Jones Energy, Inc. - FORM 10-Q

Attached files

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EX-32.2 - EX-32.2 - Jones Energy, Inc.	jone-20170930ex3226a1c7d.htm
EX-32.1 - EX-32.1 - Jones Energy, Inc.	jone-20170930ex321f16e55.htm
EX-31.2 - EX-31.2 - Jones Energy, Inc.	jone-20170930ex31213deb9.htm
EX-31.1 - EX-31.1 - Jones Energy, Inc.	jone-20170930ex311872687.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, 2017

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

Commission file number 001-36006

Jones Energy, Inc.

(Exact name of registrant as specified in its charter)

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

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

Robert J. Brooks

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

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

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

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

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

Large accelerated filer ☐		Accelerated filer ☒

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

Emerging growth company ☒

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

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

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

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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

Balance Sheets	1

Statements of Operations	2

Statement of Changes in Stockholders’ Equity	3

Statements of Cash Flows	4

Notes to the Consolidated Financial Statements	5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	43

Item 3. Quantitative and Qualitative Disclosures About Market Risk	54

Item 4. Controls and Procedures	56

PART II—OTHER INFORMATION	56

Item 1. Legal Proceedings	56

Item 1A. Risk Factors	57

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	58

Item 3. Defaults upon Senior Securities	58

Item 4. Mine Safety Disclosures	58

Item 5. Other Information	58

Item 6. Exhibits	58

SIGNATURES	59

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

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PART 1—FINANCIAL INFORMATION

Item 1. Financial Statements

Jones Energy, Inc.

Consolidated Balance Sheets (Unaudited)


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

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

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Jones Energy, Inc.

Consolidated Statements of Operations (Unaudited)


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

Earnings (loss) per share (1) :
Basic - Net income (loss) attributable to common shareholders	$	(0.91)	$	(0.24)	$	(2.30)	$	(0.40)
Diluted - Net income (loss) attributable to common shareholders	$	(0.91)	$	(0.24)	$	(2.30)	$	(0.40)

Weighted average Class A shares outstanding (1) :
Basic		73,089		44,993		67,029		37,299
Diluted		73,089		44,993		67,029		37,299

(1)

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

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

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Jones Energy, Inc.

Statement of Changes in Stockholders’ Equity (Unaudited)


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

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

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Jones Energy, Inc.

Consolidated Statements of Cash Flows (Unaudited)


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

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

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Jones Energy, Inc.

Notes to the Consolidated Financial 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, 2017, the Company held 74,353,789 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 23,718,779 JEH Units are held by the Class B shareholders. The Class B shareholders have no voting rights with respect to their economic interest in JEH, resulting in the Company reporting this ownership interest as a non-controlling interest.

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

On August 25, 2016, the Company issued 1,840,000 shares of its 8.0% Series A Perpetual Convertible Preferred Stock, par value $0.001 per share (the “Series A preferred stock”), pursuant to a registered public offering at $50 per share. See Note 12, “Stockholders’ and Mezzanine equity”.

Description of Business

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

2. Significant Accounting Policies

Basis of Presentation

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

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

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

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

Use of Estimates

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

Production taxes

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

Recent Accounting Pronouncements

Adopted in the current year-to-date period:

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

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

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adoption date. Adoption did not have a material impact on the financial position, cash flows or results of operations.

To be adopted in a future period:

In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers,” which creates a new topic in the Accounting Standards Codification (“ASC”), topic 606, “Revenue from Contracts with Customers.” This standard sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09 by one year. The amendments are now effective for interim and annual reporting periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis. Early adoption is permitted.

The Company is in the process of comparing our current revenue recognition policies to the new requirements for each of our revenue categories based upon review of our current contracts by product category and homogenous groupings. To date, our analysis of these homogenous groupings does not indicate any significant change to our current revenue recognition methodology, although we do expect some changes in presentation of gross revenues and expenses upon adoption of the standard; such costs are currently offset against revenues. Our evaluation is not yet complete, and we have not fully concluded on the overall impacts of adopting the new requirements. In addition to changes in the presentation of the Company’s Consolidated Statement of Operations, we expect to expand disclosures related to revenue recognition. The Company will continue to further evaluate the effect that the adoption of Update 2014-09 and Update 2015-14 will have on our financial statements and disclosures. We anticipate adoption of Update 2014-09 and Update 2015-14 effective as of January 1, 2018 applied on a modified retrospective basis.

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

In August 2017, the FASB issued ASU 2017-12, “Derivatives and Hedging” (Topic 815). The amendments in this update apply to any entity that elects to apply hedge accounting in accordance with current GAAP. This standard expands an entity’s ability to apply hedge accounting for nonfinancial and financial risk components and allows for a simplified approach for fair value hedging of interest rate risk. The standard also eliminates the need to separately measure and report hedge ineffectiveness and generally requires the entire change in fair value of a hedging instrument to be presented in the same income statement line as the hedged item. Additionally, the standard simplifies the hedge documentation and effectiveness assessment requirements under the previous guidance. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the impacts of the amendment to our financial statements and accounting practices for hedging, as well as our anticipated adoption date which would occur either on or before January 1, 2019.

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3. Revision of Previously Issued Financial Statements

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

The following table presents the effect of the errors on our Consolidated Balance Sheet:


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

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


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

Earnings (loss) per share (1) :
Basic - Net income (loss) attributable to common shareholders	$	(1.28)	$	(1.39)	$	0.11
Diluted - Net income (loss) attributable to common shareholders	$	(1.28)	$	(1.39)	$	0.11

Weighted average Class A shares outstanding (1) :
Basic		65,681		65,681		—
Diluted		65,681		65,681		—

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	Six months ended June 30, 2017
(in thousands of dollars except per share data)	As corrected		As filed		Change
Operating costs and expenses
Impairment of oil and gas properties	$	148,016	$	161,886	$	(13,870)
Total operating expenses		275,931		289,801		(13,870)
Operating income (loss)		(186,072)		(199,942)		13,870
Other income (expense)
Other income (expense)		28,081		30,414		(2,333)
Other income (expense), net		46,364		48,697		(2,333)
Income (loss) before income tax		(139,708)		(151,245)		11,537
Income tax provision (benefit)		(2,215)		(2,398)		183
Net income (loss)		(137,493)		(148,847)		11,354
Net income (loss) attributable to non-controlling interests		(53,890)		(58,221)		4,331
Net income (loss) attributable to controlling interests	$	(83,603)	$	(90,626)	$	7,023
Net income (loss) attributable to common shareholders	$	(87,596)	$	(94,619)	$	7,023

Earnings (loss) per share (1) :
Basic - Net income (loss) attributable to common shareholders	$	(1.37)	$	(1.48)	$	0.11
Diluted - Net income (loss) attributable to common shareholders	$	(1.37)	$	(1.48)	$	0.11

Weighted average Class A shares outstanding (1) :
Basic		63,948		63,948		—
Diluted		63,948		63,948		—

________________________________________

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

The following table presents the effect of the errors on our Statement of Changes in Stockholders’ Equity:


	Six months ended June 30, 2017
	Retained				Total
	(Deficit)/		Non-controlling		Stockholders'
(amounts in thousands)	Earnings		Interest		Equity
As corrected - Net income (loss)	$	(83,603)	$	(53,890)	$	(137,493)
As filed - Net income (loss)	$	(90,626)	$	(58,221)		(148,847)
Change - Net income (loss)	$	7,023	$	4,331	$	11,354

As corrected - Balance at June 30, 2017	$	(114,454)	$	398,662	$	761,337
As filed - Balance at June 30, 2017	$	(121,477)	$	394,331	$	749,983
Change - Balance at June 30, 2017	$	7,023	$	4,331	$	11,354

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


	Six months ended June 30, 2017
(in thousands of dollars)	As corrected		As filed		Change
Cash flows from operating activities
Net income (loss)	$	(137,493)	$	(148,847)	$	11,354
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Impairment of oil and gas properties		148,016		161,886		(13,870)
Change in liability under tax receivable agreement		(28,266)		(30,599)		2,333
Changes in operating assets and liabilities
Other assets		(12,407)		(12,590)		183
Net cash provided by operations		21,478		21,478		—
Net increase (decrease) in cash		(28,388)		(28,388)		—
Cash
Beginning of period		34,642		34,642		—
End of period	$	6,254	$	6,254	$	—

We assessed the materiality of the errors on prior periods’ financial statements in accordance with SEC Staff Accounting Bulletin (“SAB”) Topic 1.M, Materiality, codified in ASC Topic 250, Presentation of Financial Statements, (“ASC 250”) and concluded that the errors were not material to any prior periods. The Company will revise our Consolidated Statement of Operations for the three and six-month periods ended June 30, 2017 and our Consolidated Statements of Cash Flows for the six months ended June 30, 2017 in future filings to correct the errors.

4. Acquisitions and Divestitures

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

Merge Acquisition

On September 22, 2016, JEH acquired oil and gas properties located in the Merge area of the STACK/SCOOP (the “Merge”) play in Central Oklahoma (the “Merge Acquisition”) from SCOOP Energy Company, LLC for cash consideration of $134.4 million, net of the final working capital settlement of $2.4 million received in the first quarter of 2017. The oil and gas properties acquired in the Merge Acquisition, on a closed and funded basis, principally consist of 16,975 undeveloped net acres in Canadian, Grady and McClain Counties, Oklahoma. This transaction has been accounted for as an asset acquisition. The Company used proceeds from our equity offerings to fund the purchase. See Note 12, “Stockholders’ and Mezzanine equity”.

Anadarko Acquisition

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

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

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Arkoma Divestiture

On August 1, 2017, JEH closed its previously announced agreement to sell its Arkoma Basin properties (the “Arkoma Assets”) for a purchase price of $65.0 million, prior to customary effective date adjustments of $7.3 million, and subject to customary post-close adjustments (the “Arkoma Divestiture”). JEH may also receive up to $2.5 million in contingent payments based on natural gas prices. No amounts have been recorded related to this contingent payment as of September 30, 2017.

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

5. Properties, Plant and Equipment

Oil and Gas Properties

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


	September 30,		December 31,
(in thousands of dollars)	2017		2016
Mineral interests in properties
Unproved	$	190,722	$	213,153
Proved		882,386		1,054,683
Wells and equipment and related facilities		1,375,932		1,395,291
		2,449,040		2,663,127
Less: Accumulated depletion and impairment		(870,301)		(919,539)
Net oil and gas properties	$	1,578,739	$	1,743,588

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

The Company capitalizes interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use. During the three and nine months ended September 30, 2017, the Company capitalized $0.1 million and $0.3 million, respectively, associated with such in progress projects. The Company did not capitalize any interest during the three and nine months ended September 30, 2016 as no projects lasted more than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.

Depletion of oil and gas properties amounted to $46.1 million and $126.6 million for the three and nine months ended September 30, 2017, respectively, and $36.3 million and $115.6 million for the three and nine months ended September 30, 2016, respectively.

The Company continues to monitor its proved and unproved properties for impairment. No impairments of proved or unproved properties were recorded as a result of our standard impairment assessment during the nine months ended September 30, 2017 or 2016. However, as noted in Note 4, “Acquisitions and Divestitures - Arkoma Divestiture,” the Company recognized an impairment charge of $148.0 million during the nine months ended September 30, 2017 resulting from the sale of the Arkoma Assets.

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Other Property, Plant and Equipment

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


	September 30,		December 31,
(in thousands of dollars)	2017		2016
Leasehold improvements	$	1,186	$	1,213
Furniture, fixtures, computers and software		4,391		4,170
Vehicles		1,768		1,677
Aircraft		910		910
Other		211		284
		8,466		8,254
Less: Accumulated depreciation and amortization		(5,901)		(5,258)
Net other property, plant and equipment	$	2,565	$	2,996

Depreciation and amortization of other property, plant and equipment amounted to $0.3 million and $0.8 million for the three and nine months ended September 30, 2017, respectively, and $0.3 million and $0.9 million for the three and nine months ended September 30, 2016, respectively.

6. Long-Term Debt

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


(in thousands of dollars)	September 30, 2017		December 31, 2016
Revolver	$	151,000	$	178,000
2022 Notes		409,148		409,148
2023 Notes		150,000		150,000
Total principal amount		710,148		737,148
Less: unamortized discount		(5,481)		(6,240)
Less: debt issuance costs, net		(5,927)		(6,899)
Total carrying amount	$	698,740	$	724,009

Senior Unsecured Notes

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

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

During 2016, the Company purchased an aggregate principal amount of $190.9 million of its senior unsecured notes through several open-market and privately negotiated purchases. The Company purchased $90.9 million principal amount of its 2022 Notes for $38.1 million, and $100.0 million principal amount of its 2023 Notes for $46.5 million, in each case excluding accrued interest and including any associated fees. The Company used cash on hand and borrowings from its Revolver to fund the note purchases. In conjunction with the extinguishment of this debt, JEH recognized cancellation of debt income of $99.5 million for the twelve months ended December 31, 2016, on a pre-tax basis. This income is recorded in Gain on debt extinguishment on the Company’s

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Consolidated Statement of Operations. Of the Company’s total repurchases, $20.3 million principal amount of its 2022 Notes were not cancelled and are available for future reissuance, subject to applicable securities laws.

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

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

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

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

Other Long-Term Debt

The Company has a Senior Secured Revolving Credit Facility (the “Revolver”) with a syndicate of banks. On May 15, 2017 at its bi-annual redetermination, the borrowing base under the Revolver was reaffirmed at $425.0 million. Upon closing of the Arkoma Divestiture on August 1, 2017, the Company’s borrowing base was reduced to $375.0 million, where it remained as of September 30, 2017. The Company’s oil and gas properties are pledged as collateral to secure its obligations under the Revolver.

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

Interest on the Revolver is calculated, at the Company’s option, at either (a) the London Interbank Offered (“LIBO”) rate for the applicable interest period plus a margin of 1.50% to 2.50% based on the level of borrowing base utilization at such time or (b) the greatest of the federal funds rate plus 0.50%, the one month adjusted LIBO rate plus 1.00%, or the prime rate announced by Wells Fargo Bank, N.A. in effect on such day, in each case plus a margin of 0.50% to 1.50% based on the level of borrowing base utilization at such time. For the three and nine months ended September 30, 2017, the average interest rates under the Revolver were 3.12% and 2.84%, respectively, on average outstanding balances of $172.9 million and $187.5 million, respectively. For the three and nine months ended September 30, 2016, the average interest rates under the Revolver were 2.29% and 2.38%, respectively, on average outstanding balances of $184.5 million and $170.9 million, respectively.

Total interest and commitment fees under the Revolver were $1.6 million and $4.7 million for the three and nine months ended September 30, 2017, respectively, and $1.3 million and $4.0 million for the three and nine months ended September 30, 2016, respectively.

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

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

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

As of September 30, 2017, our total leverage ratio was 3.90 to 1.00 and our current ratio was 2.49 to 1.00, as calculated based on the requirements in our covenants. We were in compliance with all terms of our Revolver at September 30, 2017.

If an event of default exists under the Revolver, the lenders would be able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change of control, as defined in the Revolver.

Going Concern Assessment and Management’s Plans

Pursuant to the FASB ASU 2014-15, the Company has assessed its ability to continue as a going concern for a period of one year from the date of the issuance of these financial statements. Substantial doubt about an entity’s ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meet its obligations as they become due within one year from the financial statement issuance date. As discussed above in “Other Long-Term Debt”, the Company has an obligation to maintain certain financial ratios in accordance with our covenants under the Revolver. Specifically, we are required to maintain a total leverage ratio of not greater than 4.00 to 1.00 and a current ratio of not less than 1.00 to 1.00, each as of the last day of any fiscal quarter. As of September 30, 2017, we were in compliance with all terms of our Revolver, with a total leverage ratio of 3.90 to 1.00 and a current ratio of 2.49 to 1.00. However, based on current projections, we expect to breach the total leverage ratio under our Revolver beginning with the next measurement date of December 31, 2017.

Management has initiated negotiations with our lenders under the Revolver to, among other things, modify or suspend the financial covenant requirements discussed above, thereby suspending our need to comply with the total leverage ratio for a specified period of time. We expect negotiations with our lenders will be finalized in advance of our next financial ratio measurement date of December 31, 2017. However, there can be no assurances that the requisite lenders under our Revolver approve any such amendment.

Any failure to comply with the conditions and covenants in our Revolver that is not waived by our lenders or otherwise cured could lead to a termination of our Revolver, acceleration of all amounts due under our Revolver, or trigger cross default provisions under other financing arrangements. These factors raise substantial doubt about the Company’s ability to continue as a going concern.

7. Derivative Instruments and Hedging Activities

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

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

Hedging Positions


	September 30, 2017
						Weighted		Final
		Low		High		Average		Expiration
Oil swaps	Exercise price	$	44.60	$	85.60	$	51.97	December 2020
	Offset exercise price	$	42.00	$	42.00	$	42.00
	Net barrels per month		55,000		216,000		116,462
Natural gas swaps	Exercise price	$	2.76	$	4.57	$	2.98	December 2020
	Net MMbtu per month		700,000		1,890,000		1,169,231
Natural gas liquids swaps	Exercise price	$	18.06	$	72.52	$	29.08	December 2018
	Barrels per month		130,000		145,000		139,333
Natural gas basis swaps	Exercise price	$	(0.50)	$	(0.30)	$	(0.39)	March 2019
	Net MMbtu per month		300,000		800,000		564,706
Oil collars	Puts (floors)	$	45.00	$	50.00	$	48.52	December 2019
	Calls (ceilings)	$	56.60	$	61.00	$	59.64
	Net barrels per month		65,000		73,000		67,500
Natural gas collars	Puts (floors)	$	2.55	$	2.55	$	2.55	December 2019
	Calls (ceilings)	$	3.08	$	3.41	$	3.19
	Net barrels per month		950,000		1,050,000		990,833

The Company recognized net losses on derivative instruments of $32.5 million and net gains of $11.3 million for the three and nine months ended September 30, 2017, respectively. The Company recognized net gains on derivative instruments of $4.0 million and net losses of $18.8 million for the three and nine months ended September 30, 2016, respectively.

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

During the three and nine months ended September 30, 2017, the Company unwound its realized 2018 and 2019 hedges resulting in approximately $14.8 million and $42.8 million, respectively, of recognized gains which have been included in Net gain (loss) on commodity derivatives on the Company’s Consolidated Statement of Operations.

Offsetting Assets and Liabilities

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

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

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


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

8. Fair Value Measurement

Fair Value of Financial Instruments

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

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

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

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

Valuation Hierarchy

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

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

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

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

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


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


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

(1)

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

(2)

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

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


	Quantitative Information About Level 3 Fair Value Measurements
	Fair Value			Unobservable
Commodity Price Hedges	(000’s)		Valuation Technique	Input	Range
Natural gas liquid swaps	$	(1,266)	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures	$22.89 - $23.94 per barrel
Crude oil collars	$	1,988	Use a discounted option model approach using inputs including interpolated volatilities for certain settlement months where market volatility quotes were unavailable for the option strike price	Market volatility quotes at the option strike for certain settlement months in 2019	$45.00 - $61.00 per barrel
Natural gas collars	$	(984)	Use a discounted option model approach using inputs including interpolated volatilities for certain settlement months where market volatility quotes were unavailable for the option strike price	Market volatility quotes at the option strike for certain settlement months in 2019	$2.55 - $3.41 per barrel

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

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


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

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Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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


	September 30, 2017				December 31, 2016
	Principal				Principal
(in thousands of dollars)	Amount		Fair Value		Amount		Fair Value
Debt:
Revolver	$	151,000	$	151,000	$	178,000	$	178,000
2022 Notes		409,148		338,496		409,148		393,150
2023 Notes		150,000		124,560		150,000		153,375

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

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

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

9. Asset Retirement Obligations

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


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

10. Stock-based Compensation

Management Unit Awards

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

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


		Weighted Average
		Grant Date Fair Value
	JEH Units	per Share
Unvested at December 31, 2016	90,762	$	15.00
Granted	—		—
Forfeited	—		—
Vested	(45,381)		15.00
Unvested at September 30, 2017	45,381	$	15.00

Stock compensation expense associated with the Management Units was $0.1 million and $0.5 million for the three and nine months ended September 30, 2017, respectively, and $0.2 million and $1.0 million for the three and nine months ended September 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

2013 Omnibus Incentive Plan

Under the Amended and Restated Jones Energy, Inc. 2013 Omnibus Incentive Plan (the “LTIP”), established in conjunction with the Company’s IPO and restated on May 4, 2016 following approval by the Company’s stockholders, the Company has reserved a total of 8,185,771 shares of Class A common stock for non-employee director, consultant, and employee stock-based compensation awards, as adjusted for the effects of the Special Stock Dividend and the preferred stock dividends paid in shares, as described in Note 12 “Stockholders’ and Mezzanine equity”.

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

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

Restricted Stock Unit Awards

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

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


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

(1)

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

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Company’s August 15, 2017 preferred stock dividend paid entirely in shares of the Company’s Class A common stock, as described in Note 12 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards. This increase is in addition to the adjustment for the effects of the Special Stock Dividend previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.

Stock compensation expense associated with the employee restricted stock unit awards was $1.1 million and $3.1 million for the three and nine months ended September 30, 2017, respectively, and $1.0 million and $2.0 million for the three and nine months ended September 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

Performance Share Unit Awards

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

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

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


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

For the performance share units granted during the nine months ended September 30, 2017, the Monte Carlo simulation model resulted in approximately 29% of performance share units expected to be earned.

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


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

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(1)

Increase of 0.002195 units for each unvested performance share unit award at the time of the Company’s May 15, 2017 preferred stock dividend for the portion of such dividend paid in shares of the Company’s Class A common stock and of 0.021931 units for each unvested performance share unit award at the time of the Company’s August 15, 2017 preferred stock dividend paid entirely in shares of the Company’s Class A common stock, as described in Note 12 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards. This increase is in addition to the adjustment for the effects of the Special Stock Dividend previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.

Stock compensation expense associated with the performance share unit awards was $0.7 million and $1.7 million for the three and nine months ended September 30, 2017, respectively, and $0.8 million and $1.9 million for the three and nine months ended September 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

Performance Unit Awards

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

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


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

For the performance units granted during the nine months ended September 30, 2017, the Monte Carlo simulation

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

Stock compensation expense associated with the performance unit awards was an expense of less than $0.1 million for the three and nine months ended September 30, 2017, respectively and $0.1 million and $0.2 million for the three and nine months ended September 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations. As of September 30, 2017, unrecognized compensation expense of $0.5 million related to the performance unit awards, subject to re-measurement and adjustment for the change in estimated final value as of the end of each reporting period, and is expected to be recognized over the remaining weighted average service period of 1.7 years.

Restricted Stock Awards

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

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


		Weighted Average
	Restricted	Grant Date Fair Value
	Stock Awards	per Share
Unvested at December 31, 2016	152,050	$	3.68
Adjustment (1)	3,948		—
Granted	180,000		2.25
Forfeited	—		—
Vested	(152,050)		3.68
Unvested at September 30, 2017	183,948	$	2.20

(1)

Increase of 0.021931 units for each unvested performance share unit award at the time of the Company’s August 15, 2017 preferred stock dividend paid entirely in shares of the Company’s Class A common stock, as described in Note 12 “Stockholders’ and Mezzanine equity,” in accordance with the terms of the original awards. This increase is in addition to the adjustment for the effects of the Special Stock Dividend previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017.

Stock compensation expense associated with awards to the members of the Board of Directors was $0.1 million and $0.4 million for the three and nine months ended September 30, 2017, respectively, and $0.1 million and $0.4 million for the three and nine months ended September 30, 2016, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

11. Income Taxes

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

The Company’s effective tax rate was 0.6% and 1.2% for the three and nine months ended September 30, 2017, respectively, and 22.6% and 20.2% for the three and nine months ended September 30, 2016, respectively. The effective tax rate reduction is primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets. The effective rate differs from the statutory rate of 35% due to net income allocated to the non-controlling interest, percentage depletion, state income taxes, the valuation allowance recorded against deferred tax assets, and other permanent differences between book and tax accounting.

The Company’s income tax provision was a benefit of $0.5 million and $2.7 million for the three and nine months ended September 30, 2017, respectively, and a benefit of $6.5 million and $8.2 million for the three and nine months ended September 30, 2016, respectively.

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


	Three Months Ended September 30,				Nine Months Ended September 30,
(in thousands of dollars)	2017		2016		2017		2016
Jones Energy, Inc.	$	(495)	$	(6,254)	$	(2,711)	$	(7,900)
Non-controlling interest		3		(295)		4		(334)
Income tax provision (benefit)	$	(492)	$	(6,549)	$	(2,707)	$	(8,234)

The Company had deferred tax assets for its federal and state net operating loss carry forwards at September 30, 2017 recorded in its deferred taxes. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. As of September 30, 2017, we have a valuation allowance of $5.4 million as a result of management’s assessment of the realizability of federal and state deferred tax assets.

Internal Revenue Code ("IRC") Section 382 addresses corporate shareholder changes and specifically limits the utilization of certain deductions and other tax attributes on an annual basis following an ownership change as

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defined under the IRC. The Company experienced an ownership change within the meaning of IRC Section 382 during the third quarter that will subject a portion of the Company’s net operating loss carryforwards and other tax attributes to an IRC Section 382 limitation in future periods.

Tax Receivable Agreement

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

The actual amount and timing of payments to be made under the TRA will depend upon a number of factors, including the amount and timing of taxable income generated in the future, changes in future tax rates, the use of loss carryovers, and the portion of the Company’s payments under the TRA constituting imputed interest. As of September 30, 2017 and December 31, 2016, the Company had a gross TRA liability of $60.7 million and $45.7 million, respectively. As a result of the valuation allowance recorded against the Company’s deferred tax assets associated with prior exchanges, the TRA liability was reduced, as the payment of the TRA liability is dependent on the realizability of the associated deferred tax assets. As of September 30, 2017 and December 31, 2016, the amount of the TRA liability was reduced by $4.9 million and $2.7 million, respectively, as a result of the valuation allowance recorded against the Company’s deferred tax assets. To the extent the Company does not realize all of the tax benefits in future years or in the event of a change in future tax rates, this liability may change.

As of September 30, 2017 and December 31, 2016, the Company had recorded a net TRA liability of $55.8 million and $43.0 million, respectively, for the estimated payments that will be made to the Class B shareholders who have exchanged shares, after adjusting for the TRA liability reduction, along with corresponding deferred tax assets, net of valuation allowances, of $65.7 million and $50.6 million, respectively, as a result of the increase in tax basis from such shares exchanged by current and former Class B shareholders.

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

Cash Tax Distributions

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

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

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12. Stockholders’ and Mezzanine equity

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

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

Equity Distribution Agreement

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

During the nine months ended September 30, 2017, the Company sold approximately 3.7 million Class A Shares under the Equity Distribution Agreement for net proceeds of approximately $8.4 million ($8.7 million gross proceeds, net of approximately $0.3 million in commissions and professional services expenses). During the three months ended September 30, 2017, the Company did not sell any Class A Shares under the Equity Distribution Agreement. The Company used the net proceeds from the sale of shares under the Equity Distribution Agreement for general corporate purposes. As of September 30, 2017, approximately $62.2 million in aggregate offering proceeds remained available to be issued and sold under the Equity Distribution Agreement.

Offering of Class A Common Stock

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

Offering of 8.0% Series A Perpetual Convertible Preferred Stock

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

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

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

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

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

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

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

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

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


(in thousands of dollars)
Mezzanine equity at December 31, 2016	$	88,975
Dividends on preferred stock, net		—
Accretion on preferred stock		438
Mezzanine equity at September 30, 2017	$	89,413

Preferred Stock Dividends

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

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

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

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

Special Stock Dividend

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

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

13. Earnings per Share

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

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


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

(1)

14. Related Parties

Related Party Transactions

Transactions with Our Executive Officers, Directors and 5% Stockholders

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

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

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

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

In connection with the Company’s entering into the 2013 Monarch agreement, Monarch issued to JEH equity interests in Monarch, having an estimated fair value of $15.0 million, in return for marketing services to be provided throughout the term of the agreement. The Company recorded this amount as deferred revenue which is being amortized on an estimated units-of-production basis commencing in September 2013, the first month of product sales to Monarch. The Company amortized $0.5 million and $1.4 million, respectively, of the deferred revenue balance during the three and nine months ended September 30, 2017, and $0.6 million and $1.8 million, respectively, of the deferred revenue balance during the three and nine months ended September 30, 2016. This revenue is recorded in Other revenues on the Company’s Consolidated Statement of Operations.

Following the issuance of $15.0 million Monarch equity interests to JEH, JEH assigned $2.4 million of the equity interests to Jonny Jones, the Company’s chief executive officer and chairman of the Board of Directors, and reserved $2.6 million of the equity interests for future distribution through an incentive plan to certain of the Company’s officers, including Mike McConnell, Robert Brooks and Eric Niccum. The remaining $10.0 million of Monarch equity interests was distributed to certain of the Class B shareholders, which included, among others, Metalmark Capital, the Jones family entities, and certain of the Company’s officers and directors, including Jonny Jones, Mike McConnell and Eric Niccum. As of September 30, 2017, equity interests in Monarch of $0.4 million are included in Other assets on the Company’s Consolidated Balance Sheet. During the three and nine months ended September 30, 2017, equity interests in Monarch of $0.3 million were distributed to management under the incentive plan. The Company recognized expense of $0.1 million and $0.3 million during the three and nine months ended September 30, 2017, respectively, in connection with the incentive plan.

In September 2014, the Company signed a 10-year oil gathering and transportation agreement with Monarch Oil Pipeline LLC, pursuant to which Monarch Oil Pipeline LLC built, at its expense, a new oil gathering system and connected the gathering system to dedicated Company leases in Texas. At the time the Company entered into the agreement, Metalmark Capital owned the majority of the outstanding equity interests of Monarch Oil Pipeline LLC and/or its parent. The system began service during the fourth quarter of 2015 and provides connectivity to both a regional refinery market as well as the Cushing market hub. The Company incurred gathering fees, which were paid to Monarch Oil Pipeline LLC, of $0.5 million and $1.8 million for the three and nine months ended September 30, 2017, respectively, associated with the approximately 0.3 MMBoe and 0.9 MMBoe, respectively, of oil production transported under the agreement. These costs are recorded as an offset to Oil and gas sales in the Company’s Consolidated Statement of Operations. The aforementioned production was recognized as Oil and gas sales on the Company’s Consolidated Statement of Operations at the time it was sold to the purchasers, who are unaffiliated third parties, after passing through the gathering and transportation system. The audit committee of the Board of Directors reviewed and approved the terms of the agreement with Monarch Oil Pipeline LLC.

Purchases of Senior Unsecured Notes

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

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Issuance of Class A Shares

In connection with the August 2016 issuance of Class A common stock pursuant to an underwritten public offering as described above under “Item 11. Stockholders’ and Mezzanine equity—Offering of Class A Common Stock,” affiliates of JVL Advisors, L.L.C. (“JVL”), who then owned more than 5% of a class of voting securities of the Company, purchased 9,025,270 shares of Class A common stock, prior to adjustment for the effects of the 0.087423 per share Special Stock Dividend, as defined in Note 12, “Stockholders’ and Mezzanine equity”, in the offering, for gross proceeds to the Company of $25.0 million, before underwriting discounts and commissions of $1.1 million.

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

it will not acquire any material assets of the Company;

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

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

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

Issuance of Series A Preferred Stock

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

Amended and Restated Registration Rights and Stockholders Agreement

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

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

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

15. Commitments and Contingencies

Litigation

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

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

16. Subsequent Events

Class B to Class A Share Exchanges

On October 2, 2017, certain Class B shareholders, including Metalmark, exchanged an aggregate of 12,689,815 shares of Class B common stock (together with a corresponding number of JEH Units) for shares of Class A common stock on a one-for-one basis (the “October Exchanges”). As of September 30, 2017 and December 31, 2016, the Company had recorded a TRA liability of $55.8 million and $43.0 million, respectively, for the estimated payments that will be made to Class B shareholders who have exchanged shares of Class B common stock, after adjusting for the TRA liability reduction as a result of the increase in tax basis arising from such exchanges. After the October Exchanges, the gross TRA liability increased by approximately $50.3 million. Substantially all of the increase in TRA liability will be offset as a result of the valuation allowance recorded against the deferred tax asset generated in the exchange, the utilization of which would lead to payment of the TRA liability.

Preferred Stock Dividend Declared

On October 9, 2017, the Company’s Board of Directors declared a quarterly dividend per share equal to 8.0% based on the liquidation preference of $50.00 per share on an annualized basis, or $1.00 per share, on the Series A preferred stock, to be paid entirely in shares of Class A common stock (the “November Preferred Dividend”). The price per share of the Class A common stock used to determine the number of shares issued will equal 95% of the average volume-weighted average price per share for each day during the five-consecutive day trading period ending immediately prior to the payment date. The November Preferred Dividend will be paid on November 15, 2017 for the period beginning on the last payment date of August 15, 2017 through November 14, 2017 to shareholders of record as of November 1, 2017.

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17. Subsidiary Guarantors

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

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

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

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

As of September 30, 2017, the Company held 74,353,789 JEH Units and all of the preferred units representing membership interests in JEH, and the remaining 23,718,779 JEH Units are held by the Class B shareholders. The Class B shareholders have no voting rights with respect to their economic interest in JEH.

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

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

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

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During the preparation of the condensed consolidating financial information of Jones Energy, Inc. and Subsidiaries in the second quarter of 2017, it was determined that the Issuer Investment in subsidiaries and the related Eliminations at December 31, 2016 as filed in the Company’s 2016 Form 10-K were improperly calculated and understated by $453.2 million. Additionally, it was determined that the Guarantor Subsidiaries Intercompany payable balances and the related Eliminations and the Issuer Intercompany receivable and the related Eliminations at December 31, 2016 as filed in the Company’s 2016 Form 10-K were improperly calculated and overstated by $453.2 million and $80.0 million, respectively. In addition, it was determined that the Issuer Equity interest in income (loss) and the related Eliminations for the three and nine months period ended September 30, 2016 as filed in the Company’s third quarter 2016 Form 10-Q were improperly calculated and understated by $13.2 million and $19.1 million, respectively. Lastly, it was determined that the Issuer Adjustments to reconcile net income (loss) to net cash provided by operating activities and the related Eliminations for the nine months period ended September 30, 2016 as filed in the Company’s third quarter 2016 Form 10-Q was improperly calculated and overstated by $19.1 million.

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

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

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Jones Energy, Inc.

Condensed Consolidating Balance Sheet

September 30, 2017


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

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Jones Energy, Inc.

Condensed Consolidating Balance Sheet

December 31, 2016


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

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2017


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

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2017


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

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Three Months Ended September 30, 2016


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

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Jones Energy, Inc.

Condensed Consolidating Statement of Operations

Nine Months Ended September 30, 2016


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

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Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2017


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

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Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Nine Months Ended September 30, 2016


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

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Item 2. Management’s Discussion and 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, 2016, filed with the Securities and Exchange Commission (the “Commission”) on March 10, 2017, and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report and in our quarterly report for the quarter ended March 31, 2017, filed with the Commission on May 5, 2017 and our quarterly report on Form 10-Q for the quarter ended June 30, 2017, filed with the Commission on August 7, 2017. Unless indicated otherwise in this Quarterly Report or the context requires otherwise, all references to “Jones Energy,” the “Company,” “our company,” “we,” “our” and “us” refer to Jones Energy, Inc. and its subsidiaries, including Jones Energy Holdings, LLC (“JEH”). Jones Energy, Inc. (“JONE”) is a holding company whose sole material asset is an equity interest in JEH.

Overview

We are an independent oil and gas company engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States, spanning areas of Texas and Oklahoma. Our Chairman and Chief Executive Officer, Jonny Jones, founded our predecessor company in 1988 in continuation of his family’s long history in the oil and gas business, which dates back to the 1920’s. We have grown rapidly by leveraging our focus on low cost drilling and completion methods and our horizontal drilling expertise to develop our inventory and execute several strategic acquisitions. We have accumulated extensive knowledge and experience in developing the Anadarko basin, having concentrated our operations in the Anadarko basin for over 25 years. We have drilled approximately 905 total wells as operator, including nearly 730 horizontal wells, since our formation and delivered compelling rates of return over various commodity price cycles. Our operations are focused on horizontal drilling and completions within two distinct areas in the Texas Panhandle and Oklahoma:

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

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

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

Third Quarter and Year-to-Date 2017 Highlights:

Strong initial rates seen from six recently completed wells in the Merge, with rates still increasing.

First pair of long lateral Merge wells drilled at Company-record pace, currently undergoing completions.

Suspended drilling activity in Western Anadarko, released last remaining rig in October.

Average daily net production for third quarter 2017 of 21.4 MBoe/d.

Working with lenders to increase financial flexibility to enable increased Merge activity in 2018.

Net loss for the third quarter of 2017 of $83.0 million, non-GAAP adjusted net loss of $10.9 million, or a loss of $0.13 per share, and EBITDAX of $47.1 million.

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Updated Capital Expenditures Outlook

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

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Results of Operations

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


(in thousands of dollars except for	Three Months Ended September 30,						Nine Months Ended September 30,
production, sales price and average cost data)	2017		2016		Change		2017		2016		Change
Revenues:
Oil	$	21,566	$	15,817	$	5,749	$	63,145	$	45,239	$	17,906
Natural gas		9,421		9,580		(159)		33,615		21,237		12,378
NGLs		12,649		7,185		5,464		35,667		19,584		16,083
Total oil and gas		43,636		32,582		11,054		132,427		86,060		46,367
Other		566		771		(205)		1,634		2,295		(661)
Total operating revenues		44,202		33,353		10,849		134,061		88,355		45,706
Costs and expenses:
Lease operating		9,458		7,865		1,593		27,689		24,027		3,662
Production and ad valorem taxes		2,757		1,733		1,024		4,641		5,061		(420)
Exploration		1,969		998		971		11,638		1,237		10,401
Depletion, depreciation and amortization		46,353		36,550		9,803		127,343		116,449		10,894
Impairment of oil and gas properties		—		—		—		148,016		—		148,016
Accretion of ARO liability		253		323		(70)		720		913		(193)
General and administrative		7,819		6,448		1,371		24,493		22,078		2,415
Total costs and expenses		68,609		53,917		14,692		344,540		169,765		174,775
Operating income (loss)		(24,407)		(20,564)		(3,843)		(210,479)		(81,410)		(129,069)
Other income (expenses):
Interest expense		(12,817)		(12,792)		(25)		(38,381)		(40,397)		2,016
Gain on debt extinguishment		—		—		—		—		99,530		(99,530)
Net gain (loss) on commodity derivatives		(32,539)		4,014		(36,553)		11,308		(18,769)		30,077
Other income/(expense)		(13,692)		364		(14,056)		14,389		251		14,138
Total other income (expense)		(59,048)		(8,414)		(50,634)		(12,684)		40,615		(53,299)
Income (loss) before income tax		(83,455)		(28,978)		(54,477)		(223,163)		(40,795)		(182,368)
Income tax provision (benefit)		(492)		(6,549)		6,057		(2,707)		(8,234)		5,527
Net income (loss)		(82,963)		(22,429)		(60,534)		(220,456)		(32,561)		(187,895)
Net income (loss) attributable to non-controlling interests		(18,157)		(12,576)		(5,581)		(72,047)		(18,374)		(53,673)
Net income (loss) attributable to controlling interests	$	(64,806)	$	(9,853)	$	(54,953)	$	(148,409)	$	(14,187)	$	(134,222)
Dividends and accretion on preferred stock		(1,966)		(765)		(1,201)		(5,959)		(765)		(5,194)
Net income (loss) attributable to common shareholders	$	(66,772)	$	(10,618)	$	(56,154)	$	(154,368)	$	(14,952)	$	(139,416)

Net production volumes:
Oil (MBbls)		481		396		85		1,391		1,271		120
Natural gas (MMcf)		5,171		4,602		569		15,663		14,130		1,533
NGLs (MBbls)		627		549		78		1,833		1,633		200
Total (MBoe)		1,970		1,712		258		5,835		5,259		576
Average net (Boe/d)		21,413		18,609		2,804		21,374		19,193		2,181
Average sales price, unhedged:
Oil (per Bbl), unhedged	$	44.84	$	39.94	$	4.90	$	45.40	$	35.59	$	9.81
Natural gas (per Mcf), unhedged		1.82		2.08		(0.26)		2.15		1.50		0.65
NGLs (per Bbl), unhedged		20.17		13.09		7.08		19.46		11.99		7.47
Combined (per Boe), unhedged		22.15		19.03		3.12		22.70		16.36		6.34
Average sales price, hedged:
Oil (per Bbl), hedged	$	79.50	$	87.34	$	(7.84)	$	81.44	$	86.26	$	(4.82)
Natural gas (per Mcf), hedged		3.62		3.46		0.16		3.77		3.51		0.26
NGLs (per Bbl), hedged		13.63		17.54		(3.91)		14.30		17.40		(3.10)
Combined (per Boe), hedged		33.26		35.12		(1.86)		34.03		35.69		(1.66)
Average costs (per BOE):
Lease operating	$	4.80	$	4.59	$	0.21	$	4.75	$	4.57	$	0.18
Production and ad valorem taxes		1.40		1.01		0.39		0.80		0.96		(0.16)
Depletion, depreciation and amortization		23.53		21.35		2.18		21.82		22.14		(0.32)
General and administrative		3.97		3.77		0.20		4.20		4.20		—

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Non-GAAP financial measures

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

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

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


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

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

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


	Three Months Ended September 30,						Nine Months Ended September 30,
(in thousands except per share data)	2017			2016			2017			2016
Net income (loss)	$	(82,963)		$	(22,429)		$	(220,456)		$	(32,561)
Net (gain) loss on derivative contracts		32,539			(4,014)			(11,308)			18,769
Current period settlements of matured derivative contracts		21,892			27,538			66,145			101,619
Impairment of oil and gas properties		—			—			148,016			—
Exploration		1,969			998			11,638			1,237
Non-cash stock compensation expense		1,966			2,185			5,702			5,269
Deferred and other non-cash compensation expense		155			213			335			614
(Gain) on debt extinguishment		—			—			—			(99,530)
Financing expenses		—			—			—			—
Tax impact of adjusting items (1)		(15,543)			(5,374)			(48,666)			(5,705)
Change in TRA liability		12,435			(260)			(15,831)			(422)
Change in valuation allowance		16,616			106			62,105			498
Adjusted net income (loss)		(10,934)			(1,037)			(2,320)			(10,212)
Adjusted net income (loss) attributable to non-controlling interests		(3,665)			(1,074)			(6,683)			(6,640)
Adjusted net income (loss) attributable to controlling interests		(7,269)			37			4,363			(3,572)
Dividends and accretion on preferred stock		(1,966)			(765)			(5,959)			(765)
Adjusted net income (loss) attributable to common shareholders	$	(9,235)		$	(728)		$	(1,596)		$	(4,337)

Earnings per share (basic and diluted): (2)	$	(0.91)		$	(0.24)		$	(2.30)		$	(0.40)
Net (gain) loss on derivative contracts		0.33			(0.05)			(0.07)			0.24
Current period settlements of matured derivative contracts		0.23			0.35			0.69			1.41
Impairment of oil and gas properties		—			—			1.51			—
Exploration		0.02			0.01			0.12			0.02
Non-cash stock compensation expense		0.02			0.03			0.06			0.07
Deferred and other non-cash compensation expense		—			—			—			0.01
(Gain) on debt extinguishment		—			—			—			(1.32)
Financing expenses		—			—			—			—
Tax impact of adjusting items (1)		(0.21)			(0.12)			(0.73)			(0.15)
Change in TRA liability		0.17			—			(0.24)			(0.01)
Change in valuation allowance		0.22			—			0.94			0.01
Adjusted earnings per share (basic and diluted)	$	(0.13)		$	(0.02)		$	(0.02)		$	(0.12)

Weighted average Class A shares outstanding: (2)
Basic		73,089			44,993			67,029			37,299
Diluted		73,089			44,993			67,029			37,299
Effective tax rate on net income (loss) attributable to controlling interests		37.9	%		35.5	%		37.9	%		35.5	%

(1)

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

(2)

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

Operating revenues

Oil and gas sales. Oil and gas sales increased $11.0 million, or 33.7%, to $43.6 million for the three months ended September 30, 2017, as compared to $32.6 million for the three months ended September 30, 2016. The increase was attributable to the increase in production volumes ($6.4 million) and the increase in commodity prices ($4.6 million). The increase in production volumes was driven by the year-over-year increase in producing wells due to continued drilling activity. The average realized oil price, excluding the effects of commodity derivative instruments, increased from $39.94 per Bbl for the three months ended September 30, 2016 to $44.84 per Bbl for the three months ended September 30, 2017, or 12.3%. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $2.08 per Mcf for the three months ended September 30, 2016 to $1.82 per Mcf for the three months ended September 30, 2017, or 12.5%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increased from $13.09 per Bbl for the three months ended September 30, 2016 to $20.17 per Bbl for the three months ended September 30, 2017, or 54.1%. Average daily production increased 15.1% to 21,413 Boe per day for the three months ended September 30, 2017 as compared to 18,609 Boe per day for the three months ended September 30, 2016.

Costs and expenses

Lease operating. Lease operating expenses increased by $1.6 million, or 20.3%, to $9.5 million for the three months ended September 30, 2017, as compared to $7.9 million for the three months ended September 30, 2016. The increase in lease operating expenses is primarily attributable to the increase in number of producing wells. On a per unit basis, lease operating expenses increased $0.21 per Boe, or 4.6%, from $4.59 per Boe in the three months ended September 30, 2016 to $4.80 per Boe in the three months ended September 30, 2017.

Production and ad valorem taxes. Production and ad valorem taxes increased by $1.1 million, or 64.7%, to $2.8 million for the three months ended September 30, 2017, as compared to $1.7 million for the three months ended September 30, 2016. Production taxes increased $0.7 million, from $1.5 million for the three months ended September 30, 2016 to $2.2 million for the three months ended September 30, 2017. The increase was attributable to the increase in production volumes. Production tax rates vary between states, products, and production levels; therefore, the overall blended rate is impacted by numerous factors and the mix of producing wells at any given time. Further, estimated ad valorem taxes increased $0.3 million, from $0.2 million for the three months ended September 30, 2016 to $0.5 million for the three months ended September 30, 2017. The average effective rate excluding the impact of ad valorem taxes increased from 4.7% for the three months ended September 30, 2016 to 5.1% for the three months ended September 30, 2017.

Exploration. Exploration expense increased from $1.0 million for the three months ended September 30, 2016 to $2.0 million for the three months ended September 30, 2017. The Company recognized charges for lease abandonment of $1.8 million relating to certain leases that the Company decided during the third quarter of 2017 not to develop. Spending during 2017 primarily related to geological data and seismic processing associated with unproved acreage. No exploratory wells resulted in exploration expense during the three months ended September 30 of either year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $9.8 million, or 26.8%, to $46.4 million for the three months ended September 30, 2017, as compared to $36.6 million for the three months ended September 30, 2016. On a per unit basis, depletion expense increased $2.18 per Boe or 10.2% from $21.35 per Boe for the three months ended September 30, 2016 to $23.53 per Boe for the three months ended September 30, 2017. The increase was primarily the result of capital spending related to our drilling program.

General and administrative. General and administrative expenses increased by $1.4 million, or 21.9%, to $7.8 million for the three months ended September 30, 2017, as compared to $6.4 million for the three months ended September 30, 2016. The increase was primarily attributable to increased headcount associated with the opening of our Oklahoma City office. Non-cash compensation expense decreased $0.3 million, from $2.4 million for the three months ended September 30, 2016 to $2.1 million for the three months ended September 30, 2017. On a per unit basis, general and administrative expenses, excluding all non-cash items, increased from $2.30 per Boe for the three months ended September 30, 2016 to $2.60 per Boe for the three months ended September 30, 2017.

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Interest expense. Interest expense remained consistent at $12.8 million for the three months ended September 30, 2017 and 2016. During the three months ended September 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 3.12%, 6.75% and 9.25%, respectively. Average outstanding balances for the three months ended September 30, 2017 were $172.9 million, $409.1 million and $150.0 million under the Revolver, the 2022 Notes and the 2023 Notes, respectively.

Net gain (loss) on commodity derivatives. The net gain (loss) on commodity derivatives was a net loss of $32.5 million for the three months ended September 30, 2017, as compared to a net gain of $4.0 million for the three months ended September 30, 2016. The loss was primarily driven by higher average crude oil prices ($48.18 per barrel) for the three months ended September 30, 2017, as compared to the crude oil prices as of June 30, 2017 ($46.02 per barrel). The Company unwound its realized 2018 hedges resulting in recognized gains of approximately $14.8 million for the three months ended September 30, 2017. See Note 7, “Derivative Instruments and Hedging Activities,” for further details.

Other income (expense). Other income (expense) for the three months ended September 30, 2017 was net expense of $13.7 million, as compared to net income of $0.4 million for the three months ended September 30, 2016. Other income (expense) during the three months ended September 30, 2017 primarily related to a decrease in the TRA valuation allowance which resulted in expense of $12.4 million.

Income taxes. The provision for federal and state income taxes for the three months ended September 30, 2017 was a benefit of $0.5 million resulting in a 0.6% effective tax rate as a percentage of our pre-tax book income for the quarter as compared to a benefit of $6.5 million resulting in a 22.6% effective tax rate as a percentage of our pre-tax book income for the three months ended September 30, 2016. Our effective tax rate is based on the statutory rate applicable to the U.S. and the blended rate of the states in which we conduct business and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest. The effective tax rate reduction is primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets. See Note 11, “Income Taxes,” for further details.

Results of Operations - Nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016

Operating revenues

Oil and gas sales. Oil and gas sales increased $46.3 million, or 53.8%, to $132.4 million for the nine months ended September 30, 2017, as compared to $86.1 million for the nine months ended September 30, 2016. The increase was attributable to the increase in commodity prices ($33.7 million) and the increase in production volumes ($12.6 million). The increase in production volumes was driven by the year-over-year increase in producing wells due to continued drilling activity. The average realized oil price, excluding the effects of commodity derivative instruments, increased from $35.59 per Bbl for the nine months ended September 30, 2016 to $45.40 per Bbl for the nine months ended September 30, 2017, or 27.6%. The average realized natural gas price, excluding the effects of commodity derivative instruments, increased from $1.50 per Mcf for the nine months ended September 30, 2016 to $2.15 per Mcf for the nine months ended September 30, 2017, or 43.3%. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, increased from $11.99 per Bbl for the nine months ended September 30, 2016 to $19.46 per Bbl for the nine months ended September 30, 2017, or 62.3%. Average daily production increased 11.4% to 21,374 Boe per day for the nine months ended September 30, 2017 as compared to 19,193 Boe per day for the nine months ended September 30, 2016.

Costs and expenses

Lease operating. Lease operating expenses increased by $3.7 million, or 15.4%, to $27.7 million for the nine months ended September 30, 2017, as compared to $24.0 million for the nine months ended September 30, 2016. The increase in lease operating expenses is primarily attributable to the increase in number of producing wells. On a per unit basis, lease operating expenses increased $0.18 per Boe, or 3.9%, from $4.57 per Boe in the nine months ended September 30, 2016 to $4.75 per Boe in the nine months ended September 30, 2017.

Production and ad valorem taxes. Production and ad valorem taxes decreased by $0.5 million, or 9.8%, to $4.6 million for the nine months ended September 30, 2017, as compared to $5.1 million for the nine months ended September 30, 2016. During the first quarter of 2017, the Company's application for High-Cost Gas Incentive refunds in Texas was

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approved for qualified wells on which taxes were initially paid between October 2012 and September 2016. The Company received a net production tax refund of $3.3 million during the nine months ended September 30, 2017, which was recorded as a reduction in Production and ad valorem taxes on the Company’s Consolidated Statement of Operations. Production taxes, excluding the impact of this refund, increased from $4.1 million for the nine months ended September 30, 2016 to $6.4 million for the nine months ended September 30, 2017. The increase was attributable to the increase in production volumes. Production tax rates vary between states, products, and production levels; therefore, the overall blended rate is impacted by numerous factors and the mix of producing wells at any given time. Offsetting, estimated ad valorem taxes increased $0.6 million from $1.0 million for the nine months ended September 30, 2016 to $1.6 million for the nine months ended September 30, 2017. The average effective rate excluding the impact of ad valorem taxes decreased from 4.8% for the nine months ended September 30, 2016 to 2.3% for the nine months ended September 30, 2017.

Exploration. Exploration expense increased from $1.2 million for the nine months ended September 30, 2016 to $11.6 million for the nine months ended September 30, 2017. The Company recognized charges for lease abandonment of $8.7 million relating to certain leases that the Company decided during 2017 not to develop. Spending during 2017 primarily related to geological data and seismic processing associated with unproved acreage. No exploratory wells resulted in exploration expense during the nine months ended September 30 of either year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization increased by $10.9 million, or 9.4%, to $127.3 million for the nine months ended September 30, 2017, as compared to $116.4 million for the nine months ended September 30, 2016. The increase was primarily the result of capital spending related to our drilling program. On a per unit basis, depletion expense decreased $0.32 per Boe or 1.4% from $22.14 per Boe for the nine months ended September 30, 2016 to $21.82 per Boe for the nine months ended September 30, 2017. The decrease was primarily the result of lower production and capital spending throughout 2016, driven by a temporary suspension of the drilling program late in 2015 and continuing into early 2016.

Impairment of oil and gas properties. As a result of the Arkoma Divestiture, the Company recognized an impairment charge due to the loss on disposal of the Arkoma Basin oil and gas property assets and related liabilities. Based on the Company’s sales price, an impairment charge of $148.0 million was recognized during the nine months ended September 30, 2017. No impairment charges were recognized during the nine months ended September 30, 2016.

General and administrative. General and administrative expenses increased by $2.4 million, or 10.9%, to $24.5 million for the nine months ended September 30, 2017, as compared to $22.1 million for the nine months ended September 30, 2016. The increase was primarily driven by a litigation settlement for which the Company recognized an additional charge of $1.4 million during the second quarter of 2017. Non-cash compensation expense increased $0.1 million, from $5.9 million for the nine months ended September 30, 2016 to $6.0 million for the nine months ended September 30, 2017. On a per unit basis, general and administrative expenses, excluding all non-cash items, decreased from $2.85 per Boe for the nine months ended September 30, 2016 to $2.84 per Boe for the nine months ended September 30, 2017.

Interest expense. Interest expense decreased by $2.0 million, or 5.0%, to $38.4 million for nine months ended September 30, 2017, as compared to $40.4 million for the nine months ended September 30, 2016. The decrease was driven by a reduction in the outstanding balance of the 2022 Notes and the 2023 Notes as a result of our 2016 debt extinguishments. During the nine months ended September 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.84%, 6.75% and 9.25%, respectively. Average outstanding balances for the nine months ended September 30, 2017 were $187.5 million, $409.1 million and $150.0 million under the Revolver, the 2022 Notes and the 2023 Notes, respectively.

Net gain (loss) on commodity derivatives. The net gain (loss) on commodity derivatives was a net gain of $11.3 million for the nine months ended September 30, 2017, as compared to a net loss of $18.8 million for the nine months ended September 30, 2016. The gain was primarily driven by lower average crude oil and natural gas prices ($49.30 per barrel and $3.01 per Mcf, respectively) for the nine months ended September 30, 2017, as compared to the crude oil and natural gas prices as of December 31, 2016 ($53.75 per barrel and $3.71 per Mcf, respectively). Additionally, the Company unwound its realized 2018 and 2019 hedges resulting in recognized gains of approximately $42.8 million for the nine months ended September 30, 2017. See Note 7, “Derivative Instruments and Hedging Activities,” for further details.

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Other income (expense). Other income (expense) for the nine months ended September 30, 2017 was net income of $14.4 million, as compared to net income of $0.3 million for the nine months ended September 30, 2016. Other income (expense) during the nine months ended September 30, 2017 primarily related to an increase in the TRA valuation allowance which resulted in income of $15.8 million.

Income taxes. The provision for federal and state income taxes for the nine months ended September 30, 2017 was a benefit of $2.7 million resulting in a 1.2% effective tax rate as a percentage of our pre-tax book income year-to-date as compared to a benefit of $8.2 million resulting in a 20.2% effective tax rate as a percentage of our pre-tax book income for the nine months ended September 30, 2016. Our effective tax rate is based on the statutory rate applicable to the U.S. and the blended rate of the states in which we conduct business and is adjusted from the enacted rates for the share of net income allocated to the non-controlling interest. The effective tax rate reduction is primarily due to the effect of the valuation allowance recorded against the Company’s deferred tax assets. See Note 11, “Income Taxes,” for further details.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been private and public sales of our debt and equity, borrowings under bank credit facilities and cash flows from operations. Our primary use of capital has been for the exploration, development and acquisition of oil and gas properties. As we pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We strive to maintain financial flexibility in order to maintain substantial borrowing capacity under our Revolver (as defined in Note 6), facilitate drilling on our undeveloped acreage positions and permit us to selectively expand our acreage positions. Depending on the profitability, timing and concentration of the development of our non-proved locations, we may be required to generate or raise significant amounts of capital to develop all of our potential drilling locations should we endeavor to do so. In the event our profitability or cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending. Our balance sheet at September 30, 2017 reflects a negative working capital balance. We have historically maintained, and in the future we expect to maintain, a negative working capital balance, and we use our Revolver to help manage our working capital.

Availability under the Revolver is subject to a borrowing base, as well as financial covenants. Our borrowing base at September 30, 2017 was $375.0 million, of which $151.0 million was utilized, leaving an unused capacity of $224.0 million. The borrowing base will be re-determined at least semi-annually on or about April 1 and October 1 of each year, with such re-determination based primarily on reserve reports using lender commodity price expectations at such time. Any reduction in the borrowing base will reduce our liquidity, and, if the reduction results in the outstanding amount under our Revolver exceeding the borrowing base, we will be required to repay the deficiency within a short period of time. The financial covenants may further constrain our ability to borrow under our Revolver.

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

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

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

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2017. However, factors including those outside of our control, such as commodity price declines, may prevent us from maintaining compliance with these covenants, at future measurement dates in 2017 and beyond. We are currently in discussions with the lenders under our Revolver regarding an amendment to the Revolver that would modify the financial covenants discussed above. Without the amendment, we may breach the total leverage ratio under our Revolver. If an event of default exists under the Revolver, the lenders would be able to accelerate the obligations outstanding under the Revolver and exercise other rights and remedies. Our Revolver contains customary events of default, including the occurrence of a change of control, as defined in the Revolver. See Note 6, “Long-Term Debt” for more information.

The Company routinely enters into oil and natural gas swap contracts as seller, thus resulting in a fixed price. During 2016 and 2017, the Company realized certain mark-to-market gains associated with oil and natural gas hedges the Company had in place for years 2018 and 2019. The gains were effectively realized by purchasing, as opposed to selling, oil and natural gas swap contracts for the equal volume that was associated with the initial hedge transaction. During the three and nine months ended September 30, 2017, the Company unwound its realized 2018 and 2019 hedges resulting in approximately $14.8 million and $42.8 million, respectively, of recognized gains which have been included in Net gain (loss) on commodity derivatives on the Company’s Consolidated Statement of Operations.

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

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


	Nine Months Ended September 30,
(in thousands of dollars)	2017		2016
Net cash provided by operating activities	$	41,425	$	14,909
Net cash (used in) investing activities		(47,530)		(104,847)
Net cash (used in) / provided by financing activities		(23,059)		92,086
Net increase (decrease) in cash	$	(29,164)	$	2,148

Cash flow provided by operating activities

Net cash provided by operating activities was $41.4 million during the nine months ended September 30, 2017 as compared to $14.9 million during the nine months ended September 30, 2016. The increase in operating cash flows was primarily due to the $46.3 million increase in oil and gas revenues for the nine months ended September 30, 2017 as compared to the nine months ended September 30, 2016, primarily driven by the increase in commodity prices, as well as production volumes.

Cash flow (used in) investing activities

Net cash used in investing activities was $47.5 million during the nine months ended September 30, 2017 as compared to $104.8 million during the nine months ended September 30, 2016. The decrease in investing cash flow was primarily driven by reduced capital spending during 2017 as compared to 2016. During 2016, capital spending levels increased upon resuming the drilling program in early 2016 following the temporary suspension of the program beginning late in 2015.

Cash flow (used in) / provided by financing activities

Net cash (used in) / provided by financing activities was cash used of $23.1 million during the nine months ended September 30, 2017 as compared to cash provided of $92.1 million during the nine months ended September 30, 2016. The decrease in financing cash flows was primarily due to repayments under the Revolver, net of borrowings, which

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totaled $27.0 million during the nine months ended September 30, 2017 as compared to net borrowings of $33.0 million during the nine months ended September 30, 2016. Cash flows provided by financing activities were also impacted by net equity offerings of $8.3 million during the nine months ended September 30, 2017 as compared to $153.8 million during the nine months ended September 30, 2016. Offsetting these decrease, the Company did not engage in the repurchase of our senior unsecured notes during the nine months ended September 30, 2017 as compared to cash used toward repurchases of $85.0 million during the nine months ended September 30, 2016.

Contractual Obligations

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

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

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

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

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

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

Item 3. Quantitative and Qualitative 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, 2016, as well as with the unaudited consolidated financial statements and notes included in this Quarterly Report.

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

Potential Impairment of Oil and Gas Properties

Oil and natural gas prices are inherently volatile and have decreased significantly since 2014. Depressed commodity prices have continued into 2017 and historically low commodity prices may exist for an extended period. Taking into

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consideration the business environment in which we operate, we continually review our oil and gas properties for indicators of potential impairment on an undiscounted basis. No such indicators were present at September 30, 2017.

Our revenues and net income are sensitive to crude oil, NGL and natural gas prices which have been and are expected to continue to be highly volatile. The recent volatility in crude oil and natural gas prices increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. Although we are unable to predict future commodity prices, a prolonged period of depressed commodity prices may have a significant impact on the volumetric quantities of our proved reserves. The impact of commodity prices on our estimated proved reserves can be illustrated as follows: if the prices used for our December 31, 2016 Reserve Report had been replaced with the unweighted arithmetic average of the first-day-of-the-month prices for the applicable commodity for the trailing twelve-month period ended September 30, 2017 (without regard to our commodity derivative positions and without assuming any change in development plans, costs, or other variables), then estimated proved reserves volumes as of December 31, 2016 would have increased by approximately 3.7%. The use of this pricing example is for illustration purposes only, and does not indicate management’s view on future commodity prices, costs or other variables, or represent a forecast or estimate of the actual amount by which our proved reserves may fluctuate when a full assessment of our reserves is completed as of December 31, 2017.

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

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

Increases in service costs;

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

Increases in operating costs;

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

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

Commodity price risk and hedges

Our principal market risk exposure is to oil, natural gas and NGL prices, which are inherently volatile. As such, future earnings are subject to change due to fluctuations in such prices. Realized prices are primarily driven by the prevailing prices for oil and regional spot prices for natural gas and NGLs. We have used, and expect to continue to use, oil, natural gas and NGL derivative contracts to reduce our risk of price fluctuations of these commodities. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with projected production levels. The fair value of our oil, natural gas and NGL derivative contracts at September 30, 2017 was a net liability of $11.9 million.

Counterparty risk

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

Interest rate risk

We are subject to market risk exposure related to changes in interest rates on our variable rate indebtedness. The terms of our Revolver provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 0.50% to 2.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. The terms of our senior notes provide for a fixed interest rate through their respective maturity dates. During the three months ended September 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 3.12%, 6.75% and 9.25%, respectively. During the nine months ended September 30, 2017, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.84%, 6.75% and 9.25%, respectively.

Item 4. Controls and Procedures

Changes in Internal Control over Financial Reporting

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

Evaluation of Disclosure Controls and Procedures

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

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

Management’s Assessment of Internal Control over Financial Reporting

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

PART II—OTHER 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.

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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, 2016, could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations.

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

In certain circumstances including transactions involving a change in control, significant payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

Under certain circumstances, we could become obligated to make significant payments under our Tax Receivable Agreement that could exceed or represent a substantial portion of our liquidity and market capitalization. These payment obligations could be to persons without significant equity ownership in the Company at the time such obligation arises. If we elect to terminate the Tax Receivable Agreement early or it is terminated early due to certain mergers or other changes of control, we would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the Tax Receivable Agreement. Such calculation of anticipated future tax benefits will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including the assumptions that (i) we have sufficient taxable income to fully utilize such benefits, (ii) any JEH Units that the Class B shareholders or their permitted transferees own on the termination date are exchanged for shares of our Class A common stock on the termination date and (iii) the amount of future depletion deductions to which we are entitled is based on recoverable reserves and rates of recovery reflected in the most recent reserve reports and estimates available on the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of such future benefits.

In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, other forms of business combinations or other changes of control due to the additional transaction cost a potential acquirer may attribute to satisfying such obligations. For example, if the Tax Receivable Agreement were terminated at September 30, 2017, we estimate that the termination payment would be approximately $105.1 million (calculated using a discount rate equal to LIBOR, plus 100 basis points, applied against the anticipated undiscounted liability and assuming a market value of our Class A common stock equal to $1.92 per share, the closing price on September 29, 2017). The foregoing is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. The holders of rights under the Tax Receivable Agreement will not reimburse us for any payments previously made under the Tax Receivable Agreement if such basis increases or other benefits are subsequently disallowed, except that excess payments made to any Class B shareholder will be netted against payments otherwise to be made, if any, to such Class B shareholder after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

We may be unable to maintain compliance with certain financial ratio covenants of our outstanding indebtedness which could result in an event of default that, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations.

Our Revolver requires us to maintain certain financial ratios, including a total leverage ratio, consisting of consolidated debt to EBITDAX, of not more than 4.00 to 1.00 and a current ratio, consisting of consolidated current assets, including the unused amounts of the total commitments, to consolidated current liabilities, of not less than 1.00 to 1.00.

As of September 30, 2017, we were in compliance with our financial covenants. However, we cannot guarantee that we will be able to comply with such terms at all times in the future. As of September 30, 2017, our total leverage ratio was 3.90 to 1.00 and our current ratio was 2.49 to 1.00. We are currently in discussions with the lenders under our Revolver

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

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

Item 6. Exhibits


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

* - filed herewith

** - furnished herewith

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SIGNATURES

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


	Jones Energy, Inc.

	(registrant)


Date: November 8, 2017	By:	/s/ Robert J. Brooks
	Name: Robert J. Brooks
	Title: Chief Financial Officer (Principal Financial Officer)

Signature Page to Form 10-Q (Q3 2017)

Jones Energy, Inc. - FORM 10-Q - November 8, 2017

Attached files

Jones Energy, Inc. Reports