Exhibit 99.1

JONES ENERGY, INC. ANNOUNCES 2018 FOURTH QUARTER AND FULL YEAR FINANCIAL AND OPERATING RESULTS AND 2018 YEAR END PROVED RESERVES

Austin, TX — February 27, 2019 — Jones Energy, Inc. (OTCQX: JONE) (“Jones Energy” or “the Company”) today announced financial and operating results for the fourth quarter and full year ended December 31, 2018. The Company also announced its 2018 year-end proved reserves as well as initial first quarter 2019 production guidance and 2019 capital budget.

Highlights

·Second operated WAB Marmaton well, Malinda-1HR achieves peak to-date IP30 rate of 1,144 Boe/d consisting of 864 Bo/d and 1,679 Mcf/d, with gas rates still increasing.

·Merge Meramec single-section well, Margaret 2H achieved peak IP30 rate of 1,074 Boe/d consisting of 676 Bo/d and 2,387 Mcf/d.

·Merge 2-mile lateral Meramec well, Tomahawk-1HX achieves peak IP30 rate of 1,697 Boe/d consisting of 732 Bo/d and 5,792 Mcf/d.

·Average daily net production for the fourth quarter 2018 achieves 22,109 Boe/d, 11% above guidance midpoint. Production for the full year 2018 of 8.3 MMBoe (22,753 Boe/d).

·Total proved year-end 2018 reserves of 68.0 MMBoe (55% liquids) of which 61.0 MMBoe or 90% were classified as proved developed. Year-end 2018 proved reserves standardized measure value of $547 million. Corresponding Non-GAAP SEC PV-10(1) value of $570 million, based on SEC prices(2).

·Recognized impairment charges of $1.3 billion in aggregate to Proved and Unproved WAB properties and Proved Merge properties.

·Net loss for the fourth quarter 2018 of $1,235.5 million, or $239.73 per share. Non-GAAP adjusted net loss(3) of $100.3 million, or a loss of $20.21 per share. Net loss for the full year 2018 of $1,346.7 million. Non-GAAP adjusted net loss(3) of $184.6 million and EBITDAX(3) for the full year 2018 of $93.8 million.

(1)  SEC PV-10 is a supplemental Non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements. For additional information, including a reconciliation to standardized measure, the most comparable GAAP financial measure, please see “Non-GAAP Financial Measures and Reconciliations” below.

(2)  SEC prices for 2018 year-end proved reserves were $65.56 per barrel for oil and $3.11 per MMBtu for natural gas based on the average of such prices for 2018.

(3)  Adjusted net loss, adjusted net loss per share and EBITDAX are supplemental non-GAAP financial measures that are used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. For additional information, including reconciliations to the most comparable GAAP financial measures, please see “Non-GAAP Financial Measures and Reconciliations” below.

1

Financial Results

Total operating revenues for the three months ended December 31, 2018 were $53.9 million as compared to $54.5 million for the three months ended December 31, 2017. For the full year 2018, operating revenues were $236.4 million as compared to $188.6 million for the full year 2017. Total revenues including current period settlements of matured derivative contracts were $40.8 million and $185.7 million for the fourth quarter and full year 2018, respectively, as compared to $55.2 million and $255.4 million for the fourth quarter and full year 2017, respectively.

Total operating expenses for the three months ended December 31, 2018 were $72.5 million when excluding a one-time impairment charge of $1.3 billion, as compared to $60.8 million for the three months ended December 31, 2017.  For the full year 2018, total operating expenses were $275.0 million as compared to 2017 full year total operating expenses of $255.7 million, omitting full year impairment charges of $1.3 billion in 2018 and $149.6 million in 2017. The Company incurred the $1.3 billion impairment charge in 2018 as a result of its limited ability to continue to book proved undeveloped reserves due to a prolonged period of low commodity prices and capital constraints.

For the fourth quarter ended December 31, 2018, the Company reported a net loss of $1,235.5 million, or a net loss of $239.73 per share attributable to common shareholders, compared to fourth quarter of 2017 net income of $41.6 million, or net income of $10.17 per share attributable to common shareholders. For the full year 2018 the Company reported a net loss of $1,346.7 million, or a net loss of $271.94 per share compared to full year 2017 net loss of $178.8 million, or a net loss of $30.22 per share attributable to common shareholders.

Excluding, on a tax-adjusted basis, certain items that the Company does not view as indicative of its ongoing financial performance, and adjusting for non-controlling interest, the Company had an adjusted net loss(4) for the fourth quarter 2018 of $98.7 million, or an adjusted net loss per share of $20.21, as compared to adjusted net loss of $27.2 million, or adjusted net loss per share of $6.59 for the three months ended December 31, 2017. Adjusting for non-controlling interests, the Company had an adjusted net loss(4) for the full year 2018 of $174.3 million, or an adjusted net loss per share of $38.11 attributable to common shareholders as compared to adjusted net loss of $22.8 million, or adjusted net loss per share of $8.48 attributable to common shareholders for the full year 2017.

(4)  Adjusted net loss, adjusted net loss per share are supplemental non-GAAP financial measures that are used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. For additional information, including reconciliations to the most comparable GAAP financial measures, please see “Non-GAAP Financial Measures and Reconciliations” below.

2

Earnings before interest, impairment, income taxes, depreciation, amortization, and exploration expense (“EBITDAX”) for the fourth quarter and full year 2018 was $16.9 million and $93.8 million, respectively(5). This compares to fourth quarter and full year 2017 EBITDAX of $37.7 million and $186.4 million, respectively.

Full year 2018 lease operating expense (“LOE”) was $44.9 million compared to the Company’s full year 2017 LOE of $36.6 million. Fourth quarter 2018 LOE was $12.0 million compared to the Company’s fourth quarter 2017 LOE of $8.9 million. On a dollar per Boe basis, full year 2018 LOE was $5.41 per Boe compared to full year 2017 LOE which was $4.71 per Boe. Fourth quarter 2018 LOE of $5.88 per Boe was approximately 28% higher than fourth quarter 2017 LOE of $4.59.

Preferred Stock Dividend Update

During the fourth quarter, on October 15, 2018, the Company’s Board of Directors declared a contingent dividend on the Company’s 8.0% Series A Perpetual Convertible Preferred Stock (“Preferred Stock”), payable in Class A common stock on November 15, 2018 to holders of record as of November 1, 2018. It was announced on November 15, 2018 that the Dividend Valuation Price did not meet the required Floor Price(6), and the dividend was not paid. Subsequent to quarter end, on January 16, 2019 the Company’s Board of Directors again declared a contingent dividend on the Preferred Stock under the same terms, payable in Class A common stock on February 15, 2019 to holders of record as of February 1, 2019, including the requirement that the Dividend Valuation Price of the stock must meet the required Floor Price in order to be paid. On February 14, 2019 it was announced that the Floor price was not met, and that the dividend would not be paid. The Company has now used four of its five permitted dividend holidays without penalty and the right to receive those dividends will accrue for holders of Preferred Stock.

Preferred Stock Conversion Window Extension

During the fourth quarter, on November 26, 2018, the Company issued a Fundamental Change notice to holders of the Preferred Stock in conjunction with the delisting of the Company’s Class A common stock from the New York Stock Exchange, giving such holders special rights to convert shares of Preferred Stock to Class A Common Stock at a premium to the existing conversion rate, originally until January 14, 2019. The Company’s Board of Directors has since extended the special rights conversion end date to March 31, 2019.

(5)  EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

(6)  As defined in the Certificate of Designations for the Preferred Stock and as adjusted in accordance with the terms of the Certificate of Designations.

3

2018 Year-End Proved Reserves

Jones Energy’s year-end 2018 proved reserves based on SEC pricing were 68.0 MMBoe, of which 90% were classified as proved developed reserves. Total proved oil reserves at year-end 2018 were 15.8 MMBbls, of which 13.8 or 87% were classified as proved developed reserves. The Company’s limited ability to book additional proved undeveloped reserves due to its ongoing capital constraints has resulted in a significant reduction in total proved reserves as compared to prior years. The SEC standardized measure value of the Company’s proved reserves was $547 million. Its NYMEX PV-10 (7) value of proved reserves for year-end 2018 was $570 million.

The following tables set forth the Company’s total proved reserves. These estimates are based on reports prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Year-end proved reserves were determined utilizing a WTI oil price of $65.56 per barrel and a Henry Hub spot market natural gas price of $3.11 per MMBtu as prescribed by the SEC.

Proved Reserves as of December 31, 2018

	Oil (MMBbl)	Gas (Bcf)	NGLs (MMBbl)	Total (MMBoe)	% Liquids (Oil & NGLs)
Eastern Anadarko(8)	5.3	64.8	6.7	22.9	53	%
Western Anadarko(9)	10.4	118.7	14.8	45.0	56	%
Other	0.0	0.3	0.0	0.1	41	%
Total Proved	15.8	183.9	21.6	68.0	55	%
Proved Developed	13.8	165.2	19.7	61.0	55	%

Assuming strip pricing as of January 2, 2019, through 2023 and keeping pricing flat thereafter, instead of 2018 SEC pricing, while leaving all other parameters unchanged, the Company’s proved reserves would have been 63.8 MMBoe, and the corresponding NYMEX PV—10(10) would have been $378 million. This alternative pricing scenario is provided only to demonstrate the impact that the current pricing environment may have on reserve volumes and SEC PV-10 value. There is no assurance that these prices will actually be realized.

(7)  NYMEX PV-10 is a supplemental Non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements. For additional information, including a reconciliation to standardized measure, the most comparable GAAP financial measure, please see “Non-GAAP Financial Measures and Reconciliations” below.

(8)  Eastern Anadarko includes the Merge Meramec and Woodford.

(9)  Western Anadarko includes the Cleveland, Granite Wash, Tonkawa and Marmaton.

(10)  NYMEX PV-10 is a supplemental Non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements. For additional information, including a reconciliation to standardized measure, the most comparable GAAP financial measure, please see “Non-GAAP Financial Measures and Reconciliations” below.

4

Changes in Proved Reserves (MMBoe)
Proved reserves as of December 31, 2017	104.8
Extensions and discoveries	8.4
Production	(8.3	)
Purchases of Minerals in Place	—
Sales of Minerals in Place	—
Revisions of previous estimates	(36.9	)
Proved reserves as of December 31, 2018	68.0

Operating Results

Western Anadarko Basin (WAB)

During the fourth quarter the Company spud two wells and completed two wells in the Western Anadarko. The second well spud was initially scheduled for January 2019, but the Company took advantage of rig schedule availability in late December. The well, a Marmaton target, was still in the process of drilling at year end.

The Company’s second operated Marmaton well, the Malinda 1HR located in Ochiltree county, TX, spud in the third quarter, was one of the two wells completed during the fourth quarter. The well has to-date achieved a peak IP30 rate of 864 Bo/d and 1,679 Mcf/d, although gas continues to climb. Malinda 1HR has shown exceedingly strong early production, surpassing type curve expectations. Management is encouraged by this early-time performance.

Jones Energy is providing further production data for its first operated Marmaton well placed online in September 2018. The Company previously announced a peak IP30 rate for the Malinda 2H of 580 Boe/d three-stream, 63% oil, 78% liquids. Today, Jones Energy is pleased to announce a peak IP60 rate of 467 Boe/d three-stream, which was 65% oil, 79% liquids as well as a peak IP90 rate of 403 Boe/d three-stream which was 65% oil, 79% liquids.

For the full year 2018, the Company drilled seven and completed six wells in the Western Anadarko. Jones Energy exited 2018 with 556 operated wells producing in the WAB. The Company will continue to drill wells required to maintain existing agreements in the WAB and will evaluate additional Marmaton and Cleveland drilling opportunities on a returns-focused basis.

Jones Energy recently entered into definitive agreements to sell several non-core assets related to its WAB and other properties, for a combined total of up to $11 million, which is subject to closing adjustments. The transactions are expected to be completed in the first quarter of 2019, subject to customary closing conditions. The sales are expected to impact first quarter 2019 production by approximately 350 Boe/d. This has been accounted for in the Company’s first quarter 2019 production guidance noted later in this release.

5

Merge

In the fourth quarter of 2018 the Company spud one well and completed three wells in the Merge. The Margaret 2H well, a Meramec target, was drilled to a 4,873-foot lateral length and achieved a peak IP30 oil rate of 676 Bo/d and gas rate of 2,387 Mcf/d, or a combined peak IP30 rate of 1,074 Boe/d. Another Meramec well, the Tomahawk 1HX was drilled to a 9,778-foot lateral was completed and placed online in mid-December. The well achieved a peak IP30 oil rate of 732 Bo/d and 5,792 Mcf/d. The well is located adjacent to the Company’s record-setting Bomhoff pad in Canadian County, OK.

For the full year 2018 the Company drilled 14 and completed 22 wells in the Merge. As of year-end 2018, Jones Energy held by production (“HBP”) all its operated sections and operated 43 producing wells in the Merge. Going forward, management plans to evaluate opportunities for drilling on its Merge properties on a selective basis.

Fourth Quarter and Full Year 2018 Production

Jones Energy produced 2,034 MBoe, or 22,109 Boe/d during the fourth quarter of 2018 with all three product streams outpacing Company guidance. Strong fourth quarter volumes are attributed to both outperformance in base production as well as a number of development wells exceeding performance expectations.

A breakout of fourth quarter production is shown in the table below.

	Three months ended December 31, 2018:
	Oil (MBbls)	Natural Gas (MMcf)	NGLs (MBbls)	Total (MBoe)	% of Total
WAB	285	2,649	356	1,083	53	%
Merge	196	2,454	246	851	42	%
Other	7	404	26	100	5	%
Total	488	5,507	628	2,034	100	%

For the full year 2018, Jones Energy produced 22,753 Boe/d with total liquids volumes of 57%. For the full year 2018, the Company’s production grew 7% as compared to average 2017 production, excluding production from the divested Arkoma properties in 2017.

6

Capital Expenditures Update for the Fourth Quarter and Full Year 2018

The Company’s capital expenditures for the 2018 fourth quarter totaled $38.5 million, achieving the low end of previously issued Company guidance. $29.7 million, or 77% of fourth quarter spending, was related to the drilling and completing of wells. The remaining $8.8 million was primarily related to leasing and workover activity.

For the full year 2018, total capital expenditures excluding impairments were $192.6 million, of which $149.5 million, or 78% was related to drilling and completing wells. Capital expenditures related to participating in non-op drilling for the full year 2018 totaled $23.7 million. Spending for the second half of 2018 totaled $82.1 million, which is reflective of the Company’s reduced operating activity and cost-cutting measures as compared to first half 2018 capital expenditures of $110.5 million.

Initial 2019 First Quarter Guidance

Jones Energy is announcing projected average daily production of 18,300 to 20,300 Boe/d for the first quarter of 2019. The Company anticipates a quarter-over-quarter decline in production as a result of several factors including the previously mentioned non-core asset sales, natural PDP declines, and no meaningful contributions from new completion activity in the first quarter. Jones Energy expects to run a limited capital program in 2019, with an approved capital budget of $60 million.  A table has been provided below with production guidance by category.

	1Q19E
2019 First Quarter Production Guidance
Total Production (MMBoe)	1.6 – 1.8
Average Daily Production (MBoe/d)	18.3 – 20.3
Crude Oil (MBbl/d)	4.8 – 5.3
Natural Gas (MMcf/d)	48.7 – 51.4
NGLs (MBbl/d)	5.4 – 6.0

	2019E
Full Year 2019 Capital Expenditures ($MM)
Merge D&C	$	33
WAB D&C	15
Other (Maintenance, Leasing, Pooling, etc.)	12
Total Capital Expenditures	$	60

7

Liquidity and Hedging Update

As of December 31, 2018, Jones Energy had approximately $58.5 million in cash. As previously announced, the Company continues to explore strategic alternatives and debt reduction initiatives. The following table summarizes the Company’s net commodity derivative contracts outstanding as of February 27, 2019:

	1Q19		2Q19		3Q19		4Q19		2019		2020
Oil Hedges
Swaps (MBbl)	165		125		130		120		540		660
Price ($/Bbl)	$	49.95	$	49.93	$	49.96	$	49.96	$	49.95	$	50.00
Collars (MBbl)	215		204		196		195		810		—
Floor ($/Bbl)	$	48.52	$	48.52	$	48.52	$	48.52	$	48.52	—
Ceiling ($/Bbl)	$	59.64	$	59.64	$	59.64	$	59.64	$	59.64	—
Gas Hedges
Swaps (MMcf)	1,680		1,740		1,890		1,950		7,260		8,400
Price ($/Mcf)	$	2.83	$	2.83	$	2.82	$	2.82	$	2.83	$	2.79
Collars (MMcf)	3,120		3,010		2,910		2,850		11,890		—
Floor ($/Mcf)	$	2.55	$	2.55	$	2.55	$	2.55	$	2.55	—
Ceiling ($/Mcf)	$	3.19	$	3.19	$	3.19	$	3.19	$	3.19	—

Conference Call Details

Jones Energy will host a conference call for investors and analysts to discuss its results on Thursday, February 28, 2019 at 10:30 a.m. ET (9:30 a.m. CT).  The conference call can be accessed via webcast through the Investor Relations section of Jones Energy’s website, www.jonesenergy.com, or by dialing (833) 231-8272 (for domestic U.S.) or (647) 689-4117 (International) and entering conference code 3399073.  If you are not able to participate in the conference call, the webcast replay and a downloadable audio file will be available shortly following the call through the Investor Relations section of the Company’s website, www.jonesenergy.com.

About Jones Energy

Jones Energy, Inc. is an independent oil and natural gas company engaged in the exploration and development of oil and natural gas properties in the Anadarko basin of Oklahoma and Texas. Additional information about Jones Energy may be found on the Company’s website at: www.jonesenergy.com.

Investor Contact:

Page Portas

Investor Relations

512-493-4834

ir@jonesenergy.com

8

Forward-Looking Statements

This press release 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 press release 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 press release specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including guidance regarding the deployment of rigs in the Company’s areas of operation and the anticipated drilling plans, the initial 2019 capital budget,  the expected sales of non-core assets and their impact on first quarter production, plans for drilling in the Merge, timing of production impacts, and projections regarding total production, average daily production, lease operating expenses, production taxes, cash G&A expenses and capital expenditure levels for 2018.  These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements.  These include, but are not limited to, changes in oil and natural gas prices, weather and environmental conditions, the timing and amount of planned capital expenditures, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, covenants in the Company’s debt documents and their potential effect on the ability to engage in certain transactions, the condition of the capital markets generally, as well as the Company’s ability to access them, ability to fund growth opportunities, the proximity to and capacity of transportation facilities, non-performance by third parties of contractual obligations, 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.

9

Jones Energy, Inc.

(Unaudited) Consolidated Statement of Operations

	Three months ended December 31,						Year ended December 31,
(in thousands of dollars except per share data)	2018			2017			2018			2017
Operating revenues
Oil and gas sales	$	54,077		$	53,966		$	236,873		$	186,393
Other revenues	(190		)	546			(516		)	2,180
Total operating revenues	53,887			54,512			236,357			188,573
Operating costs and expenses
Lease operating	11,951			8,947			44,921			36,636
Production and ad valorem taxes	3,102			2,233			12,087			6,874
Transportation and processing costs	863			—			3,368			—
Exploration	1,156			2,507			8,157			14,145
Depletion, depreciation and amortization	47,924			39,881			173,904			167,224
Impairment of oil and gas properties	1,331,785			1,632			1,331,785			149,648
Accretion of ARO liability	282			240			1,066			960
General and administrative	7,001			5,399			31,204			29,892
Other operating	250			—			250			—
Total operating expenses	1,404,314			60,839			1,606,742			405,379
Operating income (loss)	(1,350,427		)	(6,327		)	(1,370,385		)	(216,806		)
Other income (expense)
Interest expense	(22,214		)	(13,270		)	(89,328		)	(51,651		)
Gain on debt extinguishment	—			—			—			—
Net gain (loss) on commodity derivatives	49,296			(29,293		)	(2,757		)	(17,985		)
Other income (expense)	52,956			42,563			53,935			56,952
Other income (expense), net	80,038			—			(38,150		)	(12,684		)
Income (loss) before income tax	(1,270,389		)	(6,327		)	(1,408,535		)	(229,490		)
Income tax provision (benefit)	(34,901		)	(47,960		)	(61,841		)	(50,667		)
Net income (loss)	(1,235,488		)	41,633			(1,346,694		)	(178,823		)
Net income (loss) attributable to non-controlling interests	(44,416		)	(5,284		)	(55,655		)	(77,331		)
Net income (loss) attributable to controlling interests	$	(1,191,072	)	$	46,917		$	(1,291,039	)	$	(101,492	)
Dividends and accretion on preferred stock	(1,848		)	(1,965		)	(7,737		)	(7,924		)
Net income (loss) attributable to common shareholders	$	(1,192,920	)	$	44,952		$	(1,298,776	)	$	(109,416	)
Earnings (loss) per share:
Basic - Net income (loss) attributable to common shareholders	$	(239.73	)	$	10.17		$	(271.94	)	$	(30.22	)
Diluted - Net income (loss) attributable to common shareholders	$	(239.73	)	$	10.17		$	(271.94	)	$	(30.22	)
Weighted average Class A shares outstanding:
Basic	4,976			4,419			4,776			3,621
Diluted	4,976			4,419			4,776			3,621

10

Jones Energy, Inc.

(Unaudited) Consolidated Balance Sheet

	December 31,			December 31,
(in thousands of dollars)	2018			2017
Assets
Current assets
Cash and cash equivalents	$	58,464		$	19,472
Accounts receivable, net
Oil and gas sales	33,954			34,492
Joint interest owners	23,997			31,651
Other	614			1,236
Commodity derivative assets	5,003			3,474
Other current assets	8,099			14,376
Total current assets	130,131			104,701
Oil and gas properties, net, under the successful efforts method	271,846			1,597,040
Other property, plant and equipment, net	1,639			2,719
Commodity derivative assets	1,415			172
Deferred tax assets	129			—
Other assets	415			5,431
Total assets	$	405,575		$	1,710,063
Liabilities and Stockholders’ Equity
Current liabilities
Trade accounts payable	$	32,506		$	72,663
Oil and gas sales payable	34,035			31,462
Accrued liabilities	37,799			21,604
Commodity derivative liabilities	370			36,709
Other current liabilities	4,927			4,049
Total current liabilities	109,637			166,487
Long-term debt	982,157			759,316
Deferred revenue	4,118			5,457
Commodity derivative liabilities	—			8,788
Asset retirement obligations	20,432			19,652
Liability under tax receivable agreement	—			59,596
Other liabilities	495			811
Deferred tax liabilities	—			14,281
Total liabilities	1,116,839			1,034,388
Mezzanine equity
Series A preferred stock, $0.001 par value; 1,804,478 shares issued and outstanding at December 31, 2018 and 1,839,995 shares issued and outstanding at December 31, 2017	93,719			89,539
Stockholders’ equity
Class A common stock, $0.001 par value; 5,025,632 shares issued and 5,024,491 shares outstanding at December 31, 2018 and 4,506,991 shares issued and 4,505,861 shares outstanding at December 31, 2017	5			5
Class B common stock, $0.001 par value; 172,193 shares issued and outstanding at December 31, 2018 and 481,391 shares issued and outstanding at December 31, 2017	—			—
Treasury stock, at cost: 1,141 shares at December 31, 2018 and December 31, 2017	(358		)	(358		)
Additional paid-in-capital	638,108			606,414
Retained (deficit) / earnings	(1,435,050		)	(136,274		)
Stockholders’ equity	(797,295		)	469,787
Non-controlling interest	(7,688		)	116,349
Total stockholders’ equity	(804,983		)	586,136
Total liabilities and stockholders’ equity	$	405,575		$	1,710,063

11

Jones Energy, Inc.

(Unaudited) Consolidated Statement of Cash Flow Data

	Year ended December 31,
(in thousands of dollars)	2018			2017
Cash flows from operating activities
Net income (loss)	$	(1,346,694	)	$	(178,823	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depletion, depreciation, and amortization	173,904			167,224
Exploration (dry hole and lease abandonment)	4,191			11,017
Impairment of oil and gas properties	1,331,785			149,648
Accretion of ARO liability	1,066			960
Amortization of debt issuance costs	10,649			3,955
Stock compensation expense	1,381			6,260
Deferred and other non-cash compensation expense	56			208
Amortization of deferred revenue	(1,555		)	(1,854		)
Loss on commodity derivatives	2,757			17,985
(Gain) loss on sales of assets	(9,749		)	127
(Gain) on debt extinguishment	—			—
Deferred income tax provision	(61,835		)	(47,082		)
Change in liability under tax receivable agreement	(54,936		)	(59,492		)
Other - net	400			2,044
Changes in operating assets and liabilities
Accounts receivable	9,685			(34,615		)
Other assets	7,191			(12,330		)
Accrued interest expense	11,841			(1,422		)
Accounts payable and accrued liabilities	(25,697		)	35,198
Net cash provided by operations	54,440			59,008
Cash flows from investing activities
Additions to oil and gas properties	(188,800		)	(245,364		)
Net adjustments to purchase price of properties acquired	—			2,391
Proceeds from sales of assets	11,082			61,290
Acquisition of other property, plant and equipment	(360		)	(586		)
Current period settlements of matured derivative contracts	(53,147		)	72,265
Net cash used in investing	(231,225		)	(110,004		)
Cash flows from financing activities
Proceeds from issuance of long-term debt	20,000			162,000
Repayment of long-term debt	(231,000		)	(129,000		)
Proceeds from senior notes	438,867			—
Payment of debt issuance costs	(11,624		)	(1,115		)
Payment of cash dividends on preferred stock	—			(3,368		)
Net distributions paid to JEH unitholders	—			(562		)
Net payments for share based compensation	(466		)	(462		)
Proceeds from sale of common stock	—			8,333
Net cash provided by financing	215,777			35,826
Net increase (decrease) in cash and cash equivalents	38,992			(15,170		)
Cash and cash equivalents
Beginning of period	19,472			34,642
End of period	$	58,464		$	19,472
Supplemental disclosure of cash flow information
Cash paid for interest, net of capitalized interest	$	68,561		$	49,101
Cash paid for income taxes	—			2,318
Change in accrued additions to oil and gas properties	(3,377		)	3,921
Asset retirement obligations incurred, including changes in estimate	695			924

12

Jones Energy, Inc.

(Unaudited) Selected Financial and Operating Statistics

The following table sets forth summary data regarding revenues, production volumes, average prices and average production costs associated with our sale of oil and natural gas for the periods indicated:

	Three Months Ended December 31,								Year Ended December 31,
(in thousands of dollars)	2018			2017		Change			2018			2017		Change
Revenues:
Oil and gas sales	$	54,077		$	53,966	$	111		$	236,873		$	186,393	$	50,480
Other revenues	(190		)	546		(736		)	(516		)	2,180		(2,696		)
Current period settlements of matured derivative contracts	(13,064		)	706		(13,770		)	(50,657		)	66,851		(117,508		)
Total operating revenues	$	40,823		$	55,218	$	(14,395	)	$	185,700		$	255,424	$	(69,724	)
Net production volumes:
Oil (MBbls)	488			572		(84		)	2,241			1,964		277
Natural gas (MMcf)	5,507			4,763		744			21,384			20,425		959
NGLs (MBbls)	628			585		43			2,500			2,418		82
Total (MBoe)	2,034			1,951		83			8,305			7,786		519
Average net (Boe/d)	22,109			21,207		902			22,753			21,332		1,421
Average sales price, unhedged:
Oil (per Bbl), unhedged	$	55.89		$	52.56	$	3.33		$	63.02		$	47.46	$	15.56
Natural gas (per Mcf), unhedged	2.12			1.80		0.32			1.62			2.07		(0.45		)
NGLs (per Bbl), unhedged	24.06			26.20		(2.14		)	24.38			21.09		3.29
Combined (per Boe), unhedged	26.59			27.66		(1.07		)	28.52			23.94		4.58
Average sales price, hedged:
Oil (per Bbl), hedged	$	38.98		$	59.15	$	(20.17	)	$	46.38		$	74.91	$	(28.53	)
Natural gas (per Mcf), hedged	1.64			2.62		(0.98		)	1.63			3.50		(1.87		)
NGLs (per Bbl), hedged	20.61			14.30		6.31			18.99			14.30		4.69
Combined (per Boe), hedged	20.16			28.02		(7.86		)	22.42			32.53		(10.11		)
Average costs (per BOE):
Lease operating	$	5.88		$	4.59	$	1.29		$	5.41		$	4.71	$	0.70
Production and ad valorem taxes	1.53			1.14		0.39			1.46			0.88		0.58
Depletion, depreciation, amortization	23.56			20.44		3.12			20.94			21.48		(0.54		)
General and administrative	3.44			2.77		0.67			3.76			3.84		(0.08		)

13

Jones Energy, Inc.

(Unaudited) Non-GAAP Financial Measures and Reconciliations

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

The Company defines EBITDAX as earnings before interest expense, impairment, 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 the Company’s operating performance and compare the results of its operations from period to period and against its peers without regard to its financing methods or capital structure.  The Company excludes the items listed above from net income in arriving at EBITDAX because these amounts can vary substantially from company to company within its 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 the Company’s 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.  The Company’s presentation of EBITDAX should not be construed as an inference that its results will be unaffected by unusual or non-recurring items and should not be viewed as a substitute for GAAP.  The Company’s 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 December 31,						Year Ended December 31,
(in thousands of dollars)	2018			2017			2018			2017
Reconciliation of net income to EBITDAX
Net income (loss)	$	(1,235,488	)	$	41,633		$	(1,346,694	)	$	(178,823	)
Interest expense	22,214			13,270			89,328			51,651
Exploration expense	1,156			2,507			8,157			14,145
Income taxes	(34,901		)	(47,960		)	(61,841		)	(50,667		)
Depreciation and depletion	47,924			39,881			173,904			167,224
Impairment of oil and natural gas properties	1,331,785			1,632			1,331,785			149,648
Accretion of ARO liability	282			240			1,066			960
Change in TRA liability	(52,344		)	(43,661		)	(53,330		)	(59,492		)
Other non-cash charges	21			152			400			2,044
Stock compensation expense	(130		)	558			1,381			6,260
Deferred and other non-cash compensation expense	(32		)	(127		)	56			208
Net (gain) loss on derivative contracts	(49,296		)	29,293			2,757			17,985
Current period settlements of matured derivative contracts	(13,064		)	706			(50,657		)	66,851
Amortization of deferred revenue	(373		)	(437		)	(1,555		)	(1,854		)
(Gain) loss on sale of assets, net of proceeds	(1,148		)	(4		)	(1,333		)	127
(Gain) on debt extinguishment	—			—			—			—
Stand-by rig costs	250			—			250			—
Financing expenses and other loan fees	22			25			105			97
EBITDAX	$	16,878		$	37,708		$	93,779		$	186,364

14

Jones Energy, Inc.

(Unaudited) Non-GAAP Financial Measures and Reconciliations

Adjusted net loss is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements.  The Company defines Adjusted net loss as net income (loss) 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.  The Company believes adjusted net loss is useful to investors because it provide readers with a more meaningful measure of its profitability before recording certain items for which the timing or amount cannot be reasonably determined.  However, this measure is provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in the Company’s financial statements prepared in accordance with GAAP.  The following table provides a reconciliation of net income (loss) as determined in accordance with GAAP to adjusted net loss for the periods indicated:

	Three Months Ended December 31,						Year Ended December 31,
(in thousands except per share data)	2018			2017			2018			2017
Net income (loss)	$	(1,235,488	)	$	41,633		$	(1,346,694	)	$	(178,823	)
Net (gain) loss on derivative contracts	(49,296		)	29,293			2,757			17,985
Current period settlements of matured derivative contracts	(13,064		)	706			(50,657		)	66,851
Impairment of oil and gas properties	1,331,785			1,632			1,331,785			149,648
Exploration	1,156			2,507			8,157			14,145
Non-cash stock compensation expense	(130		)	558			1,381			6,260
Deferred and other non-cash compensation expense	(32		)	(127		)	56			208
(Gain) on debt extinguishment	—			—			—			—
Stand-by rig costs	250			—			250			—
Financing expenses	—			—			3,926			—
Tax impact of adjusting items (1)	(344,997		)	(20,961		)	(350,422		)	(69,627		)
Change in TRA liability	(52,344		)	(43,661		)	(53,330		)	(59,492		)
Change in valuation allowance (2)	261,864			(40,386		)	268,185			21,719
Adjusted net income (loss)	(100,296		)	(28,806		)	(184,606		)	(31,126		)
Adjusted net income (loss) attributable to non-controlling interests	(1,588		)	(1,650		)	(10,318		)	(8,333		)
Adjusted net income (loss) attributable to controlling interests	(98,708		)	(27,156		)	(174,288		)	(22,793		)
Dividends and accretion on preferred stock	(1,848		)	(1,965		)	(7,737		)	(7,924		)
Adjusted net income (loss) attributable to common shareholders	$	(100,556	)	$	(29,121	)	$	(182,025	)	$	(30,717	)
Effective tax rate on net income (loss) attributable to controlling interests							23.0		%	25.1		%

(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.

(2)Includes adjustment for valuation allowance and IRC Section 382 limitation.

15

Jones Energy, Inc.

(Unaudited) Non-GAAP Financial Measures and Reconciliations

Adjusted net loss per share is a supplemental non-GAAP financial measure that is used by management and external users of the Company’s consolidated financial statements.  The Company defines adjusted net loss per share as earnings per share plus that portion of the components of adjusted net income (loss) allocated to the controlling interests divided by weighted average shares outstanding.  The Company believes adjusted net loss per share is useful to investors because it provides readers with a more meaningful measure of its profitability before recording certain items for which the timing or amount cannot be reasonably determined.  However, this measure is provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in the Company’s financial statements prepared in accordance with GAAP.  The following table provides a reconciliation of earnings per share to adjusted net loss per share for the period indicated:

	Three Months Ended December 31,						Year Ended December 31,
	2018			2017			2018			2017
Earnings per share (basic and diluted):	$	(239.73	)	$	10.17		$	(271.94	)	$	(30.22	)
Net (gain) loss on derivative contracts	(9.57		)	5.92			0.04			5.84
Current period settlements of matured derivative contracts	(2.54		)	0.14			(9.94		)	12.90
Impairment of oil and gas properties	258.65			0.33			269.48			28.51
Exploration	0.22			0.51			1.58			2.84
Non-cash stock compensation expense	(0.03		)	0.11			0.26			1.24
Deferred and other non-cash compensation expense	(0.01		)	(0.03		)	0.01			0.03
Stand-by rig costs	0.05			—			0.05			—
Financing expenses	—			—			0.74			—
Tax impact of adjusting items (1)	(69.36		)	(4.73		)	(73.39		)	(19.20		)
Change in TRA liability	(10.52		)	(9.88		)	(11.16		)	(16.43		)
Change in valuation allowance (2)	52.63			(9.13		)	56.16			6.01
Adjusted earnings per share (basic and diluted)	$	(20.21	)	$	(6.59	)	$	(38.11	)	$	(8.48	)
Weighted average Class A shares outstanding:
Basic	4,976			4,419			4,776			3,621
Diluted	4,976			4,419			4,776			3,621

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

(2)Includes adjustment for valuation allowance and IRC Section 382 limitation.

16

Reconciliation of PV-10 to Standardized Measure

SEC PV-10 and NYMEX PV-10 are considered non-GAAP financial measures. SEC PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. SEC PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. SEC PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of SEC PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil, NGL and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil, NGL and natural gas properties. SEC PV-10, however, is not equal to, or a substitute for, the standardized measure of discounted future net cash flows. Our SEC PV-10 measure and the standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

NYMEX PV-10 as disclosed in this release differs from SEC PV-10 due to the oil and natural gas prices utilized in the determination of future net cash flows and other factors including, but not limited to, regional differentials in pricing that vary from SEC pricing. We believe that NYMEX PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows based on the current commodity price environment.

The following table provides a reconciliation of the components of the standardized measure of discounted future net cash flows to SEC PV-10 at December 31, 2018 and 2017 and NYMEX PV-10 at December 31, 2018 assuming strip pricing as of January 2, 2019 through 2023 and keeping pricing flat thereafter.

	As of December 31,
(in millions of dollars)	2018			2017
Standardized measure	$	547		$	566
Present value of future income taxes discounted at 10%	23			61
SEC PV-10	$	570		$	627
Change in pricing assumptions from NYMEX to SEC and other	(192		)
NYMEX PV-10	$	378

17