Exhibit 99.1

JONES ENERGY, INC. PROVIDES 2014 YEAR-END RESERVES, OPERATIONS UPDATE, AND 2015 GUIDANCE

Austin, TX — February 10, 2015 — Jones Energy, Inc. (NYSE: JONE) (“Jones Energy” or “the Company”) today provided its 2014 year-end reserves, an operations update, and 2015 capital budget plan and guidance.

Highlights

·                  Proved reserves increased 29.4% from year-end 2013 to 115.3 MMBoe at year-end 2014 based on SEC pricing(1); proved oil reserves increased 65.9% to 27.7 MMBbls

·                  Cleveland proved reserves increased 44.3% from year-end 2013 to 83.0 MMBoe

·                  PV-10 value of proved reserves increased 47.6% to a record $1.5 billion at SEC prices(1)

·                  2015 capital budget of $210 million; Cleveland development comprises more than 90% of all activity

·                  Three rigs running in the Cleveland as of January 31, 2014 with additional rigs on stand-by; expect to ramp activity to 5 rigs by mid-year pending lower drilling and completion costs

·                  Cleveland well costs have decreased from the December 2014 AFE of $3.8 million to $3.1 million per well as of January 2015; additional cost reductions expected

·                  January production is projected between 25,500 and 26,500 Boe/d (new company record)

·                  2015 full-year production guidance of 21,700 to 23,700 Boe/d; first quarter 2015 production guidance of 24,000 to 25,000 Boe/d

Jones Energy Founder, Chairman, and CEO, Jonny Jones stated, “Our efforts during 2014 have resulted in strong proved reserve growth, particularly in our Cleveland play, and we are now prepared to capitalize on the oil uplift achieved due to our very strong hedging program.  As we enter 2015, over 90% of our projected oil and gas production for the year is hedged at very attractive prices, which has allowed us to reduce our drilling activity while commodity prices and service costs realign.  We find ourselves in the enviable position of being prepared to ramp activity when well-level returns improve, without needing to drill ahead just to meet contract obligations.

(1)  SEC prices for 2014 year-end proved reserves were $94.99 per barrel for oil and $4.35 per MMBtu for natural gas based on the average of such prices for 2014.

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We have been able to drive down our drilling and completion cost for Cleveland wells by nearly 20% in a very short amount of time and we expect that there is still plenty of room to improve upon those expected savings.  Ultimately, we believe that Jones Energy is well prepared to weather the current commodity downturn and to emerge in excellent shape.”

2014 Year-End Proved Reserves

Jones Energy’s year-end 2014 proved reserves based on SEC pricing and definitions increased 29.4% from year-end 2013 to 115.3 MMBoe, of which 52.2% were classified as proved developed (PDP) reserves.  Total proved oil reserves were up 65.9% when compared to year-end 2013, with PDP oil reserves up 56.2%.  The SEC PV-10(2) value of proved reserves for year-end 2014 was approximately $1.5 billion with a corresponding standardized measure(3) value of approximately $1.4 billion.

The following tables set forth the Company’s total proved reserves and the changes in 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 an average 2014 WTI oil price of $94.99 per barrel and an average 2014 Henry Hub spot market natural gas price of $4.35 per MMBtu.

Proved Reserves as of December 31, 2014

Changes in Proved Reserves (MMBoe)

(2)  SEC PV-10 is a non-GAAP financial measure.

(3)  Standardized measure is calculated in accordance with Statement of Financial Accounting Standards No. 69 Disclosures about Oil and Gas Producing Properties, as codified in ASC topic 932, Extractive Activities — Oil and Gas.

(4) Full year 2014 production figures are estimates pending final audit results by the company’s outside auditor

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As of December 31, 2014 the Company had identified 2,765 gross drilling locations.  These include 704 gross drilling locations in the Cleveland play and 777 gross locations in the Arkoma Woodford shale.

2015 Capital Budget and Operating Plan

The Company has established a capital budget of $210 million for 2015, with approximately $190 million dedicated to Cleveland drilling and completion activity and the remainder allocated to capital work-overs and field maintenance projects.  This budget represents a nearly 60% reduction in capital expenditures from 2014 and provides for a development program which keeps capital spending within expected cash flow.  The Company will continue at its current 3 rig pace during the first portion of the year, and assuming targeted additional cost reductions for drilling and completions are achieved, will deploy 2 additional rigs to the Cleveland to reach a 5 rig pace by mid-year.  As of January, the Company’s average estimated cost to drill and complete a Cleveland well with its 33 stage open-hole design had been reduced to $3.1 million, a $700,000 reduction from the $3.8 million estimate provided during December 2014.  The Company continues to actively negotiate with its various service providers and expects that additional cost savings can be attained.

Operations Update

Production Update for the Fourth Quarter of 2014

The Company produced an estimated 2.1 MMBoe (23,200 — 23,400 Boe/d) in the fourth quarter of 2014 and 8.5 MMBoe (approximately 23,200 Boe/d) for the full year.  Oil volumes comprised 28% of production for the fourth quarter and 29% for the full year.  NGL volumes accounted for 29% of the fourth quarter production and 28% of the full year volumes.  During the fourth quarter, liquids accounted for 57% of total production.  Fourth quarter production was negatively impacted by continued delays in well completions and sand flow back issues.  In addition, December production was impacted by more than 1,000 Boe per day due to field production issues, including an outage at a third party processing facility.

These production issues were resolved in January 2015, and as a result, the Company achieved record single day wellhead production reaching over 29,000 Boe/d.  Production for January is projected to be between 25,500 and 26,500 Boe/d.  The significant jump in average daily production between December 2014 and January 2015 was primarily attributable to closing the timing gap between drilled wells and completed wells.

Revenues and EBITDAX for the Fourth Quarter of 2014

The Company estimates revenues for the fourth quarter of 2014 of between $74.1 million and $79.1 million based upon internally projected production figures and estimated realized commodity prices.  The Company estimates EBITDAX for the fourth quarter of 2014 of between $70 million and $75 million.

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2015 Guidance

Based upon the current 2015 capital budget and operating plan, we are projecting 2015 average daily production of between 21,700 and 23,700 Boe/d.  Production is expected to peak during the first quarter and eventually flatten out during the second half of the year.  Assuming targeted cost reductions are achieved and additional rigs are deployed, capital spending is expected to be $210 million for the full year.  First quarter capital expenditures are expected to be higher than the rest of the year, much like production, due to carry-over activity from late 2014, primarily well completions.  For 2015, the company expects to drill between 60 and 70 gross wells with an average working interest of approximately 80%.  Due to carry-over of drilled but uncompleted wells from 2014, the Company expects to complete between 70 and 80 wells during 2015, also with an average working interest of approximately 80%.  A table has been provided below with full year and first quarter 2015 guidance by category:

2015 Guidance

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Risk Management

The Company has provided updated hedge positions.  The estimated mark-to-market value of our hedges was $208.5 million as of December 31st, 2014.  The following table summarizes the Company’s commodity derivative contracts outstanding:

Operations Update, Proved Reserves and Capital Budget Conference Call

In connection with this press release, Jones Energy will host a conference call for investors and analysts to discuss the information provided on Wednesday, February 11, 2015, at 11:30 a.m. ET (10:30 a.m. CT).  Participants may join the conference call by dialing (877) 201-0168 (for domestic U.S.) or (647) 788-4901 (International) and entering conference code 84798577.  If you are not able to participate in the conference call, an audio replay will be available through February 18, 2015, by dialing (855) 859-2056 for domestic U.S., or (404) 537-3406 for international participants, and entering conference code 84798577.  A replay of the conference call may also be found on the Company’s website, www.jonesenergy.com.

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About Jones Energy

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

Investor Contacts:

Robert Brooks, 512-328-2953

Executive Vice President & CFO

Or

Mark Brewer, 512-493-4833

Investor Relations Manager

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 timing and location of additional rigs, results of the Company’s drilling program, the 2015 capital budget, the projected drilling and completion cost savings and the resultant impact on 2015 capital budget, the ability to fund the Company’s 2015 capital expenditure budget largely with free cash, projections regarding total production, average daily production, percentage liquids, operating expenses, production taxes as a percentage of revenue, G&A expenses and capital expenditure levels for 2015.  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, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as the Company’s ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments

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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.

Information Concerning Proved Reserves

Proved reserves volumes and related PV-10 values as of December 31, 2014 contained herein are based on SEC mandated first-day-of-the-month unweighted average prices for 2014 and costs as of December 31, 2014. These prices and costs are not representative of current market values and do not fully reflect declines in such prices and costs which have occurred since mid-year 2014. PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows. The Company expects to release its December 31, 2014 Standardized Measure with year-end earnings results. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. The oil and gas industry uses PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

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