowance which resulted in expense of $8.1 million. Additionally, sales of non-core assets resulted in net losses of $4.4 million during the three months ended September 30, 2018.

Income taxes. The provision for federal and state income taxes for the three months ended September 30, 2018 was a benefit of $18.5 million resulting in a 34.4% effective tax rate as a percentage of our pre-tax book income for the quarter as compared to a benefit of $0.5 million resulting in a 0.6% effective tax rate as a percentage of our pre-tax book income for the three months ended September 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 September 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 September 30, 2018 and 2017. See Note 11, “Income Taxes,” for further details.

Results of Operations - Nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017

Operating revenues

Oil and gas sales. Oil and gas sales increased $50.4 million, or 38.1%, to $182.8 million for the nine months ended September 30, 2018, as compared to $132.4 million for the nine months ended September 30, 2017. The increase was attributable to the increase in commodity prices ($25.6 million) and the increase in production volumes ($24.8 million). The increase in production volumes was driven by the year-over-year increase in producing wells due to continued drilling activity. The average realized oil price, excluding the effects of commodity derivative instruments, increased from $45.40 per Bbl for the nine months ended September 30, 2017 to $65.00 per Bbl for the nine months ended September 30, 2018, or 43.2%. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $2.15 per Mcf for the nine months ended September 30, 2017 to $1.45 per Mcf for the nine months ended September 30, 2018, or 32.6%, due to changes in the production mix as a result of increased production in the Merge and associated sales contracts. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increased from $19.46 per Bbl for the nine months ended September 30, 2017 to $24.49 per Bbl for the nine months ended September 30, 2018, or 25.8%. Average daily production increased 7.5% to 22,971 Boe per day for the nine months ended September 30, 2018 as compared to 21,374 Boe per day for the nine months ended September 30, 2017.

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Costs and expenses

Lease operating. Lease operating expenses increased by $5.3 million, or 19.1%, to $33.0 million for the nine months ended September 30, 2018, as compared to $27.7 million for the nine months ended September 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 $0.51 per Boe, or 10.7%, from $4.75 per Boe in the nine months ended September 30, 2017 to $5.26 per Boe in the nine months ended September 30, 2018.

Production and ad valorem taxes. Production and ad valorem taxes increased by $4.4 million to $9.0 million for the nine months ended September 30, 2018, as compared to $4.6 million for the nine months ended September 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 nine months ended September 30, 2017. During the nine months ended September 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 $6.4 million for the nine months ended September 30, 2017 to $7.4 million for the nine months ended September 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 $0.1 million, from $1.6 million for the nine months ended September 30, 2017 to $1.7 million for the nine months ended September 30, 2018. The average effective rate excluding the impact of ad valorem taxes increased from 2.3% for the nine months ended September 30, 2017 to 4.0% for the nine months ended September 30, 2018.

Exploration. Exploration expense decreased from $11.6 million for the nine months ended September 30, 2017 to $7.0 million for the nine months ended September 30, 2018. The Company recognized charges for lease abandonment of $3.1 million during the nine months ended September 30, 2018 as compared to $8.7 million during the nine months ended September 30, 2017, relating to certain leases that the Company decided during the respective nine-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 nine months ended September 30 of either year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased by $1.3 million, or 1.0%, to $126.0 million for the nine months ended September 30, 2018, as compared to $127.3 million for the nine months ended September 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 $1.73 per Boe or 7.9% from $21.82 per Boe for the nine months ended September 30, 2017 to $20.09 per Boe for the nine months ended September 30, 2018.

Impairment of oil and gas properties. As a result of the Arkoma Divestiture, the Company recognized an impairment charge due to the loss on disposal of the Arkoma Basin oil and gas property assets and related liabilities. Based on the Company’s sales price, an impairment charge of $148.0 million, before tax, was recognized during the nine months ended September 30, 2017. No impairment charges were recognized during the nine months ended September 30, 2018.

General and administrative. General and administrative expenses decreased by $0.3 million, or 1.2%, to $24.2 million for the nine months ended September 30, 2018, as compared to $24.5 million for the nine months ended September 30, 2017. Non-cash compensation expense decreased $4.4 million, from $6.0 million for the nine months ended September 30, 2017 to $1.6 million for the nine months ended September 30, 2018. This decrease was offset by additional compensation expense of $1.7 million in the nine months ended September 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 $2.84 per Boe for the nine months ended September 30, 2017 to $3.51 per Boe for the nine months ended September 30, 2018. The increase was primarily due to our ongoing restructuring efforts.

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Interest expense. Interest expense increased by $28.7 million, or 74.7%, to $67.1 million for the nine months ended September 30, 2018, as compared to $38.4 million for the nine months ended September 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 debt issuance costs of $3.8 million during the nine months ended September 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 nine months ended September 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 nine months ended September 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 $52.1 million for the nine months ended September 30, 2018, as compared to a net gain of $11.3 million for the nine months ended September 30, 2017. The loss was primarily driven by higher average crude oil prices ($66.93 per barrel) for the nine months ended September 30, 2018, as compared to the crude oil prices as of December 31, 2017 ($60.46 per barrel).

Other income (expense). Other income (expense) for the nine months ended September 30, 2018 was net income of $1.0 million, as compared to net income of $14.4 million for the nine months ended September 30, 2017. Other income (expense) during the nine months ended September 30, 2018 was primarily related to an increase in the TRA valuation allowance which resulted in income of $1.0 million, as opposed to income of $15.8 million during the nine months ended September 30, 2017.

Income taxes. The provision for federal and state income taxes for the nine months ended September 30, 2018 was a benefit of $27.0 million resulting in a 19.5% effective tax rate as a percentage of our pre-tax book income for the nine months ended September 30, 2018 as compared to a benefit of $2.7 million resulting in a 1.2% effective tax rate as a percentage of our pre-tax book income for the nine months ended September 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 nine months ended September 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 nine months ended September 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 development of our assets and 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 maintain and 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 September 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. However, we are currently operating at a net loss and we may have difficulty accessing other sources of capital, including through private and public sales of debt and equity or borrowings under credit facilities. As a result, we may be unable to generate additional cash to meet financial obligations and planned capital expenditures.

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 planned 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

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returns and potential to generate near-term cash flow. We may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We continuously monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and completion costs, industry conditions, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control.

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


	Nine Months Ended September 30,
(in thousands of dollars)	2018		2017
Net cash provided by operating activities	$	45,001	$	41,425
Net cash used in investing activities		(186,505)		(47,530)
Net cash provided by / (used in) financing activities		215,708		(23,059)
Net increase (decrease) in cash	$	74,204	$	(29,164)

Cash flow provided by operating activities

Net cash provided by operating activities was $45.0 million during the nine months ended September 30, 2018 as compared to $41.4 million during the nine months ended September 30, 2017. The increase in operating cash flows was primarily due to the $50.4 million increase in oil and gas revenues for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017, driven by the increase in commodity prices and production volumes. The increase in oil and gas revenues was offset by the impact of commodity derivative losses during the nine months ended September 30, 2018.

Cash flow (used in) investing activities

Net cash used in investing activities was $186.5 million during the nine months ended September 30, 2018 as compared to $47.5 million during the nine months ended September 30, 2017. The increase in investing cash used was primarily driven by cash used toward current period settlements of matured derivative contracts of $42.7 million during the nine months ended September 30, 2018 as compared to cash provided by current period settlements of matured derivative contracts of $69.4 million during the nine months ended September 30, 2017. Additionally, during the nine months ended September 30, 2018 there were no significant divestitures. In contrast, during the nine months ended September 30, 2017, the Company closed on the Arkoma Divestiture which resulted in investing cash flows of $52.8 million.

Cash flow provided by / (used in) financing activities

Net cash provided by financing activities was $215.7 million during the nine months ended September 30, 2018 as compared to $23.1 million during the nine months ended September 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.

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

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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.

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 September 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 September 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 5.4%. 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

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prices, have historically been highly volatile and may be highly volatile in the future. This high degree of volatility causes a high degree of uncertainty associated with the estimation of reserve quantities and estimated future cash flows. Therefore, future results are highly uncertain and subject to potentially significant revisions. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions, as such revisions could be negatively impacted by:

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

Increases in service costs;

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

Increases in operating costs;

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

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

Commodity price risk and hedges

Our principal market risk exposure is to oil, natural gas and NGL prices, which are inherently volatile. As such, future earnings are subject to change due to fluctuations in such prices. Realized prices are primarily driven by the prevailing prices for oil and regional spot prices for natural gas and NGLs. We have used, and expect to continue to use, oil, natural gas and NGL derivative contracts to reduce our risk of price fluctuations of these commodities. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. The fair value of our oil, natural gas and NGL derivative contracts at September 30, 2018 was a net liability of $56.3 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 September 30, 2018, borrowings under the 2022 Notes, the 2023 Notes and the 2023 First Lien Notes bore interest at a weighted average rate of 6.75%, 9.25% and 9.25%, respectively. During the nine months ended September 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 our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Evaluation of Disclosure Controls and Procedures

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

Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures. Based on that evaluation, our principal executive officer and principal financial officer concluded that as of September 30, 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. 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. Because we are a smaller reporting company as defined in Rule 12b-2 of the Exchange Act, we are exempt from Section 404(b) of the Sarbanes-Oxley Act and our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal control over financial reporting until such time as we cease being a smaller reporting company.

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.

Future commodity price declines or downward reserve revisions may result in write downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write down constitutes a non-cash charge to earnings. Such impairment may be accompanied by a reduction in proved reserves, thereby increasing future depletion charges per unit of production. We may incur impairment charges and related reductions in proved reserves in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. If commodity prices decline relative to their historical levels, we may incur future impairments to long lived assets.

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As a result of our third quarter 2018 evaluations, we did not recognize an impairment charge for proved properties. However, our current liquidity position may cause us to recognize a significant impairment on the assets in the Western Anadarko Basin, which had a carrying value of approximately $1.2 billion as of September 30, 2018.

Our market capitalization is nearing the lower limits permitted by the NYSE. In addition, we are not currently compliant with the NYSE’s requirement to have a majority-independent Board of Directors and three independent directors on the Audit Committee of our Board of Directors. If we cease to be compliant with the NYSE’s market capitalization or audit committee requirements, we 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, including maintaining a global market capitalization over a consecutive 30 trading-day period of at least $15,000,000. Our global market capitalization on October 26, 2018 was $14.0 million and our global market capitalization over the consecutive 30 trading-day period ending October 26, 2018 was approximately $26.2 million. Assuming that our market capitalization as of October 26, 2018 remains unchanged, we would cease to be compliant with the NYSE’s continued listing requirements on November 29, 2018. If we fail to comply with the global market capitalization requirement, the NYSE can initiate suspension and delisting procedures.

In addition, as a result of the departures of John V. Lovoi and Paul B. Loyd, Jr. from our Board of Directors, we do not currently have a majority-independent Board and only have two independent directors available to serve on the Audit Committee of our Board of Directors. NYSE rules requires that a listed company have a majority-independent board of directors and three independent directors on their audit committee. If we are unable to identify a third independent director who causes our Board to be majority-independent and qualifies for service on the Audit Committee of our Board of Directors, the NYSE may initiate suspending and delisting procedures.

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
3.1		Amendment to the Amended and Restated Certificate of Incorporation of Jones Energy, Inc., effective September 7, 2018 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on September 10, 2018).
3.2		Certificate of Correction to Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Jones Energy, Inc., effective September 7, 2018 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on September 10, 2018).
10.1*		Amended and Restated Employment Agreement, dated September 24, 2018 and effective July 12, 2018, between Jones Energy, LLC and Carl F. Gielser, Jr.
10.2*		Form of Cash Award Agreement
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: November 2, 2018	By:	/s/ Robert J. Brooks
	Name: Robert J. Brooks
	Title: Chief Financial Officer (Principal Financial Officer)

Signature Page to Form 10-Q (Q3 2018)

Jones Energy, Inc. - FORM 10-Q - November 2, 2018

Attached files

Jones Energy, Inc. Reports