Jones Energy (JONEQ) 10-Q 2016 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the Quarterly Period Ended March 31, 2016

or

oTRANSITION 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 x   No o

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 x   No o

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

Large accelerated filer o	Accelerated filer x
Non-accelerated filer o	Smaller reporting company o
(Do not check if a smaller reporting company)

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

On April 29, 2016, the Registrant had 30,818,210 shares of Class A common stock outstanding and 31,230,213 shares of Class B common stock outstanding.

JONES ENERGY, INC.

TABLE OF CONTENTS

PART 1—FINANCIAL INFORMATION	1
Item 1. Financial Statements	1
Unaudited Consolidated Financial Statements
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	26
Item 3. Quantitative and Qualitative Disclosures About Market Risk	33
Item 4. Controls and Procedures	34
PART II—OTHER INFORMATION	36
Item 1. Legal Proceedings	36
Item 1A. Risk Factors	36
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	36
Item 3. Defaults Upon Senior Securities	36
Item 4. Mine Safety Disclosures	36
Item 5. Other Information	36
Item 6. Exhibits	36
SIGNATURES	38

i

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, including guidance regarding the timing and location of our anticipated drilling and completion activity, our ability to increase capital spending in connection with leasing, our ability to mitigate commodity price risk through our hedging program, our revised 2016 capital expenditure program, and our ability to successfully execute our 2016 development plan and guidance for the remaining quarters and full year 2016. 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, future prices and change 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, including future development costs, property acquisitions and dispositions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, customers’ elections to reject ethane and include it as part of the natural gas stream, ability to fund our 2016 capital expenditure budget, availability and terms of capital, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company’s business and other important factors that could cause actual results to differ materially from those projected as described in the Company’s reports filed with the SEC.

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

ii

PART 1—FINANCIAL INFORMATION

Item 1. Financial Statements

Jones Energy, Inc.

Consolidated Balance Sheets (Unaudited)

	March 31,			December 31,
(in thousands of dollars)	2016			2015
Assets
Current assets
Cash	$	53,805		$	21,893
Restricted cash	361			330
Accounts receivable, net
Oil and gas sales	16,093			19,292
Joint interest owners	7,399			11,314
Other	15,105			15,170
Commodity derivative assets	107,762			124,207
Other current assets	3,991			2,298
Total current assets	204,516			194,504
Oil and gas properties, net, at cost under the successful efforts method	1,600,290			1,635,766
Other property, plant and equipment, net	3,509			3,873
Commodity derivative assets	84,284			93,302
Other assets	7,309			7,709
Total assets	$	1,899,908		$	1,935,154
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	8,835		$	7,467
Oil and gas sales payable	28,548			32,408
Accrued liabilities	23,426			27,341
Commodity derivative liabilities	—			11
Asset retirement obligations	679			679
Total current liabilities	61,488			67,906
Long-term debt	749,312			837,654
Deferred revenue	10,772			11,417
Asset retirement obligations	20,629			20,301
Liability under tax receivable agreement	37,623			38,052
Deferred tax liabilities	33,533			22,972
Total liabilities	913,357			998,302
Commitments and contingencies (Note 12)
Stockholders’ equity
Class A common stock, $0.001 par value; 30,573,509 shares issued and 30,550,907 shares outstanding at March 31, 2016 and December 31, 2015	31			31
Class B common stock, $0.001 par value; 31,273,130 shares issued and outstanding at March 31, 2016 and December 31, 2015	31			31
Treasury stock, at cost; 22,602 shares at March 31, 2016 and December 31, 2015	(358		)	(358		)
Additional paid-in capital	364,908			363,723
Retained earnings	55,480			36,569
Stockholders’ equity	420,092			399,996
Non-controlling interest	566,459			536,856
Total stockholders’ equity	986,551			936,852
Total liabilities and stockholders’ equity	$	1,899,908		$	1,935,154

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

1

Jones Energy, Inc.

Consolidated Statements of Operations (Unaudited)

	Three Months Ended March 31,
(in thousands of dollars except per share data)	2016			2015
Operating revenues
Oil and gas sales	$	25,080		$	57,234
Other revenues	778			862
Total operating revenues	25,858			58,096
Operating costs and expenses
Lease operating	8,617			12,262
Production and ad valorem taxes	1,601			3,708
Exploration	162			164
Depletion, depreciation and amortization	41,762			52,083
Accretion of ARO liability	293			194
General and administrative	7,504			8,511
Other operating	—			3,012
Total operating expenses	59,939			79,934
Operating income (loss)	(34,081		)	(21,838		)
Other income (expense)
Interest expense	(14,798		)	(14,129		)
Gain on debt extinguishment	90,652			—
Net gain (loss) on commodity derivatives	17,219			46,306
Other income (expense)	225			(2,299		)
Other income (expense), net	93,298			29,878
Income (loss) before income tax	59,217			8,040
Income tax provision (benefit)	10,703			2,344
Net income (loss)	48,514			5,696
Net income (loss) attributable to non-controlling interests	29,603			3,508
Net income (loss) attributable to controlling interests	$	18,911		$	2,188
Earnings per share:
Basic	$	0.62		$	0.12
Diluted	$	0.62		$	0.12
Weighted average shares outstanding:
Basic	30,551			18,304
Diluted	30,551			18,304

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

2

Jones Energy, Inc.

Statement of Changes In Stockholders’ Equity (Unaudited)

	Common Stock						Treasury Stock				Additional		Retained				Total
	Class A			Class B			Class A				Paid-in		(Deficit)/		Non-controlling		Stockholders’
(amounts in thousands)	Shares	Value		Shares	Value		Shares	Value			Capital		Earnings		Interest		Equity
Balance at December 31, 2015	30,551	$	31	31,273	$	31	23	$	(358	)	$	363,723	$	36,569	$	536,856	$	936,852
Stock-compensation expense	—	—		—	—		—	—			1,185		—		—		1,185
Net income (loss)	—	—		—	—		—	—			—		18,911		29,603		48,514
Balance at March 31, 2016	30,551	$	31	31,273	$	31	23	$	(358	)	$	364,908	$	55,480	$	566,459	$	986,551

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

3

Jones Energy, Inc.

Consolidated Statements of Cash Flows (Unaudited)

		Three Months Ended March 31,
(in thousands of dollars)		2016			2015
Cash flows from operating activities
Net income (loss)		$	48,514		$	5,696
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, and amortization	��	41,762			52,083
Exploration (dry hole and lease abandonment)		27			—
Accretion of ARO liability		293			194
Amortization of debt issuance costs		1,129			937
Stock compensation expense		1,185			1,424
Other non-cash compensation expense		268			109
Amortization of deferred revenue		(645		)	(525		)
(Gain) loss on commodity derivatives		(17,219		)	(46,306		)
(Gain) loss on sales of assets		4			26
(Gain) on debt extinguishment		(90,652		)	—
Deferred income tax provision		10,564			2,314
Other - net		(963		)	407
Changes in operating assets and liabilities
Accounts receivable		10,655			36,268
Other assets		(1,700		)	323
Accrued interest expense		(384		)	10,904
Accounts payable and accrued liabilities		(7,634		)	(18,340		)
Net cash (used in) / provided by operations		(4,796		)	45,514
Cash flows from investing activities
Additions to oil and gas properties		(7,176		)	(151,104		)
Proceeds from sales of assets		3			3
Acquisition of other property, plant and equipment		40			(62		)
Current period settlements of matured derivative contracts		42,298			32,611
Change in restricted cash		(30		)	(37		)
Net cash (used in) / provided by investing		35,135			(118,589		)
Cash flows from financing activities
Proceeds from issuance of long-term debt		75,000			65,000
Repayment under long-term debt		—			(335,000		)
Proceeds from senior notes		—			236,475
Purchase of senior notes		(73,427		)	—
Payment of debt issuance costs		—			(1,473		)
Proceeds from sale of common stock		—			122,778
Net cash provided by financing		1,573			87,780
Net increase (decrease) in cash		31,912			14,705
Cash
Beginning of period		21,893			13,566
End of period		$	53,805		$	28,271
Supplemental disclosure of cash flow information
Cash paid for interest		$	14,053		$	1,939
Change in accrued additions to oil and gas properties		(686		)	(68,521		)
Current additions to ARO		—			736

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

4

Jones Energy, Inc.

Notes to the Consolidated Financial Statements (Unaudited)

1.Organization and Description of Business

Organization

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

JEH was formed as a Delaware limited liability company on December 16, 2009 through investments made by the Jones family and through private equity funds managed by Metalmark Capital and Wells Fargo Energy Capital (collectively, the “Pre-IPO Owners”). 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 owners of JEH prior to the Company’s initial public offering (“IPO”) and can be exchanged (together with a corresponding number of 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 a result of the IPO and as of March 31, 2016, the Pre-IPO Owners had 74.7% and 50.6%, respectively, of the total economic interest in JEH, but with no voting rights or management power over JEH, resulting in the Company reporting this ownership interest as a non-controlling interest.

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. The Company’s assets are located within the Anadarko and Arkoma basins of Texas and Oklahoma, 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”). All significant intercompany transactions and balances have been eliminated in consolidation. The Company’s financial position as of December 31, 2015 and the financial statements reported for March 31, 2016 and 2015 and the three month period then ended include the Company and all of its subsidiaries.

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

These interim financial statements have not been audited. However, in the opinion of management, all adjustments necessary for a fair statement of the financial statements have been included, and all such adjustments are of a normal, reoccurring nature. As these are interim financial statements, they do not include all disclosures required for financial statements prepared in conformity with GAAP. Interim period results are not necessarily indicative of results of operations or cash flows for a full year.

These consolidated financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) regarding interim financial reporting. Accordingly, they do not include all disclosures required by GAAP and 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, 2015.

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, 2015

5

Recent Accounting Pronouncements

Adopted in the current period:

In January 2015, the FASB issued ASU No. 2015-01, Income Statement—Extraordinary and Unusual Items. This ASU removes the concept of extraordinary items from GAAP. Under existing guidance, an entity is required to separately disclose extraordinary items, net of tax, in the income statement after income from continuing operations if an event or transaction is of an unusual nature and occurs infrequently. This separate, net of tax presentation will no longer be allowed. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. Therefore, the Company has adopted ASU No. 2015-01 for the period ended March 31, 2016. Adoption did not have a material impact on the financial position, cash flows or results of operations.

In April 2015, the FASB issued ASU No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. Entities that have historically presented debt issuance costs as an asset, related to a recognized debt liability, will be required to present those costs as a direct deduction from the carrying amount of that debt liability. The ASU does not change the recognition, measurement, or subsequent measurement guidance for debt issuance costs. Adoption of this ASU will be applied retrospectively. In August 2015, the FASB issued ASU No. 2015-15, Interest—Imputation of Interest (Subtopic 835-30), which addresses the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within ASU No. 2015-03 for debt issuance costs related to line-of-credit arrangements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2015. Therefore, the Company has adopted ASU No. 2015-03 for the period ended March 31, 2016. Changes to the balance sheet have been applied on a retrospective basis. This resulted in the reclassification of debt issuance costs of $10.3 million from Other assets to Long-term debt in the Consolidated Balance Sheet for the period ended December 31, 2015. 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 Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers,” which creates a new topic in the ASC, topic 606, “Revenue from Contracts with Customers.” This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14 which deferred the effective date of ASU 2014-09 by one year. The amendments are now effective for interim and annual reporting periods beginning after December 15, 2017 and may be applied on either a full or modified retrospective basis. Early adoption is permitted. The Company is currently evaluating the effect that the adoption of Update 2014-09 and Update 2015-14 will have on our financial statements.

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

In March 2016, the FASB issued ASU 2016-09, Compensation—Stock Compensation (Topic 718). This amendment is intended to simplify the accounting for share-based payment awards to employees, specifically in regard to (1) the income tax consequences, (2) classification of awards as either equity or liabilities, and (3) classification on the statement of cash flows. The amendments are effective for interim and annual reporting periods beginning after December 15, 2016. Early adoption is permitted. The Company is currently evaluating the effect that the adoption of ASU 2016-09 will have on our financial statements.

6

3.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 March 31, 2016 and December 31, 2015:

	March 31,			December 31,
(in thousands of dollars)	2016			2015
Mineral interests in properties
Unproved	$	75,769		$	75,308
Proved	1,034,029			1,031,669
Wells and equipment and related facilities	1,292,491			1,289,323
	2,402,289			2,396,300
Less: Accumulated depletion and impairment	(801,999		)	(760,534		)
Net oil and gas properties	$	1,600,290		$	1,635,766

There were no exploratory wells during the three months ended March 31, 2016 and 2015, and as such, no associated costs were capitalized.

The Company did not capitalize any interest during the three months ended March 31, 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 $41.5 million and $51.8 million for the periods ended March 31, 2016 and March 31, 2015, respectively.

The Company assessed its proved and unproved properties for impairment as of March 31, 2016 and no impairment charges were recorded.

Other Property, Plant and Equipment

Other property, plant and equipment consisted of the following at March 31, 2016 and December 31, 2015:

	March 31,			December 31,
(in thousands of dollars)	2016			2015
Leasehold improvements	$	1,213		$	1,260
Furniture, fixtures, computers and software	4,092			4,090
Vehicles	1,537			1,537
Aircraft	910			910
Other	252			247
	8,004			8,044
Less: Accumulated depreciation and amortization	(4,495		)	(4,171		)
Net other property, plant and equipment	$	3,509		$	3,873

Depreciation and amortization of other property, plant and equipment amounted to $0.3 million and $0.3 million during the three months ended March 31, 2016 and 2015, respectively.

7

4.Long-Term Debt

Long-term debt consisted of the following at March 31, 2016 and December 31, 2015:

(in thousands of dollars)	March 31, 2016			December 31, 2015
Revolver	$	185,000		$	110,000
2022 Notes	429,485			500,000
2023 Notes	150,000			250,000
Total principal amount	764,485			860,000
Less: unamortized discount	(7,000		)	(12,088		)
Less: debt issuance costs, net	(8,173		)	(10,258		)
Total carrying amount	$	749,312		$	837,654

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 (together the “Issuers”), sold $500.0 million in aggregate principal amount of the Issuers’ 6.75% senior notes due 2022 (the “2022 Notes”). The Company used the net proceeds from the issuance of the 2022 Notes to repay all outstanding borrowings under the Term Loan ($160.0 million), a portion of the outstanding borrowings under the Revolver ($308.0 million) and for working capital and general corporate purposes. The Company subsequently terminated the Term Loan in accordance with its terms. The 2022 Notes bear interest at a rate of 6.75% per year, payable semi-annually on April 1 and October 1 of each year beginning October 1, 2014.

On February 5, 2015, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the 2022 Notes, except that the transfer restrictions, registration rights and additional interest provisions related to the outstanding 2022 Notes do not apply to the new 2022 Notes. On February 20, 2015, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $500 million outstanding principal amount of 2022 Notes for an equal amount of new 2022 Notes. The exchange offer expired on March 23, 2015. Tenders of $500 million aggregate principal amount, or 100%, of the 2022 Notes were received.

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

On November 18, 2015, the Company filed a registration statement on Form S-4 to register exchange notes that are substantially similar to the 9.25% senior notes due November 2023 (the “2023 Notes”), except that the transfer restrictions, registration rights and additional interest provisions related to the outstanding 2023 Notes do not apply to the new 2023 Notes. On January 12, 2016, the registration statement was declared effective and the Company commenced an offer to exchange any and all of its $250 million outstanding principal amount of 2023 Notes for an equal amount of new 2023 Notes. The exchange offer expired on February 11, 2016. Tenders of $250 million aggregate principal amount, or 100%, of the 2023 Notes were received.

In January and February 2016, through several open market and privately negotiated purchases, the Company purchased an aggregate principal amount of $170.5 million of its senior unsecured notes. As of March 31, 2016, the Company had purchased $70.5 million principal amount of its 2022 Notes for $27.1 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 $90.7 million on a pre-tax basis. This income is recorded in Gain on debt extinguishment on the Company’s Consolidated Statement of Operations.

During the second quarter of 2016, the Company has repurchased additional 2022 Notes. See Note 13, “Subsequent Events,” for further discussion.

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.

8

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. However, many of these covenants will be suspended if the Notes are rated investment grade.

Other Long-Term Debt

The Company entered into two credit agreements dated December 31, 2009, with Wells Fargo Bank N.A, the Senior Secured Revolving Credit Facility (the “Revolver”) and the Second Lien Term Loan (the “Term Loan”), each of which have been or were amended periodically. On April 1, 2014, the Term Loan was repaid in full and terminated in connection with the issuance of the 2022 Notes. On November 6, 2014, the Company amended the Revolver to, among other things, increase the borrowing base under the Revolver from $550.0 million to $625.0 million until the next re-determination thereof, and extend the maturity date of the Revolver to November 6, 2019. The Company’s oil and gas properties are pledged as collateral to secure its obligations under the Revolver. The borrowing base on the Revolver was subsequently adjusted to $562.5 million in accordance with its terms as a result of the issuance of the 2023 Notes in February 2015 and was reaffirmed at this level effective April 1, 2015. Effective October 8, 2015, the borrowing base was reduced to $510 million during the semi-annual borrowing base re-determination.

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. In light of current commodity prices, it is our expectation that the borrowing base will be reduced during the upcoming re-determination. Any reduction in the borrowing base will reduce our liquidity, and, if the reduction results in the outstanding amount under our revolving credit facility exceeding the borrowing base, we will be required to repay the deficiency within a short period of time.

Interest on the Revolver is calculated, at the Company’s option, at either (a) the London Interbank Offered (“LIBO”) rate for the applicable interest period plus a margin of 1.50% to 2.50% based on the level of borrowing base utilization at such time or (b) the greatest of the federal funds rate plus 0.50%, the one month adjusted LIBO rate plus 1.00%, or the prime rate announced by Wells Fargo Bank, N.A. in effect on such day, in each case plus a margin of 0.50% to 1.50% based on the level of borrowing base utilization at such time. For the three months ended March 31, 2016, the average interest rate under the Revolver was 2.67% on an average outstanding balance of $143.1 million. For the three months ended March 31, 2015, the average interest rate under the Revolver was 2.46% on an average outstanding balance of $271.9 million.

Total interest and commitment fees under the Revolver were $1.3 million and $2.0 million for the three months ended March 31, 2016 and 2015, respectively.

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

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

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

As of March 31, 2016, our total leverage ratio is approximately 3.0 and our current ratio is approximately 6.9, as calculated based on the requirements in our covenants. We are in compliance with all terms of our Revolver at March 31, 2016.

9

5.Derivative Instruments and Hedging Activities

The Company had various commodity derivatives in place that could affect its future operations as of March 31, 2016 and December 31, 2015, as follows:

Hedging Positions

	March 31, 2016
								Weighted			Final
		Low			High			Average			Expiration
Oil swaps	Exercise price	$	60.00		$	92.60		$	79.97		June 2019
	Offset exercise price	$	34.70		$	49.00		$	44.53
	Net barrels per month	—			133,000			51,436
Natural gas swaps	Exercise price	$	2.84		$	5.56		$	4.21		June 2019
	Offset exercise price	2.34			3.02			2.83
	Net mmbtu per month	—			1,500,000			619,231
Basis swaps	Contract differential	$	(0.30	)	$	(0.15	)	$	(0.18	)	December 2016
	mmbtu per month	1,240,000			1,380,000			1,295,556
Natural gas liquids swaps	Exercise price	$	8.90		$	84.11		$	32.94		December 2017
	Barrels per month	2,000			107,000			43,381

	December 31, 2015
								Weighted			Final
		Low			High			Average			Expiration
Oil swaps	Exercise price	$	54.53		$	100.87		$	79.16		June 2019
	Barrels per month	54,000			194,000			97,119
Natural gas swaps	Exercise price	$	3.22		$	6.45		$	4.25		June 2019
	mmbtu per month	700,000			1,640,000			1,042,857
Basis swaps	Contract differential	$	(0.39	)	$	(0.11	)	$	(0.18	)	December 2016
	mmbtu per month	1,190,000			1,730,000			1,360,833
Natural gas liquids swaps	Exercise price	$	8.90		$	95.24		$	32.62		December 2017
	Barrels per month	2,000			112,000			51,792

The Company recognized a net gain on derivative instruments of $17.2 million and $46.3 million for the three months ended March 31, 2016 and 2015, respectively.

The Company routinely enters into oil and natural gas swap contracts as seller, thus resulting in a fixed rate. In the first quarter of 2016, the Company crystalized 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 crystalized by purchasing, as opposed to selling, oil and natural gas swap contracts for the equal volume that was associated with the initial hedge transaction. Therefore, as prices fluctuate, the loss (or gain) on any single contract in 2018 and 2019 will be offset by an equal gain (or loss). This essentially leaves the underlying production open to fluctuations in market prices. Since no contracts were canceled or liquidated, the gains will be recognized as the hedge contracts mature in 2018 and 2019. 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.

Offsetting Assets and Liabilities

As of March 31, 2016 the counterparties to our commodity derivative contracts consisted of six financial institutions. All of our counterparties or their affiliates are also lenders under the Revolver. We are not generally required to post additional collateral under our derivative agreements.

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

10

We adopted the guidance requiring disclosure of both gross and net information about financial instruments eligible for netting in the balance sheet under our derivative agreements. The following table presents information about our commodity derivative contracts that are netted on our Consolidated Balance Sheet as of March 31, 2016 and December 31, 2015:

(in thousands of dollars)	Gross Amounts of Recognized Assets / Liabilities			Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets / Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet		Net Amount
March 31, 2016
Commodity derivative contracts
Assets	$	192,936		$	(890	)	$	192,046		$	—	$	192,046
Liabilities	(890		)	890			—			—		—
December 31, 2015
Commodity derivative contracts
Assets	$	218,036		$	(527	)	$	217,509		$	—	$	217,509
Liabilities	(538		)	527			(11		)	—		(11		)

6.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 1Pricing inputs are based on published prices in active markets for identical assets or liabilities as of the reporting date.

Level 2Pricing 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.

11

Level 3Pricing 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 March 31, 2016 and December 31, 2015, by consolidated balance sheet caption and by valuation hierarchy, as described above are as follows:

	March 31, 2016
(in thousands of dollars)	Fair Value Measurements
Commodity Price Hedges	(Level 1)		(Level 2)		(Level 3)		Total
Current assets	$	—	$	106,795	$	967	$	107,762
Long-term assets	—		84,284		—		84,284
Current liabilities	—		—		—		—
Long-term liabilities	—		—		—		—

	December 31, 2015
(in thousands of dollars)	Fair Value Measurements
Commodity Price Hedges	(Level 1)		(Level 2)		(Level 3)		Total
Current assets	$	—	$	122,779	$	1,428	$	124,207
Long-term assets	—		93,302		—		93,302
Current liabilities	—		11		—		11
Long-term liabilities	—		—		—		—

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 March 31, 2016.

	Quantitative Information About Level 3 Fair Value Measurements
Commodity Price Hedges	Fair Value (000’s)		Valuation Technique	Unobservable Input	Range
Natural gas liquid swaps	$	967	Use a discounted cash flow approach using inputs including forward price statements from counterparties	Natural gas liquid futures prices	$8.90 - $47.25 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 three months ended March 31, 2016. 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.

(in thousands of dollars)
Balance at December 31, 2015, net	$	1,428
Purchases	—
Settlements	(431		)
Transfers to Level 2	—
Transfers to Level 3	—
Changes in fair value	(30		)
Balance at March 31, 2016, net	$	967

12

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:

	March 31, 2016				December 31, 2015
(in thousands of dollars)	Principal Amount		Fair Value		Principal Amount		Fair Value
Debt:
Revolver	$	185,000	$	185,000	$	110,000	$	110,000
2022 Notes	429,485		236,217		500,000		260,000
2023 Notes	150,000		84,375		250,000		153,283

The Revolver (as defined in Note 4) 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 4) 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 4) is based on indicative pricing that is available in the public market. Accordingly, the 2023 Notes are classified as Level 2 in the valuation hierarchy as the pricing is based on quoted market prices for the debt securities but is not actively traded.

The Company reviews its proved oil and gas properties for impairment purposes by comparing the expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. Significant assumptions associated with the calculation of future cash flows used in the impairment analysis include the Company’s estimate of future commodity prices, production costs, development expenditures, production, risk-adjusted discount rates, and other relevant data. As such, the fair value of oil and gas properties used in estimating impairment represents a nonrecurring Level 3 measurement.

7.Asset Retirement Obligations

A summary of the Company’s ARO for three months ended March 31, 2016 is as follows:

(in thousands of dollars)
Balance at December 31, 2015	$	20,980
Liabilities incurred	—
Accretion of ARO liability	293
Liabilities settled due to sale of related properties	—
Liabilities settled due to plugging and abandonment	(15		)
Change in estimate	50
Balance at March 31, 2016	21,308
Less: Current portion of ARO	(679		)
Total long-term ARO at March 31, 2016	$	20,629

8.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

13

awarded since the IPO and no new JEH Units or shares of Class B common stock are created upon a vesting event. Grants listed below reflect the transfer of JEH units that occurred upon forfeiture.

The following table summarizes information related to the vesting of management units as of March 31, 2016:

	JEH Units		Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2015	189,355		$	15.00
Granted	39,198		15.00
Forfeited	(39,198	)	15.00
Vested	(39,198	)	15.00
Unvested at March 31, 2016	150,157		$	15.00

Stock compensation expense associated with the management units was $0.5 million and $0.3 million for the three months ended March 31, 2016 and 2015, respectively and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

2013 Omnibus Incentive Plan

Under the Jones Energy, Inc. 2013 Omnibus Incentive Plan (the “LTIP”), established in conjunction with the Company’s IPO, the Company reserved 3,850,000 shares of Class A common stock for non-employee director, consultant and employee stock-based compensation awards. On May 4, 2016, following approval by the Company’s stockholders, the Company adopted the Amended and Restated LTIP, pursuant to which, among other things, the Company reserved an additional 3,500,000 shares of Class A common stock for non-employee director, consultant and employee stock-based compensation awards.

The Company granted (i) performance 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 and 2015.

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 was 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 March 31, 2016:

	Restricted Stock Unit Awards		Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2015	757,245		$	11.65
Granted	40,701		3.85
Forfeited	(191,674	)	10.75
Vested	—		—
Unvested at March 31, 2016	606,272		$	11.41

Stock compensation expense associated with the employee restricted stock unit awards for the three months ended March 31, 2016 and 2015 was $0.1 million and $0.5 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

14

Performance Unit Awards

The Company has outstanding performance unit awards granted to certain members of the senior management team of the Company under the LTIP. Upon the completion of the applicable three-year performance period, each recipient may vest in a number of performance units. The percent of awarded performance 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 unit is exchangeable for one share of the Company’s Class A common stock. The grant date fair value of the performance units was determined using a Monte Carlo simulation model, which results in an estimated percentage of performance units earned. The fair value of the performance units is expensed on a straight-line basis over the applicable three-year performance period.

The following table summarizes information related to the total number of units awarded to the officers as of March 31, 2016:

	Performance Unit Awards		Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2015	539,188		$	14.22
Granted	16,195		3.85
Forfeited	(85,460	)	12.21
Vested	—		—
Unvested at March 31, 2016	469,923		$	14.23

Stock compensation expense associated with the performance unit awards for the three months ended March 31, 2016 and 2015 was $0.4 million and $0.4 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

Restricted Stock Awards

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

The following table summarizes information related to the total value of the awards to the Board of Directors as of March 31, 2016:

	Restricted Stock Awards	Weighted Average Grant Date Fair Value per Share
Unvested at December 31, 2015	67,380	$	7.30
Granted	—	—
Forfeited	—	—
Vested	—	—
Unvested at March 31, 2016	67,380	$	7.30

Stock compensation expense associated with the Board of Directors awards for the three months ended March 31, 2016 and 2015 was $0.2 million and $0.1 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statement of Operations.

9.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 for the three months ended March 31, 2016 and 2015 was 18.1% and 29.2%, respectively. 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, and other permanent differences between book and tax accounting.

15

The Company’s income tax provision was an expense of $10.7 million and $2.3 million for the three months ended March 31, 2016 and 2015, 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 March 31,
(in thousands of dollars)	2016		2015
Jones Energy, Inc.	$	10,569	$	441
Non-controlling interest	134		1,903
Income tax provision (benefit)	$	10,703	$	2,344

The Company had deferred tax assets for its federal and state net operating loss carry forwards at March 31, 2016 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 March 31, 2016, we have a valuation allowance of $3.5 million as a result of management’s assessment of the realizability of deferred tax assets in Oklahoma. Management believes that there will be sufficient future taxable income based on the reversal of temporary differences to enable utilization of substantially all other tax carryforwards.

Tax Receivable Agreement

As of March 31, 2016 and December 31, 2015, respectively, the Company had recorded a TRA liability of $37.6 million and $38.1 million for the estimated payments that will be made to the pre-IPO members who have exchanged shares. Such exchanges generated tax basis increases leading to deferred tax assets as of March 31, 2016 and December 31, 2015, respectively, of $44.3 million and $44.8 million, net of valuation allowance. During the three months ended March 31, 2016, the amount of the TRA liability was reduced by $0.5 million as a result of the valuation allowance recorded against the Company’s deferred tax assets, which was recorded in other income (expense) on the Company’s Consolidated Statement of Operations. 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 March 31, 2016, the Company had not made any payments under the TRA to pre-IPO members who have exchanged JEH units and Class B common stock for Class A common stock. The Company does not anticipate making a material payment under the TRA in either 2016 or 2017.

10.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 stock awards that have been granted to directors and employees. Awards of nonvested 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 months ending March, 31, 2016, 606,272 restricted stock units, and 469,923 performance units were excluded from the calculation as they would have had an anti-dilutive effect.

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 months ended March 31, 2016:

(in thousands, except per share data)	Three Months Ended March 31, 2016
Income (numerator):
Net income attributable to controlling interests	$	18,911
Weighted-average shares (denominator):
Weighted-average number of shares of Class A common stock - basic	30,551
Weighted-average number of shares of Class A common stock - diluted	30,551
Earnings per share:
Basic	$	0.62
Diluted	$	0.62

16

11.Related Parties

Related Party Transactions

Transactions with Our Executive Officers, Directors and 5% Stockholders

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. 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. Therefore, no related party revenue relating to natural gas and NGL production was recognized during 2016 associated with the aforementioned agreement. 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 directors, Howard I. Hoffen and Gregory D. Myers, are managing directors of Metalmark Capital.

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 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. During the three months ended March 31, 2016 and 2015, the Company amortized $0.6 million and $0.5 million, respectively, of the deferred revenue balance. This revenue is recorded in Other revenues on the Company’s Consolidated Statement of Operations.

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 of $0.7 million which were paid to Monarch Oil Pipeline LLC associated with the approximately 0.3 MMBoe of oil production transported under the agreement for the three months ended March 31, 2016. 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.

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 own 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 own 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.

12.Commitments and Contingencies

The Company is subject to legal proceedings and claims that arise in the ordinary course of its business. The Company believes that the final disposition of such matters will not have a material adverse effect on its financial position, results of operations, or liquidity.

17

13.Subsequent Events

During the second quarter of 2016 through April 29, 2016, the Company purchased, through several open market purchases, $20.3 million principal amount of its 2022 Notes for $11.2 million excluding accrued interest and including any associated fees. This debt was not cancelled and is available for future reissuance at the Company’s discretion. The Company used cash on hand to fund the note purchases. As a result of these purchases, the Company had aggregate principal amount of senior unsecured notes outstanding of $559.1 million, outstanding borrowings under its revolving credit facility of $185.0 million, $325.0 million undrawn on its revolving credit facility, and approximately $34.3 million in cash as of April 29, 2016.

On April 12, 2016, JEH made an aggregate cash tax distribution of approximately $10.9 million to its members, including the Company, in accordance with the terms of its operating agreement. The distribution was made pro-rata to all members, and resulted in a $5.4 million payment to the Company, and a $5.5 million payment to Pre-IPO Owners. The distribution was based on projected taxable income of JEH for 2016 and represented the first quarterly payment required under the terms of its operating agreement. The determination regarding the payment of such amount was made by a Special Committee of the Board of Directors of the Company comprised solely of directors who do not have a direct or indirect financial interest in such distribution.

On May 4, 2016, following approval by the Company’s stockholders, the Company adopted the Amended and Restated LTIP, pursuant to which, among other things, the Company reserved an additional 3,500,000 shares of Class A common stock for non-employee director, consultant and employee stock-based compensation awards.

14.Subsidiary Guarantors

On April 1, 2014, the Issuers sold $500.0 million in aggregate principal amount of the 2022 Notes. On February 23, 2015, the Issuers sold $250.0 million in aggregate principal amount of the 2023 Notes.

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.

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 March 31, 2016, the Company held approximately 49.4% of the economic interest in JEH, with the remaining 50.6% economic interest held by a group of investors that owned interests in JEH prior to the Company’s IPO (the “Pre-IPO  Owners”). The Pre-IPO Owners 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. 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.

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 Existing Owner held. Holders of the

18

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 Pre-IPO Owners collectively have a number of votes in the Company equal to the aggregate number of JEH Units that they hold.

The Pre-IPO Owners have the right, pursuant to the terms of an Exchange Agreement by and among the Company, JEH and each of the Pre-IPO Owners, 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.

19

Jones Energy, Inc.

Condensed Consolidating Balance Sheet

March 31, 2016

(in thousands of dollars)	JEI (Parent)			Issuers		Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	12,380	$	41,305	$	20		$	—		$	53,805
Restricted cash	—			—		361		—			—			361
Accounts receivable, net
Oil and gas sales	—			—		16,093		—			—			16,093
Joint interest owners	—			—		7,399		—			—			7,399
Other	—			14,817		288		—			—			15,105
Commodity derivative assets	—			107,762		—		—			—			107,762
Other current assets	—			233		3,758		—			—			3,991
Intercompany receivable	13,954			1,189,090		—		—			(1,203,044		)	—
Total current assets	14,054			1,324,282		69,204		20			(1,203,044		)	204,516
Oil and gas properties, net, at cost under the successful efforts method	—			—		1,600,290		—			—			1,600,290
Other property, plant and equipment, net	—			—		2,826		683			—			3,509
Commodity derivative assets	—			84,284		—		—			—			84,284
Other assets	—			7,056		253		—			—			7,309
Investment in subsidiaries	473,332			—		—		—			(473,332		)	—
Total assets	$	487,386		$	1,415,622	$	1,672,573	$	703		$	(1,676,376	)	$	1,899,908
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	—		$	204	$	8,631	$	—		$	—		$	8,835
Oil and gas sales payable	—			—		28,548		—			—			28,548
Accrued liabilities	—			15,891		7,535		—			—			23,426
Commodity derivative liabilities	—			—		—		—			—			—
Asset retirement obligations	—			—		679		—			—			679
Intercompany payable	—			—		1,419,994		2,460			(1,422,454		)	—
Total current liabilities	—			16,095		1,465,387		2,460			(1,422,454		)	61,488
Long-term debt	—			749,312		—		—			—			749,312
Deferred revenue	—			10,772		—		—			—			10,772
Asset retirement obligations	—			—		20,629		—			—			20,629
Liability under tax receivable agreement	37,623			—		—		—			—			37,623
Deferred tax liabilities	29,671			3,862		—		—			—			33,533
Total liabilities	67,294			780,041		1,486,016		2,460			(1,422,454		)	913,357
Stockholders’ / members’ equity
Members’ equity	—			635,581		186,557		(1,757		)	(820,381		)	—
Class A common stock, $0.001 par value; 30,573,509 shares issued and 30,550,907 shares outstanding	31			—		—		—			—			31
Class B common stock, $0.001 par value; 31,273,130 shares issued and outstanding	31			—		—		—			—			31
Treasury stock, at cost; 22,602 shares	(358		)	—		—		—			—			(358		)
Additional paid-in-capital	364,908			—		—		—			—			364,908
Retained earnings	55,480			—		—		—			—			55,480
Stockholders’ equity	420,092			635,581		186,557		(1,757		)	(820,381		)	420,092
Non-controlling interest	—			—		—		—			566,459			566,459
Total stockholders’ equity	420,092			635,581		186,557		(1,757		)	(253,922		)	986,551
Total liabilities and stockholders’ equity	$	487,386		$	1,415,622	$	1,672,573	$	703		$	(1,676,376	)	$	1,899,908

20

Jones Energy, Inc.

Condensed Consolidating Balance Sheet

December 31, 2015

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Assets
Current assets
Cash	$	100		$	12,448		$	9,325	$	20		$	—		$	21,893
Restricted cash	—			—			330		—			—			330
Accounts receivable, net
Oil and gas sales	—			—			19,292		—			—			19,292
Joint interest owners	—			—			11,314		—			—			11,314
Other	—			14,444			726		—			—			15,170
Commodity derivative assets	—			124,207			—		—			—			124,207
Other current assets	—			444			1,854		—			—			2,298
Intercompany receivable	12,866			1,161,997			—		—			(1,174,863		)	—
Total current assets	12,966			1,313,540			42,841		20			(1,174,863		)	194,504
Oil and gas properties, net, at cost under the successful efforts method	—			—			1,635,766		—			—			1,635,766
Other property, plant and equipment, net	—			—			3,168		705			—			3,873
Commodity derivative assets	—			93,302			—		—			—			93,302
Other assets	—			7,456			253		—			—			7,709
Investment in subsidiaries	444,362			—			—		—			(444,362		)	—
Total assets	$	457,328		$	1,414,298	��	$	1,682,028	$	725		$	(1,619,225	)	$	1,935,154
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	—		$	388		$	7,079	$	—		$	—		$	7,467
Oil and gas sales payable	—			—			32,408		—			—			32,408
Accrued liabilities	—			15,741			11,600		—			—			27,341
Commodity derivative liabilities	—			11			—		—			—			11
Asset retirement obligations	—			—			679		—			—			679
Intercompany payable	—			—			1,391,838		2,434			(1,394,272		)	—
Total current liabilities	—			16,140			1,443,604		2,434			(1,394,272		)	67,906
Long-term debt	—			837,654			—		—			—			837,654
Deferred revenue	—			11,417			—		—			—			11,417
Asset retirement obligations	—			—			20,301		—			—			20,301
Liability under tax receivable agreement	38,052			—			—		—			—			38,052
Deferred tax liabilities	19,280			3,692			—		—			—			22,972
Total liabilities	57,332			868,903			1,463,905		2,434			(1,394,272		)	998,302
Stockholders’ / members’ equity
Members’ equity	—			545,395			218,123		(1,709		)	(761,809		)	—
Class A common stock, $0.001 par value; 30,573,509 shares issued and 30,550,907 shares outstanding	31			—			—		—			—			31
Class B common stock, $0.001 par value; 31,273,130 shares issued and outstanding	31			—			—		—			—			31
Treasury stock, at cost; 22,602 shares	(358		)												(358		)
Additional paid-in-capital	363,723			—			—		—			—			363,723
Retained earnings	36,569			—			—		—			—			36,569
Stockholders’ equity	399,996			545,395			218,123		(1,709		)	(761,809		)	399,996
Non-controlling interest	—			—			—		—			536,856			536,856
Total stockholders’ equity	399,996			545,395			218,123		(1,709		)	(224,953		)	936,852
Total liabilities and stockholders’ equity	$	457,328		$	1,414,298		$	1,682,028	$	725		$	(1,619,225	)	$	1,935,154

21

Jones Energy, Inc.

Condensed Consolidating Statement of Operations and Comprehensive Income

Three Months Ended March 31, 2016

(in thousands)	JEI (Parent)		Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—	$	—		$	25,080		$	—		$	—		$	25,080
Other revenues	—		645			133			—			—			778
Total operating revenues	—		645			25,213			—			—			25,858
Operating costs and expenses
Lease operating	—		—			8,617			—			—			8,617
Production and ad valorem taxes	—		—			1,601			—			—			1,601
Exploration	—		—			162			—			—			162
Depletion, depreciation and amortization	—		—			41,739			23			—			41,762
Accretion of ARO liability	—		—			293			—			—			293
General and administrative	—		2,878			4,601			25			—			7,504
Total operating expenses	—		2,878			57,013			48			—			59,939
Operating income	—		(2,233		)	(31,800		)	(48		)	—			(34,081		)
Other income (expense)
Interest expense	—		(15,038		)	240			—			—			(14,798		)
Gain on debt extinguishment	—		90,652			—			—			—			90,652
Net gain (loss) on commodity derivatives	—		17,219			—			—			—			17,219
Other income (expense)	429		(200		)	(4		)	—			—			225
Other income (expense), net	429		92,633			236			—			—			93,298
Income (loss) before income tax	429		90,400			(31,564		)	(48		)	—			59,217
Equity interest in income	28,968		—			—			—			(28,968		)	—
Income tax provision	10,486		217			—			—			—			10,703
Net income (loss)	$	18,911	$	90,183		$	(31,564	)	$	(48	)	$	(28,968	)	$	48,514
Net income attributable to non-controlling interests	—		—			—			—			29,603			29,603
Net income attributable to controlling interests	$	18,911	$	—		$	—		$	—		$	—		$	18,911

22

Jones Energy, Inc.

Condensed Consolidating Statement of Operations and Comprehensive Income

Three Months Ended March 31, 2015

(in thousands)	JEI (Parent)		Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Operating revenues
Oil and gas sales	$	—	$	—		$	57,234		$	—		$	—		$	57,234
Other revenues	—		525			337			—			—			862
Total operating revenues	—		525			57,571			—			—			58,096
Operating costs and expenses
Lease operating	—		—			12,262			—			—			12,262
Production and ad valorem taxes	—		—			3,708			—			—			3,708
Exploration	—		—			164			—			—			164
Depletion, depreciation and amortization	—		—			52,060			23			—			52,083
Accretion of ARO liability	—		—			194			—			—			194
General and administrative	—		2,827			5,661			23			—			8,511
Other operating	—		—			3,012			—			—			3,012
Total operating expenses	—		2,827			77,061			46			—			79,934
Operating income	—		(2,302		)	(19,490		)	(46		)	—			(21,838		)
Other income (expense)
Interest expense	—		(13,684		)	(445		)	—			—			(14,129		)
Gain on debt extinguishment	—		—			—			—			—			—
Net gain (loss) on commodity derivatives	—		46,306			—			—			—			46,306
Other income (expense)	—		(2,273		)	(26		)	—			—			(2,299		)
Other income (expense), net	—		30,349			(471		)	—			—			29,878
Income (loss) before income tax	—		28,047			(19,961		)	(46		)	—			8,040
Equity interest in income	2,629		—			—			—			(2,629		)	—
Income tax provision	441		1,903			—			—			—			2,344
Net income (loss)	$	2,188	$	26,144		$	(19,961	)	$	(46	)	$	(2,629	)	$	5,696
Net income attributable to non-controlling interests	—		—			—			—			3,508			3,508
Net income attributable to controlling interests	$	2,188	$	—		$	—		$	—		$	—		$	2,188

23

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2016

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	18,911		$	90,183		$	(31,564	)	$	(48	)	$	(28,968	)	$	48,514
Adjustments to reconcile net income (loss) to net cash provided by operating activities	(18,911		)	(134,122		)	70,707			48			28,968			(53,310		)
Net cash (used in) / provided by operations	—			(43,939		)	39,143			—			—			(4,796		)
Cash flows from investing activities
Additions to oil and gas properties	—			—			(7,176		)	—			—			(7,176		)
Proceeds from sales of assets	—			—			3			—			—			3
Acquisition of other property, plant and equipment	—			—			40			—			—			40
Current period settlements of matured derivative contracts	—			42,298			—			—			—			42,298
Change in restricted cash	—			—			(30		)	—			—			(30		)
Net cash (used in) / provided by investing	—			42,298			(7,163		)	—			—			35,135
Cash flows from financing activities
Proceeds from issuance of long-term debt	—			75,000			—			—			—			75,000
Repayment under long-term debt	—			—			—			—			—			—
Proceeds from senior notes	—			—			—			—			—			—
Purchase of senior notes				(73,427		)										(73,427		)
Payment of debt issuance costs	—			—			—			—			—			—
Proceeds from sale of common stock, net of expense	—			—			—			—			—			—
Net cash (used in) / provided by financing	—			1,573			—			—			—			1,573
Net increase (decrease) in cash	—			(68		)	31,980			—			—			31,912
Cash
Beginning of period	100			12,448			9,325			20			—			21,893
End of period	$	100		$	12,380		$	41,305		$	20		$	—		$	53,805

24

Jones Energy, Inc.

Condensed Consolidating Statement of Cash Flows

Three Months Ended March 31, 2015

(in thousands of dollars)	JEI (Parent)			Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities
Net income (loss)	$	2,188		$	26,144		$	(19,961	)	$	(46	)	$	(2,629	)	$	5,696
Adjustments to reconcile net income (loss) to net cash provided by operating activities	(124,966		)	(23,757		)	185,866			46			2,629			39,818
Net cash (used in) / provided by operations	(122,778		)	2,387			165,905			—			—			45,514
Cash flows from investing activities
Additions to oil and gas properties	—			—			(151,104		)	—			—			(151,104		)
Net adjustments to purchase price of properties acquired	—			—			—			—			—			—
Proceeds from sales of assets	—			—			3			—			—			3
Acquisition of other property, plant and equipment	—			—			(62		)	—			—			(62		)
Current period settlements of matured derivative contracts	—			32,611			—			—			—			32,611
Change in restricted cash	—			—			(37		)	—			—			(37		)
Net cash (used in) / provided by investing	—			32,611			(151,200		)	—			—			(118,589		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	—			65,000			—			—			—			65,000
Repayment under long-term debt	—			(335,000		)	—			—			—			(335,000		)
Proceeds from senior notes	—			236,475			—			—			—			236,475
Payment of debt issuance costs	—			(1,473		)	—			—			—			(1,473		)
Proceeds from sale of common stock, net of expense	122,778			—			—			—			—			122,778
Net cash (used in) / provided by financing	122,778			(34,998		)	—			—			—			87,780
Net increase (decrease) in cash	—			—			14,705			—			—			14,705
Cash
Beginning of period	100			1,000			12,436			30			—			13,566
End of period	$	100		$	1,000		$	27,141		$	30		$	—		$	28,271

25

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, 2015, filed on March 9, 2016 with the Securities and Exchange Commission, and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report. Unless indicated otherwise in this Quarterly Report or the context requires otherwise, all references to “Jones Energy,” the “Company,” “our company,” “we,” “our” and “us” refer to Jones Energy, Inc. and its subsidiaries, including Jones Energy Holdings, LLC (“JEH”). Jones Energy, Inc. (“JONE”) is a holding company whose sole material asset is an equity interest in JEH.

Overview

We are an independent oil and gas company engaged in the exploration, development, production and acquisition of oil and natural gas properties in the mid-continent United States, spanning areas of Texas and Oklahoma. Our Chairman and CEO, Jonny Jones, founded our predecessor company in 1988 in continuation of his family’s long history in the oil and gas business, which dates back to the 1920’s. We have grown rapidly by leveraging our focus on low cost drilling and completion methods and our horizontal drilling expertise to develop our inventory and execute several strategic acquisitions. We have accumulated extensive knowledge and experience in developing the Anadarko and Arkoma basins, having concentrated our operations in the Anadarko basin for over 25 years and applied our knowledge to the Arkoma basin since 2011. We have drilled 827 total wells as operator, including over 650 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 basins in the Texas Panhandle and Oklahoma:

·the Anadarko Basin—targeting the liquids-rich Cleveland, Granite Wash, Tonkawa and Marmaton formations; and

·the Arkoma Basin—targeting the Woodford shale formation.

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 and Woodford shale formations.

The Anadarko and Arkoma basins are among the most prolific and largest onshore producing oil and natural gas basins in the United States, characterized by multiple producing horizons and extensive well control collected over 100 years of development. We leverage our extensive geologic experience in the basin and seek to identify the most profitable exploration and development opportunities to apply our operational expertise. The formations we target are generally characterized by oil and/or liquids-rich natural gas content, extensive production histories, long-lived reserves, high drilling success rates and attractive initial production rates. We focus on formations in our operating areas that we believe offer significant development and acquisition opportunities and to which we can apply our technical experience and operational excellence to increase proved reserves and production to deliver attractive economic rates of return. Our goal is to build value through a disciplined balance between developing our current inventory of identified drilling locations, identifying new opportunities within our existing asset base, and actively pursuing organic leasing, strategic acquisitions and joint development agreements. In all of our joint development agreements, we control the drilling and completion of a well, which is the phase during which we can most effectively leverage our operational expertise and cost discipline. Following completion, we may in some cases turn over operatorship to a partner during the production phase of a well. We believe the ceding to us of drilling and completion operatorship in our areas of operation by several large oil and gas companies, including ExxonMobil and BP, reflects their acknowledgement of our low-cost, safe and efficient operations.

Year to Date 2016 Highlights:

·Average daily net production for the first quarter 2016 of 20.4 MBoe/d, with oil production of 5.3 MBoe/d

·EBITDAX for the first quarter 2016 of $51.1 million and net income of $48.5 million

·Adjusted net loss for the first quarter 2016 is a loss of $3.5 million, or $(0.03) per share

·Repurchased an additional $20.3 million in face value of senior notes for $11.2 million (55% of par), resulting in total repurchases year-to-date of $190.9 million in face value of senior notes for $84.8 million (44% of par)

·Year-to-date debt repurchases expected to result in $13 million in expected annual interest savings and approximately $90 million in interest savings over the life of the bonds

26

·Resuming Cleveland drilling program with $2.03 million AFE; expect to have 3 rigs running by the end of the second quarter of 2016

·Locked in $47 million in gains associated with 2018 and 2019 hedges and added hedges as a result of the drilling program resumption; mark-to-market hedge value of $173 million incorporating strip pricing as of April 29, 2016

Updated Capital Expenditures Outlook

In our Annual Report on Form 10-K for the year ended December 31, 2015, we provided an overview of our 2016 capital expenditures budget, which was initially set at $25 million with the majority dedicated to capital well workovers and field optimization activities. On May 4, 2016 the Company announced a revised 2016 capital expenditures program of $100 million, which we expect to fund entirely with cash flows from operations. The Company resumed drilling with one rig in the Cleveland in April 2016 and plans to have three rigs running in the Cleveland by the end of the second quarter of 2016.

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 production, sales price	Three Months Ended March 31,
and average cost data)	2016			2015			Change
Revenues:
Oil	$	13,314		$	33,349		$	(20,035	)
Natural gas	6,542			14,507			(7,965		)
NGLs	5,224			9,378			(4,154		)
Total oil and gas	25,080			57,234			(32,154		)
Other	778			862			(84		)
Total operating revenues	25,858			58,096			(32,238		)
Costs and expenses:
Lease operating	8,617			12,262			(3,645		)
Production and ad valorem taxes	1,601			3,708			(2,107		)
Exploration	162			164			(2		)
Depletion, depreciation and amortization	41,762			52,083			(10,321		)
Accretion of ARO liability	293			194			99
General and administrative	7,504			8,511			(1,007		)
Other operating	—			3,012			(3,012		)
Total costs and expenses	59,939			79,934			(19,995		)
Operating income	(34,081		)	(21,838		)	(12,243		)
Other income (expenses):
Interest expense	(14,798		)	(14,129		)	(669		)
Gain on debt extinguishment	90,652			—			90,652
Net gain (loss) on commodity derivatives	17,219			46,306			(29,087		)
Other income (expense)	225			(2,299		)	2,524
Total other income (expense)	93,298			29,878			63,420
Income before income tax	59,217			8,040			51,177
Income tax provision	10,703			2,344			8,359
Net income (loss)	48,514			5,696			42,818
Net income (loss) attributable to non-controlling interests	29,603			3,508			26,095
Net income (loss) attributable to controlling interests	$	18,911		$	2,188		$	16,723
Net production volumes:
Oil (MBbls)	479			756			(277		)
Natural gas (MMcf)	4,920			5,964			(1,044		)
NGLs (MBbls)	555			627			(72		)
Total (MBoe)	1,854			2,377			(523		)
Average net (Boe/d)	20,374			26,411			(6,037		)

27

(in thousands of dollars except for production, sales price	Three Months Ended March 31,
and average cost data)	2016		2015		Change
Average sales price, unhedged:
Oil (per Bbl), unhedged	$	27.80	$	44.11	$	(16.31	)
Natural gas (per Mcf), unhedged	1.33		2.43		(1.10		)
NGLs (per Bbl), unhedged	9.41		14.96		(5.55		)
Combined (per Boe) realized, unhedged	13.53		24.08		(10.55		)
Average sales price, hedged:
Oil (per Bbl), hedged	$	84.03	$	71.98	$	12.05
Natural gas (per Mcf), hedged	3.67		3.69		(0.02		)
NGLs (per Bbl), hedged	17.04		27.41		(10.37		)
Combined (per Boe) realized, hedged	36.54		39.38		(2.84		)
Average costs (per Boe):
Lease operating	$	4.65	$	5.16	$	(0.51	)
Production and ad valorem taxes	0.86		1.56		(0.70		)
Depletion, depreciation and amortization	22.53		21.91		0.62
General and administrative	4.05		3.58		0.47

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 non-recurring 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 March 31,
(in thousands of dollars)	2016			2015
Reconciliation of EBITDAX to net income
Net income	$	48,514		$	5,696
Interest expense	14,035			13,361
Exploration expense	162			164
Income taxes	10,703			2,344
Amortization of deferred financing costs	763			768
Depreciation and depletion	41,762			52,083
Accretion of ARO liability	293			194
Reduction of TRA liability	(429		)	—
Other non-cash charges	(534		)	407
Stock compensation expense	1,185			1,424
Other non-cash compensation expense	268			109
Net (gain) loss on commodity derivatives	(17,219		)	(46,306		)
Current period settlements of matured derivative contracts	42,671			36,375
Amortization of deferred revenue	(645		)	(525		)
(Gain) loss on sales of assets	4			26
(Gain) on debt extinguishment	(90,652		)	—
Stand-by rig costs	—			3,012
Financing expenses and other loan fees	200			2,273
EBITDAX	$	51,081		$	71,405

28

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.

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

	Three Months Ended March 31,
(in thousands of dollars, except per share data)	2016			2015
Net income	$	48,514		$	5,696
Net (gain) loss on commodity derivatives	(17,219		)	(46,306		)
Current period settlements of matured derivative contracts	42,671			36,375
Exploration	162			164
Non-cash stock compensation expense	1,185			1,424
Other non-cash compensation expense	268			109
(Gain) on debt extinguishment	(90,652		)	—
Stand-by rig costs	—			3,012
Financing expenses	—			2,250
Reduction of TRA liability	(429		)	—
Tax impact of adjusting items (1)	11,059			321
Change in valuation allowance	989			—
Adjusted net income (loss)	$	(3,452	)	$	3,045
Adjusted net income (loss) attributable to non-controlling interests	(2,618		)	1,495
Adjusted net income (loss) attributable to controlling interests	$	(834	)	$	1,550
Earnings per share (basic and diluted)	$	0.62		$	0.12
Net (gain) loss on commodity derivatives	(0.27		)	(0.83		)
Current period settlements of matured derivative contracts	0.69			0.65
Exploration	—			—
Non-cash stock compensation expense	0.02			0.03
Other non-cash compensation expense	—			—
(Gain) on debt extinguishment	(1.47		)	—
Stand-by rig costs	—			0.05
Financing expenses	—			0.04
Reduction of TRA liability	(0.01		)	—
Tax impact of adjusting items (1)	0.36			0.02
Change in valuation allowance	0.03			—
Adjusted earnings (loss) per share (basic and diluted)	$	(0.03	)	$	0.08
Effective tax rate on net income attributable to controlling interests	31.3		%	36.1		%

(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.

29

Results of Operations - Three months ended March 31, 2016 as compared to three months ended March 31, 2015

Operating revenues

Oil and gas sales. Oil and gas sales decreased by $32.1 million (56.1%) to $25.1 million for the three months ended March 31, 2016, as compared to $57.2 million for the three months ended March 31, 2015. The decrease was attributable to the decline in commodity prices ($22.4 million), as well as decreased production volumes ($9.7 million). The average realized oil price, excluding the effects of commodity derivative instruments, decreased from $44.11 per Bbl for the three months ended March 31, 2015 to $27.80 per Bbl for the three months ended March 31, 2016, or 37.0% year over year. The average realized natural gas price, excluding the effects of commodity derivative instruments, decreased from $2.43 per Mcf for the three months ended March 31, 2015 to $1.33 per Mcf for the three months ended March 31, 2016, or 45.3% year over year. The average realized natural gas liquids price, excluding the effects of commodity derivative instruments, decreased from $14.96 per Bbl for the three months ended March 31, 2015 to $9.41 per Bbl for the three months ended March 31, 2016, or 37.1%. Average daily production decreased 22.9% to 20,374 Boe per day for the three months ended March 31, 2016 as compared to 26,411 Boe per day for the three months ended March 31, 2015.

Costs and expenses

Lease operating. Lease operating expense decreased by $3.7 million (30.1%) to $8.6 million for the three months ended March 31, 2016, as compared to $12.3 million for the three months ended March 31, 2015. The decrease is principally attributable to reduction in post-completion costs driven by a halt in the drilling program, operational focus on reducing recurring operating expenses, such as optimizing the usage of compressors and rental equipment, and vendor price reductions. On a per unit basis, lease operating expenses decreased $0.51 per Boe, or 9.9%, from $5.16 per Boe for the three months ended March 31, 2015 to $4.65 per Boe for the three months ended March 31, 2016.

Production and ad valorem taxes. Production and ad valorem taxes decreased by $2.1 million (56.8%) to $1.6 million for the three months ended March 31, 2016, as compared to $3.7 million for the three months ended March 31, 2015. The decrease is driven by a $1.7 million (58.6%) reduction in production taxes, which decreased in conjunction with the 56.1% decrease in oil and gas revenue. Production tax rates vary between states, products, and production levels; therefore, the overall blended rate is impacted by numerous factors and the mix of producing wells at any given time. Additionally, estimated ad valorem taxes decreased $0.4 million from $0.8 million for the three months ended March 31, 2015 to $0.4 million for the three months ended March 31, 2016, reflecting lower property assessments due to lower commodity prices. The average effective rate excluding the impact of ad valorem taxes decreased from 5.1% for the three months ended March 31, 2015 to 4.9% for the three months ended March 31, 2016.

Exploration. Exploration expense remained consistent at $0.2 million for the three months ended March 31, 2016 and 2015. Spending during 2016 primarily related to geological data and seismic processing associated with unproved acreage. There were no exploratory wells drilled in the first quarter of either year.

Depreciation, depletion and amortization. Depreciation, depletion and amortization decreased by $10.3 million (19.8%) to $41.8 million for the three months ended March 31, 2016, as compared to $52.1 million for the three months ended March 31, 2015. The decrease was primarily the result of lower production caused by a reduction in capital spending driven by a halt in the drilling program. On a per unit basis, depletion expense increased $0.62 per Boe or 2.8% from $21.91 per Boe for the three months ended March 31, 2015 as compared to $22.53 per Boe for the three months March 31, 2016.

General and administrative. General and administrative expenses decreased by $1.0 million (11.8%) to $7.5 million for the three months ended March 31, 2016, as compared to $8.5 million for the three months ended March 31, 2015. The decrease in general and administrative expense was primarily attributable to staff and other cost reductions. Non-cash compensation expense remained consistent at $1.5 million for the three months ended March 31, 2016 and 2015. On a per unit basis, cash general and administrative expenses increased from $3.58 per Boe for the three months ended March 31, 2015 to $4.05 per Boe for the three months ended March 31, 2016 primarily due to production declines.

Other operating expense. Other operating expense decreased from $3.0 million for the three months ended March 31, 2015 to none for the three months ended March 31, 2016. Expense for the three months ended March 31, 2015 represents stand-by rig costs associated with the termination of four drilling rigs.  There were no similar charges during 2016.

Interest expense.  Interest expense increased by $0.7 million (5.0%) to $14.8 million for three months ended March 31, 2016, as compared to $14.1 million for the three months ended March 31, 2015. The increase was driven by the issuance of the 2023 Notes on February 23, 2015. During the three months ended March 31, 2016, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.67%, 6.75% and 9.25%, respectively. Average outstanding balances for the three months ended March 31, 2016 were $143.1 million, $451.9 million and $215.6 million under the Revolver, the 2022 Notes and the 2023 Notes, respectively.

30

Gain on debt extinguishment. The gain on debt extinguishment of $90.7 million for the three months ended March 31, 2016 was related to the purchase of an aggregate principal amount of $170.5 million of our senior unsecured notes for cash of $73.4 million. The company recognized accelerated amortization of debt issuance costs of $6.4 million associated with the cancellation. See Note 4, “Long-Term Debt,” for further details regarding the debt extinguishment.

Net gain (loss) on commodity derivatives. The net gain (loss) on commodity derivatives was a net gain of $17.2 million for the three months ended March 31, 2016, as compared to a net gain of $46.3 million for the three months ended March 31, 2015. The gain was driven by lower average crude oil and natural gas prices ($33.35 and $1.99, respectively) for the three months ended March 31, 2016, as compared to the crude oil and natural gas prices as of December 31, 2015 ($37.13 per barrel and $2.28 per Mcf, respectively) as well as additional hedging activity during 2016.

Other income (expense).  Other income (expense) increased by $2.5 million to net income of $0.2 million for the three months ended March 31, 2016, as compared to a net expense of $2.3 million for the three months ended March 31, 2016. The change is related to financing costs incurred during 2015, for which there were no similar charges during 2016.

Income taxes. The provision for federal and state income taxes for the three months ended March 31, 2016 was an expense of $10.7 million resulting in a 18.1% effective tax rate as a percentage of our pre-tax book income for the quarter as compared to an expense of $2.3 million for the three months ended March 31, 2015, which was 29.2% of pre-tax book income. 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 change in effective tax rate was due primarily to the magnitude of state tax expense as a percentage of total tax expense and the percentage of income allocated to the non-controlling interest. See Note 9, “Income Taxes,” for further details.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been private and public sales of our debt and equity, borrowings under bank credit facilities and cash flows from operations. Our primary use of capital has been for the exploration, development and acquisition of oil and gas properties. As we pursue reserves and production growth, we continually consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our ability to grow proved reserves and production will be highly dependent on the capital resources available to us. We strive to maintain financial flexibility in order to maintain substantial borrowing capacity under our Revolver (as defined below), facilitate drilling on our undeveloped acreage positions and permit us to selectively expand our acreage positions. Depending on the 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 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 March 31, 2016 reflects a positive working capital balance largely due to the value of our current commodity derivative assets as of this date. We have historically and in the future expect to maintain a negative working capital balance, and we use our Revolver to help manage our working capital.

Availability under the Revolver is subject to a borrowing base. Our borrowing base at March 31, 2016 was $510 million of which $185 million was utilized leaving an unused capacity of $325 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. In light of current commodity prices and our reduction in drilling activities, it is our expectation that the borrowing base will be reduced during the upcoming re-determination. 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 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 required under the Revolver 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

31

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

As of March 31, 2016, our total leverage ratio is approximately 3.0 and our current ratio is approximately 6.9, as calculated based on the requirements in our covenants. We are in compliance with all terms of our Revolver at March 31, 2016, and we expect to maintain compliance throughout 2016. 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 2016 and beyond. In the event it were to become necessary, we believe we have the ability to take actions that would prevent us from failing to comply with our covenants, such as hedge restructuring. While it is our expectation that we will continue to be in compliance with our covenants, no assurance can be given that this will be the case. If an event of default exists under the Revolver, the lenders will 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.

The following table summarizes our cash flows for the three months ended March 31, 2016 and 2015:

	Three Months Ended March 31,
(in thousands of dollars)	2016			2015
Net cash provided by / (used in) operating activities	$	(4,796	)	$	45,514
Net cash provided by / (used in) investing activities	35,135			(118,589		)
Net cash provided by financing activities	1,573			87,780
Net increase in cash	$	31,912		$	14,705

Cash flow provided by / (used in) operating activities

Net cash used in operating activities was $4.8 million during the three months ended March 31, 2016 as compared to net cash provided by operating activities of $45.5 million during the three months ended March 31, 2015. The decrease in operating cash flows was primarily due to the $32.1 million decrease in oil and gas revenues for the three months ended March 31, 2016 as compared to the three months ended March 31, 2015, driven by declines in prices for all products.

Cash flow provided by / (used in) investing activities

Net cash provided by investing activities was $35.1 million during the three months ended March 31, 2016 as compared to net cash used in investing activities of $118.6 million during the three months ended March 31, 2015. The increase in investing cash flow was primarily driven by the reduction in capital spending, resulting from a halt in the drilling program.

Cash flow provided by financing activities

Net cash provided by financing activities was $1.6 million during the three months ended March 31, 2016 as compared to net cash provided by financing activities of $87.8 million during the three months ended March 31, 2015. The decrease in financing cash flows was primarily due to the purchase of an aggregate principal amount of $170.5 million of our senior unsecured notes for cash of $73.4 million. The Company used cash on hand and borrowings from its Revolver to fund the note purchases. Borrowings under the Revolver totaled $75.0 million during the three months ended March 31, 2016.

Contractual Obligations

The holders of JEH Units, including Jones Energy, Inc., 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 the holders 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.

As outlined in Note 7, “Subsequent Events,” on April 12, 2016, 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, an aggregate cash tax distribution of approximately $10.9 million to its unitholders towards its total 2016 projected tax distribution obligation. Based on our 2016 capital budget, debt extinguishment through April 29, 2016, and other information available as of this filing, we estimate that the total amount

32

of tax distributions to JEH unitholders in 2016 would be approximately $45.6 million, including the approximately $10.9 million that has been paid to date. The distributions are to be made pro-rata to all members, and would result in a $17.3 million payment to the Company, and a $17.4 million payment to Pre-IPO Owners. The 2016 tax distributions are the result of taxable income generated by our operations and debt extinguishment, and our current projections do not currently lead us to anticipate payment of such tax distribution obligations beyond the current year.

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, 2015.

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, 2015.

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, 2015, 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 2016, and historically low commodity prices may exist for an extended period. In applying the prescribed impairment test under the successful efforts method at March 31, 2016, no impairment charge was indicated.

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, 2015 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 12-month period ended March 31, 2016 (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, 2015 would have decreased by approximately 2%. 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, 2016.

33

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

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

·Increases in service costs;

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

·Increases in operating costs;

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

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

Commodity price risk and hedges

Our principal market risk exposure is to oil, natural gas and NGL prices, which are inherently volatile. As such, future earnings are subject to change due to fluctuations in such prices. Realized prices are primarily driven by the prevailing prices for oil and regional spot prices for natural gas and NGLs. We have used, and expect to continue to use, oil, natural 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 March 31, 2016 was a net asset of $192.0 million.

Interest rate risk

We are subject to market risk exposure related to changes in interest rates on our variable rate indebtedness. The terms of the senior secured revolving credit facility provide for interest on borrowings at a floating rate equal to prime, LIBOR or federal funds rate plus margins ranging from 0.50% to 2.50% depending on the base rate used and the amount of the loan outstanding in relation to the borrowing base. The base rate margins under the terminated term loan were 6.0% to 7.0% depending on the base rate used and the amount of the loan outstanding. The terms of our senior notes provide for a fixed interest rate through their respective maturity dates. During the three months ended March 31, 2016, borrowings under the Revolver, the 2022 Notes and the 2023 Notes bore interest at a weighted average rate of 2.67%, 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 March 31, 2016 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.

34

Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were not effective as of March 31, 2016 because of the material weakness in internal control over financial reporting described in our Annual Report on Form 10-K for the year ended December 31, 2015.

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, 2015 included a report of management’s assessment regarding internal control over financial reporting.

35

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

For a discussion of legal proceedings, see Note 12 “Commitments and contingencies,” in the Notes to Consolidated Financial Statements for further discussion appearing in Part I, Item 1 of this Quarterly Report on Form 10-Q, which is incorporated in this item by reference.

Item 1A. Risk Factors

Our business faces many risks. Any of the risks discussed elsewhere in this Form 10-Q and our other SEC filings, including our Annual Report on Form 10-K for the year ended December 31, 2015, 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, 2015. Other than as set forth below, there have been no material changes in our risk factors from those described in our Annual Report. To the extent the material change relates to a risk factor disclosed in the Annual Report, the risk factor heading is included below for reference purposes, but does not purport to otherwise modify the disclosure in the Annual Report unless the context indicates otherwise.

Risks Relating to the Oil and Natural Gas Industry and Our Business:

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGLs we produce; and actual impacts of climate change like extreme weather conditions could adversely affect our operations.

As part of a joint strategy announced by President Barack Obama and Canadian Prime Minister Justin Trudeau regarding climate change and the reduction of greenhouse gas emissions from the energy sector, the U.S. Environmental Protection Agency (“EPA”) stated in March 2016 that it will be taking steps to develop regulations to reduce methane emissions from existing oil and gas emission sources.  As a first step, the EPA is conducting a formal Information Collection Request to gather information to assist in the development of the regulations.  Because the timing and details of the anticipated future regulations are not yet known, it is not possible to estimate any potential impact on our business.

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.

36

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

37

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: May 6, 2016	By:	/s/ Robert J. Brooks
		Name:	Robert J. Brooks
		Title:	Chief Financial Officer (Principal Financial Officer)

Signature Page to Form 10-Q (Q1 2016)

38